Workover Well Control • •

RILLIN N D G S EE CH D O R O E L B S A WORKOVER WELL CONTROL • •

W R E T L N L E C C O G N IN TROL TRAIN CONTENTS

1. INTRODUCTION TO WORKOVER WELL CONTROL 1-1

2. FUNDAMENTAL PRINCIPLES OF RIG WELL CONTROL 2-1

WORKSHOP 1 2-25 WORKSHOP 1 - ANSWERS 2-28 WORKSHOP 2 2-52 WORKSHOP 2 ANSWERS 2-56 WORKSHOP 3 2-77 WORKSHOP 3 - ANSWERS 2-80 WORKSHOP 4 2-86 WORKSHOP 4 - ANSWERS 2-89 WORKSHOP 5 2-123 WORKSHOP 5 - ANSWERS 2-127

3. WELL CONTROL METHODS 3-1

4. REASONS FOR WELL INTERVENTIONS 4-1

5. WELL INTERVENTION SERVICES 5-1

6. PREVENTION OF FORMATION DAMAGE 6-1

7. PRESSURE BASICS 7-1

8. PRODUCTION WELL KILL PROCEDURES 8-1

9. WELL CONTROL EQUIPMENT 9-1

10. OVERVIEW OF COMPLETIONS 10-1

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A. APPENDIX - FORMULAE AND CONVERSION FACTORS COMMONLY USED IN WELL CONTROL A-1

B. API GUIDELINES (API RP53) B-1

C. APPENDIX - PREVENTERS C-1

D. APPENDIX - CHOKES D-1

E. APPENDIX - WIRELINE SURFACE PRESSURE CONTROL EQUIPMENT E-1

F. APPENDIX - COILED TUBING SURFACE WELL CONTROL EQUIPMENT F-1

G. APPENDIX - HYDRAULIC WORKOVER/SNUBBING EQUIPMENT AND HAZARDS G-1

H. APPENDIX - EQUIPMENT SPECIFIC REQUIREMENTS H-1

I. APPENDIX - HYDRATE FORMATION & PREVENTION I-1

J. SURFACE BOP AND CONTROL SYSTEMS J-1

K. KILL SHEETS K-1

1.1 WHAT IS WORKOVER ? 1-1

1.2 REASONS FOR WORKOVER 1-1

1.2.1 Equipment Failure 1-1

1.2.2 Well Performance Problems 1-2

1.2.3 General 1-2

1.3 METHODS OF WORKING OVER A WELL 1-3

1.4. AIMS AND OBJECTIVES 1-3

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1 INTRODUCTION TO WORKOVER WELL CONTROL

1.1 What is Workover?

Once the well has been drilled and completed it will be utilised to: · Produce formation fluid(s) · Inject fluid into formation(s)

Workover is the term we shall use to describe the process anytime the well is entered after its completion.

This normally involves a process to stop the well producing hydrocarbons, so that the purpose for which it has been entered may be carried out in a safe and controlled manner.

1.2 Reasons for Workover

Problems associated with well completions account for the majority of workovers conducted on oil and gas wells. The necessity to perform a workover may be due to a problem in one of two categories:

· Equipment failure associated with the completion string · The need to replace/change the completion due to well performance problems, or other reservoir management needs

1.2.1 Equipment Failure

A typical completion string has many components and sometimes is designed with an incomplete knowledge of the likely operating conditions for the full life of the well. Equipment may fail for a number of reasons including: · Effects of pressure · Effects of thermal stress · Applied and induced mechanical loading

· Corrosion failure (O2, CO2, H 2S, and acids) · Erosion

It is also important to distinguish between the two types of failure, namely: · Catastrophic failure implying a safety concern e.g. tubing leak · Inability to function with no immediate significant safety concerns, e.g. gas lift valve failure

The failure of the equipment may dictate two courses of action: · Repair or removal and replacement · Abandon the well – In a case where due to safety implications the well is not salvageable

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Typical component failures may include: · Tubing failure · Packer failure · Failure of flow control device such as SCSSV, sliding sleeve, wireline nipple · Xmas tree / tubing hanger failure / leakage · Failure of gas lift valve and / or mandrel · Downhole pump failure

The consequences of a component failure depend upon its integration with the completion string and its replacement may require: · Removal and replacement by means of wireline or coiled tubing without having to kill the well · Removal and replacement of the Xmas tree · Partial or full removal and replacement of the completion string · Other remedial work

1.2.2 Well Performance Problems

Workovers designed to improve the vertical lift performance of wells are very common. Workovers conducted in this way can be directed at: · The improvement or restoration of the performance of wells under artificial lift · The installation or replacement of artificial lift equipment

The two major factors affecting well performance are reservoir pressure and water cut and changes in completion design have to be made accordingly

1.2.3 General

It may not always be possible, or desirable, to perform a workover immediately, if for example, the means are not readily available. In this case the well may be:

· Shut-In, if there is no safety problem. This may be in the case of high water-cut, for example.

· Temporarily suspended, if there is a safety problem, such as a tubing leak. This involves installing the required number of mechanical and fluid barriers so that the well is rendered safe.

· Abandonment, if the problem is so severe that it is not safe or economical to perform a workover. This may occur if there are major well performance problems or irretrievable junk in the well. In this case, permanent barriers such as cement plugs will be placed in the well, perhaps along with other requirements such as removing the wellhead.

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1.3 METHODS OF WORKING OVER A WELL

The following methods can be used to work over a completed well.

· Drilling / Workover rig · Wireline · Coiled Tubing · Hydraulic workover / snubbing unit

Each one of these methods and their implications for well control shall be discussed in some detail in this manual.

1.4 AIMS AND OBJECTIVES

The overall aim of the course is to provide a delegate with the theoretical skills essential in applying well control during workover operations with the objective of improving the individuals knowledge and level of competence.

AIMS

The individual aims are to: • Provide an appreciation of completion types, equipment, equipment functions and practices as recognised by the industry. • Establish an increased awareness of workover well control equipment, methods and practices. • Furnish a student with a knowledge of legislative guidelines and standards. • Provide an awareness of how to discern well pressure control problems and apply solutions.

OBJECTIVES

The individual objectives are to assist the delegate to: • Improve his/her competence in Workover Well Control. • Identify well pressure control problems from available well data i.e. pressure, volume and flow characteristic. • Identify solutions to various well control problems. • Understand legislative guidelines and standards. • Determine if well control equipment is fit for purpose. • Obtain certification.

2.0 OBJECTIVES 2-1

2.1 GENERAL INFORMATION 2-1

2.2 HYDROSTATIC PRESSURE 2-3

2.3 FORMATION PRESSURE 2-4

2.4 NORMAL FORMATION PRESSURE 2-4

2.5 ABNORMAL PRESSURE 2-7

2.5.1 Under-compaction in shales 2-7

2.5.2 Salt Beds 2-9

2.5.3 Mineralisation 2-9

2.5.4 Tectonic Causes 2-9

2.5.5 Faulting 2-10

2.5.6 Diapirism 2-10

2.5.7 Reservoir Structure 2-10

2.5.8 Typical types of hydrocarbon traps versus percentage of world total 2-11

2.5.9 Typical hydrocarbon seals versus percentage of world total 2-11

2.6 FORMATION FRACTURE pressure 2-12

2.7 Leak-off tests 2-14

2.7.1 Leak-Off Test Procedure 2-14

2.8 Maximum allowable annular surface pressure - maasp 2-2 2.9 casing setting depths 2-21

2.9.1 Deep Casing Setting Depths 2-22

2.10 Circulating Pump pressure 2-23

WORKSHOP 1 2-25 WORKSHOP 1 - ANSWERS 2-28

CAUSES OF KICKS 2-31

2.11 objectives 2-31

2.12 introduction 2-31

2.13 primary well control - how it is effected 2-31

2.14 CAUSES OF KICKS & INFLUXES 2-36

2.14.1 Failure to keep the hole full during a trip 2-37 2.14.2 Swabbing & Surging 2-37 2.14.3 Loss & Circulation 2-40 2.14.4 Insufficient mud weight 2-40 2.14.5 Abnormal pressure formations 2-40 2.14.6 Shallow Gas Sands 2-43 2.14.7 Special Situations 2-43

2.15 Extracts from api rp59 2-45

WORKSHOP 2 2-52 WORKSHOP 2 ANSWERS 2-56

KICK INDICATORS 2-58

2.16 objectives 2-58

2.17 EARLY WARNING SIGN 2-58

2.18 INCREASE IN DRILLING RATE OF PENETRATION - DRILLING BREAK 2-58

2.19 INCREASED TORQUE AND DRAG 2-59 2.20 DECREASE IN SHALE DENSITY 2-59

2.21 INCREASE IN CUTTING SIZE AND SHAPE 2-60

2.22 MUD PROPERTY CHANGES 2-60

2.23 INCREASE IN TRIP, CONNECTION & A BACKGROUND GAS 2-61

2.24 CHANGE IN THE TEMPERATURE OF THE RETURN DRILLING MUD 2-62

2.25 DECREASE IN D-EXPONENT 2-64

2.26 POSITIVE KICK SIGNS 2-66

2.27 KICK BEHAVIOUR 2-67

2.28 CONTROLLING INFLUENCES & KICKS 2-69

2.28.1 Circulating Principles 2-69 2.28.2 Normal Circulation Rate 2-70 2.28.3 Fluid Displacement/Pump Condensations 2-70 2.28.4 Gas Migration Expansion/Non Expansion 2-71

WORKSHOP 3 2-77 WORKSHOP 3 - ANSWERS 2-80

SHUT-IN PROCEDURES

2.29 OBJECTIVES 2-81

2.30 GENERAL INTRODUCTION TO SHUT-IN PROCEDURES ON A FIXED RIG 2-81

2.31 SOFT SHUT-IN PROCEDURE WHILE DRILLING ON A FIXED RIG 2-82

2.32 SOFT SHUT-IN PROCEDURE WHILE TRIPPING ON A FIXED RIG 2-82

2.33 HARD SHUT-IN PROCEDURE WHILE DRILLING ON A FIXED RIG 2-83

2.34 FAST SHUT-IN PROCEDURE WHILE DRILLING ON A FIXED RIG 2-84 2.35 DIVERTER PROCEDURE WHILE DRILLING ON A FIXED RIG 2-84

WORKSHOP 4 2-86 WORKSHOP 4 - ANSWERS 2-89

METHODS OF WELL CONTROL 2-90

2.36 OBJECTIVES 2-90

2.37 KILL METHODS GENERAL 2-90

2.38 CONSTANT BOTTOM HOLE PRESSURE KILL METHODS 2-93

2.39 THE DRILLER'S METHOD 2-94

2.40 THE WAIT & WEIGHT METHOD 2-102

2.41 volumetric well control 2-106

2.41.1 Calculations for Mud Volume to Bleed for PW 2-107 2.41.2 Graphical Example of a Volumetric Bleed 2-108 2.41.3 Important Points 2-109 2.41.4 Lubrication 2-110

2.42 volumetric stripping 2-112 2.42.1 Example of Volumetric Stripping 2-112 2.42.2 Well Details 2-113 2.42.3 Shut-in Procedure for a Swabbed Kick while Tripping 2-114 2.42.4 Universal Volumetric Well Control Equation 2-114

2.43 edited extract from api rp53 2-117

2.44 removal of gas trapped in bop's 2-119

WORKSHOP 5 2-123 WORKSHOP 5 - ANSWERS 2-127

2.45 ORGANISING AND DIRECTING WELL CONTROL OPERATIONS 2-129

2.45.1 Organising Considerations 2-129 2.45.2 Drills 2-130 2.45.2.1 Pit Drills 2-130 2.42.2.2 H2S Drills

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FUNDAMENTAL PRINCIPLES OF RIG WELL CONTROL

2.0 OBJECTIVES

The objectives of this section are to introduce the Fundamental Principles of Well Control.

2.1 GENERAL INFORMATION

The function of Rig Well Control can be conveniently subdivided into three main categories, namely PRIMARY WELL CONTROL, SECONDARY WELL CONTROL and TERTIARY WELL CONTROL. These categories are briefly described in the following paragraphs.

Primary Well Control

It is the name given to the process which maintains a hydrostatic pressure in the wellbore greater than the pressure of the fluids in the formation being drilled, but less than formation fracture pressure. If hydrostatic pressure is less than formation pressure then formation fluids will enter the wellbore. If the hydrostatic pressure of the fluid in the wellbore exceeds the fracture pressure of the formation then the fluid in the well could be lost. In an extreme case of lost circulation the formation pressure may exceed hydrostatic pressure allowing formation fluids to enter into the well.

An overbalance of hydrostatic pressure over formation pressure is maintained, this excess is generally referred to as a trip margin.

Secondary Well Control

If the pressure of the fluids in the wellbore ( i.e. mud) fail to prevent formation fluids entering the wellbore, the well will flow. This process is stopped using a “blow out preventer” to prevent the escape of wellbore fluids from the well.

This is the initial stage of secondary well control. Containment of unwanted formation fluids.

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Tertiary Well Control

Tertiary well control describes the third line of defence. Where the formation cannot be controlled by primary or secondary well control (hydrostatic and equipment). An underground blowout for example. However in well control it is not always used as a qualitative term. ‘Unusual well control operations’ listed below are considered under this term:-

a) A kick is taken with the kick off bottom.

b) The drill pipe plugs off during a kill operation.

c) There is no pipe in the hole.

d) Hole in drill string.

e) Lost circulation.

f) Excessive casing pressure.

g) Plugged and stuck off bottom.

h) Gas percolation without gas expansion.

We could also include operations like stripping or snubbing in the hole, or drilling relief wells. The point to remember is "what is the well status at shut in?" This determines the method of well control.

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2.2 HYDROSTATIC PRESSURE

Hydrostatic pressure is defined as the pressure due to the unit weight and vertical height of a column of fluid.

Hydrostatic Pressure = Fluid Density x True Vertical Depth

Note: It is the vertical height/depth of the fluid column that matters, its shape is unimportant. TVD

Figure 2.1 Different shaped vessels

Since the pressure is measured in psi and depth is measured in feet, it is convenient to convert mud weights from pounds per gallon ppg to a pressure gradient psi/ft. The conversion factor is 0.052.

Pressure Gradient psi/ft = Fluid Density in ppg X 0.052

Hydrostatic Pressure psi = Density in ppg X 0.052 X True Vert. Depth

The Conversion factor 0.052 psi/ft per lb/gal is derived as follows:

A cubic foot contains 7.48 US gallons.

A fluid weighing 1 ppg is therefore equivalent to 7.48 lbs/cu.ft

The pressure exerted by one foot of that fluid over the area of the base would be:

7.48 lbs –––––––– = 0.052 psi 144 sq.ins 12"

12" Figure 2.2 Area definition of a cubic foot 12"

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Example:

The Pressure Gradient of a 10 ppg mud

= 10 x 0.052

= 0.52 psi/ft

Conversion constants for other mud weight units are:

Specific Gravity x 0.433 = Pressure Gradient psi/ft

Pounds per Cubic Foot ÷ 144 = Pressure Gradient psi/ft

2.3 FORMATION PRESSURE

Formation pressure or pore pressure is said to be normal when it is caused solely by the hydrostatic head of the subsurface water contained in the formations and there is pore to pore pressure communication with the atmosphere.

Dividing this pressure by the true vertical depth gives an average pressure gradient of the formation fluid, normally between 0.433 psi/ft and 0.465 psi/ft. The North Sea area pore pressure averages 0.452 psi/ft. In the absence of accurate data, 0.465 psi/ft which is the average pore pressure gradient in the Gulf of Mexico is often taken to be the “normal” pressure gradient.

Note: The point at which atmospheric contact is established may not necessarily be at sea-level or rig site level.

2.4 NORMAL FORMATION PRESSURE

Normal Formation Pressure is equal to the hydrostatic pressure of water extending from the surface to the subsurface formation. Thus, the normal formation pressure gradient in any area will be equal to the hydrostatic pressure gradient of the water occupying the pore spaces of the subspace formations in that area.

The magnitude of the hydrostatic pressure gradient is affected by the concentration of dissolved solids (salts) and gases in the formation water. Increasing the dissolved solids (higher salt concentration) increases the formation pressure gradient whilst an increase in the level of gases in solution will decrease the pressure gradient.

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For example, formation water with a salinity of 80,000 ppm sodium chloride (common salt) at a temperature of 25°C, has a pressure gradient of 0.465 psi/ft. Fresh water (zero salinity) has a pressure gradient of 0.433 psi/ft.

Temperature also has an effect as hydrostatic pressure gradients will decrease at higher temperatures due to fluid expansion.

In formations deposited in an offshore environment, formation water density may vary from slightly saline (0.44 psi/ft) to saturated saline (0.515 psi/ft). Salinity varies with depth and formation type. Therefore, the average value of normal formation pressure gradient may not be valid for all depths. For instance, it is possible that local normal pressure gradients as high as 0.515 psi/ft may exist in formations adjacent to salt formations where the formation water is completely salt-saturated.

The following table gives examples of the magnitude of the normal formation pressure gradient for various areas. However, in the absence of accurate data, 0.465 psi/ft is often taken to be the normal pressure gradient.

Figure 2.3 Average Normal Formation Pressure Gradients

Pressure Gradient Formation Water Example area psi/ft (SG) Fresh water 0.433 1.00 Rocky Mountains and Mid- continent, USA Brackish water 0.438 1.01 Salt water 0.442 1.02 Most sedimentary basins worldwide Salt water 0.452 1.04 North Sea, South China Sea Salt water 0.465 1.07 Gulf of Mexico, USA Salt water 0.478 1.10 Some area of Gulf of Mexico

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Figure 2.4

Porosity % 0 1020304050607080 0

1000

2000 Permian Pennsylvania and Oklahoma (Athy) Lias Germany (Won Engelwardt)

3000 Miocene and Pliocene Po Valley (Storer) Depth (metres) Tertiary Gulf Coast (Dickinson)

4000 Tertiary Japan (Magara)

Joides

5000

Reduction in clay porosity as a function of depth (modified from Magara, 1978)

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2.5 ABNORMAL PRESSURE

Every pressure which does not conform with the definition given for normal pressure is abnormal.

The principal causes of abnormal pressures are:-

2.5.1 Under-compaction in shales

When first deposited, shale has a high porosity. More than 50% of the total volume of uncompacted clay-mud may consist of water in which it is laid. During normal compaction, a gradual reduction in porosity accompanied by a loss of formation water occur as the thickness and weight of the overlaying sediments increase. Compaction reduces the pore space in shale, as compaction continues water is squeezed out. As a result, water must be removed from the shale before further compaction can occur. See Fig 2.4.

Not all of the expelled liquid is water, hydrocarbons may also be flushed from the shale.

If the balance between the rate of compaction and fluid expulsion is disrupted such that fluid removal is impeded then fluid pressures within the shale will increase. The inability of shale to expel water at a sufficient rate results in a much higher porosity than expected for the depth of shale burial in that area.

Figure 2.5a

Quality of reservoir permeability.

Coarse-grained, Fine Grained Poorly-sorted well sorted Good permeability Poor permeability

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Fig 2.5b

10000 8000 6000 4000

2000

1000 800 600 400

200

100 80 60 40

PERMEABILITY (md) PERMEABILITY 20 Coarse - and very coarse - grained

10 Coarse - and medium - grained 8 Fine - grained 6 4 Silty Clayey 2

1 0 246810121416182024283032343622 26 POROSITY % The relationship between permeability and porosity (from Chilingar, 1964)

Figure 2.5c

WATER ESCAPE CURVE WATER CONTENT OF SHALES (SCHEMATIC) WATER AVAILABLE % WATER FOR MIGRATION 0 1020304050607080 SEDIMENT SURFACE

PORE WATER PORE AND INTERLAYER WATER EXPULSION 1st DEHYDRATION AND LATTICE WATER STABILITY ZONE INTER- LAYER LATTICE WATER WATER STABILITY ZONE

BURIAL DEPTH BURIAL (SCHEMATIC) 2nd DEHYD'N INTERLAYER WATER STAGE ISOPLETH

3rd DEHYDRATION DEEP BURIAL STAGE WATER LOSS 'NO MIGRATION LEVEL' Water Distribution Curves for Shale Dehydration

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2.5.2 Salt Beds

Continuous salt depositions over large areas can cause abnormal pressures. Salt is totally impermeable to fluids and behave plastically. It deforms and flows by recrystallisation. Its properties of pressure transmission are more like fluids than solids, thereby exerting pressures equal to the overburden load in all directions. The fluids in the underlying formations cannot escape as there is no communication to the surface and thus the formations become over pressured.

2.5.3 Mineralisation

The alteration of sediments and their constituent minerals can result in variations of the total volume of the minerals present. An increase in the volume of these solids will result in an increased fluid pressure. An example of this occurs when anhydrite is laid down. If it later takes on water crystallisation, its structure changes to become gypsum, with a volume increase of around 35%.

2.5.4 Tectonic Causes

Is a compacting force that is applied horizontally in subsurface formations. In normal pressure environments water is expelled from clays as they are being compacted with increasing overburden pressures. If however an additional horizontal compacting force squeezes the clays laterally and if fluids are not able to escape at a rate equal to the reduction in pore volume the result will be an increase in pore pressure.

Figure 2.6

EXTENSION EXTENSION

COMPRESSION COMPRESSION

Amount of Shortening

POSSIBLE OVERPRESSURED ZONES Abnormal Formation Pressures caused by Tectonic Compressional Folding

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2.5.5 Faulting

Faults may cause abnormally high pressures. Formation slippage may bring a permeable formation laterally against an impermeable formation preventing the flow of fluids. IMPERVIOUS SHALE GAS Non-sealing faults may allow fluids to move from a deeper OIL permeable formation to a shallower formation. If the shallower formation is sealed then it will be pressurised from the deeper zone.

Figure 2.7 WATER

2.5.6 Diapirism This is a trap resulting from faulting in which the block on the right has moved up with respect to the one A salt diapirism is an upward intrusion of salt to form a salt on the left. dome. This upthrust disturbs the normal layering of sediments and over pressures can occur due to the folding Cap Rock and faulting of the intruded formations. Gas Oil Water Water

Figure 2.8 Salt

2.5.7 Reservoir Structure Salt domes often deform overlying Abnormally high pressures can develop in normally rocks to form traps like the one shown here. compacted rocks. In a reservoir in which a high relief structure contains oil or gas, an abnormally high pressure gradient as measured relative to surface will exist as shown in the following fig:

a Gas-Oil Contact Gas (GOC) Closure OIL Oil-Water Oil Contact (OWC) Water Spill Point Figure 2.9a Figure2.9b b

Gas

Gas Water Gas-Water Gas-Oil Oil WATER Contact Contact (GWC) (GOC)

An anticlinal type of folded structure Trap nomenclature (a) in a simple is shown here. Anticline differs from structural trap and (b) in stratigraphic traps. a dome in being long and narrow. Note that the size of the stratigraphic trap on the left is limited only by its petroleum content, while the size of the trap on the right is self-limiting.

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2.5.8 Typical types of hydrocarbon traps versus percentage of world total.

Major types of oil traps and percentage of world’s petroleum occurrence for each.

75%

7% 9% 1% 2% 3% 3%

Anticlines Faults Salt Diapirs Unconformity Reef Other Combination Stratigraphic

Structural Traps Stratigraphic Traps Combination Traps

Figure 2.10

2.5.9 Typical hydrocarbon seals versus percentage of world total

Types of seals and percentage of world’s petroleum occurrence for each.

65% 33%

Shale Evaporite Carbonate (salt) (limestone & dolomite)

Figure 2.11

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2.6 FORMATION FRACTURE PRESSURE

In order to plan to drill a well safely it is necessary to have some knowledge of the fracture pressures of the formation to be encountered. The maximum volume of any uncontrolled influx to the wellbore depends on the fracture pressure of the exposed formations.

If wellbore pressures were to equal or exceed this fracture pressure, the formation would break down as fracture was initiated, followed by loss of mud, loss of hydrostatic pressure and loss of primary control. Fracture pressures are related to the weight of the formation matrix (Rock) and the fluids (water/oil) occupying the pore space within the matrix, above the zone of interest. These two factors combine to produce what is known as the overburden pressure. Assuming the average density of a thick sedimentary sequence to be the equivalent of 19.2 ppg then the overburden gradient is given by:

0.052 x 19.2 = 1.0 psi/ft

Since the degree of compaction of sediments is known to vary with depth the gradient is not constant.

NORMAL COMPACTION Abnormally High Pressure Due to Hydrocarbon Column

0 1. Pressure on the Gas-Water Contact = 2790 psi

1 2. Less Gas Column Pressure = 0.10 x 1000’ = 100 psi

3. Pressure at top of Sand = 2690 psi

4 4. Abnormal Gradient at top Sand 2690 psi ÐÐÐÐÐÐÐ = 0.538 psi/ft 5000 ft

1000’ GAS GRADIENT = 0.10 psi/ft 6 Normal pressure at WATER the Gas-Water contact .465 x 6000’ = 2790 psi

DEPTH - 1000 ft 7

Figure 2.12

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Onshore, since the sediments tend to be more compacted, the overburden gradient can be taken as being close to 1.0 psi/ft. Offshore, however the overburden gradients at shallow depths will be much less than 1.0 psi/ft due to the effect of the depth of seawater and large thicknesses of unconsolidated sediment. This makes surface casing seats in offshore wells much more vulnerable to break down and is the reason why shallow gas kicks should never be shut in. See Fig 2.13

Fracture Gradient Comparisons (for illustration purposes only) AB

0 ft

Hydrostatic due to sea water 1500 x 0.445 = 667.5 psi 1500 ft Pressure due to overburden 3000 x 1.0 = 3000 psi Pressure due to overburden 1500 x 1.0 = 1500 psi

3000 ft Total Overburden Total Overburden 2167.5 psi (0.723 psi/ft) 3000 psi (1.0 psi/ft)

0 ft

Hydrostatic due to sea water 1500 x 0.445 = 667.5 psi 1500 ft

Pressure due to overburden 12000 x 1.0 = 12000 psi Pressure due to overburden 10500 x 1.0 = 10500 psi

12000 ft Total Overburden Total Overburden 11167.5 psi (0.93 psi/ft) 12000 psi (1.0 psi/ft)

Figure 2.13

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2.7 LEAK-OFF TESTS

The leak-off test establishes a practical value for the input into fracture pressure predictions and indicates the limit of the amount of pressure that can be applied to the wellbore over the next section of hole drilled. It provides the basic data needed for further fracture calculations and it also tests the effectiveness of the cement job.

The test is performed by applying an incremental pressure from the surface to the closed wellbore/casing system until it can be seen that fluid is being injected into the formation. Leak-off tests should normally be taken to this leak-off pressure unless it exceeds the pressure to which the casing was tested. In some instances as when drilling development wells this might not be necessary and a formation competency test, where the pressure is only increased to a predetermined limit, might be all that is required.

2.7.1 Leak-Off Test Procedure:

Before starting, gauges should be checked for accuracy. The upper pressure limit should be determined.

1) The casing should be tested prior to drilling out the shoe. 2) Drill out the shoe and cement, exposing 5 - 10 ft of new formation. 3) Circulate and condition the mud, check mud density in and out. 4) Pull the bit inside the casing. Line up cement pump and flush all lines to be used for the test. 5) Close BOPs. 6) With the well closed in, the cement pump is used to pump a small volume at a time into the 1 1 well typically a /4 or /2 bbl per min. Monitor the pressure build up and accurately record the volume of mud pumped. Plot pressure versus volume of mud pumped. 7) Stop the pump when any deviation from linearity is noticed between pump pressure and volume pumped. 8) Bleed off the pressure and establish the amounts of mud, if any, lost to the formation.

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EXAMPLES OF LEAK-OFF TEST PLOT INTERPRETATION

In non-consolidated or highly permeable formations fluid can be lost at very low pressures. In this case the pressure will fall once the pump has been stopped and a plot such as that shown in Fig 2.14a will be obtained. Figs 2.14b and 2.14c show typical plots for consolidated permeable and consolidated impermeable formations respectively.

a) Unconsolidated b) Consolidated Permeable Formations Formations PRESSURE PRESSURE

CUMULATIVE VOLUME CUMULATIVE VOLUME

c) Consolidated Impermeable Formations

Final Pumping Pressure After Each Volume Increment

Final Static Pressure After Each Volume Increment

Leak-off Point PRESSURE

CUMULATIVE VOLUME

IDEALISED LEAK-OFF TEST CURVES

Figure 2.14

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Working example of leak-off test procedure (floating rigs)

“Operational Drilling Procedures for Floating Rigs” is designed to determine the equivalent mud weight at which the formation will accept fluid. This test is not designed to break down or fracture the formation. This test is normally performed at each casing shoe.

Prior to the formation leak-off, have “handy” a piece of graph paper (see graph 1 ), pencil and straight edge (ruler). Utilising the high pressure cement pumping unit, perform leak-off as follows:

1. Upon drilling float equipment, clean out rat hole and drill 15 ft of new hole. Circulate and condition hole clean. Be assured mud weight in and mud weight out balance for most accurate results.

2. Pull bit up to just above casing shoe. Install circulating head on DP.

3. Rig up cement unit and fill lines with mud. Test lines to 2500 psi. Break circulation with cementing unit, be assured bit nozzles are clear. Stop pumping when circulation established.

4. Close pipe rams. Position and set motion compensator, overpull drillpipe (+/- 10,000 lbs), close choke/kill valves.

5. At a slow rate (i.e. 1/4 or 1/2 BPM), pump mud down DP.

6. a. Pump 1/4 bbl - record/plot pressure on graph paper.

b. Pump 1/4 bbl - record/plot pressure on graph paper.

c. Pump 1/4 bbl - record/plot pressure on graph paper.

d. Pump 1/4 bbl - record/plot pressure on graph paper.

e. Pump 1/4 bbl - record/plot pressure on graph paper.

f. Continue this slow pumping. Record pressure at 1/4 bbl increments until two points past leak-off. (See examples, Graph 1, 2 & 3.)

g. Upon two points above leak-off, stop pumping. Allow pressure to stabilize. Record this stabilized standing pressure (normally will stabilize after 15 mins or so).

h. Bleed back pressure into cement unit tanks. Record volume of bleed back.

i. Set and position motion compensator, open rams.

j. Rig down and cement unit lines. Proceed with drilling operations.

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k. Leak-off can be repeated after step 6 if data confirmation is required, otherwise leak-off test is complete.

NOTE: For 20" and 13 3/8" csg leak-off tests, plot pressure every 1/2 bbl. Results will be the same.

It should be noted that in order to obtain the proper leak-off and pumping rate plot, it will be necessary to establish a continuous pump rate at a slow rate in order to allow time to read the pressure and plot the point on the graph. (Barrels pumped vs. pressure - psi), normally 1/2 BPM is sufficient time.

A pressure gauge of 0-2000 psi with 20 or 25 increments is recommended.

NOTE: In the event Standing Pressure is lower than leak-off point. Use standing pressure to calculate equivalent mud weight. Always note volume of mud bled back into tanks.

2.7.2 Formation Breakdown Pressure (psi)

= hydrostatic pressure of mud in casing + applied surface pressure = (mud wt. x constant x vert shoe depth) + surface pressure The formation breakdown pressure can be expressed as a GRADIENT.

Formation Breakdown Pressure (psi) Formation Breakdown Gradient (psi/ft) = –––––––––––––––––––––––––––––– Vert. Shoe Depth (ft)

The formation breakdown gradient expressed as a maximum allowable mud weight:

Maximum Allowable Mud Weight (ppg) = Formation Breakdown Gradient (psi/ft) ÷ 0.052

or Formation Breakdown Pressure (psi) Maximum Allowable Mud Weight (ppg) = –––––––––––––––––––––––––––––– ÷ 0.052 Vert Shoe Depth (ft)

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Graph 2.1 Formation Pressure Test Work Sheet

1100

1000

900

800

700

600

500

400 SURFACE TEST PRESSURE - PSI SURFACE

300

NOTE: Commence measuring volume 200 NOTE: after pressuring up to 200 psi NOTE: Pump at a 0.3 BPM rate and NOTE: plot pressures and volumes NOTE: (BBL's MUD)

100

0 01234567891011121314

BARRELS MUD PUMPED

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Graph 2.2

Typical Pressure Test csg set at 5000' TVD 1100 w/12 lb mud in hole.

1000 Required Test Pressure (Equivalent to 16,0 Mud)

900

800 705 psi 5 min stabilized pressure

700

600

500

400 SURFACE TEST PRESSURE - PSI SURFACE

300

NOTE: Commence plotting pressure 200 NOTE: and pumped volume after NOTE: pressuring up to 200 psi

100

0 01234567891011121314

BARRELS MUD PUMPED

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Graph 2.3

Formation Typical Pressure Plot for Breakdown Formation Breakdown and Pressure Fracture Propagation 1100

Leak-off Pressure 1000

900

800

700

600

500

400 SURFACE TEST PRESSURE - PSI SURFACE

300

NOTE: Commence plotting pressure 200 NOTE: and pumped volume after NOTE: pressuring up to 200 psi

100

0 01234567891011121314

BARRELS MUD PUMPED

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2.8 MAXIMUM ALLOWABLE ANNULAR SURFACE PRESSURE - MAASP.

The leak-off test was used to determine the strength of the formations below the

casing shoe.

The Formation Breakdown Pressure = an applied surface pressure + hydrostatic pressure of mud in the casing

The applied surface pressure at which leak-off occurred is the maximum allowable annular

surface pressure with the mud weight in use at that time. MAASP is the maximum surface

pressure that can be tolerated before the formation at the shoe fractures.

MAASP = Formation Breakdown pressure at shoe – Hydrostatic Pressure of mud in use in the

casing shoe

or rewritten as:

MAASP = (Fracture gradient – Mud gradient) x True Vert. Shoe Depth

or as:

MAASP = (Max equiv. mud wt. – Mud wt. in casing) x (0.052 x True Vert. shoe depth)

MAASP is only valid if the casing is full of the original mud, if the mud weight in the casing is

changed MAASP must be recalculated.

The calculated MAASP is no longer valid if influx fluids enter into the casing.

a a

2.9 CASING SETTING DEPTHS Seabed a a aa a a a a 30" Casing aa a a a a (Conductor) a a a a a aa a a a The choice of setting depths for all the casing strings is a 36" Hole a a a a a a a a aa aa vital part of the well planning process. An incorrect a a 20" Casing (Surface String.) a aa aa decision with the casing setting depths too shallow could 26" Hole a a a a aa a a a a a aaa a have serious consequences. An unnecessarily deep setting a a a aa a a a depth could have adverse economic consequences when a aa a aa a a a a a considering the extra time needed to drill the hole deeper a aa a a a 13 1/8" Casing a(Intermediate String) aaaa and the extra amount of casing required to be run and 17 1/2" Holea a a a a a a a cemented. a a a a a a a a a aa a a a a a a a a a aa a a a a a a a a a a a a a aa a a a aa a a a a a a aa a a a a a a 9 5/8" Casing (Production String) a a a aa 12 1/4" Hole a a a a a Figure 2.15 a a a aa aa a a a a a aaa a a Typical Offshore Casing Program a a a 7" Liner aaa a a 8 1/2" Hole

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2.9.1 DEEP CASING SETTING DEPTHS

The selection of deeper casing setting depths will use different criteria to those used for shallow

casing seats. Initial selection of the setting depth is made with reference to the anticipated

lithological column, formation pressure and fracture gradient profiles. Once all the information has been collated from offset well data a plot similar to that shown in Fig 2.16 can be drawn up. By studying the geology and pressure profiles, tentative setting depths can be chosen based on the prevention of formation breakdown by mud weights in use in the subsequent hole section. See Fig 2.17. From a Well Control point of view, it is necessary to determine whether this tentative setting depth will give adequate protection against formation breakdown when a kick is taken. A kick tolerance “factor” will normally be applied.

Preferred Setting Depths Required Setting Depths (based on lithological column) (to prevent formation fracture due to weight of mud column) 0 0

2 Fracture Gradient 2 a a a a Fracture Gradient a 4 a 4 a a a a a a a a a a 6 a6 a

Proposed Mud 8 8 Depth x 1000 ft Depth x 1000 ft Weight program

10 10

Pore Pressure Gradient Pore Pressure Gradient

12 12

14 14

8.0 10.0 12.0 14.0 16.0 18.0 20.0 8.0 10.0 12.0 14.0 16.0 18.0 20.0 Pressure Gradient - lb/gal Equivalent Pressure Gradient - lb/gal Equivalent PRESSURE PROFILE PREDICTIONS PRESSURE PROFILES WITH CASING SETTING DEPTHS

Figure 2.16 Figure 2.17

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The pressure provided by the rig pump is the sum of all of the individual pressures in the circulating systems. All the pressure produced by the pump is expended in this process, overcoming friction losses between the mud and whatever it is in contact with:

• Pressure loss in surface lines • Pressure loss in drill-string • Pressure loss across but jets • Pressure loss in annulus

Pressure losses are independent of hydrostatic and imposed pressures.

Pressure losses in the annulus acts as a “back pressure” on the exposed formations, consequently the total pressure at the bottom of the annulus is higher with the pump on than with the pump off. Static bottom Annulus Circulating bottom hole pressure = hole pressure + pressure losses

STATIC CIRCULATING Formation Formation under will Kick Control

0 3000 psi psi

Annulus Pressure Loss = 250 psi

10 ppg MUD

BHP = 5200 psi BHP = 5450 psi

10000’ 5300 psi Formation Pressure 5300 psi

Figure 2.18

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The total pressure on bottom can be calculated and converted to an equivalent static mud weight which exerts the same pressure.

÷ ÷ Equivalent Mud Wt (ppg) = (APL + Pmuda) 0.052 TVD

or APL Equivalent Mud wt E.C.D = Mud Wt in use + –––––––––– 0.052 X TVD

Where: APL = Annulus Pressure Loss

Pmuda = Hydrostatic Mud Pressure in Annulus

Circulating pressure will be affected if the pump rate or the properties of the fluid being circulated are changed.

Example:- Assuming a circulating pump pressure is 3000 psi when pumping at 100 spm. The pump speed is increased to 120 spm. To approximate the new circulating pump pressure:

New Pump Speed 2 P(2) = P(1) x ––––––––––––––––– (Original Pump Speed ) Where:- P(1) = Original pump pressure at original pump speed. P(2) = New circulating pressure at new pump speed.

120 2 P(2) = 3000 x –––– P(2) = 4320 psi at 120 spm ( 100 ) Example:- Assuming a circulating pump pressure in 3000 psi with a 10 ppg mud weight pumping at 100 spm. If the mud weight in the system was changed to 12 ppg. To approximate the new circulating pump pressure:

New Mud Weight 12 P(2) = P(1) x –––––––––––––––– P(2) = 3000 x ––– Original Mud Weight 10

P(2) = 3600 psi when circulating with 12 ppg mud.

Note: Changing either pump speed or mud weight will affect annulus pressure losses.

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WORKSHOP 1

SCORE 1. Convert the following mud densities into pressure gradients. a. 13.5 ppg ______psi/ft b. 16 ppg ______psi/ft c. 12 ppg ______psi/ft 2

2. Convert the following gradients into mud densities.

a. 0.806 psi/ft ______ppg b. 0.598 psi/ft ______ppg c. 0.494 psi/ft ______ppg 2

3. Calculate the hydrostatic pressure for the following.

a. 9.5 ppg mud at 9000ft MD/8000 ft TVD =______b. 15.5 ppg mud at 18000ft TVD/21000ft MD =______c. 0.889 psi/ft mud at 11000ft MD/9000ft TVD =______2

4. Convert the following pressures into equivalent mud weights in PPG.

a. 3495 psi at 7000ft =______b. at 4000ft with 2787 psi =______c. 12000ft MD/10500ft TVD with 9000 psi =______2

5. High bottom hole temperatures could affect the hydrostatic pressure gradients resulting in:

a. An increase in the hydrostatic gradient b. A decrease in the hydrostatic gradient c. Would have no effect 2

6. Assuming a 10 ppg mud is being circulated at 700 GPM at a depth of 10000ft TVD/MD the circulating pump pressure is 3000 psi. If the circulating friction losses in the system are as follows:

Pressure losses through pipe/collars 1200 psi Pressure loss across the bit jets 1600 psi Pressure loss in the annulus 200 psi

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SCORE a. When circulating what is the dynamic bottom hole pressure?

Answer...... 2

b. What is the static bottom hole pressure?

Answer...... 2

c. What is the equivalent circulating density ECD?

Answer...... 2

d. If the pump speed is increased to give 800 GPM, what will the pump pressure be?

Answer...... 2 e. Will this increase in the pump speed have any effect on bottom hole pressure?

Answer YES/NO 2

f. Referring to the data given above, if the mud weight being circulated at 700 GPM was 12 ppg rather than 10 ppg, what would pump pressure be?

Answer...... 2

7. When circulating a 12 ppg mud at 10000ft ECD is 12.3 ppg. What is the annular pressure loss?

Answer...... 2

8. Calculate the pressure that one barrel of 12 ppg mud Wt exerts.

a. Around the drill collars if the annular capacity is 0.03 bbls/ft.

Answer...... 2

b. Around the drill pipe if the annular capacity is 0.05 bbls/ft.

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Answer...... 2

SCORE

9. If the fluid level in a well bore fell by 480ft, what is the reduction in bottom hole pressure if the mud weight is 12 ppg?

Answer...... 2

10.If a 12 ppg mud over-balances the formation pressure by 240 psi theoretically how far could the mud level fall before going under-balance?

Answer...... 2

11.Drilling at 12700ft with an 8 1/2" bit, the drill pipe is 5" with 700ft of 6 1/2" collars. The mud weight = 12 ppg. The yield point of the mud is 12lbs/100ft2. Use the equation given below to determine ECD.

Answer...... 4

Annular-pressure loss = YP x L ————— 200(DH-DP)

where YP = Yield point of mud in lbs/100ft2 L = Length of annulus, collar or pipe DH = Hole diameter DP = Collar or pipe diameter

12.If a formation pore pressure gradient at 8500ft is 0.486 psi/ft, what mud weight is required to give an over-balance of 200 psi?

Answer...... 2

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WORKSHOP 1 - ANSWERS

1. MUD WEIGHT x 0.052

a. 13.5 x 0.052 = 0.702 psi/ft b. 16.0 x 0.052 = 0.832 psi/ft c. 12.0 x 0.052 = 0.624 psi/ft

2. GRADIENT ÷ 0.052

a. 0.806 ÷ 0.052 = 15.5 ppg b. 0.598 ÷ 0.052 = 11.5 ppg c. 0.494 ÷ 0.052 = 9.5 ppg

3. T.V.D. x MUD WEIGHT x 0.052

a. 8000 x 9.5 x .052 = 3952 psi b. 18000 x 15.5 x .052 = 14508 psi c. 9000 x 0.889 = 8001 psi

4. PRESS ÷ T.V.D ÷ .052

a. 3495 ÷ 7000 ÷ .052 = 9.6 ppg b. 2787 ÷ 4000 ÷ .052 = 13.39 ppg (13.4) c. 9000 ÷ 10500 ÷ .052 = 16.48 ppg (16.5)

5. b.

6. (T.V.D. x MUD WT x .052) + A.P.L.

a. (10000ft x 10ppg x .052) + 200 = 5400 psi b. 10000 x 10 x .052 = 5200 psi c. 5400 ÷ 10000 ÷ .052 = 10.38 ppg d. 3000 x (800)2 = 3918 psi —— (700)

Note d. This calculation is the same relationship as Press-Strokes-Relationship. (i.e.) P x (new S.P.M)2 ————— (old S.P.M.)

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e. YES

f. PRESS x (new MUD WT) ———————— (old MUD WT)

3000 x (12) —— (10) = 3600 psi

7. A.P.L. = (ECD - MUD WT) x (TVD x .052) = (12.3 - 12) x (10000 x .052) = .3 x 520 A.P.L.= 156 psi

8. MUD g psi/ft ——— ANN vol psi/ft

a. = 12 x .052 = .624 = 20.8 psi/bbl —— .03

b. = .624 psi/bbl —————— = 12.48 Psi/bbl .05

9. 480 x 12 .052 = 299.52 psi (300 psi)

10. PRESS - psi = 240 = 384ft ——— —— MUD g psi/ft .624ft

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11. A.P.L. around D/C = 12 x 700 = 21 psi ————— 200(8.5-6.5)

A.P.L. around D/P = 12 x 12000 = 206 psi —————— 200 x (8.5 - 5)

TOTAL A.P.L. = 227psi

227 ECD = 12 + —— ÷ .052 12700

ECD = 12.34 PPG

12. 8500 x .486 = 4131 + 200 = 4331 psi

4331 ÷ 8500 ÷ .052 = 9.79 ppg = (9.8 ppg)

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CAUSES OF KICKS

2.11 OBJECTIVES

The objectives of this section are to Highlight the Causes of Kicks and Influxes.

2.12 INTRODUCTION

Primary control is defined as using the drilling fluid to control formation fluid pressure. The drilling fluid has to have a density that will provide sufficient pressure to overbalance pore pressure. If this overbalance is lost, even temporarily then formation fluids can enter the wellbore. Preventing the loss of primary control is of the utmost importance.

Definition of Kick

A kick is an intrusion of unwanted fluids into the wellbore such that the effective hydrostatic pressure of the wellbore fluid is exceeded by the formation pressure.

Definition of Influx

An influx is an intrusion of formation fluids into the wellbore which does not immediately cause formation pressure to exceed the hydrostatic pressure of the fluid in the wellbore, but may do, if not immediately recognised as an influx, particularly if the formation fluid is gas.

2.13 PRIMARY WELL CONTROL - HOW IT IS EFFECTED

To ensure primary well control is in place the following procedures and precautions must be observed.

Mud Weight

Mud into and out of the well must be weighted to ensure the correct weight is being maintained to control the well. This task is normally carried out by the shaker man at least every thirty minutes or less, depending upon the nature of the drilling operation and/or company policy. The mud weight can be increased by increasing the solid content and decreased either by dilution or the use of solids control equipment.

Tripping Procedures

Tripping in or out of the well must be maintained using an accurate log called a trip sheet. A trip sheet is used to record the volume of mud put into the well or displaced from the well when tripping.

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Figure 2.19

Well Name Trip No. Date Mud Weight Fluid Loss Depth D.P. Size D.P. Displacement Time Trip Started D.C. Size D.C. Displacement

DISPLACEMENT Number of Stands Theoretical Last Trip This Trip Comments Per ___ Std. Total Per ___ Std. Total Per ___ Std. Total

If rig pump is used, calculate from strokes. If trip tank is used, record level of decrease.

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When tripping pipe or drill collars out of the hole, a given volume of mud is put into the well for the volume of steel removed. If the volume required to fill the hole is significantly less than the volume of steel removed, then tripping must be stopped to ensure the well is stable, and consideration given to going back to bottom to condition the mud and investigate the cause of the problem.

THE HOLE MUST BE KEPT FULL AT ALL TIMES

A full opening or safety valve should be available at all times on the drill floor together with the required crossover subs. A non-return (i.e. grey) valve should also be readily available.

Figure 2.21 Figure 2.20 NON RETURN SAFETY VALVE (GREY VALVE) FULL BORE OPENING SAFETY VALVE

RELEASE TOOL VALVE RELEASE ROD

Upper Seat Body

Crank

Ball

VALVE SEAT

Lower Seat

VALVE SPRING

Trip Margin (Safety Factor)

Trip Margin (Safety Factor) is an overbalance to compensate for the loss of ECD and to overcome the effects of swab pressures during a trip out of the hole.

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Flow Checks

Flow checks are performed to ensure that the well is stable. Flow checks should be carried out with the pumps off to check the well with ECD effects removed. Flow checks are usually performed when a trip is going to take place at the following minimum places:

• on bottom

• at the casing shoe

• before the BHA is pulled into the BOP's

Short Trips/Wiper Trips

In some circumstances prior to pulling out of the hole a short trip, 5 or 10 stands should be considered. The well is then circulated and mud returns carefully monitored.

Pumping a Slug of Heavy Mud

This is a practice often carried out to enable the pipe to be pulled dry and the hole to be more accurately monitored during the trip. The following equation is used to calculate the dry pipe volume for the slug pumped:

Dry Pipe Volume = Slug Volume x (Slug Weight ÷ Mud Weight - 1)

This dry pipe volume can be converted to Dry Pipe Length by dividing this volume by the internal capacity of the pipe as illustrated in the following equation:

Dry Pipe Length = Dry Pipe Volume (bbls) ÷ Drill Pipe Capacity (bbls/ft)

Mud Logging

A logging unit if available is extremely important particularly with respect to well control. The unit carries out some of the following services:

• Gas detection in the mud

• Gas analysis

• Cuttings density analysis

• Recording mud densities in and out

• Recording flow line temperatures

• Recording penetration rates

• Pore Pressure Trends

A typical mud logging system is illustrated in Figure 2.4 below.

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FIG 2.4 TYPICALFig 2.22 MUD LOGGING SYSTEM

KELLY POSITION ROP WOB DEPTH

KELLY HOSE SWIVEL STAND PIPE

STANDPIPE PRESSURE

PUMP PUMP RATE KELLY

SUCTION

SUCTION PIT FLOWLINE PIT LEVELS SHAKER

SHALE CUTTINGS DENSITY SLIDE

GAS QUANTITY GAS TYPE MUD TEMPERATURE RETURN MUD WEIGHT

PROCESSINGEVALUATION AND ¥ ROTARY SPEED ¥ TORQUE

MUD UNITLOGGING VDU IN COMPANY REP'S OFFICE

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Communication

If a transfer of mud to the active system is requested the driller will be informed, the logging unit must likewise be informed. Good communication all round is essential.

Alarms

The high and low settings for the pit level recorder and flow line recorder must be checked and are set to appropriate values.

2.14 CAUSES OF KICKS AND INFLUXES

The most common causes of kicks are:

• Improper monitoring of pipe movement (drilling assembly and casing).

- Trip out - making sure hole takes the proper amount of mud. - Trip in - making sure it gives up proper amount of mud and preventing lost circulation due to surges.

• Swabbing during pipe movement.

• Loss of circulation.

• Insufficient mud weight.

- Abnormal pressured formations - Shallow gas sands

• Special situations.

- Drill stem testing - Drilling into an adjacent well - Excessive drilling rate through a gas sand

Surveys in the past have shown that the major portion of well control problems have occurred during trips. The potential exists for the reduction of bottom hole pressure due to:

• Loss of ECD with pumps off.

• Reduction in fluid levels when pulling pipe and not filling the hole.

• Swabbing.

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2.14.1 Failure to keep the hole full during a trip

If the fluid level in the hole falls as pipe is removed a reduction in bottom hole pressure will occur. If the magnitude of the reduction exceeds the trip margin or safety overbalance factor a kick may occur. The hole must be kept full with a lined up trip tank that can be monitored to ensure that the hole is taking the correct amount of mud. If the hole fails to take the correct mud volume, it can be detected. A trip tank line up is shown in Fig 2.5. BELL NIPPLE RETURN LINE

FLOAT FILL UP LINE

TANK

INDICATOR PUMP

Figure 2.23 CONTINUOUS CIRCULATING TRIP TANK

It is of the utmost importance that drill crews properly monitor displacement and fill up volumes when tripping. The lack of this basic practice results in a large amount of well control incidents every year.

2.14.2 Swabbing and Surging

Swabbing is when bottom hole pressure is reduced below formation pressure due to the effects of pulling the drill string, which allows an influx of formation fluids into the wellbore.

When pulling the string there will always be some variation to bottom hole pressure. A pressure loss is caused by friction, the friction between the mud and the drill string being pulled. Swabbing can also be caused by the full gauge down hole tools (bits, stabilisers, reamers, core barrels, etc.) being balled up. This can create a piston like effect when they are pulled through mud. This type of swabbing can have drastic effects on bottom hole pressure.

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The factors affecting swabbing and surging are:

• Pulling speed of pipe.

• Mud properties.

• Viscosity.

• Hole geometry.

Surging

Surging is when the bottom hole pressure is increased due to the effects of running the drill string too fast in the hole. Down hole mud losses may occur if care is not taken and fracture pressure is exceeded while RIH. Proper monitoring of the displacement volume with the trip tank is required at all times.

Figure 2.24

PRESSURE SURGES SWABBING ACTION Swabbing is a recognised hazard whether it is “low" volume swabbing or “high” volume swabbing. A small influx volume may be swabbed into the open hole section. The net decrease in hydrostatics due to this low density fluid will also be small. If the influx fluid is gas it can of course migrate and expand. The expansion may occur when there is little or no pipe left in the hole. The consequences of running pipe into the hole and into swabbed gas must also be considered.

Pulling Speeds

Tripping speeds must be controlled to reduce the possibility of swabbing. It is normal practice for the Mud Logger to run a swab and surge programme and to make this information available to the Driller. This will provide ample information to reduce the possibility of unforeseen influx occurring.

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Mud Properties

Controlling the rheology of mud is important. Controlling water-loss to avoid thick wall cake will also help.

Trip Margin

A safety factor to provide an overbalance to compensate for swab pressure can be:

Trip Margin Factor APL psi ––––––––––––––––– = ––––––––––––––––– (psi/ft) True Vert. Depth. ft

APL = Annulus Pressure Loss

If swabbing has been detected and the well is not flowing a non return valve should be installed and the bit returned to bottom. Flow check each stand. Once back on bottom the well should be circulated and the bottoms up sample checked for contamination.

If the well is flowing or the returns from the well are excessive when tripping in then the following should be carried out:

• Install a non return valve. If there is a strong flow then a kelly cock may have to be installed first.

• Shut the well in.

• Prepare for stripping.

• Strip in to bottom.

• Circulate the well, check bottoms up for contamination.

Continuous monitoring of replacement and displacement volumes is essential when performing tripping. A short wiper trip and circulating the well before pulling completely out of the hole will provide useful information about swabbing and pulling speeds.

Useful formulae for calculating the psi reduction per foot of drill pipe pulled are as follows: mud grad. (psi/ft) x metal disp. (bbls/ft) Pulling Dry Pipe: psi/ft or dry pipe pulled = –––––––––––––––––––––––––––––––––– (casing cap. (bbls/ft) - metal disp. (bbls/ft)

(mud grad. (psi/ft) x metal disp. + cap. (bbls/ft) Pulling Wet Pipe: psi/ft or wet pipe pulled = –––––––––––––––––––––––––––––––––– (casing cap. (bbls/ft) - metal disp. + cap. (bbls/ft))

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2.14.3 Loss of Circulation

Another cause for a kick to occur is the reduction of hydrostatic pressure through loss of drilling fluid to the formation during lost circulation. When this happens, the height of the mud column is shortened, thus decreasing the pressure on the bottom and at all other depths in the hole.

The amount the mud column can be shortened before taking a kick from a permeable zone can be calculated by dividing the mud gradient into the overbalance at the top of the permeable kick zone.

Overbalance (psi) H (ft) = –––––––––––––––––––––– Mud Gradient (psi/ft)

2.14.4 Insufficient Mud Weight

A kick can occur if a permeable formation is drilled which has a higher pressure than that exerted by the mud column. If the overpressurised formations have low permeability then traces of the formation fluid should be detected in the returns after circulating bottoms up. If the overpressured formations have a high permeability then the risk is greater and the well should be shut-in as soon as flow is detected.

2.14.5 Abnormal Pressured Formations

A further cause of kicks from drilling accidentally into abnormally pressured permeable zones. This is because we had ignored the warning signals that occur, these help us detect abnormal pressures. Some of these warning signals are: an increased penetration rate, an increase in background gas or gas cutting of the mud, a decrease in shale density, an increase in cutting size, or an increase in flow-line temperature, etc.

In some areas, there were adequate sands that were continuous and open into the sea or to the surface. In these areas the water squeezed from the shale formations, travelled through the permeable sands and was released to the sea or to a surface outcrop. This de-watering allowed the formations to continue to compact and thereby increase their density.

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Figure 2.25

SEA

PERMEABLE ZONE

NORMAL PRESSURE In other areas, or at other times, the sands did not develop or were sealed by deposition of salt or other impervious formations, or by faulting such as we have indicated here. Although the shale water was squeezed, it could not escape. Since water is nearly incompressible, the shales could not compress past the point where the water in the shale started to bear the weight of the rock above. This section caused a condition in which the weight of the formation - that is, the overburden - was borne not by the shale alone, but assisted by the fluids in the shale. In this situation the shale will have more porosity, and a lower density, than they would have had if the now pressured water had been allowed to escape. These formations, both sand and shale, are then overpressured. If a hole is drilled into an overpressured formation, weighted mud will be required to hold back the fluids contained in the pore space.

Figure 2.26

SEA

FAULT

ABNORMAL PRESSURE

Abnormally high formation pressure is defined as any formation pressure that is greater than the hydrostatic pressure of the water occupying the formation pore spaces. Abnormally high formation pressures are also termed surpressures, overpressures and sometimes geopressures. More often, they are simply called abnormal pressures.

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Abnormally high formation pressures are found worldwide in formations ranging in age from the Pleistocene age (approximately 1 million years) to the Cambrian age (500 to 600 million years). They may occur at depths as shallow as only a few hundred feet or exceeding 20,000 ft and may be present in shale/sand sequences and/or massive evaporite-carbonate sequences.

The causes of abnormally high formation pressures are related to a combination of geological, physical, geochemical and mechanical processes.

As defined, the magnitude of abnormally high formation pressures must be greater than the normal hydrostatic pressure for the location, and may be as high as the overburden pressure. Abnormally high pressure gradients will thus be between the normal hydrostatic gradient (0.433 to 0.465 psi/ft) and the overburden gradient (generally 1.0 psi/ft).

However, locally confined pore pressure gradients exceeding the overburden gradient by up to 40% are known in areas such as Pakistan, Iran, Papua New Guinea, and the CIS. These super pressures can only exist because the internal strength of the rock overlying the super pressured zone assists the overburden load in containing the pressure. The overlying rock can be considered to be in tension.

In the Himalayan foothills of Pakistan, formation pressure gradients of 1.3 psi/ft have been encountered. In Iran, gradients of 1.0 psi/ft are common and in Papua New Guinea, a gradient of 1.04 psi/ft has been reported. In one area of Russia, local formation pressure in the range of 5870 to 7350 psi at 5250 feet were reported. This equates to a formation pressure gradient of 1.12 to 1.4 psi/ft.

In the North Sea abnormal pressures occur with widely varying magnitudes in many geological formations.

The Tertiary sediments are mainly clays and may be overpressured for much of their thickness. Pressure gradients of 0.52 psi/ft are common with locally occurring gradients of 0.8 psi/ft being encountered. An expandible clay (gumbo) also occurs which is of volcanic origin and is still undergoing compaction. The consequent decrease in clay density would normally indicate an abnormal pressure zone but this is not the case. However, in some areas, mud weights of the order of 0.62 psi/ft or higher are required to keep the wellbore open because of the swelling nature of these clays. This is almost equal to the low overburden gradients in these areas.

In the Mesozoic clays of the North Sea Central Graben, overpressures of 0.9 psi/ft have been recorded. One reported case indicated a formation pressure gradient of 0.91 psi/ft in the Jurassic section. In the Jurassic of the Viking Graben, abnormal formation pressure gradients of up to 0.69 psi/ft have been recorded.

In Triassic sediments, abnormally high formation pressures have been found in gas bearing zones of the Bunter Sandstone in the southern North Sea. Also in the southern North Sea, overpressures are often found in Permian carbonates, evaporates and sandstones sandwiched between massive Zechsteins salts.

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2.14.6 Shallow Gas Sands

Kicks from shallow sands (gas and water) whilst drilling in the top hole section with short casing strings can be very hazardous, as documented by many case histories. Some of the kicks from shallow sands are caused by charged formations: poor cement jobs, casing leaks, injection operations, improper abandonments, and previous underground blowouts can produce charged formations.

2.14.7 Special Situations

a) Drill Stem Testing (DST)

The formation test is one of the most hazardous operations encountered in drilling and completing oil and gas wells. The potential for stuck tools, blowouts, lost circulations, etc., is greatly increased.

A drill stem test is performed by setting a packer above the formation to be tested, and allowing the formation to flow. Down hole chokes can be incorporated in the test string to limit surface pressures and flow rates to the capabilities of the surface equipment to handle or dispose of the produced fluid.

During the course of the test, the bore hole or casing below the packer, and at least a portion of the drill pipe or tubing, is filled with formation fluid. At the conclusion of the test, this fluid must be removed by proper well control techniques to return the well to a safe condition. Failure to follow the correct procedures to kill the well could lead to a blowout.

b) Drilling Into an Adjacent Well

Drilling into an adjacent well is a potential problem, particularly offshore where a large number of directional wells are drilled from the same platform. If the drilling well penetrates the production string of a previously completed well, the formation fluid from the completed well will enter the wellbore of the drilling well, causing a kick. If this occurs at a shallow depth, it is an extremely dangerous situation and could easily result in an uncontrolled blowout.

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c) Excessive Drilling Rate Through a Gas Sand/Limestone

When drilling a gas bearing formation, the mud weight will be gas cut due to the gas breaking out of the pore space of the cuttings near the surface. The severity of the influx will depend on the penetration rate, porosity and permeability, and is independent of mud weight. The importance attached to gas cutting is that gas is entering the wellbore in small quantities, which calls for caution. Degassing is necessary to ensure that good mud is being pumped back into the hole to prevent the percentage of gas from increasing with each circulation, which would allow greater and greater bottom hole hydrostatic pressure reductions.

Figure 2.27 Reduction in Hydrostatic Head Due to Gas Cutting of the Mud

18 ppg mud cut 50% to 9.0 ppg

Depth Normal Head Reduced Head 18 ppg mud Head Reduction 1,000' 936 psi 866 psi 60 psi 5,000' 4,680 psi 4,598 psi 82 psi 10,000' 9,360 psi 9,265 psi 95 psi 20,000' 18,720 psi 18,615 psi 105 psi

Most of mud cutting is close to surface. Divert flow through choke manifold to prevent belching and to safely contain gas through mud gas separator. Time drill the gas cap to prevent severe gas cutting of mud.

Gas cutting alone does not indicate the well is kicking, unless it is associated with pit gain. Allowing the well to belch over the nipple could cause reduction in hydrostatic pressure to the point that the formation would start flowing, resulting in a kick.

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2.15 EXTRACTS FROM API RP59

4.1 Introduction. Loss of primary well control most frequently results from: 1) failure to keep the hole full; 2) swabbing; 3) insufficient drilling fluid density; and/or 4) lost circulation. These problems can occur during any operation conducted on a well. The goal of well control is to prevent a well kick (influx of formation fluid into the wellbore) from becoming a blowout (uncontrolled flow of formation fluid).

4.2 Conditions Necessary for a Kick. The two conditions that must be present in the wellbore for a kick to occur are 1) the pressure in the wellbore at the face of the kicking formation must be less than the formation pressure; and 2) the kicking formation must have sufficient permeability to allow flow into the wellbore. To maintain primary well control, drilling personnel should utilise all techniques at their disposal to ensure that the hydrostatic pressure in the wellbore is always greater than the formation pressure. A number of conditions which can cause or contribute to well kicks are discussed in Paras 4.3 through 4.15.

4.3 Hole Not Full of Drilling Fluid. When the fluid level in the wellbore is allowed to drop or is maintained with a lighter density fluid, the resultant reduced hydrostatic head can allow fluid entry from the formation. The rig should have drilling fluid measuring devices to determine that proper fluid replacement or displacement occurs when pulling or running pipe. The type of fluid measuring equipment used should be influenced by the anticipated well control operations involved in drilling the well.

4.4 Tripping Out of the Hole. When pulling pipe, its displacement volume should be replaced with the proper amount of drilling fluid to maintain constant hydrostatic pressure. Any significant reduction in hydrostatic pressure may result in loss of primary control. If the hole fails to take the proper amount of drilling fluid, hoisting operations should be suspended and an immediate safe course of action determined while observing the well. This usually requires returning to bottom and circulating the hole. The frequency of filling the hole during tripping operations is critical in maintaining primary control. The hole should be completely filled at intervals that will prevent an influx of formation fluid. Continuous filling or filling after each stand of drill pipe may be advisable. The hole should be filled after each stand of drill collars. When the hole is filled continuously, an isolated drilling fluid volume measurement facility (such as a trip tank) must be used.

4.5 Tripping In the Hole. In running pipe back in the hole, the drilling fluid volume increase at the surface should be no greater than predicted displacement. Some holes take significant volumes of drilling fluid during trips because of seepage loss. It is necessary to keep a trip book (refer to Para. 10.3 and Table 10.1) for ready comparison to determine if an abnormal condition occurs. The gauging of fluid returns and comparison with prior trip records should provide a warning of possible loss of primary well control. The hole and fluid returns should be checked at frequent intervals.

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4.6 Out of the Hole. Time with pipe out of the hole should be minimised. Particular care should be taken when a servicing tool, such as a core barrel, with its length too great to clear the ram closure zone and/or its outside diameter too large to fit the pipe rams, to have the necessary crossover connection(s) readily available so that correct pipe movement can be effected to be able to close more than the annular blowout preventer. In case of equipment repair on drilling rigs, the pipe should be run at least back to the last easing shoe, if possible, before repairs are undertaken. In well servicing operations, when making equipment repairs, effecting routine maintenance, or shutting down overnight, the pipe should be run to a sufficient depth to ensure that the well can be controlled.

4.7 Swabbing. When pipe is pulled from a well, a reduction in bottom-hole hydrostatic pressure (swabbing) may occur. Bottom-hole pressure reduction of several hundred pounds per square inch (psi) can occur when swabbing takes place. This pressure reduction, which can be sufficient to permit the entry of formation fluid into the wellbore, is one of the major reasons for losing primary well control. This type of swabbing action should not be confused with the more obvious concept of actually pulling fluid from a well with a balled up bit or packer, or swabbing in a producing well through tubing. When pipe is pulled from a well, swabbing can be difficult to detect. The well may take some fluid as the pipe is withdrawn but less than the complete pipe displacement. The detection of swabbing, therefore, can only be done by accurately measuring the drilling fluid added to the hole as pipe is pulled. Three prime factors in controlling swabbing are: 1) drilling fluid properties; 2) rate of pulling pipe; and 3) drill string and hole configurations.

4.8 Trip Margin. The use of a trip margin is encouraged to offset the effects of swabbing. The additional hydrostatic pressure will permit some degree of swabbing without losing primary well control.

4.9 Short Trip. After tripping and circulating “bottoms-up,” the amount of gas, salt water, or oil contamination will enable the evaluation of operating practices affecting swabbing. Adjustments in pulling speed, drilling fluid flow properties, and/or drilling fluid density may be warranted. A short trip and circulating “bottoms-up” before pulling out of the hole can also be used to determine the system’s swabbing characteristics.

4.10 Insufficient Drilling Fluid Density. The condition where formation pressure exceeds existing hydrostatic pressure in the wellbore is referred to as under-balance and can be caused be insufficient drilling fluid density.

4.11 Lost Circulation. Lost circulation occurs in both drilling and well servicing operations and may quickly destroy the hydrostatic overbalance that constitutes primary control. The loss can result from natural or induced causes. Natural causes include fractured, vugular, cavernous, subnormally-pressured, or pressure-depleted formations. Induced loss can result from mechanical formation fracturing resulting from 1) excessive drilling fluid density, 2) excessive annular circulating pressure, 3) pressure surges related to running pipe or tools. 4) breaking circulation, or 5) packing off in the annulus.

4.12 Drill Stem Testing. Drill stem tests are performed by setting a packer above the formation to be tested and allowing the formation to flow. During the course of testing, the borehole or casing below the packer and at least a portion of the drill pipe or tubing is filled with formation fluid. At the conclusion of the test, the fluid in the test string above the circulating 2-46 © Aberdeen Drilling Schools 2002 Rev 2 5/02 RILLIN N D G S EE CH D O R O E L B S A •

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valve must be removed by proper well control techniques, such as reversing, to return the well to a safe condition. Depending on the length of hole below the packer, type of fluid entry, and formation pressure, the normal drilling hydrostatic overbalance can be reduced or lost. Caution should be exercised to avoid swabbing when pulling the test string because of the large diameter packers.

4.13 Drilling Into an Adjacent Well. Frequently, a large number of directional wells are drilled from the same offshore platform or onshore drilling pad. If a drilling well penetrates the production string of a previously completed well, the formation fluid from the completed well may enter the wellbore of the drilling well, causing a kick. Special care should be exercised to avoid a collision course with another well.

4.14 Excessive Drilling Rate Through a Gas Sand. Even if the drilling fluid density in the hole is sufficient to control gas zone pressure, gas from the drilled cuttings will mix with the drilling fluid. Excessive drilling rate through a shallow gas zone or coal bed can supply sufficient gas from cuttings to reduce the hydrostatic pressure of the drilling fluid column through a progressive combination of density reduction and drilling fluid loss from “belching” to the point that the formation will begin flowing into the wellbore.

4.15 Others. Primary control can also be lost while performing operations other than circulating, drilling, or running and pulling pipe, loss of well control can occur during coring, perforating, fishing, performing primary or remedial cementing, running casing or liner operations, or when differential fill equipment malfunctions. All such operations require the accurate measurement and control or drilling fluid replaced or displaced in the well to maintain primary control. Complications can occur in primary control during floating drilling operations due to distorted readings caused by motion and heave. The measurement of drilling fluid volume and flow rate is most critical in floating operations and requires pit level monitoring devices (floats) located in the centre of the pits or multi-floats with sequential integration utilised. A trip tank and pit watcher should be considered if vessel movement creates any problem in measuring drilling fluid requirements on trips.

4.16 Special Situations. The accurate prediction of pressure gradients, particularly abnormal pressure, and the prevention of an insufficient drilling fluid density situation, are highly desirable but not always attainable. In some situations of insufficient drilling fluid density, operations can be safely handled and proceed without increasing drilling fluid density, yet maintain control (underbalanced drilling). An abnormally pressured gas zone with low productivity (e.g., shale gas) is a possible example where the well will not flow appreciably but gas exists after

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a trip which may require use of blowout prevention equipment and/or rotating heads. Sometimes fluid influx will occur when circulation is stopped, but will not occur during drilling operations due to the effect of annular circulating pressure. In this instance, successful operations usually require an increase in drilling fluid density or, in some fields, the use of a lighter drilling fluid and another heavier drilling fluid to control the well on trips.

WELL CONTROL WARNING SIGNALS

4.17 General. Well control warning signals can be classified in three major general categories as follows:

A. Previous Field History and Drilling Experiences.

1. Depth of zones capable of flowing.

2. Formation gradients.

3. Fracture gradients.

4. Formation content.

5. Formation permeability.

6. Intervals of lost circulation.

B. Physical Response From the Well.

1. Pit gain or loss.

2. Increase in drilling fluid return rate.

3. Changes in flowline temperature.

4. Drilling breaks.

5. Variations in pump speed and/or standpipe pressure.

6. Swabbing.

7. Drilling fluid density reduction.

8. Effects of connections, short trip, and trip on shows and gains.

9. Hole problems indicating underbalance (i.e., tight hole, packing-off, sloughing).

10. Excessive pressure or pressure changes between casing strings.

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C. Chemical and Other Technical Responses From the Well.

1. Chloride changes in the drilling fluid.

2. Oil show.

3. Gas show (chromatograph).

4. Formation water.

5. Shale density.

6. Electric logs.

7. Drilling equation exponents.

4.18 Volume of Drilling Fluid to Keep the Hole Full on a Trip is Less Than Calculated or Less Than Trip Book Record. This condition is usually caused by formation fluid entering the wellbore due to the swabbing action of the drill string. As soon as swabbing is detected, the drill string should be run back to bottom. Circulate and condition the drilling fluid to minimise further swabbing. It may be necessary to increase the drilling fluid density, but this should not be the first step considered because of the inherent potential problems of causing lost returns or differential sticking.

4.19 Gain in Pit Volume. An unaccounted volume gain in the drilling fluid pit(s) is an indication that a kick may be occurring. As the formation fluid feeds into the wellbore, it causes more drilling fluid to flow from the annulus than is pumped down the drill string, thus the volume of fluid in the pit(s) increases.

4.20 Increased Flow From Annulus. If the pumping rate is held constant, the flow from the annulus should be constant. If the annulus flow increases without a corresponding change in pumping rate, the additional flow is caused by formation fluid(s) feeding into the wellbore or gas expansion.

4.21 Sudden Increase in Bit Penetration Rate. A sudden increase in penetration rate (drilling break) is usually caused by a change in the type of formation being drilled: however, it may also signal an increase in formation pore pressure. Increased penetration rates due to higher pore pressures are usually not as abrupt as formation drilling breaks, but they can be. In order to be certain that gradual increases in pore pressure are recognised, a penetration rate versus depth curve plot is recommended to highlight the trend of increasing pore pressure.

4.22 Change in Pump Speed or Pressure. The initial surface indication that a well kick has occurred could be a momentary increase in pump pressure. The pump pressure increase is seldom recognised because of its short duration, but it has been noted on some pump pressure recording charts after a kick was detected.

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The pressure increase is followed by a gradual decrease in pump pressure, and may be accompanied by an increase in pump speed. As the lighter formation fluid flows into the wellbore, the hydrostatic pressure exerted by the annular column of fluid decreases, and the drilling fluid in the drill pipe tends to U-tube into the annulus. When this occurs, the pump pressure will drop and the pump speed will increase. The lower pump pressure and increase in pump speed symptoms are also indicative of a hole in the drill string, commonly referred to as a washout. Until a confirmation can be made whether a washout or a well kick has occurred, a kick should be assumed.

4.23 Gas-cut Drilling Fluid. Gas-cut drilling fluid often occurs during drilling operations and can be considered one of the early warning signs of a potential well kick: however, it is not a definite indication that a kick has occurred or is impending. An essential part of analysing this signal is being able to determine the downhole conditions causing the drilling fluid to be gas-cut. Gas-cut fluid occurs as a result of one or more of the following downhole conditions: 1) drilling a gas-bearing formation with the correct drilling fluid density in the hole (drilled gas); 2) swabbing while making connections or making a trip (trip or connection gas); and 3) influx of gas from a formation having a pore pressure greater than the pressure exerted by the drilling fluid (gas flow).

A. Drilled Gas. When the hydrostatic pressure exerted by the drilling fluid is greater than the pore pressure of a gas-bearing formation being drilled, there will be no influx of gas from the formation. Nevertheless, gas from the drilled cuttings will usually mix with the drilling fluid causing the returns to be gas cut. As gas is circulated up the annulus, it expands slowly until just before reaching the surface. The gas then undergoes a rapid expansion, resulting in the drilling fluid density being reduced considerably upon leaving the annulus. In some cases this reduction in density can be quite extreme but it may not mean that a kick is about to occur. Usually, only a small loss in hydrostatic pressure results because the majority of gas expansion occurs in the top of the hole. Drilling fluid of proper density is still maintained in most of the hole. Quite often when the drilled gas reaches the surface, the annular preventer must be closed and the drilling fluid circulated through the open choke manifold. This prevents the expanding gas from “belching” fluid through the bell nipple. If “belching” continues, the hydrostatic head will be reduced due to loss of drilling fluid from the hole.

B. Trip or Connection Gas. After circulating “bottoms-up” following a trip or connection, a higher level of gas entrained in the drilling fluid returns may cause a short duration density reduction or gas unit increase. If the well did not flow when the pumps were stopped during the trip or connection, it can be reasonably assumed that the gas was swabbed into the wellbore by the pipe movement. These symptoms can indicate increasing formation pressure when compared with previous trips and connections.

C. Gas Flow. Influx from a gas zone while drilling is a serious situation. While drilling, the formation pore pressure must exceed the hydrostatic pressure of the drilling fluid plus the circulating friction losses in the annulus for gas from the formation to flow into the wellbore. Once influx begins, continued circulation without the proper control of surface pressures will induce additional flow, since the density of the hydrostatic column

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(annulus) is continually lessened by the flow of formation fluid and expansion of gas.

4.24 Liquid-cut Drilling Fluid. When a permeable liquid-bearing formation having pore pressure greater than the drilling fluid hydrostatic pressure is encountered, fluid will feed into the wellbore. Depending upon the pressure differential between the formation and the drilling fluid, influx may be detected by: 1) a gain in pit volume, 2) lower density returns, 3) a change in drilling fluid chlorides, and/or 4) an increase in rotary torque. The volume of liquid contained in the cuttings is usually so small that unless accompanied by gas, it will not significantly affect the drilling fluid density.

NOTE: A rare exception to this rule is the very low permeability formation which can be drilled while allowing a continuous small influx to occur. This type of underbalanced drilling is only practicable in certain well-known drilling areas where the geology is sufficiently known to allow preplanning for the rig equipment and drilling practices necessary.

ADDITIONAL CAUSES OF KICKS UNIQUE TO SUBSEA OPERATIONS

9.2 Loss of Integrity. Wellbore hydrostatic pressure is a function of height and density of the drilling fluid column from the flowline to the depth of interest. If a riser fails, leaks, or becomes disconnected, the drilling fluid gradient in the riser is lost and replaced by a sea water gradient (approximately 0.445 psi/ft — 8.56 Ib/gal) from the point of failure to sea level. The loss of wellbore hydrostatic pressure associated with this situation can sometimes be sufficient to allow the well to flow. The first response should be to close the blowout preventers. In some situations, the drilling fluid density may be sufficient to compensate for the loss of hydrostatic pressure. If not, the loss of hydrostatic pressure should be restored prior to opening the blowout preventer.

9.3 Trapped Gas Below Blowout Preventers Subsequent to control operations during which gas is circulated out the choke line, free gas will remain trapped below the closed preventer. If the closed preventer is an annular preventer, it is possible for this volume of gas to be quite significant. In order to prevent a rapid unloading of the riser due to trapped gas when the annular preventer is opened or the introduction of a secondary kick due to light density drilling fluid in the riser, close the uppermost rams below the choke line and close the diverter. Open the preventer above the trapped gas and allow this gas to rise toward the surface. Displace the riser with kill fluid and reopen the rams. It may be necessary in extreme cases to close the bottom rams to isolate the hole and fill the riser by circulating through the kill line. This problem becomes more severe with increased water depth and/or preventer size.

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WORKSHOP 2

SCORE

1. There are a variety of mechanisms that can cause abnormal formation fluid pressures. List 4 of the principle causes below.

Answer (a) ———————— (b) ———————— (c) ———————— (d) ———————— 2

2. Shown below is a pressure versus volume plot of a leak off test.

1200 1000 800 600 400 PRESSURE (PSI) 200 0 VOLUME The leak off was carried out with a 10.6 ppg mud. The casing shoe is at 4000ft TVD.

a. What is the maximum pressure that the exposed formations below the shoe can support? ANSWER...... 2

b. What is the “Fracture Gradient?” ANSWER...... 2

c. What is the maximum mud weight? ANSWER...... 2

d. If drilling was resumed and the mud weight was increased to 12.6 ppg. Calculate M.A.A.S.P ANSWER...... 2

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SCORE 3. M.A.A.S.P. The maximum allowable annular surface pressure should be re-calculated..

a. At the start of each shift b. As soon as possible after a drilling break c. When approaching a suspected transition zone d. When the mud weight has been increased in the system e. If a kick has occurred and the well is shut-in

ANSWER...... 2

4. The calculated M.A.A.S.P. value is relevant..

a. When the influx is in the open-hole section b. As the influx approaches the surface

ANSWER...... 2

5. Given the following data:

Depth 10000ft TVD Bit size 8 1/2" Shoe depth 8500ft TVD Mud weight 12.6 ppg

Collars - 600ft. capacity = 0.0077 bbl/ft Metal displacement = 0.03 bbl/ft Drill-pipe 5" capacity = 0.0178 bbl/ft Metal displacement = 0.0075 bbl/ft Casing/pipe annular capacity = 0.0476 bbl/ft Casing capacity = 0.0729 bbl/ft One stand of drill-pipe = 94ft.

Assuming the 12.6 ppg mud gives an over-balance of 200 psi.

a. If 10 stands of pipe are removed “dry” without filling the hole, what would be the resultant reduction in bottom-hole pressure?

ANSWER...... 3

b. If 5 stands of pipe had been pulled “wet” without filling the hole, the resultant reduction in bottom-hole pressure would be.

ANSWER...... 3

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SCORE

c. If prior to tripping a 20 barrel slug of 14.6 ppg mud was displaced to prevent a wet trip, what would be the expected volume return due to the U-tubing of the heavy mud?

ANSWER...... 2

6. Prior to tripping out of the hole a trip tank and pump are lined up to keep the hole full as the pipe is removed. The trip tank contains 30 barrels of mud. After pulling 10 stands of pipe the level in the trip tank is 27 barrels. (Use data given in Question 6). Would the safest option be..

a. To continue tripping but flow-check when bits at shoe. b. Stop and shut the well in. If no pressures seen open the well up and continue tripping. c. Flow-check. If no flow, go back to bottom and circulate. d. Flow-check. If no flow, continue tripping

ANSWER...... 2

7. A well can be induced to flow by swabbing. Swabbing is the reduction of bottom hole pressure due to the effects of pulling pipe. List below 3 conditions that can cause swabbing.

Answer (a) ——————— (b) ——————— (c) ——————— 2

8. A drill string consist of 5" 20 lb/ft drill-pipe and 8 1/2" drill-collars. The spare kelly cock has 4 1/2" I. F. thread connections. What crossover sub is required for the collars?

ANSWER...... 2

9. A fixed rig is set in 300ft of sea water. The marine conductor has been set X ft below the sea-bed. The flow line is 65ft above the mean sea-level. The strength of the sub-sea formations is 0.68 psi/ft. Sea-water gradient is 0.445 psi/ft. It is proposed to drill with 9.2 ppg mud. What is the minimum depth that the conductor has to be set below sea-bed to prevent losses?

ANSWER...... 8

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SCORE 10. An over-balance or trip margin is added to the mud. When tripping this will prevent a loss of B.H.P. due to the swabbing effect of pulling the pipe.

ANSWER. TRUE/FALSE 2

11. Assume casing is set at 4800ft TVD/MD and that gas sands were encountered at 5000ft and at 8500ft. If the formation pressure gradient at 5000ft is 0.47 psi/ft and at 8500ft it is 0.476 psi/ft. What mud weight is required to give an over-balance or trip margin of 200 psi?

ANSWER...... 4

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WORKSHOP 2- ANSWERS

1. (a) Under compacted shales (b)Thick gas sands (c) Faults (d)Diaprism salt domes (e) Shape of reservoir structure

2. Surface pressure = 1100 psi

a. (CSG TVD x MUD WT x .052) + Surface pressure = (4000 x 10.6 x .052) + 1100 = 3305 psi

b. Frac g = Max press ÷ CSG TVD = 3305 ÷ 4000 = 0.826 psi/ft

c. Max Mud Wt = Frac g ÷ .052 = .826 ÷ .052 = 1 5.88ppg

d. MAASP = (Max mud wt - Drlg mud wt) x .052 x CSG TVD = (15.88 - 12.6) x .052 x 4000 = 682 psi

3. d.

4. a.

5. a. Mud g x Met Disp ————————— CSG Cap - Met Disp

= .655 x .0075 = .0049 = .0751 psi/ft ————— ——— .0729 – .0075 .0654

.0751 x 940 = 71 psi

b. Mud g x (Met Disp + pipe cap) ——————————————— Ann Cap

= .655 (.0075 + .0178) = .3525 psi/ft ————————— .047

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c. Dry pipe vol = Slug vol x (slug wt) ————— - 1 (mud wt)

= 14.6 20 X ———– – 1 ( 12.6 )

= 3.17 bbls

6. c.

7. (a) Pulling speed. (b)Mud Properties, viscosity - Gel strength. (c) Profile of hole (Wellbore geometry).

8. 4 1/2" if box - 6 5/8" reg pin.

9. (Hyd mud to sea bed) - (Hyd sea water) —————————————————— (Frac g - Mud g)

= (365 x 9.2 x .052) - (300 x .445) ————————————— (.68 - .478) = 41.1 —— .202 203 ft.

10. False.

11. Mud Wt to give 200 psi overbalance = 5000 x .47 psi/ft = 2350 + 200 = 2550

\ 2550 ÷ 5000 ÷ .052 = 9.8 ppg

If the 200 psi is to overbalance formation pressure at 8500ft mud wt wouldbe 9.6 ppg. This would overbalance the sands at 5000ft by 148 psi.

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KICK INDICATORS

2.16 OBJECTIVES

The objectives of this section are to review the indication of a kick. Early warning signs will be covered as well as positive kick signs.

2.17 EARLY WARNING SIGNS

The alertness in determining early warning signs in well control is of the upmost importance to wellbore safety. Careful observance and positive reaction to these signs will keep the well under control and prevent the occurrence of a well flow situation. The various signs that have been recorded as early warning indicators are not consistent in all situations. The signs however may have to be used collectively as one indicator may not accurately provide the warning of getting into an unbalanced situation. Even though the series of signs may change between wells, early warning indications can be found from the following list.

• Increase in drilling rate of penetration. • Increase torque and drag. • Decrease in shale density. • Mud property changes. • Increase in cutting size and shape. • Increase in trip, connection and/or background gas. • Increase in the temperature of the return drilling mud. • Decrease in D-exponent.

2.18 INCREASE IN DRILLING RATE OF PENETRATION - DRILLING BREAK

When drilling ahead and using consistent drilling parameters, as the bit wears, a normal trend of decrease penetration rate should occur. If the differential pressure between the hydrostatic pressure of the drilling fluid and formation pore pressure decreases, an increase in the drilling rate occurs as the chip hold down effect is reduced.

A general and consistent increase in penetration rate is often a fairly good indicator that a transition zone may have been penetrated. A rapid increase in penetration rate may indicate that an abnormal pressure formation has been entered and an underbalance situation has occurred.

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2.19 INCREASED TORQUE AND DRAG

Increased drag and rotary torque are often noted Figure 2.28 when drilling into overpressured shale formations due to the inability of the underbalanced mud density to hold back physical encroachment of the formation into the wellbore. ∆W ÐÐÐÐ Drag and rotating torque are both indirect and qualitative drag indicators of overpressure. They are also indicators of hole (up) instability and other mechanical problems.

Torque and drag trend increases often indicate to the driller that a transition zone is being drilled. Up drag and down drag as well as average torque figures should be recorded on each connection. These trends are valuable when comparing other trend changes.

∆W ÐÐÐÐ drag (down)

2.20 DECREASE IN SHALE DENSITY

The density of shale normally increases with depth, but decreases as abnormal pressure zones are drilled. The density of the cuttings can be determined at surface and plotted against depth. A normal trend line will be established and deviations can indicate changes in pore pressure.

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2.21 INCREASE IN CUTTING SIZE AND SHAPE

In transition zones or in abnormally pressured shales (sandy shales and bedding sand streaks) the shales break off and fall into hole because of under balanced condition (pore pressure greater than mud hydrostatic pressure). Water wetting may further aggravate this problem.

Changes in the Shape of Shale Cuttings can occur as an underbalanced situation is developing. The particles are often larger and may be sharp and angular in the transition zone. Extra fill on bottom may coincide with the trend change. Severe sloughing will often cause changes in pressure and stroke relationship.

Normally pressured shales produce small cuttings with rounded edges and are generally flat, while cuttings from an over pressured shale are often long and splintery with angular edges. As reduction of hydrostatic differential between the pore pressure and bottomhole pressure occurs, the hole cuttings will have a greater tendency to come off bottom. This can also lead to shale expansion causing cracking, and sloughing of the shales into the wellbore. Changes in cuttings shape and cuttings load over the shakers needs to be monitored at surface.

2.22 MUD PROPERTY CHANGES

Water cut mud or a chloride (and sometimes calcium) increase that has been circulated from bottom always indicates that formation fluid has entered the wellbore. It could be created by swabbing or it could indicate a well flow is underway. Small chloride or calcium increases could be indicative of tight (non-permeable) zones that have high pressure.

In certain type muds, the viscosity will increase when salt water enters the wellbore and mixed with the mud. This is called flocculation because the little molecules of mud solids, which are normally dispersed, form little “groups” called flocs. These flocs cause viscosity and gel increases.

In other type muds you might see a viscosity decrease caused by water cutting (weight decrease). This is true when operating with low pH salt saturated water base muds.

In oil muds, any water contamination would act as a “solid” and cause viscosity increases.

Gas cut mud would be fluffy and would have higher viscosities (and lower mud weight).

IT IS ESSENTIAL TO KNOW THAT TREND CHANGES ARE MORE IMPORTANT THAN ACTUAL VALUE OF THE CHANGE.

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2.23 INCREASE IN TRIP, CONNECTION AND A BACKGROUND GAS

Return mud must be monitored for contamination with formation fluids. This is done by constantly recording the flowline mud density and accurately monitoring gas levels in the returned mud.

Gas cut mud does not in itself indicate that the well is flowing (gas may be entrained in the cuttings). However, it must be treated as early warning of a possible kick. Therefore pit levels should be closely monitored if significant levels of gas are detected in the mud.

An essential part of interpreting the level of gas in the mud is the understanding of the conditions in which the gas entered the mud in the first place.

Gas can enter the mud for one or more of the following reasons:

• Drilling a formation that contains gas even with a suitable overbalance.

• Temporary reduction in hydrostatic pressure caused by swabbing as pipe is moved in the hole.

• Pore pressure in a formation being greater than the hydrostatic pressure of the mud column.

Gas due to one or a combination of the above, can be classified as one of the following groups:

Drilled Gas

When porous formations containing gas are drilled, a certain quantity of the gas contained in the cuttings will enter the mud.

Gas that enters the mud, unless in solution with oil base mud and kept at a pressure higher than its bubble point, will expand as it is circulated up the hole, causing gas cutting at the flowline. Gas cutting due to this mechanism will occur even if the formation is overbalanced. Raising the mud weight will not prevent it.

It should be noted that drilled gas will only be evident during the time taken to circulate out the cuttings from the porous formation.

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Connection Gas

Connection gases are measured at surface as a distinct increase above background gas as bottoms up occurs after a connection.

Connection gases are caused by the temporary reduction in effective total pressure of the mud column during a connection. This is due to pump shut down and the swabbing action of the pipe.

In all cases, connection gases indicate a condition of near balance. When an increase trend of connection gases are identified, consideration should be given to weighting up the mud before drilling, operations continue and particularly prior to any tripping operations.

Trip Gas

Trip gas is any gas that enters the mud while tripping the pipe with the hole appearing static. Trip gas will be detected in the mud when circulating bottoms up occurs after a round trip.

If the static mud column is sufficient to balance the formation pressure, the trip gas will be caused by swabbing and gas diffusion.

Significant trip gas may indicate that a close to balance situation exists in the hole.

Gas Due to Inadequate Mud Density

Surface indication of an underbalanced formation depend on the degree of underbalance, as well as the formation permeability. Drilling of a permeable formation that is significantly overbalanced will cause an immediate flow increase followed by a pit gain.

2.24 CHANGE IN THE TEMPERATURE OF THE RETURN DRILLING MUD

The temperature will normally take a sharp increase in transition zones. The circulating rate, elapsed time since tripping and mud volume will influence flowline temperature trends.

The temperature gradient in abnormally pressured formations is generally higher than normal. The temperature gradient decreases before penetrating the interface and, therefore marked differences can give and early indication of abnormal pressures. This is usually a surface measurement which has a tendency to be influenced by operating factors. Figure 2.2 shows plots of temperature increase while penetrating an abnormal pressure formation.

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Figure 2.29 Flowline Temperature Data

5 8

6 ∆T = 0.53 °F 100' 9

∆T = 0.23 °F 100' 7 10 DEPTH 1000 ft DEPTH 1000 ft ∆T = 4.33 °F 100' 8 11 ∆ ° TOP OF ABNORMAL TOP OF T = 2.08 F 100' PRESSURE ZONE ABNORMAL PRESSURE ZONE 9 12 90 100 110 120 130 110 120 130 140 150 160 FLOWLINE TEMPERATURE = °F FLOWLINE TEMPERATURE = °F Temperature data from Gulf Coast well Temperature data from South Texas well

7 3

8 ∆T = 0.39 °F 100' 4

∆T = 0.70 °F 100' 9 TOP OF ABNORMAL 5 PRESSURE ZONE DEPTH 1000 ft DEPTH 1000 ft ∆T = 10.0 °F 100' 10 6 ∆T = 3.38 °F 100' TOP OF ABNORMAL PRESSURE ZONE 11 7 120 130 140 150 160 100 110 120 130 140 150 FLOWLINE TEMPERATURE = °F FLOWLINE TEMPERATURE = °F Temperature data from Pacific Coast well Temperature data from South China Sea well

∆T = 0.43 °F 100' 2

∆T = 5.20 °F 100' 3 DEPTH 1000 ft TOP OF 4 ABNORMAL PRESSURE ZONE

5 70 80 90 100 110 120 FLOWLINE TEMPERATURE = °F Temperature data from North Sea well

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2.25 DECREASE IN D-EXPONENT

The D-Exponent will be plotted by the well loggers and maintained current at all times. This value was introduced in the mid sixties to calculate a normalised penetration rate in relation to certain drilling parameters.

log (R/60N) d = –––––––––––––– log (12W/10°D)

Where:

R = rate of penetration, ft/hr N = rotary speed, rpm W = weight on bit, lbs D = bit size, ins d = D-exponent

The D-exponent may be corrected and normalised for mud weight changes and/or ECD (equivalent circulating density) by the following:

d x normal pressure (ppg) dc = ––––––––––––––––––––––– mud weight or ECD (ppg)

Figure 2.30

SAMPLE PLOT OF D EXPONENT vs. DEPTH A plot of Dc-Exponent versus depth in shale c sections, has been used with moderate success 1.0 1.5 2.0 in predicting abnormal pressure. Trends of Dc-exponent normally increase with depth, but in transition zones, its value decreases to 10 - lower than expected values. Mud logging companies have further variations/models which try to normalise for other parameters (such as bit wear and rock strength) to 11 - Normal Trend varying degrees of success. An illustration of a Line Dc plot is attached as figure 2.3.

Depth (1000 ft) 12 -

13 - 17 16 15 14 13 12 11 10 9

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2.26 POSITIVE KICK SIGNS

A kick occurs when the hydrostatic pressure of the mud column in the well is less than the formation pressure provided that the formation has the ability to produce. A kick is a positive indicator that formation fluid is entering the wellbore and Secondary Well Control must be initiated.

Recognising a Kick While Drilling

Flow into the wellbore causes two changes to occur in the mud circulating system:

• Increase of active mud system volume.

• The mud return flow rate exceeds the mud flow rate into the well.

Since a rig’s fluid system is a closed system, and increase in returns detected by a flow monitoring system will also be indicated by a gain in pit level. Detecting a change in pit level may be done by visual observation. This means placing some type of pit level marker in the tank, then posting someone to keep a constant watch. From your own experience, you know that to keep a constant watch on the pit level is next to impossible. This is especially true during trips, when most kicks occur. A more accurate and reliable method is to use any of the several pit level measuring instruments with the recorder mounted at the driller’s console and supported by the mud logger’s monitoring system. This allows a constant watch on the pit level by the driller, both while tripping and drilling. Good communication between crew members is essential on the rig. Drillers should make sure crew hands notify them if they do anything to change the level in the pits. If crew hands are adding volume to the pits, they should also notify the driller when they stop adding volume.

When drilling a formation containing gas, a minor pit level rise will be noted because of the core volume of gas being drilled. However, this will occur only as the gas nears the surface, and is due to the drilled gas expanding and is not necessarily an indication that the well is underbalanced. The timing of the increase in pit volume is important in distinguishing between a true kick and gas expansion only. The hole will also take the same volume of fluid that it gave up, after the gas bubble has reached the surface. However, if there is any question as to the cause of the pit gain, stop the pump and check the well for flow.

On trips, the drill crew should be able to recognise a 5-barrel kick or less. During drilling, the crews are generally able to recognise a 10 barrel kick or less.

The size or severity of a kick depends on the volume of foreign fluid allowed to enter the wellbore, which depends on the degree of underbalance, the formation permeability, and the length of time it takes the drilling crew to detect that the well is kicking.

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Recognising a Kick While Tripping

Flow into the wellbore will cause improper hole fill up, if this is seen a flow check should be performed.

• If the flow check is positive then the well should be shut in.

• If the flow check is negative the drill string should be run back to bottom to circulate bottoms up (stripping may have to be used here).

Trip tanks are recognised to be the safest and most reliable method of monitoring mud volumes on trips. It is recommended that a continuous hole fill up be used when tripping out of the hole. When tripping in the hole the, trip tank should be used to ensure the correct mud displacement is taking place.

Rig movement with a floating drilling rig makes it more difficult to recognise kick indicators while drilling or tripping. For this reason additional fluid volume detection equipment is installed in the mud pits to compensation for rig motion. It is recommended for floating drilling units that flow checks be performed on the trip tank with the hole fill pump circulating across the bell nipple to eliminate rig motion as much as possible.

Situations that can mask a kick:-

• Mud weight adjustments while drilling.

• Mud transfers while drilling.

• Partial lost circulation.

• Solids control equipment and degassing mud.

• Spills and leaks in surface equipment.

• Drain back.

• Pump start up and shut down.

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2.27 KICK BEHAVIOUR

A Comparison Between Oil and Water Base Muds

Due to high temperatures and pressure a small gas kick can turn into a serious well control problem with oil base muds. Solution gas can become dissolved and miscible. The reason for this is that the gas remains in solution until it reaches its bubble point. In the same way that gas in a disposable lighter remains in its liquid phase until the pressure is relieved.

In fig 2.4a three barrels of mud have entered the wellbore at 10,000 ft, but we would see no pit gain while drilling until the gas has been circulated up to 2600 ft. The gas then expands rapidly and there is a real danger of blowing out sufficient mud to put the entire well underbalance. This problem is easier to detect in water based muds because the original volume of the gas will expand much earlier as the pressure above the gas is reduced (see fig. 2.4b). The problem in OBM's is that if a kick has entered the wellbore undetected it is impossible to know where the top of the gas is. For example if the drilling rate is say 80 SPM and the pump output is .117bbls per stroke then in an 8.5" hole section with 5" drillpipe the influx would travel 203 ft. for each minute that the kick is undetected. In extreme cases the gas could be 6000 - 7000ft. away from the surface without the driller realising anything is wrong.

Under these conditions it may be prudent to count all drilling breaks as primary indicators. Stop drilling, shut off the pumps and close the well in. The gas can then be circulated through the choke in a safe manner utilising the first circulation of the drillers method. Some procedures advise that the gas should be circulated to 2500 ft. below the BOP before the well is shut in and the gas circulated through the choke. It may be the case that the bubble point is lower and unless this information is known, even though the first procedure may take a little longer, remember safety is always our main concern.

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Figure 2.31a - Oil Base Mud Figure 2.31b - Water Base Mud

ASSUME: Three bbls of gas is swabbed into the hole during a connection (undetectable)

0 Surface Conditions 0 Surface Conditions 15 psi 70°F 15 psi 70°F

Bubble Point 100% of Total Expansion 1000' - 2000'

12 bbls Gas 2,500' 2,500' Volume

Detectable Pit Gain Depth Depth

6 bbls 5,000' 5,000' Gas Volume

Bottom Hole Conditions Bottom Hole Conditions 7000 psi 250°F 7000 psi 250°F 10,000' 10,000' 0 3 bbls Bbls 1,400 0 3 bbls Bbls 1,400

Solution gas will not migrate or expand until Gas in WBM will migrate and expand as bubble point pressure is reached. pressure is reduced.

NOTE:The dissolving of gas into oil base mud does not hinder the detection of large volume kicks (5 bbls +), normal kick detection applies. After the well is shut in. Normal kick killing procedures apply.

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2.28 CONTROLLING INFLUXES AND KICKS

Influxes and kicks are circulated out of the well via an adjustable choke such that the bottom hole pressure (BHP) is maintained greater than (FP). The principle of keeping BHP greater than FP requires a reliable method of measuring BHP – this is why having tubing close to the bottom whilst circulating out a kick is useful as the surface tubing pressure can be used as a reliable indication of BHP.

2.28.1 Circulating Principles Workover fluid or any other type of fluid will require pump energy for it to be circulated in any system. The pump energy is measured as pump pressure (psi) and the fluid displacement is commonly measured in strokes per minute (stks/min).

This energy required to pump a fluid is dependent upon the following:

· The greater the density of the fluid, the greater the pump energy required and vice versa. · The smaller the cross section area of the circulating system, the greater the pump energy required and vice versa. · The faster the pump speed (stks/min) the greater the pump energy required and vice versa. · The longer the circulating system the greater the pump energy required and vice versa.

We should know the pump energy required to pump a fluid of known density (commonly called weight) around a system of known dimensions. This process is called taking slow circulating pump pressures (SCRs).

If we have some measurements of SCRs for rig, cement, kill pumps, or any other pump we would use for circulating workover fluid, then we can assess anticipated pump pressures from the recorded data to aid our control of the circulating process.

Example: Rig Pump 10 ppg fluid showing increased pump pressure for increased pump rate

Pump Rate Pump Pressure (Strokes per Minute) (PSI)

30 spm 400 psi 40 spm 520 psi 50 spm 650 psi

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2.28.2 Normal Circulation Rate

The normal circulation route is to pump down the tubing and up and out of the annulus. We shall discuss tubing and annulus and the various barriers as they relate to workover more specifically in chapter 8 (Production Well Kill), but for the moment let us consider the mechanisms of fluid being pumped into and out of the well for any well operation.

Circulating Pressure

Circulating pressure is made up of all the components of friction within the circulating system. These are commonly divided into

a) surface b) tubing c) bottom of tubing d) annulus back pressure ‘losses’. Annulus back pressure losses add to the effective hydrostatic pressure of the fluid being pumped into the annulus. Remember that the density of the fluid, geometry of the well and rate of pumping can effect the circulating pressure and in turn the bottom hole pressure (BHP) whilst circulating.

In effect, circulating back pressure past the bottom of the tubing acts on the bottom of the well – we need to be aware of this when establishing a suitable circulating pressure / speed.

Reverse Circulation

Reverse circulation entails pumping down the annulus, and up and out of the tubing. This method requires a tubing choke to adjust casing pressure to the required value.

The pump pressure at the same speed for normal and reverse circulation may be different for the same fluid density in the same geometry well because of the difference in back pressure characteristics past the bottom of the tubing in either direction.

The choice of reverse or normal circulation will depend on operational requirements and circumstances.

2.28.3 Fluid Displacement / Pump Calculations

A barrel (bbl) is equivalent to 42 gallons (US), pump displacement is commonly calculated in barrels per stroke (bbl/stk)

7.48 gallons = 1 cubic foot (cu.ft.) therefore, 5.6146 cu.ft = 1 bbl A typical rig pump output is 0.1193 bbl/stk Or, 0.6698 cu.ft./ stk Assuming volume of fluid to be displaced is 600 bbls. How many strokes to displace that

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volume with the pump output given above?

Total volume to be displaced (bbls) Total strokes = Pump output (bbl/stk)

= 600__ 0.1193 = 5029 strokes

If the pump speed was 30 strokes per minute (stks/min) how long would it take for total displacement?

5029 strokes Time (minutes) = 30 strokes / minute

= 68 minutes or 2 hrs 48 minutes

Pump Rate

Choice of pump rate is extremely important. The choice will depend on:

1. Margin between hydrostatic influences in the well (control fluid and applied pump pressure) and the formation fracture value. 2. What fluid(s) are being circulated. 3. Equipment Pressure Rating 4. How effective pump will perform at lower (or higher) speeds.

2.28.4 Gas Migration – Expansion / Non Expansion

A light fluid will tend to float on top of a heavier fluid. Gas in most circumstances will tend to float on top of liquids. As gas released from depth in a well will tend to maintain close to its original pressure if it is not allowed to expand or cool. Liquid will tend to lose some of their pressure when allowed to cool as will gas but the relative magnitude is much greater for gas as it relates to volume and temperature.

Two principles measure gas behaviour; ‘Boyle’s Law’ and ‘Charles’Law’. The former explains the relationship between pressure and volume of gas, the latter explains the relationship between pressure and temperature of gas.

Both principles are used in an equation for the behaviour of gas and incorporates a factor – called the Z factor or compression factor which allows the equation to work for a range of gases.

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Boyle’s Law

States that the volume of a gas is inversely proportional to its pressure providing temperature remains constant.

Ignoring temperature and compressibility factors the pressure multiplied by volume in any part of the system will be constant:

Hence, Pressure x Volume = k (constant)

Doubling the pressure will halve the volume and vice versa. Hence the volume or pressure of the gas can be calculated anywhere in the system knowing the current volume and pressure and at least one of the values of pressure or volume in any one part of the system.

Example 1 – Gas Migration with Expansion

If we have 10 cu.ft. of gas at a pressure of 1500 psi and the pressure changes to 700 psi, what will the new volume be?

P1V1 = P2V2 where P1 = 1500psi, V1 = 10 cu.ft. and P2 = 700 psi

So,V2 = P1V1 = 1500 x 10 = 21.43 cu.ft.

P2 700

Example 2 – Gas Migration with No Expansion

If 2 bbl of gas are swabbed into a hole at 7000ft. and the bottom hole pressure is 3640 psi, what will be the volume of the gas be if it has been allowed to migrate up to 3500 ft. without closing the well in? The mud weight is 10 ppg.

Hydrostatic pressure at 3500’ is 10 x 0.052 x 3500 = 1820 psi

Using P1V1 = P2V2

V2 = P1V1 = 3640 x 2 = 4 bbl

P2 1820

In the following example:

If 2 bbl gas is allowed to migrate to surface with the well closed in:

Annular capacity = 0.046 bbl / ft Bottom hole pressure (BHP) = 3640 psi Formation pressure = 3500 psi

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Overbalance = 150 psi Gas gradient = 0.07 psi / ft

In this case we do not have a kick. The mud hydrostatic pressure on bottom is 3640 psi and the formation pressure is 3500 psi. So we have an overbalance of (3640-3500) or 140 psi. The gas as it migrates upwards is not allowed to expand therefore it carries its original pressure (3640 psi) with it. When the gas reaches 3500 ft. the pressure is still 3640 psi upwards and downwards so the closed in pressure at the surface becomes 3640-(3500 x10 x 0.52) or 1820 psi while the bottom hole pressure becomes 3640 + (3500 x 10 x 0.052) or 5640 psi. At 1750 ft. the surface pressure becomes 3640- (1750 x 10 x 0.052) or 2730 psi and the bottom hole pressure 3640 + (5250 x 10 x 0.052) or 6370 psi.

Finally, when the gas reaches the surface, surface pressure is 3640 psi while the bottom hole pressure is 3640 + (7000 x 10 x 0.52) or 7280 psi. In practice the formation would probably break down before this bottom hole pressure is reached.

If the 2 bbl gas was swabbed in and allowed to migrate to surface without closing in the well it could cause a blowout. When the gas reaches 3500 ft. it will have expanded to a height of 86.08 ft in the annulus. This expansion will have pushed out 4 bbl mud at the surface and the gas will have replaced it, causing a reduction in bottom hole hydrostatic pressure at 875ft of 155psi. Note that the bottom hole hydrostatic pressure is now 3485 psi against the formation pressure of 3500 psi, and a kick situation has developed.

This example demonstrates an influx leading to a kick situation and this is the reason we should behave in all respects as if we had a kick from the outset when the influx was originally identified. Figure 2.32 shows the first situation with no expansion and Figure 2.33 illustrates the initial circumstances with expansion.

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Figure 2.32 Gas Migration without Expansion

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Figure 2.33 Gas Migration with Expansion

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Charles’ Law

States that the pressure of a stated volume of gas is directly proportional to its absolute temperature.

That is if you heat the gas its pressure will increase, if the cool the gas its pressure will decrease.

Incorporating this principle into Boyle’s Law and also incorporating a gas compression factor (Z) produces the general gas equation

General Gas Equation

P1V2 = P1V1 –––––– –––––

T1Z1 TNZN

If we ignore temperatures and compressibility effects, then we build in a significant safety factor particularly where wide variations in surface and formation temperatures exist. In any event you will use what refinements in calculations you need to use for the operational circumstances that present themselves.

Temperature considerations are important especially the effect on the density of brines – which we shall discuss later and also the expansion and contraction of tubing and its effect on packer integrity.

Gas Expansion and Well Control

It is clear gas must be allowed to expand particularly in kick situations but in a way that allows well hydrostatics vis a vis bottom hole pressure to be at least as or greater than formation pressure. This is explained in more depth in the following sections.

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WORKSHOP 3

1) GAS cutting of the mud could be prevented by having a mud weight that gives a large over pressure.

(a) TRUE

(b)FALSE

2) The affect on bottom hole pressure of gas cutting will be greatest:

(a) Initially when the gas enters into the mud.

(b)When the gas cut mud nears the casing shoe.

3) Given the following data:

Depth 9850 ft TVD Shoe 5500 ft TVD Mud 11 ppg (Assume this mud gives an overbalance of 150 psi.)

If the top 500 ft of this mud column is cut to 9 ppg and from 500 ft to 1300 ft the mud in the cut to 10.5 ppg, from 1300 ft to 1500 ft the mud is 10.8 ppg. If the rest of the system is uncut, what is the reduction in bottom hole pressure.

Answer–––––––––––––––––––––

4) If the gas cutting of the mud is at a constant level but shows significantly bigger peak levels when connections are made, this indicates:

(a) That formation permeability has changed.

(b)That it must be high pressure gas from the formations.

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5) Generally predictions are based on the fact that abnormally pressured formations are not as “dense” as normally pressured formations at the same depth. Is this statement:

(a) TRUE

(b)FALSE

6) An increase in both the volume and size of cuttings at the shaker is an indication of overpressured formations:

(a) TRUE

(b)FALSE

7) Drilling in a deep high pressure high temperature well with oil based muds. A small gas kick that goes into solution: (Select two answers)

(a) Will remain in solution until it gets to the surface.

(b)Will come out of solution when it reaches a bubble point pressure.

8) An increase in penetration rate of a drilling break can be caused:

(a) By an increase in formation porosity.

(b)By an increase in permeability.

(d)By a change in one OR all of the above.

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9) Connection gas as opposed to background gas can be caused:

(a) Due to a temporary reduction in the overall mud pressure during a connection.

b) Due to a temporary increase in the overall mud pressure during the connection.

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WORKSHOP 3 - Answers

1. B

2. C

3. 75 psi Reduction

500ft x 9ppg x .052 = 234psi 500 + 800ft x 10.5ppg x .052 = 437psi

1300 +

200ft x 10.8ppg x .052 = 112psi

1500 +

8350 x 11ppg x .052 = 4776psi 5559psi

9850 9850 x 11ppg x .052 = 5634 - 5559 = 75psi

4. B

5. A

6. A

7. B & C

8. D

9. A

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SHUT-IN PROCEDURES

2.29 OBJECTIVES

To cover the shut-in procedures and diverter procedures for a surface BOP. To cover A.P.I. recommendations for these procedures which includes advantages and disadvantages.

To cover the shut-in procedures and diverter procedures for a subsea BOP. To cover A.P.I. recommendations for these procedures which includes advantages and disadvantages.

2.30 GENERAL INTRODUCTION TO SHUT-IN PROCEDURES ON A FIXED RIG

Note: A fixed rig is defined as a drilling rig equipped with a surface BOP.

Shut-in procedure should be agreed by contractor and operating company and posted on rig floor before drilling the well begins.

When any positive indication of a kick is observed such as a sudden increase in flow or an increase in pit level, then the well should be shut in immediately without doing a flow check. If the increase in flow or pit gain is hard to detect then a flow check can be done to confirm the well is flowing.

If surface hole is being drilled and the conductor pipe is not set in a competent formation and a shallow gas kick is taken then the gas should be diverted. This will be discussed at the end of this section.

The procedures which follow are generalised suggestions and not necessarily applicable to any specific rig.

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2.31 SOFT SHUT-IN PROCEDURE WHILE DRILLING ON A FIXED RIG

1. When any indications are observed, while drilling, that the well may be flowing, stop rotating the drill string, raise the drill string with pumps on until tool joint is above the drill floor.

2. Stop pumps and check for flow, if positive:

3. Open choke line HCR valve.

4. Close BOP.

5. Close choke. If the choke is not a positive closing choke then close a valve downstream of choke.

6. Call supervisors and commence plotting a graph of shut in drill pipe pressure. Check pit volume gain.

7. Refer to A.P.I. R.P. 59 section 3.8 for the advantages and disadvantages of the soft shut-in.

Note: Choke in open position while drilling.

2.32 SOFT SHUT-IN PROCEDURE WHILE TRIPPING ON A FIXED RIG

1. If there is an indication of swabbing and the well flows during a flow check proceed as follows.

2. Set the slips.

3. Install full opening safety valve (Kelly cock).

4. Close safety valve.

5. Open choke line HCR valves.

6. Close BOP.

7. Close choke.

8. Call supervisor and check pressures.

9. Install inside blowout preventer (Gray valve or Non-Return Valve).

10. Open safety valve.

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11. Reduce annular preventer pressure and start stripping drill pipe in the hole.

Note: Choke in open position while tripping.

With a swabbed kick there are four options:

1. Strip back in hole.

2. Perform a volumetric bleed.

3. Bullhead kick back into formation.

4. Perform off bottom kill then return to bottom and circulate well to desired mud weight.

2.33 HARD SHUT-IN PROCEDURE WHILE DRILLING ON A FIXED RIG

1. When any indication is observed while drilling that the well maybe flowing, stop rotating the drill string, raise the drill string with pumps on until tool joint is above the drill floor.

2. Stop pumps and check for flow, if positive:

3. Close annular or pipe rams.

4. Open choke line HCR valve.

5. Call supervisor and commence plotting a graph of shut in drill pipe pressure. Check pit volume gain.

6. Refer to A.P.I. R.P. 59 sections 3:7 for advantages and disadvantages of the hard shut-in.

After the well has been shut in.

In any shut-in procedure it is prudent to line up the annulus to the trip tank above the annular or rams. This will assist in double checking to see if they are leaking. Double check that the well is lined up through the choke manifold prior to circulating kick out.

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2.34 FAST SHUT-IN PROCEDURE WHILE DRILLING ON A FIXED RIG

1. When any indication is observed while drilling that the well maybe flowing, stop rotating the drill string, raise the drill string with pumps on until tool joint is above the drill floor.

2. Stop pumps and check for flow, if positive:

3. Open choke line HCR valve.

4. Close Annular.

5. Call supervisors and commence plotting a graph of shut in drill pipe pressure. Check pit volume gain.

Note: There are no A.P.I recommendations for the fast shut-in

2.35 DIVERTER PROCEDURE WHILE DRILLING ON A FIXED RIG

1. Where shallow casing strings or conductor pipe are set, fracture gradients will be low. It may be impossible to close the BOP on a shallow gas kick without breaking down the formation at the shoe. If a shallow gas kick is taken while drilling top hole then the kick should be diverted.

Drilling shallow sand too fast can result in large volumes of gas cut mud in the annulus and cause the well to flow, also fast drilling can load up the annulus increasing the mud density leading to lost circulation and if the level in annulus drops far enough then well may flow.

When drilling top hole a diverter should be installed and it is good practice to leave the diverter installed until 13 3/8" casing has been run. An automatic diverter system should first:-

a) Open an alternative flow path to overboard lines.

b) Close shaker valve and trip tank valve.

c) Close diverter annular around drill pipe.

d) If there are two overboard lines then the upwind valve should be manually closed.

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2. If any indication of flow is observed while drilling top hole, close diverter immediately as the gas will reach surface in a very short time and it is inadvisable to attempt a flow check.

3. Suggested diverting procedure in the event of a shallow gas kick.

a) Maintain maximum pump rate and commence pumping kill mud if available.

b) Space out so that the lower safety valve is above the drill floor.

c) With diverter line open close shaker valve and diverter packer.

d) Shut down all nonessential equipment, if there is an indication of gas on rig floor or cellar area then activate deluge systems.

e) On jack-up and platform rigs monitor sea for evidence of gas breaking out around conductor.

f) If mud reserves run out then continue pumping with sea-water.

g) While drilling top hole a float should be run. This will prevent gas entering drill string if a kick is taken while making a connection. It will also stop backflow through the drill string on connections.

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WORKSHOP 4

ANNULAR PREVENTER Note: The well will be killed using the left hand automatic choke.

Remotely operated choke - left hand SHEAR RAM P To mud/gas separators, 15 pits and diverter lines Manual 8 Adjustable Choke 9 5" PIPE RAM To pit

HCR HCR 7 VALVE VALVE CHOKE LINE Bleed line DRILL SPOOL 11 12 1 2 3 4 10

13 5" PIPE RAM P To mud/gas separators, pits and diverter lines 14 Remotely operated choke - right hand CASING HEAD 5 6 P = Positive Closing Choke

Questions 1-4 refer to the diagram above. The valves shown are numbered 1 to 15.

1. If all of the above valves were closed, indicate below those valves that should be in the open position if the Manifold is lined up to suit a Soft Shut-in (excluding choke).

Answer:

2 . Referring to the above question indicate the position of the chokes, when lined up for a Soft Shut-in .

a. Left hand remote choke Opened Closed b. Manual adjustable choke Opened Closed c. Right hand remote choke Opened Closed

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3. Indicate the position of the chokes, when lined up for a Fast Shut-in .

a. Left hand remote choke Opened Closed b. Manual adjustable choke Opened Closed c. Right hand remote choke Opened Closed

4. Indicate the position of the chokes, when lined up for a Hard Shut-in .

a. Left hand remote choke Opened Closed b. Manual adjustable choke Opened Closed c. Right hand remote choke Opened Closed

If an indication of a Kick while Drilling occurs, or if the Well flows while Tripping, then the well must be closed-In. (A Kelly is being used) The following is a list of possible Actions that could or could not be taken when shutting the well in.

1. Pick up and space out 2. Stop Rotating 3. Set Slips 4. Open HCR valve 5. Close HCR valve 6. Install Safety Valve(FOSV) 7. Open Safety Valve 8. Close Safety Valve 9. Open Ram Preventer 10. Close Ram Preventer 11. Open Annular Preventer 12. Close Annular Preventer 13. Stop pumping 14. Install Inside B.O.P (Grey Valve) 15. Open Choke 16. Close Choke 17. Record Data

For questions 5 to 8 refer to the list shown above.

5. Select the correct sequence of actions which should be taken if a well kicks while drilling and the Soft Shut-in is to be used.

Answer:

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6. Select the correct sequence of actions which should be taken if a well kicks while drilling and the Fast shut-in is to be used.

Answer:

7. Select the correct sequence of actions which should be taken if a well kicks while drilling and the Hard shut-in is to be used.

Answer:

8. If a well flow while Tripping, select the correct sequence of actions which should be taken if the Fast shut-in is to be used.

Answer:

9. Secondary well control could be defined as initially;

a. Controlling formation fluids with the pressure of the mud column, in a static or dynamic condition. b. Controlling formation fluids with the pressure of the mud column and the well closed in.

10. Prior to Stripping back to bottom, and assuming there is no float valve in the string, the equipment made up on top of the string would generally be;

a. A Safety valve (Kelly cock) in the closed position. b. An Inside Blow-Out Preventer (Grey valve). c. An I.B.O.P valve on top of a opened Safety Valve. d. A Safety valve closed with an IBOP valve below it. e. A closed Regan "Fast Shut-off valve". f. An I.B.O.P. valve on top of an opened Regan "Fast Shut-off valve".

11. If a well starts to Flow due to Gas at shallow levels, the safest action would be: (Select three answers)

a. Shut the Well in as fast as possible, use a ram preventer. b. Shut the diverter and then open the vent line and close the flow line. c. Open the vent line, close the flow line and then close the diverter. d. Have all nonessential personnel removed from the rig. e. Pump into the well at the fastest rate. f. Line up the returns to go through the Poor-Boy Degasser.

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WORKSHOP 4 Answers

1. The valves which should be in the open position: numbers: 2, 3, 7, 8 and 15. ref ch 6-43

2. Left hand remote choke- opened Manual Adjustable choke- closed Right hand remote choke- closed

3. Left hand remote choke- closed Manual Adjustable choke- closed Right hand remote choke- closed

4. As Q 3. All chokes Closed

5. 2, 1, 13, 4, 12, 16 and 17. ref. ch 4-2

6. 2, 1, 13, 4, 12 and 17 ref. ch 4-5

7. 2, 1, 13, 10 or 12, 4 and 17 ref. ch 4-3

8. 1, 3, 6, 8, 4, 12, 14, 7 and 17 ref. ch 5-29

9. b. ref. ch 1-1

10. c. ref. ch 5-29

11. c. d. and e. ref. ch 4-4

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METHODS OF WELL CONTROL

2.36 OBJECTIVES

To cover the methods of well control for fixed rigs, to cover the special considerations for subsea rigs and to look at step down graphs for deviated and horizontal wells.

2.37 KILL METHODS GENERAL

The objective of the various kill methods is to circulate out any invading fluid and circulate a satisfactory weight of kill mud into the well without allowing further fluid into the hole. Ideally this should be done with the minimum of damage to the well.

If this can be done, then once the kill mud has been fully circulated around the well, it is possible to open up the well and restart normal operations. Generally, a kill mud which just provides hydrostatic balance for formation pressure is circulated.

This allows approximately constant bottom hole pressure which is slightly greater than formation pressure to be maintained as the kill circulation proceeds because of the additional small circulating friction pressure loss.

After circulation, the well is opened up again and the mud weight may be further increased to provide a safety or trip margin.

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BALANCE OF PRESSURES

Once the well is shut-in providing nothing has broken down, the pressures in the well will be in balance. What is lacking in hydrostatic head of fluid in the well is now being made up by surface applied pressure on the annulus and on the drill pipe.

Providing the bit is on bottom and the string is full with a known mud density this allows us to determine what the formation pressure is and hence what kill mud weight is required to achieve balance.

On the drill pipe side of the U-tube. (Figure 2.1):

Formation Pressure = [Hydrostatic Pressure of Mud in Drill pipe] + [Shut-in Drill Pipe Pressure SIDPP]

On the casing side of the U-tube:

Formation = Hydrostatic Pressure + Hydrostatic Pressure + Shut-in Casing Pressure of Mud in Annulus of Influx Pressure

The mixture of mud and formation fluid in the annulus makes it impossible to determine formation pressure using the casing information. The drill pipe, however, is full of clean mud of known weight and can be used as a “barometer’ of what is happening downhole.

PF = Head of Mud In Drill pipe + SIDPP

We require the mud to produce a hydrostatic pressure equal to the formation pressure over a length equal to the true vertical depth of the hole. This can be expressed as a gradient, and converted to any desired mud weight unit; in this case ppg.

The kill mud weight required could also be described as the original mud weight increased by an amount which will provide a hydrostatic pressure equal to the amount of the drill pipe shut- in pressure over the vertical length of the hole.

Kill Mud Original Mud SIDPP (psi) ÷ Weight (ppg) = Weight (ppg) + –––––––––––––––––– 0.052 [True Vertical Depth (ft) ] Once the formation pressure is known, the mud weight required to balance, or ‘kill’, it can be calculated, since:-

Formation Pressure (psi) Kill Mud Weight (ppg) = ––––––––––––––––––– ÷ 0.052 True Vertical Depth (ft)

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DRILL PIPE ANNULUS

DRILL PIPE CASING PRESSURE PRESSURE

800 psi 1220 psi

MUD HYDROSTATIC MUD HYDROSTATIC PRESSURE IN THE PRESSURE IN THE DRILL PIPE ANNULUS

8613 psi

9100 psi 67 psi

TOTAL PRESSURE TOTAL PRESSURE ACTING DOWN ACTING DOWN (9100 + 800 = 9900 psi) (8613 + 1220 + 67 =9900 psi)

9900 psi 9900 psi

FORMATION 9900 psi 9900 psi PRESSURE 9900 psi

Drill Pipe: SIDPP + Hydrostatic Pressure of Mud = Formation Pressure Annulus: SICP + Hydrostatic Pressure of Mud + Hydrostatic Pressure of Influx = Formation Pressure

Fig 2.34

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2.38 CONSTANT BOTTOM HOLE PRESSURE KILL METHODS

There are three ‘constant bottom-hole pressure’ kill methods in common use today which are:

• Driller’s Method

• Wait & Weight Method (also known as the ‘Engineer’s Method’)

• Concurrent Method

These three techniques are very similar in principle, and differ only in respect of when kill mud is pumped down.

In the Driller’s Method, the kill is split into two circulations. During the first, the kick fluid is circulated without changing the mud weight; once the kick is out, the mud is weighted up and pumped around the well on the second circulation.

The Wait & Weight method achieves both of these operations simultaneously. Kill mud is prepared before starting the kill, and the kick fluid is circulated out while this mud is circulated into the well.

In the Concurrent method, a compromise is adopted between these two methods. The kick fluid is circulated out while the mud being circulated in, is weighted up in stages, towards the kill weight.

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2.39 THE DRILLER'S METHOD

In the Driller’s Method, the kick is circulated out of the hole using the existing mud weight. The mud weight is then raised to the required level and circulated around the well.

Two complete circulations are thus required, as a minimum, for this method. Since it deals separately with the removal of the kick and the addition of kill weight mud, it is generally considered to be the simplest of well control methods, and it requires least arithmetic. However, this results, in the well being circulated under pressure for a relatively long time, possibly the longest of the three methods, with an increased possibility of choke problems. Also, the annular pressures produced during the first circulation are higher than produced with any other method.

CAUTION: because very high annular pressure may arise when killing a gas kick with this method, care should be taken. Annular pressure will be at a maximum immediately before gas arrives at surface, and casing burst pressure limitations may be critical.

This method is most used on small land rigs where the Driller may have little help and limited equipment. It is also used on highly deviated and horizontal wells, where the influx is likely to be a swabbed kick.

In addition the simplicity of the Driller’s Method makes it useful when only limited information is available about the well conditions.

To summarise:

FIRST CIRCULATION: Pump the kick out of the well, using existing mud weight.

SECOND CIRCULATION: Pump kill weight mud around the well.

Advantages of Driller’s Method:

• Minimum Arithmetic • Minimum Waiting Around Time - can start kill at once • Minimum Information Required

Disadvantages of Driller’s Method:

• Highest Annular Pressure Produced • Maximum Well Under Pressure Time • Longest ‘On-choke’ Time

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Procedure for Driller’s Method (See Figure 2.2)

1. The well is closed in and the information recorded.

FIRST CIRCULATION

2. If a slow circulating rate pressure, PSCR, has been taken, then calculate the pressure required on the drill pipe for the first circulation of the well.

This is: Initial Circulation = Slow Circulation Rate + Shut-in Drill pipe Pressure Pressure Pressure

or:ICP = PSCR + SIDPP

3. Open the choke about one quarter, start the pump and break circulation; then bring the pump up to the KILL RATE.

4. While the Driller is bringing the pump up to the KILL RATE, the choke operator should operate the choke so as to keep the casing pressure at or near the closed in casing pressure reading.

5. Once the pump is up to the KILL RATE, the choke operator should transfer his attention to the drill pipe pressure gauge and adjust the choke to maintain the INITIAL CIRCULATING PRESSURE on the drill pipe pressure gauge.

6. The INITIAL CIRCULATING PRESSURE is held constant on the drill pipe pressure gauge by adjusting the choke throughout the whole of the first circulation, until all of the kick fluid has been circulated out of the well. The pump rate must also be held constant at the KILL RATE throughout this period.

7. Once the kick is out of the hole, shut the well in and mix up the kill mud weight required.

SIDPP Kill Weight Mud (ppg) = Original Mud Weight + ( –––––––––––––––) T.V.D. x 0.052

NOTE 1: This is a kill weight mud to balance formation pressure. It is the lowest possible mud weight which will ‘kill’ the well. Once the well is dead, it will be necessary to increase the mud weight further to provide a trip margin.

NOTE 2: Some operators prefer to continue circulating the well while kill weight mud is being mixed. There is no theoretical reason why this should not be done, though it does result in further wear and tear on equipment under pressure - in particular the choke.

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Figure 2.35

DRILLER’S METHOD

FIRST CIRCULATION COMPLETE

WELL KILLED WELL

Shut in - kill mud all round well

Well clean up may take Well some time - small some residual pressure on the pressure on residual casing is thus likely casing

Well closed in Well

Original weight mud all Original around well

= SIDPP

CASING

0 psi

PRESSURE

0 psi

SIDPP

Choke being steadily opened to keep F.C.P. on opened to keep F.C.P. drill pipe, hence Casing pipe, hence drill Pressure reducing Pressure

DRILLER’S METHOD

CIRCULATING KICK OUT

Expanding gas is pushing more mud out of annulus, so Casing Pressure rising to compensate and KEEP CONSTANT BOTTOM CONSTANT KEEP HOLE PRESSURE

DRILLER’S METHOD

KILL MUD KILL COMING UP ANNULUS

BEING

RISING

CASING

REDUCED

PRESSURE

KILL

MUD

GAS

EXPANDING

INITIAL

F.C.P.

PRESSURE

CIRCULATING

MUD

WEIGHT

ORIGINAL

Drill pipe pressure dropping (from I.C.P to F.C.P. as Kill Mud as Kill to F.C.P. goes to bit ) goes to

DRILLER’S METHOD

CIRCULATING KILL MUD IN KILL

DRILLER’S METHOD

KICK SHUT IN

Gas Kick

Before start of first circulation

CASING

STEADY

PRESSURE

GAS

DRILLPIPE

DROPPING

PRESSURE

SIDPP SICP

KILL

MUD

WEIGHT

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SECOND CIRCULATION

8. Once the kill mud is ready, open the choke about one quarter, start the pump and break circulation. Then bring the pump up to the kill rate.

9. While the Driller is bringing the pump up to the kill rate, the choke operator should operate the choke so as to keep the casing pressure steady at the same pressure as when closed in.

10.While the drill pipe is being filled with heavy mud there are two options for keeping B.H.P. constant, either keep the casing pressure constant or make out a graph going from I.C.P. to F. C . P.

NOTE: If the influx was gas and all the gas was not removed in first circulation, the first option of keeping casing pressure constant could lead to higher annular pressures.

The drill pipe pressure will go down as the drill pipe is being slugged with the heavier mud. In practice, if all the kick was properly removed in the first circulation, the choke should not need to be touched once the pumps are steady at the Kill Rate, until kill mud reaches the bit.

Once the kill mud reaches the bit, the pressure held on the drill pipe is just that required to circulate the kill mud around the well. This is the slow circulating rate pressure, increased slightly for the extra mud weight.

Final Circulating = Slow Circulating x Kill Mud Weight . Pressure Rate Pressure Original Mud Weight

The drill pipe pressure starts dropping below the initial circulating pressure, as the kill mud starts down the drill pipe, reaching the final circulating pressure when the kill mud reaches the bit. Thereafter the drill pipe pressure is held at the final circulating pressure by controlled opening of the choke, as the kill mud moves up the annulus.

A graph showing how drill pipe pressure drops from the initial to the final circulating pressure is shown in Figure 3 and this can be used as a guide to the drill pipe pressures required. The drill pipe pressure should drop according to the graph, as kill mud goes to the bit, without the choke being moved.

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Figure 2.36

ICP

DRILL PIPE PRESSURE FCP

PUMP STROKES 0 KILL MUD AT BIT Graph of Drill Pipe Pressure as Kill Mud is Pumped

Because of the possibility that the annulus may not be circulated completely clean, during the first circulation, it may be preferable to work out how the drill pipe pressure should vary as kill mud is pumped around the well. This will allow the drill pipe pressure to be used throughout, so eliminating the possibility of small gas bubbles in the annulus producing misleading information.

The following graphs depict the variations in pressure during the well circulation.

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Figure 2.37

FIRST CIRCULATION

Circulating Pressure START FINISH

Pressure Constant

Circulating Pressure at Reduced Rate

Drill Pipe Closed in Pressure

Time or Pump Strokes

START Annular Pressure FINISH

Gas Influx

Water Influx

Annular Pressure

Time or Pump Strokes

Profile of Circulating and Annular Pressure While Killing by Driller's Method

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Figure 2.38 SECOND CIRCULATION

Circulating Pressure START FINISH

Pressure Constant Circulating Pressure at Circulating Pressure with Kill Mud Reduced Rate

Well Dead in Drill Pipe

Drill Pipe Closed in Pressure

Surface to Bit Time or Pump Strokes

START Annular Pressure FINISH

Constant

Annular Pressure

Surface to Bit Time or Pump Strokes

Profile of Circulating and Annular Pressure While Killing by Driller's Method

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Determination of Initial Circulating Pressure

If no slow circulating rate pressure has been taken, then the initial circulating pressure can be determined using the start-up procedures described in the circulations of the Driller’s Method.

Where the casing pressure has been held constant while the pumps are brought up to a kill rate, the drill pipe pressure reading will be the initial circulating pressure.

WARNING: the existence of a predetermined kill rate gives rig personnel a wrong impression that a kick must be circulated exclusively at this rate.

The procedure consists of:

1. Noting casing pressure reading.

2. Adjusting pumps to new kill rate. Adjusting choke to hold casing pressure constant at the value noted.

3. As soon as the driller has the pumps settled on the new rate, return to the drill pipe pressure gauge. Note this new reading is the circulating pressure for the new pump rate and maintain this.

4. Check choke orifice size, in relation to kill rate

NOTE: This procedure is satisfactory at any time during a kill providing the mud weight in the drill string is not changing during the process. It is however preferable to maintain pump rate constant as much as possible. Any decision to change pump rate should be taken early.

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2.40 THE WAIT AND WEIGHT METHOD

The “Wait and Weight” is sometimes referred to as the ‘Engineers Method’ or the ‘One Circulation Method’. It does, at least in theory, kill the well in one circulation.

Once the well is shut in and pressures stabilised, the shut in drill pipe pressure is used to calculate the kill mud weight. Mud of the required weight is made up in the mud pits. When ready, kill mud is pumped down the drill pipe. At commencement, enough drill pipe pressure must be held to circulate the mud, plus a reserve equivalent to the original shut in drill pipe pressure. This total steadily decreases as the mud goes down to the bit, until with kill mud at the bit, the required pressure is simply that needed to pump kill mud around the well.

The choke is adjusted to reduce drill pipe pressure while kill mud is pumped down the string. With kill mud at the bit, the static head of mud in the drill pipe balances formation pressure. For the remainder of the circulation, as the influx is pumped to the surface, followed by drill pipe contents and the kill mud, the drill pipe pressure is held at the final circulating pressure by choke adjustment.

Advantages of the Wait and Weight Method

• Lowest wellbore pressures, and lowest surface pressures - this means less equipment stress.

• Minimum ‘on-choke’ circulating time - less chance of washing out the choke.

Disadvantages of the Wait and Weight Method

• Considerable waiting time (while weighting up) - gas migration.

• If large increases in mud weight required, this is difficult to do uniformly in one stage.

Procedure for the Wait and Weight Method

The Wait and Weight method uses the same calculations already described for a drill pipe pressure schedule. The calculations are:

______(SIDPP)______Kill Mud Weight = Original Mud Weight + (PPG) (PPG) True Vertical Depth x.052

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At the start of the circulation, with kill mud:

Initial Circulating Slow Circulating Rate Shut in Drill pipe Pressure = Pressure + Pressure (ICP) (SCRP) (SIDPP)

Once the capacity of the drill string is calculated, it is possible to draw a graph showing how drill pipe pressure varies as kill mud is pumped down to the bit. (See Figure 2.6)

Once kill mud is ready, the start-up procedure is as previously described.

The choke is cracked open, the pump started to break circulation, and then brought up slowly to the Kill Rate.

While the Driller brings the pump up to the Kill Rate, the choke operator works the choke so as to keep the casing pressure at or as near as possible to the closed in casing pressure reading.

When the pump is up to the Kill Rate, the choke operator transfers to the drill pipe pressure gauge.

As the kill mud proceeds down the drill pipe, the drill pipe pressure is allowed to drop steadily from the Initial Circulating Pressure to the Final Circulating Pressure, by choke adjustment.

Where the kick is a small one, at or near the bottom of the hole, the drill pipe pressure tends to drop of its own accord as the kill mud moves down. Little or no choke adjustment is required.

Only in cases of diffused gas kicks with gas far up the annulus will significant choke adjustments be needed during this period.

After kill mud has reached the bit, the drill pipe pressure is maintained at the Final Circulating Pressure, until the kill mud returns to surface.

As with the Driller’s method, this Final Circulating pressure is held constant as long as pump rate is held constant at the selected value. If, for any reason, the pump rate is felt to be wrong, it can be changed using the same procedure described previously. However, pump rate changes should be avoided, where possible.

While the pump rate is adjusted, the casing pressure is held steady by adjusting the choke. Once the pump is stabilised at its new speed, the revised circulating pressure is read from the drill pipe gauge. If a gas influx is very near to the surface, adjusting pump rate by holding a steady casing pressure may significantly increase the bottom hole pressure. This is due to the rapid expansion of gas near the surface. Alterations in pump rate are to be made early on!

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The following two graphs depict pressure variations during the Wait and Weight method. Figure 2.39 Circulating Pressure START FINISH

Circulating Pressure Constant Pressure at Circulating Pressure with Kill Mud Reduced Rate

Well Dead in Drill Pipe

Drill Pipe Closed in Pressure

Surface to Bit Time or Pump Strokes

START Annular Pressure FINISH

PH1 PH2 PH3 PH4

Annular Pressure

Surface to Bit Time or Pump Strokes

Profile of Circulating and Annular Pressure Killing by Wait and Weight Method

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Figure 2.40

WAIT & WAIT WEIGHT

KILL MUD KILL AT BIT AT

WAIT & WAIT WEIGHT

WELL KILLED WELL Well ‘clean up’ takes ‘clean up’ Well some time, as small some residual Casing residual Pressure is likely

Drill pipe Pressure now steady at Final Circulating Pressure

RISING

CASING

V. SLOWLY V.

PRESSURE

F.C.P

F.C.P.

Weight

Kill Mud

Drill pipe pressure dropping from Initial Circulating Pressure to Final Circulating Pressure Casing Pressure rising very slowly (little gas expansion)

WAIT & WEIGHT WAIT

CIRCULATING KILL MUD DOWN KILL

Small Casing Pressure still held - as light mud from drillpipe circulated out

WAIT & WEIGHT WAIT

DRILL PIPE DRILL CONTENTS AT SURFACE AT

RISING

SMALL

CASING

V. SLOWLY V.

PRESSURE

F.C.P.

DRILLPIPE

DROPPING

PRESSURE

Weight

Kill Mud

WAIT & WEIGHT WAIT

GAS AT SURFACE

Casing Pressure at its maximum value

Gas Kick

Just starting kill mud down drill pipe

WAIT & WEIGHT WAIT

START OF KICK START

CASING

SICP

MAXIMUM

PRESSURE

I.C.P.

F.C.P.

Weight

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2.41 VOLUMETRIC WELL CONTROL

The volumetric method is mostly used in workover and production operations. It is a means of allowing the gas to migrate to surface under control. The gas needs to migrate at over (approx.) 1000' per hour. To allow the bubble to expand the casing gauge is held constant for a given volume of mud bled off. This operation is repeated, holding an ever increasing pressure on the gauge until the gas reaches the surface. This is to ensure the BHP is constant.

WHEN TO USE VOLUMETRIC WELL CONTROL

• A gas kick is taken and is migrating and the drill string is plugged and only casing pressure can be read.

• No drill string in the well, packer leaking, wireline logging and swabbed gas migrating.

Figure 2.41 Example of volumetric well control with a plugged bit

700 WELL DATA

TVD = 12000' TVD Shoe = 8000' DP/csg/OH cap = 0.0459 bbl/ft 130 bbls DC/OH cap = 0.0291 bbl/ft Mud wt = 12.0 ppg Influx Grad = 0.12 psi/ft Casing Press = 700 psi

Active pit volume before kick = 120 bbls Active pit volume after kick = 130 bbls

For calculating safety margins and working margins use the universal volumetric well control equation below:- P.choke = Pann + Ps + Pw Pa = Initial SICP Ps = Built in safety margin prior to volumetric well control commencing. Recommended safety margin = 100 - 200 psi

Pw = Working margin for volumetric well control Recommended working margin = 50 - 100 psi

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P.choke = Pann + Ps + Pw = 700 + 100 + 50 = 850 psi

Allow the casing pressure to increase to 850 psi. Note the time taken for this pressure increase then estimate percolating rate in ft/hr.

Example:-

Pressure increased by 150 psi in 15 minutes or 600 psi/hr

Pressure increase/hr Percolating rate= ÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐ Mud grad psi/ft

600 psi = ÐÐÐÐÐÐÐÐÐ 0.624 psi/ft = 962 ft/hr

Note: With this percolating rate it will take approximately 12 hours to get the influx to the surface and it should also be noted percolating rate may increase when gas is close to surface.

When casing pressure is at 850 psi bleed off at choke a volume of mud equal to the working pressure (50 psi).

Note: Casing pressure must be kept constant at 850 psi during this operation. After 50 psi of mud equivalent has been bled off at choke allow the gas to migrate unexpanded until a further 50 psi of overbalance is attained. Bleed off 50 psi equivalent mud at choke and repeat procedure until gas is at choke. The next step lubrication will be discussed later.

2.41.1 Calculations for mud volume to bleed for Pw

OH/DC's Cap A. Around drill collars mud volume to bleed = Pw x ÐÐÐÐÐÐÐÐÐÐÐ Mud grad 0.0291 = 50 X ÐÐÐÐÐÐ 0.624 = 2.3 bbls

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B. Around Drill Pipe

DP/OH Casg Cap Mud volume to bleed = Pw x ÐÐÐÐÐÐÐÐÐÐÐÐÐÐ Mud Grad 0.0459 = 50 x ÐÐÐÐÐÐ 0.624 = 3.6 bbls

2.41.2 Graphical example of a volumetric bleed

Figure 2.42

1000 Bleed off 3.6 bbls

Allow gas to migrate until 5 casing pressure read 850 psi Bleed off 3.6 bbls 900 2 4 Bleed off 3.6 bbls keeping choke pressure ± 20 psi either side of 900 3 psi Influx around D.pipe 800 Bleed off 2.3 bbl keeping choke pressure ± 20 psi either side of 850 psi influx around DC's

1 700 First build up when well was shut in

600

500 Time

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Figure 2.11 shows what is happening to the gas in the well.

Figure 2.43

0 0 0 0 0 0

700 850 850 900 950 1000

original volume (10 bbls) (10 bbls) (12.3 bbls) (15.9 bbls) (18.5 bbls) (22.1 bbls)

Gas volume in bbls at the end of each mud bleed.

Clearly the description outlined is simplified. Four bleeds are shown. Depending upon the size of the volume bled and the well depth more or less bleeds may be required than illustrated here.

2.41.3 Important Points

1. Bleed mud at constant choke pressure using the manual choke. Ensure crew trained not to be tempted to bleed off faster than this as more influx could be induced into the well. A major problem with the method could be boredom, careful records must be kept of pressure and volumes.

2. Gas may not conveniently migrate up the well in one bubble. As soon as gas reached choke, stop bleeding until rest of gas catches up. This may build up an unacceptable overbalance and each situation will have to be judged on the operational merits of the situation.

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2.41.4 Lubrication

Once gas is at choke stop the bleed operation and commence pumping mud into the well using the kill line.

The procedure for lubrication is as follows:-

1. Pump slowly into kill line and let kill and choke line pressure equalise before opening kill line stack valves.

2. Pump 3.6 bbls mud into annulus and allow the mud time to fall through the gas, then bleed off pressure at the choke equal to the hydrostatic pressure of the mud pumped into the annulus.

Example:-

Pumped volume Pressure to bleed = ÐÐÐÐÐÐÐÐÐÐÐÐÐ x Mud grad Ann Cap 3.6 = ÐÐÐÐÐÐ x 0.624 0.0459 = 50 psi

3. Repeat the lubrication process until all the gas has been replaced with mud and referring to the drawing in figure 2.11, this will take approximately 22.1 bbls.

Note: Pit volume should return to 120 bbls the volume in active pit before kick was taken.

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Figure 2.44 Graphical example of lubricating mud into annulus

1050 After pumping mud into annulus, waiting Pump 3.6 bbls period allows mud to fall then bleed gas until 1000 casing pressure reduces by 50 psi below original pressure. 950

900

850

800

750

700

650

Casing Pressure 600

550

500

450

400 Pit Volume 152.1 148.5 145 141 138 134 130.5 127 123 120 350 3.6 7.2 10.8 14.4 18 21.6 25.2 28.8 32.4 Barrels Pumped

1. Original Pit Volume = 120 bbls

Pit volume after kick and volumetric bleed = 152.1 bbls

2. Formation pressure = SICP + P° hyd mud + P° hyd gas = 700 + (11656 x 0.624) + (344 x 0.12) = 700 + 7273 + 42 = 8015 psi

BHP after lubrication = SICP + P° Hyd mud = 550 + (12000 x 0.624) = 550 + 7488 = 8038 psi

2.41.5 Once the volumetric bleed and lubrication has been completed then the well must be circulated to kill mud. This can be done by running wire line and perforating drill pipe or drill collars. If all the gas has been bled from the annulus then SICP can be used to calculate the kill mud.

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2.42VOLUMETRIC STRIPPING

2.42.1 Example of Volumetric Stripping

The options available if an influx is swabbed or if the well starts flowing during a trip are as follows:-

a) If well is not flowing, trip back to bottom keeping a careful check on returns. Then circulate influx out of hole.

b) If well is flowing and is shut in and the gas is percolating with the bit a long way off bottom and tight hole conditions have been experienced, then consider doing a volumetric bleed.

c) If well is flowing and is shut in and the gas is percolating with the bit a long way off bottom and tight hole conditions have been experienced, then consider bullheading.

d) If well is flowing and is shut in and the gas is percolating and no problems are anticipated in stripping back to bottom, then consider volumetric stripping to get bit to bottom. Circulate influx out using first circulation of Driller's Method.

Note: A swabbed kick well can be most effectively killed with bit on bottom. So every effort must be made to get bit safely back on bottom.

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2.42.2 Well details

Figure 2.45

108

Bit size = 8 1/2" TVD = 12,000' TVD shoe = 9,000' Bit Depth = 11,000' DP Cap = 0.02776 bbl/ft DP Disp = 0.0075 bbl/ft DP/OH cap = 0.0459 bbl/ft Mud wt = 12.0 ppg Pit Gain = 15.0 bbls Influx Grad= 0.12 psi/ft

Bit depth at original shut in = 11,000'

15 bbls Figure 5.14

560 Shut in pressures and influx size with bit on bottom.

24.5 bbls

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2.42.3 Shut in procedure for a swabbed kick while tripping

Fast shut-in

1. Stab safety valve (kelly cock). 2. Close safety valve. 3. Open HCR fail safe valves. 4. Close annular. 5. Read casing pressure and if possible read drill pipe pressure. 6. Stab inside BOP (Gray valve).

7. Open safety valve. 8. Do stripping calculations, prepare stripping sheet. 9. Reduce annular pressure and commence stripping drill pipe.

Note: The above procedure (steps 1 through 5) assumes there is no float or non-return valve in the drill string.

2.42.4 For calculating safety margins and working margins use the universal volumetric well control equation below:-

P. choke =Pann + Ps + Pw

Pa = Initial SICP

Ps = 100 psi + *Increase in casing pressure with influx around drill collars ∆ * P.csg = Mud grad - Influx grad x (H2 - H1)

Pw = Working margin (Recommended working margin = 50 - 100 psi) 15 15 H1 = ÐÐÐÐ = 214' H2 = ÐÐÐÐÐ = 514' 0.07 0.0292

Pa = 108 psi

Ps = 100 + (0.624 - 0.12) x (514 - 214) = 100 + 0.504 x 300 = 251 psi

Pw = 50 psi

P. choke = 108 + 251 + 50 = 410 psi

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Theoretical bleed off in bbl/ft while stripping = DP displacement + DP cap = 0.01776 + 0.0075 = 0.02526 bbl/ft Ann Cap Excess bleed off for each 50 psi working margin = P x ÐÐÐÐÐÐÐÐÐÐ w ( Mud grad ) 0.0292 = 50 x ––––––– ( 0.0624 ) = 2.3 bbls

Note: If the gas is not migrating while stripping, only theoretical bleed off will be seen in strip tank. If gas is migrating then any excess bleed off is due to migration. When excess bleed off is ± 2.3 bbls, then build in another 50 psi working pressure. Refer to Volumetric Stripping chart (Fig. 5.15).

Figure 2.46

Average length ACCUMULATIVE VOLUMES ° P choke = 94' Theoretical Actual vol. Excess vol. No. Stands vol. bleed off bleed off bleed off

Step 1 108 Ð>410 1 1.00 1.20 0.20 After 50' pressure at 410 psi

410 2 3.37 4.53 1.16

410 3 5.74 7.86 2.12

After 15' stripped Step 2 460 4 7.74 10.72 2.98 pressure at 460 psi

460 5 10.11 14.05 3.94

460 6 12.48 17.38 4.90

After 15' stripped Step 3 510 7 14.48 20.18 5.70 pressure at 510 psi

510 8 16.85 23.51 6.66

510 9 19.22 26.84 7.62

After 15' stripped Step 4 560 10 21.59 30.07 8.48 pressure at 560 psi

560 11 23.96 33.41 9.45

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Step 1 Allow casing pressure to increase to calculated Pchoke pressure while stripping first stand, then hold casing pressure constant by bleed off at choke.

Note: The casing pressure may not rise straight away because the gas has to be compressed. It may take 2 - 3 stands before a pressure build up is seen.

Step 2, 3 & 4 With theoretical bleed already calculated, record actual bleed, when the difference between the actual and theoretical bleed is 2.3 bbls allow annulas pressure to increase by Pw (50 psi).

Figure 2.46

600 Step 4 500 Step 3 Step 2 400 Step 1

300 Pressure 200

100

0 1 2 3 4 5 6 7 8 9 10 11 12 Stands

2.42.5 With bit on bottom casing pressure reads 560 psi, gas influx has expanded by 9.45 bbls and if it was possible to read drill pipe pressure it would read zero with drill pipe full of mud. The influx should now be circulated out using auto choke.

Note: No kill mud will be required as this is a swabbed kick.

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2.43 EDITED EXTRACT FROM API RP53

PIPE STRIPPING ARRANGEMENTS - SURFACE INSTALLATIONS

PURPOSE

During operations on a drilling or producing well, a sequence of events may require tubing, casing, or drill pipe to be run or pulled while annular pressure is contained by blowout preventers; such practice is called “stripping”. Stripping is normally considered an emergency procedure to maintain well control; however, plans for certain drilling, completion, or well work operations may include stripping to eliminate the necessity of loading the well with fluid.

EQUIPMENT

Stripping techniques vary, and the equipment required depends upon the technique employed. Each stripping operation tends to be unique, requiring adaptation to the particular circumstances. Therefore, the equipment and the basic guidelines discussed herein are necessarily general in nature. Stripping requires surface equipment which simultaneously:

a. permits pipe to be pulled from or run into a well,

b. provides a means of containing and monitoring annular pressure, and

c. permits measured volumes of fluid to be bled from or pumped into the well.

Subsurface equipment is required to prevent pressure entry or flow into the pipe being stripped. This equipment should either be removable or designed so that its presence will not interfere with operations subsequent to stripping.

The well site supervisor and crew must have a thorough working knowledge of all well control principles and equipment employed for stripping. Equipment should be rigorously inspected, and, if practicable, operated prior to use.

For stripping operations, the primary surface equipment consists of blowout preventers, closing units, chokes, pumps, gauges, and trip tanks (or other accurate drilling fluid measuring equipment).

The number, type, and pressure rating of the blowout preventers required for stripping are based on anticipated or known surface pressure, the environment, and degree of protection desired. Often the blowout preventer stack installed for normal drilling is suitable for low pressure stripping if spaced so that tool joints or couplings can be progressively lowered or pulled through the stack, with at least one sealing element closed to contain well pressure.

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Annular preventers are most commonly employed for stripping because tool joints and some couplings can be moved through the preventer without opening or closing of the packing element. Wear of the packing element limits the sole use of this preventer if high annular pressure must be contained while stripping. To minimise wear the closing pressure should be reduced as much as possible and the element allowed to expand and contract (breathe) as tool joint pass through. Lubrication of the pipe with a mixture of oil and graphite or by permitting a small leakage of annular fluid will reduce wear on the packing element. A spare packing element should be at the well site during any stripping operation.

Ram type preventers or combinations of ram and annular preventers are employed when pressure and/or Configuration of the coupling could cause excessive wear if the annular preventer were used alone. Ram preventers must be opened to permit passage of tool joints or couplings. When stripping between preventers, provision should be made for pumping into and releasing fluid from the space between preventers. Pressure across the sealing element should be equalised prior to opening the preventer to reduce wear and to facilitate operation of the preventer. After equalising the pressure and opening the lower preventer a volume of drilling fluid equal to that displaced as the pipe is run into or pulled from the well should be, respectively, bled from or pumped into the space between the preventers.

Chokes are required to control the release of fluid while maintaining the desired annular pressure. Adjustable chokes which permit fast, precise control should be employed. Parallel chokes which permit isolation and repair of one choke while the other is active are desirable on lengthy stripping operations. Because of the severe service, spare parts or spare chokes should be on location. Fig. 10.A.1 illustrates an example choke installation on the standpipe suitable for stripping operations.

A pump truck or skid mounted pump is normally employed when stripping out. The relatively small volume of drilling fluid required to replace the capacity and displacement of each stand or joint of pipe may be accurately measured and pumped at a controlled rate with such equipment. Well fluid from below the preventer should not be used to equalise pressure across the stripping preventer.

A trip tank or other method of accurately measuring the drilling fluid bled off, leaked from, or pumped into the well within an accuracy of one-half barrel is required.

The lowermost ram should not be employed in the stripping operation. This ram should be reserved as a means of shutting in the well if other components of the blowout preventer stack fail. It should not be subjected to the wear and stress of the stripping process.

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2.44 REMOVAL OF GAS TRAPPED IN BOP’S

In order to displace a gas kick completely from the wellbore several circulations of the well might be needed. During this time some of the gas may have become trapped under closed rams in the BOP stack as shown in Fig 2.28. This has the potential to cause a serious problem if the gas is not removed in a controlled manner. If the rams were opened without removing the trapped gas, the gas would be released into the riser. As the gas migrated, it would expand rapidly and cause the riser to unload mud onto the rig floor.

The most thorough method of gas removal is to leave the well shut on the lower rams whilst displacing the choke and kill lines to water. By closing the kill line valves, pressure can be bled off up the choke line and “U-tubed” up the choke line by opening the pipe rams. This sequence is shown in Fig 2.29 and 2.30.

The surface diverter should be closed during the operations so that any residual gas from the riser can be safely dealt with. Once the riser has been displaced to kill weight mud the lower rams can be opened and the well flow-checked. Calculate any new riser margin or trip margin that might have to be added to the mud weight.

Figure 2.48 TRAPPED GAS IN BOP STACK

KILL CHOKE LINE LINE UPPER ANNULAR

LOWER ANNULAR BLIND/SHEAR RAMS

PIPE RAMS

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Figure 2.49 REMOVING TRAPPED GAS FROM BOP STACK

KILL CHOKE KILL CHOKE LINE LINE LINE LINE

Isolate the well from the BOP stack Slowly displace kill line to salt water. by closing the lower pipe rams. As the kill line is displaced to water, increase the kill line circulating pressure by an amount equal to the difference in hydrostatic pressure between kill mud and salt water at stack depth. This will maintain the gas at original pressure with clean salt KILL CHOKE LINE LINE water returns at surface stop pumping close choke.

Displace riser to kill mud using upper kill line.

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Figure 2.50 REMOVING TRAPPED GAS FROM BOP STACK

KILL CHOKE KILL CHOKE LINE LINE LINE LINE

Close the subsea kill line valves. Close the diverter and line up to fill the riser.

At this point the pressure is still Open the pipe rams and allow the riser to trapped in the gas bubble. U-tube taking returns up the choke line.

Bleed off pressure through the choke Fill the riser as necessary. to allow the gas to displace water from the choke line. Open the lower pipe rams and diverter element. The gas bubble should now be at close to atmospheric pressure. Flow check the well.

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Bubble Expansion Example:- Choke Line Length = 1000' Choke Line Volume = 8 bbls Kill Mud = 15 ppg Sea Water Grad = 0.445

P1 V1 780 X 3 V2 = ÐÐÐÐ = ÐÐÐÐÐÐÐ = 5.3 bbls P2 445

P1 = 15 x 1000 x 0.052 = 780 psi

V1 = 3 bbls

P2 = 0.445 x 1000 = 445 psi Example: This example gives some idea of the large volumes of gas that could be released to atmosphere if the annular is opened without sweeping the stack. Lets say that we are drilling in 1800' of water and the well has been killed to surface, via the choke line with 16.5 ppg mud. The hydrostatic head compressing the gas under the bag would be (1800 x 16.5 x .052) + 14.7 = 1559 psi If the volume of gas trapped below the BOP = 5.46 bbls then:

P1 x V1 1559 x 5.46 ÐÐÐÐÐÐ = V2 ÐÐÐÐÐÐÐÐÐÐ = 579 bbls P2 14.7 573 bbls of gas released at surface.

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WORKSHOP 5

The following questions 1-5 refer to the first stage of the Drillers Method.

1. A well was shut-in on a kick that occurred whilst drilling. During the first circulation of the Drillers Method, the choke operator maintains a constant drill pipe pressure at a constant pump speed.

Will bottom hole pressure:

a. Be increasing b. Be decreasing c. Being kept constant

2 . Referring to the question above, the choke operator has not taken into account the large volume of the surface lines, i.e. from the pump to the rig floor. This will result in:

a. An increase in bottom hole pressure b. A reduction in bottom hole pressure c. No change to bottom hole pressure

3. Referring to question 1 above if the kick was brine, (with no gas) Casing or Choke pressure will be at its highest :

a. When pressures have stabilised at shut-in b. When the kick is going into the shoe c. When the kick is nearing the surface

4. What happens to pressure at the shoe as the brine kick is being moved into the casing shoe?:

a. Pressure at the shoe will be constant b. Pressure at the shoe will reduce c. Pressure at the shoe will increase

5. If the kick is gas rather than brine and as it is being circulated into the casing shoe will:

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6. During the second stage of the Drillers Method, assuming all of the kick was removed during the first stage, if when starting the operation the choke operator maintained a constant initial circulating pressure in the drill-pipe until kill mud reached the bit. Would bottom hole pressure?

a. Be increased b. Have reduced c. Be constant

7. If at the start of the second stage of the Drillers Method, the choke operator maintained a constant Casing or Choke pressure until kill mud was at surface. How would this action affect B.H.P. ?

a. B.H.P. would be seeing an increase from the moment the pump reached kill speed until kill mud was at surface. b. B.H.P. would have increased until kill mud was at the bit, then B.H.P. would have remained constant as kill mud displaced the annulus. c. B.H.P. would have remained constant until kill mud at bit then B.H.P. would be increased as kill mud displaced the annulus.

8. If total losses occur when drilling and with the bit off bottom and the mud pumps off. Sea-water is then pumped to the annulus. Assume the volume of water it took to fill the well to the top was equivalent to 500' of annulus. What is the resultant reduction in bottom hole pressure due to this action ?

Mud weight = 10 ppg Sea-water = 8.7 ppg

a. 260 psi b. 226 psi c. 34 psi

9. The well flows with the bit 10 stands off bottom. Shut-in casing pressure reads 200 psi. If the influx is below the bit:

a. Shut-in drill pipe pressure will be higher than 200 psi b. Shut-in drill pipe pressure will be lower than 200 psi c. Shut-in drill pipe pressure should be 200 psi

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10. A well is shut-in on a kick whilst drilling and stabilised shut-in pressures have been established. Due to a delay in starting the kill operation surface pressures have increased by 100 psi as the influx is migrating. The safest action would be:

a. To bleed mud off using the choke until casing pressure reduces by 100 psi. Then keep it constant. b. Bleed mud off keeping a constant drill pipe pressure. c. Leave it until the problem causing the delay has been resolved then increase the kill mud weight by .5 ppg.

11. Referring to Q10. If surface pressure had increased by 200 psi due to migration of the influx. How far has the influx migrated if the mud weight is 10 ppg and the influx density is assumed to be .12 psi/ft ?

Answer:

12. When comparing the Drillers and Wait & Weight Kill Methods with regards to the pressures that will be exerted on the exposed foundations immediately below the casing shoe: Select 2 answers from the following statements.

a. The Drillers Method will always give a higher shoe pressure. b. The Wait & Weight Method will always give a lower shoe pressure. c. The Drillers Method will give the lowest shoe pressure when the open hole volume is smaller than the string volume. d. The Wait & Weight Method will give the lowest shoe pressure when the open hole volume is greater than the string volume. e. There will be no great difference in shoe pressures whether the Drillers or Wait/Weight Method is used if the open hole volume is less than the string volume.

13. If a well is shut-in on a gas kick and the gas is not allowed to expand as it migrates up the well-bore. What happens ?

a. To B.H.P.

(i) It increases (ii)It decreases (iii) Stays more or less the same

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b. To surface pressures

(i) They increase (ii)They stay more or less the same (iii) Only casing pressure will increase

c. To pressures at the shoe

(i) Will only increase if the influx is below the shoe (ii)Will continue to increase (iii) Will remain fairly constant

d. Pressures in the gas influx. Assuming no temperature change.

(i) Pressure in the gas will continue to increase (ii)Pressure in the gas will keep reducing as it migrates (iii) There should be no great change to the pressures in the gas influx

14. A kick is being circulated out using the Wait & Weight Kill Method. Shortly after pumping kill mud to the bit, final circulating pressure has suddenly increased by 200 psi. The pump speed has been kept constant at kill speed and there was no change noted on the choke gauge. What is the problem ?

a. The choke has plugged b. A bit nozzle has plugged c. A pack-off has occurred around the bit

15. If the choke operator opened the choke and reduced drill pipe pressure back to the calculated final circulating pressure in the problem as described in Question 14. The result would be:

a. B.H.P. would be reduced b. B.H.P. would be increased c. no change to B.H.P

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WORKSHOP 5 - Answers

1. c. Being kept constant

Maintain ICP with present mud weight until bottoms-up (1st circ. driller's method).

2 . c. No change to bottom hole pressure

Kill mud is not being circulated until the 2nd circulation.

3. a. When pressures have stabilised at shut-in

When the height of the kick is at its highest: ie around the drill collars.

4. b. Pressure at the shoe will reduce

Kick fluid is being replaced with a heavier "mud", reducing pressure at the shoe.

5. b. Pressure at the shoe decrease

Kick fluid is being replaced with a heavier "mud", reducing pressure at the shoe.

6. a. Be increased

Casing pressure should be constant while DP pressure should reduce from an ICP to a FCP.

7. c. B.H.P. would have remained constant until kill mud at bit then B.H.P. would be increased as kill mud displaced the annulus.

Casing pressure should reduce as kill mud displaces annulus.

8. c. 34 psi

500 x (10 - 8.7) x .052 = 33.8 psi

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9. c. Shut-in drill pipe pressure should be 200 psi

10. b. Bleed mud off keeping a constant drill pipe pressure.

11. Answer: 385'

200 psi = 385' .52 psift

12. d. The Wait & Weight Method will give the lowest shoe pressure when the open hole volume is greater than the string volume. e. There will be no great difference in shoe pressures whether the Drillers or Wait/Weight Method is used if the open hole volume is less than the string volume.

13. a. (i) It increases

b. (i) They increase

c. (ii)Will continue to increase

d. (iii) There should be no great change to the pressures in the gas influx

14. b. A bit nozzle has plugged

15. a. B.H.P. would be reduced

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2.45 ORGANISING AND DIRECTING WELL CONTROL OPERATIONS

During well-control operations, it is imperative that operators and contractors carefully organise rig personnel so that everyone knows where to be and what to do. Station and duty assignments and knowledge of the operator’s and contractor’s well-control policies and procedures are essential parts of successful kick control and blowout prevention. During well-control drills, the effectiveness of the crew’s organization should be a part of the drill. In addition, general well-control procedures should be posted as part of emergency safety station bills for the rig. In some cases, station bills may be required by a regulatory body.

2.45.1 ORGANISING CONSIDERATIONS

When organizing the crew for well control, the following points should be raised by supervisory personnel on the rig: . 1. Who is directly responsible for well-control operations, the contractor or the operator?

2. If the toolpusher or operator’s representative is designated to operate the choke, who is responsible for duties that the toolpusher or representative would normally perform if not operating the choke?

3. Have the rig supervisors participated in all well-control drills, and do they understand who is responsible for various actions?

4. How are communications with the office to be handled?

5. Does every person on the crew thoroughly understand where to be and what to do?

The crew and the rig are the responsibility of the toolpusher, but he or she must work closely with the operator to ensure that the crew has a clear understanding of applicable well-control procedures and policies.

The drilling crew’s reaction time to a kick plays a major role in getting the well properly shut in to prevent a blowout; however, the crew must also give proper attention to equipment. Blowout prevention equipment is primarily intended for emergencies and, as such, it is useful only if it is adequate for the pressures involved, only if it is in good operating condition, and only if it is used correctly. Ensuring that the BOP system is in good condition and adequate for its job involves the operating company, the drilling contractor, and the drilling crews. If just one person fails to do his or her part, the good work of everyone else (for example, those who designed and installed the mud program, the casing, the wellhead equipment, and the blowout preventers) may be cancelled out.

The company representative, the toolpusher, and the drillers are key persons in performing well-

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control duties; however, every person on the crew should know how to operate the basic preventer equipment and be alert for the signs of a well kick. Trial operation of the preventers and thorough pressure testing ensure that the equipment is in good operating condition and ready for use.

2.45.2 DRILLS

Blowouts can be avoided if people on the job are familiar with the warnings of a kick and understand control procedures. Time is important in killing any well; therefore, early recognition of the signs and prompt and proper action for control are essential. A vital part of any crew’s training is practice in closing the preventers under simulated kick conditions. Practice drills should be initiated without warning and at unexpected times. The drilling crew should be trained by means of detailed instruction and repeated drills to ensure that it can detect well flow quickly and can close in the well promptly. A properly trained floor crew should be expected to handle a kick in such a manner that they do not make the situation worse before the toolpusher or company representative can take charge.

Many types of drills may be required by different operators, depending on whether the rig is on land or offshore, whether a surface or subsea stack is in use, or other factors. Examples of different drills are a choke drill, hang-off drill, stripping drill, and pit drills.

2.45.2.1 Pit Drills

One of the most important drills is probably the pit drill, because it is a basic procedure that all crew members must know and understand. The primary objectives of a pit drill are to train rig personnel in the importance of constantly being aware of mud level in the pits and of being able to react quickly to shut the well in at the first indication of a kick.

Pit drills should be conducted both when the bit is on bottom and drilling and when a trip is being made. To conduct a pit drill when the bit is on bottom and drilling, the following set of steps has been used:

1. The toolpusher or company representative raises the pit-level sensor to simulate a rise in pit level.

2. Upon recognition of the simulated kick, the driller sounds the alarm.

3. The driller then picks up the kelly above the rotary table, being sure that no tool joints are in the ram BOPs.

4. The driller shuts down the pump.

5. The driller opens the remote-controlled choke line (HCR) valve.

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6. The driller closes the annular preventer.

7. The driller closes the remote choke.

8. The driller records the time (as measured from the time the simulated pit gain was recognised) required to shut the well in, in the driller’s report.

When a trip is being made, the following pit drill has been used:

1. The toolpusher or company representative manipulates the flow sensor or trip tank level indicator to simulate a kick.

2. Upon recognition of the simulated kick, the driller sounds the alarm.

3. Driller and crew set the top tool joint on the slips.

4. The rotary helpers (floorhands) stab a fully open safety valve in the drill pipe.

5. The driller opens the remote-controlled chokeline (HCR) valve.

6. The rotary helpers make up and close the drill pipe safety valve.

7. The driller closes the annular preventer.

8. The driller records the time since the simulation started to conduct the steps in the driller’s report.

2.45.2.2 H2S Drills

Since Hydrogen Sulphide (H2S) can be present in a kick, and since it is a highly toxic gas, crew training in H2S procedures is necessary in areas where H2S is expected. Crew training involves awareness of the danger of the gas, familiarization with contingency plans, use of H2S detection equipment, use and maintenance of breathing equipment, and several other factors.

Once the crew has been trained, drills for H2S emergencies should be carried out on a frequent basis. Some companies require them at least once a week, more often if conditions warrant. Many companies also require that records be kept on the date of drills and the personnel who participated. The following suggested actions may be taken.

1. Upon hearing or seeing an H2S alarm, all personnel don air-breathing equipment. Assigned individuals check the breathing-air supply valves for the piped-air system. The driller takes the necessary precautions as indicated by the company’s contingency plan.

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2. Bug blowers are made operational and all open flames are extinguished. H2S Drills

3. The buddy system is implemented and all crew members act on directions from the supervisor.

4. Nonessential personnel on the location don breathing equipment and move off location.

5.Gates to the location entrance are closed and patrolled, and appropriate H2S warning signs are displayed.

After the drill, the H2S contingency plan regarding the notification of local authorities and the alerting of residents near the location of the possible need to evacuate the area should be discussed. More details about planning for drilling in H2S zones and guidelines for H2S guidelines for offshore and land locations can be found in API RP 49

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3.1 GENERAL 3-1

3.2 BARRIER THEORY 3-2

3.2.1 Mechanical Barriers 3-3 3.2.2 Hydrostatic Barriers 3-4 3.2.3 Primary Pressure Control 3-5 3.2.4 Secondary Pressure Control 3-5 3.2.5 Tertiary Pressure Control 3-5

3.3 WORKOVER WELL CONTROL 3-6

3.3.1 Wireline 3-6 3.3.2 Coiled Tubing 3-8 3.3.3 Snubbing 3-9 RILLIN N D G S EE CH D O R O E L B S A •

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3. WELL CONTROL METHODS

3.1 GENERAL

This section illustrates the various well control methods and practices employed on all the various well servicing methods and includes a section to explain barrier theory.

The most significance between the various types of well service methods is whether they are live well or dead well interventions as this impacts specifically on the equipment and methods of well control employed. Dead well interventions, are classified as workovers and well control methods for these are covered in the drilling test. The methods are addressed in this course are those used specifically in live well interventions.

There is a distinct difference between the terminology used between well control used in rig workover operations and that in live well interventions. Workover well control uses a combination of barriers and procedures in a systematic method to contain pressure downhole whereas live well interventions use a system of barriers to contain pressure at surface. Barrier theory and these systems are described in the following sections.

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3.2 BARRIER THEORY

Definition: A Barrier is any device, fluid or substance that prevents the flow of well bore fluids.

There are two types of barriers:

• Mechanical. • Hydrostatic.

A rule common to well intervention activities worldwide regarding pressure control is that a minimum of two independent and tested barriers shall be available at all times. In any circumstance where either of the barriers has failed, or there are indications that it is likely to fail, immediate action must be taken to re-instate or supplement that barrier and returning the well to double barrier protection again.

The ‘primary barrier’ is the term used to described the first line system of pressure containment and ‘secondary barrier’ the next line of defence. Nowadays, it is common, especially of high pressure wells, to install a third line of defence or a ‘tertiary’ barrier.

The particular status of the well will have different barriers in place for given operations and well circumstances. For instance, the completion provides barriers in the form of individual Xmas tree valves and a sub-surface safety valve, however, when running coiled tubing, these cannot be closed and therefore are not available barriers until the BHA is above them.

The function of well control in well interventions, is the arrangement of the barriers into groups and their systematic operation to provide competent well control. As stated earlier, these are conveniently arranged into three main categories of pressure control, namely:

• Primary. • Secondary. • Tertiary.

Each of these consist of at least one, or a combination of mechanical barriers described below.

NOTE: These categories may not be the terms used in some areas of the world, especially where the common language is not English.

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3.2.1 Mechanical Barriers

Mechanical barriers can be either closed barrier systems such as a wireline lubricator system complete with a stuffing box, i.e. the complete surface pressure envelope or closeable barrier systems which are held open to allow well entry but available and ready to be closed at any time on demand. Various types of closed and closeable barriers are listed below.

Types of closed barriers typically are:

• Wireline stuffing box (or grease control head)/lubricator/riser pressure envelopes. • Coiled Tubing stripper/riser pressure envelops. • Snubbing strippers (or annular preventers)/riser pressure envelopes. • Coiled tubing check valves. • Snubbing work string check valves.(Back pressure valves)

Types of closeable barriers are:

• BOP rams. • Xmas tree valves. • Subsurface safety valves. * • Shear/seal valves/BOPs. • Annular preventers.

Additional barriers can be installed downhole, either as a back up to a failed primary or secondary barrier or to allow removal of the Xmas tree for repair or for installation of workover BOPs. These barriers may be:

• Wireline plugs. • Bridge plugs. • Cement plugs. • Ice plugs. • Overbalance hydrostatic fluid.

* Sub-surface safety valves are acceptable as barriers during normal operations if they are tested in accordance with the test criteria given below, however, to be used for well plugging, i.e. for Xmas tree removal before a rig operation, it must be leaktight.

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Common Barrier Definitions

Some other commonly used barrier definitions are given below:

Leaktight No observable flow or pressure change. Failsafe A device which returns to the closed position on loss of the control function. Fail to Test Failure of a barrier to meet test criteria. Fail to Close Inability of a device to move to the closed position. Positive Plug Holds pressure from above and below.

Barrier Integrity

Mechanical barriers must be tested, preferably from the direction of anticipated flow. Tests on closed type barriers should be leaktight. The leakage rate on closeable barriers such as Xmas tree valves etc. should be the API leakage criteria: 400 cc/min or 900 scf/hr with the exception of sub-surface safety valves used in well plugging (refer to note above in list of closeable barriers). Each operator should develop procedures for testing of Xmas tree and sub-surface safety valves to meet this criteria. This is problematic in subsea completions where there are long undulating production flowlines and riser systems which makes it difficult to calculate leakage rates for various well GORs and downstream volumes; however to help, formulae are provided in API 14A.

3.2.2 Hydrostatic Barriers

Hydrostatic barriers are provided by liquids. A liquid is only a barrier when the hydrostatic head of pressure is greater than the formation pore pressure at the top of the producing interval and when the fluid level and condition (i.e. weight) can be monitored. The specific gravity of the fluid to be used as a barrier may be difficult to predict without good formation pressure data. The hydrostatic overbalance provided should be circa 200 psi. but may be adjusted to counter for high losses in wells which cannot support this differential, especially troublesome when using solids free brines.

A fluid can only be confirmed as a barrier after diligent monitoring of the well over a specified period of time, to ensure that any thermal expansion contraction effects have ceased.

Typical fluid barriers are:

• Drilling muds. • Completion brines. • Seawater. • Fresh water.

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3.2.3 Primary Pressure Control

Primary pressure control is the system which provides the first line of defence from an uncontrolled well flow. In each of the well servicing intervention methods it is provided by different mechanical systems. On a wireline rig up it is simply the stuffing box and lubricator envelop, however on a C/T or snubbing rig up, it consists of the riser pressure envelop and internal workstring check valves.

3.2.4 Secondary Pressure Control

Secondary pressure control is the system which provides the second line of defence in the event that primary well control cannot be properly maintained. This is generally provided by the BOP system .

If pumping facilities are available, although undesirable, a hydostatic fluid barrier can be placed in the wellbore as a secondary barrier when either the primary or original secondary barrier has failed and there is no tertiary barrier.

3.2.5 Tertiary Pressure Control

Tertiary pressure control is not always available but may be an additional third and final line of defence in the event that secondary well control cannot be properly maintained. This is usually a shear seal valve or BOP system. This may be an integral part of the Xmas tree (e.g. a wireline or coiled tubing cutting actuator), or installed directly on top of the tree immediately before operations commence.

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3.3 WORKOVER WELL CONTROL

The method of pressure control on live wells with wireline, coiled tubing or snubbing services methods, is provided by primary, secondary and occasionally tertiary barrier systems as outlined above. In live well interventions, it is not generally necessary to provide kill facilities unless there is higher risk due extreme high pressure or the presence of high concentrations of H2S. In many applications, pumping services may be on hand for other operations such as well clean-outs and stimulations and may double as a kill facility provided there is a suitable supply of kill fluid and a handling system.

3.3.1 Wireline

Slickline

Wireline relies entirely on the lubricator system to provide primary pressure control. Secondary pressure control is provided by the wireline BOPs and tertiary well control may be available in the form of another wireline cutting valve, either contained in the Xmas tree or as a shear/ seal valve or BOP installed on top of the Xmas tree.

The various pressure control barrier systems are:

Primary

• Stuffing box and lubricator system. • Check valve if the wireline breaks and is ejected from the lubricator. • Xmas tree valves when installing into,or removing tools from, the lubricator

Secondary

• Wireline BOP rams/valve which can close and seal around the wire. • Xmas tree upper master, if the wire is broken and ejected. • SCSSV, if wire is above it.

The BOP rams can be used for stripping wire out of a well but only when absolutely necessary. Stripping through the BOPs is only carried out to find the free end of the wire for wireline recovery.

Tertiary

• Wireline cutting valve/BOP. • Xmas tree valve, if absolutely necessary.

In the event of primary and secondary failure with no tertiary barriers available, a Xmas tree valve can be used to sever the wire, as they can easily cut wireline although the valve seat may be damaged. The valve used should be the upper master for two reasons:

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• If the lower master is used and damaged, it requires the well to be plugged before repair. • If the swab is used and damaged the well cannot be used for production as there is no longer double barrier protection from the production fluid.

Braided Line

The system for braided line is very similar to slickline. Pressure control is provided by:

Primary

• Grease seal and lubricator system. • Check valve if the wire breaks and is ejected from the lubricator. • Xmas tree valves when installing into,or removing tools from, the riser.

Secondary

Two wireline BOP rams (in conjunction with a grease pump) which can close and seal around the wire.

• Xmas tree upper master, if the wire is broken and ejected. • SCSSV, if wire is above it.

Tertiary

• Wireline cutting valve. • Shear/seal valve or BOP installed directly onto the top of the Xmas tree.

In general, tertiary barriers are rarely used unless a heavy duty wireline operation is being carried out.

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3.3.2 Coiled Tubing

Coiled tubing well control equipment is similar to wireline but also includes internal workstring barrier systems.

External pressure control is provided by:

Primary

• Stripper. • Xmas tree valves when installing into,or removing tools from, the riser.

Secondary

• BOPs . • SCSSV, if the tubing is not straddling it.

Tertiary

• Shear/seal BOP mounted directly on top of the Xmas tree.

Internal pressure control is provided by:

Primary

• Two check valves in the BHA.

Secondary

• BOPs .

Tertiary

• Shear/seal BOP mounted directly on top of the Xmas tree.

In the North Sea Region, it has almost become obligatory to use shear/seal BOPs due to a number of instances where the up-to-then commonly used primary and secondary barrier systems failed to deal with some well control occurrences.

NOTE: Some well interventions are conducted without BHA check valves as it is necessary to reverse circulate. In these cases the primary inside well control is the BOP shear rams and a shear/seal BOP becomes the secondary.

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3.3.3 Snubbing

There are two types of snubbing BOP set-ups, one for running upset pipe and one for non- upset or tapered upset tubing connections (i.e. not square shouldered); Pressure control is provided by:

External pressure control is provided by:

Primary

• Stripper BOPs, stripper rubber or annular preventer.

Secondary

• Two safety (pipe) BOP rams. • SCSSV, if pipe is above it.

Tertiary

• BOP shear and blind rams or a shear/seal valve or BOP mounted directly on top of the Xmas tree.

Internal pressure control is provided by:

Primary

• Two check valves in the BHA.

Secondary

• Wireline plug installed by wireline in the BHA or an additional third check valve.

Tertiary

• A shear/seal valve or BOP mounted directly on top of the Xmas tree. • Kill pump facility to install a barite or cement plug.

4.1 GENERAL 4-1

4.2 TUBING BLOCKAGE 4-2

4.3 CONTROL OF EXCESSIVE WATER OR GAS PRODUCTION 4-3

4.3.1 Control Of Water Production 4-3 4.3.2 Control Of Gas Production 4-6

4.4 MECHANICAL FAILURE 4-7

4.5 STIMULATION OF LOW PRODUCTIVITY WELLS 4-8

4.6 PARTIALLY DEPLETED RESERVOIRS 4-9

4.7 SAND CONTROL 4-9

4.8 WORKOVER WELL CONTROL PLANNING 4-10

4.8.1 Ingredients Of Good Planning 4-10 4.8.2 Workover Programme 4-10 4.8.3 Well Control Problems During Workover 4-12 4.8.4 Troubleshooting Well Problems 4-13 RILLIN N D G S EE CH D O R O E L B S A •

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4. REASONS FOR WELL INTERVENTIONS

4.1 GENERAL

Many servicing operations can be conducted by rig workovers, however live well intervention is preferred as killing a well risks fluid invasion of the formation thereby causing potential formation damage.

The primary objective of well intervention operations is the management of wells to provide optimum well production. This is achieved by conducting live well remedial operations, obtaining downhole reservoir data or preparation of the well for a dead well workover (if a problem cannot be solved by live well servicing). Occasionally, gathering of downhole reservoir data is a secondary objective only opportunistically taken when a an intervention is planned for other reasons. This data are usually to provide well information on lateral and vertical movement, current location of oil, water and gas and identifying the producing the zones.

There are many reasons for remedial live well intervention well operations, most notably to:

• Remove obstructions to flow such as tubing blockage with sand, wax or asphalt. • Eliminate excessive water or gas production. • Repair mechanical failure. • Improve production through well stimulation, re-completions or multiple completions on low productivity wells. • Enhance production by conducting well stimulation such as hydraulic fractures on high productivity wells. • Increase production by bringing other additional potentially productive zones on stream. • Maintain control of oil, water and gas in various zones or layers in stratified reservoirs. • Side-tracking passed severely damaged formations. • Increase production by drilling laterals.

Before a well is entered, a complete analysis must be made of the current well status, the reasons for work carefully established, the associated risks identified and appropriate contingencies measures planned in the event of operational failure.

All oil and gas wells will encounter some impairment to production during it’s producing life and well service operations will need to be planned to rectify or improve the conditions within the well. Therefore, common servicing operations such as cleaning out fill, re-perforating, chemical treating, acidising, fracturing or a combination of these techniques are routinely carried out to enhance production.

A description of these main well problems are discussed in the following sections.

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4.2 TUBING BLOCKAGE

Tubing blockage is generally caused by sand, wax and asphalt production or scale build up. It can usually be remedied with a well clean out operation. Some of these can be prevented, or at least alleviated, by treating the formation with regular chemical inhibition treatments, pumped into the formation from surface.

With regard to injection wells severe formation scaling can occur if injection water is not treated so that it is compatible with the formation fluids.

Tubing blockage is one of the most commonly experienced production problems and which is remedied by clean out operations conducted normally by snubbing or coiled tubing (C/T) intervention although dead well workover may also be considered. The use of snubbing or C/ T is more desirable as they can be carried out without killing the well. C/T is preferred as it is relatively low cost, is easily organised and very effective when used in conjunction with modern jetting or clean-out tools (especially with the larger C/T sizes which allow higher pump rates). In most circumstances, flowing the well helps with the efficiency of the clean out.

Wax build-up can be removed by an operation termed ‘Hot Oiling’. This is a simple treatment consisting of pumping heated oil from surface at a temperature sufficiently high enough to melt the wax. This can also be done by circulation of the hot oil through C/T which is preferred as it prevents any fluids being pumped to the formation. Asphalt can also be removed similarly by pumping solvents rather than hot oil.

Some well clean outs may be accomplished with wireline methods using tools such as gauge cutters which can remove wax from tubing walls and bailing to remove sand or other blockages, provided the amount to be removed is relatively small. It is often easier to use wireline, even if it may be less efficient, as many platforms are already equipped with permanent wireline units or they can be easily mobilised. C/T takes longer to rig up and deploy which are considerations which need to be taken into account during the evaluation process. However in general, most operations can more efficiently be accomplished using C/T and it is sometimes the only option if the well is high angle or horizontal. The general limit for wireline operations is circa 70˚ from vertical but this may vary according to well build up angles and the types of tools to be run.

Snubbing with a Hydraulic Workover unit (HWO) may also be considered but it is generally not utilised as it is slow and costly in comparison with C/T. However, in some circumstances, e.g. where there is not enough space for a C/T injector or the reel due to their size, Hydraulic Workover may be the only alternative.

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4.3 CONTROL OF EXCESSIVE WATER OR GAS PRODUCTION

As an oil zone is depleted, the gas/oil or water/oil interfaces will move vertically in the formation. This may result in increasing undesired water or gas production.

Excessive gas production leads to a premature decrease in reservoir pressure, hence reducing the energy available to move the oil into the well bore and ultimately reduces the quantity of gas necessary to lift the oil to surface.

When excessive water is produced, it leads to reduced oil production due to; the increased hydrostatic head in the tubing acting against the formation pressure, increased risk of corrosion and production problems handling and disposing of the water. It may also cause sand production which can lead to erosion of completion and production equipment.

These problems can be controlled by the appropriate well intervention measures, as described below.

4.3.1 Control Of Water Production

There are different reasons for water problems. Firstly, fingering of water in stratified or layered reservoirs where the water production is essentially from one zone. Secondly, advancing water level due to oil depletion. Thirdly; water coning in reservoirs where there is appreciable vertical permeability; See Figure 4.1, Figure 4.2 and Figure 4.3. Once a rock becomes more saturated with water, the relatively permeability to water increases in regard to that of the other fluids. This leads to a self aggravating cycle of increasing water flow and increasing relative permeability to water.

Prior to running or planning operations for water control, production logs must be run which will identify the zones from which water is being produced. Once identified, this can usually be controlled by a number of differing methods depending upon the specific well design and well conditions:

• Sand placement in the sump. • Setting a through tubing bridge plug. • Cement squeezing. • Chemical treatment to produce a gel block.

Sand placement in the sump may solve the problem in circumstances where there is a sufficient height of sand as the vertical permeability of a column of sand is high and blocks water flow.

Cement squeezes have probably been the commonest means of plugging off water producing zones in the past utilising workover methods requiring killing of the well, pulling the completion, cementing and re-completing.

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High production liner or monobore type completions have been specifically designed for through tubing operations enabling water control by simply installing a through tubing bridge plug by wireline or C/T after which cement can be squeezed, if necessary.

Cement squeezing by C/T below regular packer style completions using modern through tubing tooling, is now also common practice.

Water blocking by creating a gel in the formation is a much more recent development. This entails pumping chemicals to the formation which react after a pre-determined period of time to form a gel. The viscosity of the gel is so high that it will not flow through the formation pores, blocking the flow of water trapped behind the gel. This method is usually expensive due to high chemical costs.

Plugging back of water producing zones may on occasions require the well to be re-completed if the packer has to be moved or if shallower zones need to be perforated and brought on stream.

Well Bore

Low Permeability

High Permeability

Water

Intermediate Permeability

Low Permeability

Figure 4.1 - Water Fingering Due to Heterogeneities

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Initial Conditions

Higher Oil/Water Contact Later In Production

Water Cut Becomes Severe

Figure 4.2 - Advancing Oil/Water Contact

Producing Oil/Water Contact Resulting Oil From Coning

Original Oil/Water Contact

Water

Figure 4.3 - Water Production by Coning

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4.3.2 Control Of Gas Production

The most common reason for excessive gas production is the growth of the gas cap as oil is produced; See Figure 4.4. A gas/oil contact will gradually move downwards causing an increase in the production of gas.

The common method of remedying excessive gas coning is to squeeze the gas producing zone and deepen the well by re-perforating (converse to water coning). An alternative, is to conduct a workover where the well is plugged back and side-tracked with the new hole drilled horizontally through the lower part of the reservoir avoiding the gas cap.

In a layered reservoir, gas producing zones can also usually be effectively squeezed off with cement. Again, most cement squeezes can be accomplished with C/T methods using through- tubing tools.

Initial Conditions

Gas Cap Is Growing

High GOR Is Produced

Figure 4.4 - Increasing Gas Cap During Oil Production

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4.4 MECHANICAL FAILURE

Well service operations to repair mechanical completion failures are still relatively common in old wells, however in new wells less servicing is required due to the increasing reliability of modern completion equipment.

In the past, one of the most common reasons for working over a well was to replace downhole safety valves which had failed. For this reason, engineers were inclined to install wireline retrievable valves as they could easily be replaced using live well interventions by wireline methods, hence avoiding the need to pull tubing. Nowadays, this is no longer the case as the reliability of tubing retrievable valves has increased substantially where it is now the most commonly used valve.

Probably the most common reason for remedial mechanical operations today is tubing failure due to erosion or corrosion.

Some completion failures can be repaired by wireline or C/T methods but, in some circumstances, a full workover programme to pull the tubing is necessary. Typical failures are:

• Downhole safety valve mechanical failure or leak. • Downhole safety valve leak. • Casing, packer or tubing leak. • Casing collapse. • Tubing collapse. • Cement failure. • Gas lift failure or inefficiency. • ESP or hydraulic pump failure. • Recover fish unable to be recovered by other methods.

A full workover programme usually entails the placement of an overbalance kill fluid against the formation unless it can be isolated using a plug, e.g. a W/L plug in a permanent packer tailpipe or setting of a through tubing plug in the casing above the producing zone(s).

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4.5 STIMULATION OF LOW PRODUCTIVITY WELLS

There are many reasons why a well may have low productivity, for instance:

• Formation damage. • Low permeability. • Pressure depletion. • Liquid hold up in a gas well. • Gas slip in an oil well. • Excessive water or gas production; Refer to Section 4.3. • Sand or other fill or debris; Refer to Section 4.2. • Mechanical failure; Refer to Section 4.4. • Artificial lift failure.

You will note that some of the above have already been addressed in previous sections. With regard to the others in the list, there may be a number of possible solutions for each problem. For instance:

• Reservoir problems such as formation damage and low permeability can sometimes be improved by stimulation operations such as acidisation or hydraulic fracturing.

• In oil or gas wells where there is liquid hold up or gas slip, this is often countered by installing smaller diameter tubing strings. These may be reeled tubing strings installed inside the original completion by large size C/T units. This tubing reaches down into the sump and 3 provides a smaller flow area to improve liquid lift. These reeled strings are normally 2 /8 ins., 7 1 2 /8 ins. or 3 /2 ins. OD and are run and hung off on a wireline lock or similar device.

• The tubing is snubbed into the well by normal C/T methods from large reels. When the correct length of tubing is in the well and has been attached to the lock mandrel, it is run to setting depth and set on regular size C/T.

• The main disadvantage with this solution is the high weight of such large reels which is often above the lifting capacity of some offshore installations. Smaller, more manageable, reel sizes entails more undesirable offshore connections to make up the full length of tubing required. These problems, however, are outweighed when set against the costs of a full programme to re-complete.

• An artificial lift system is usually required in any low permeability well to give adequate production rates. A work programme to re-complete this type of well is required once the well flow has reached the minimum economic acceptable natural flow. If the well has already been on gas lift and it is no longer efficient, then the design should be reviewed to optimise the existing gas lift mandrel spacing against re-completing with the optimum mandrel depths.

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4.6 PARTIALLY DEPLETED RESERVOIRS

Similar to low permeability wells, in a depleted oil reservoir, an effective artificial lift system can be installed to increase production. If a well was originally planned and designed for gas lift and completed with gas lift mandrels in the string then the gas lift valves are simply installed by wireline intervention. However, if a re-completion is needed, a full dead well workover would necessary. In high angle wells, gas lift valves can be installed with coiled tubing methods.

Improved recovery by reservoir pressure maintenance is usually the best long term approach to increased production rates.

4.7 SAND CONTROL

There are normally two solutions to control unconsolidated sand and these are; to gravel pack or; install a pre-packed screen although resins are occasionally used; See Section 1.2.1 d). The drawback of having to implement such sand control measures is that they reduce productivity typically by 10% to 15%.

The installation of a gravel pack entails a full workover and re-completion although new snubbing methods with HWO unit have now been developed.

For a successful gravel pack it is important to ensure that clean fluids (containing little or no dispersal solids) are used on initial completion or when the gravel pack is installed. A second requirement is that the gravel is correctly sized in relationship to the formation sand to prevent further ingress or alternatively cause a blind off. It also is desirable, if completing in a sand zone that is known to be unconsolidated, that the gravel pack is installed immediately. As it is more difficult to install at a later stage.

If an open hole (external) gravel pack is required the hole will need to be enlarged to about twice its size by under-reaming first before the liner/screen is run. Properly sized gravel is placed outside the screen by reverse circulation techniques. External gravel packs are utilised when high production rates are required. Internal gravel packs are the norm but do carry a penalty in reducing production rates.

The use of pre-packed screens has risen in recent years as they can often be installed in an existing completed well avoiding re-completion, however they are more prone to blinding off as they do not provide the same effectiveness as a regular gravel pack in controlling the production of fines.

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4.8 WORKOVER WELL CONTROL PLANNING

Clearly, well control is the key element in any workover plan and the steps to achieve the planned objective (the workover programme) will reflect this

4.8.1 Ingredients of Good Planning

Workover planning and the subsequent production of workover programmes become ‘second nature’ to those engineers who are continually involved in that process – this is not necessarily true of all those involved in the chain of communication from planning to execution of the workover.

Individuals preparing/updating the safety management system (SMS) will have involved the well operations group so that the documentation used in the planning and execution of workovers is an integral part of the SMS.

It would be useful for well operations groups to highlight the mechanism for supervisors in charge of well operations at the well site to communicate proposed changes in the workover programme to the onshore co-ordinator, and the method of responding to the proposed changes. This may seem unnecessary to those continually involved in that process, but if there is a change out of personnel, illness or vacation the ‘norm’ could become the abnormal and problems could ensure that may affect safety and costs.

Most well operations groups include well diagrams showing barriers and containment devices in the well before, during and after the workover and well files are updated accordingly. There is normally feedback to adjust procedures where necessary after a post workover review and this may include changes in barrier and containment philosophy.

4.8.2 Workover Programme

Having established the objective of the workover, a programme is produced. The following is an example of the main headings of the contents of a typical programme for a producing well.

1. Well history 2. Current status of well 3. Proposed completion details 4. Proposed deviation from standard procedures (if any) 5. Procedures for: • Well kill • Plugging • Removal of Xmas tree • Installation of BOP • Cleaning out the well • Removing BOP • Re-installing Xmas tree

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Current Status of Well

From a well control perspective we would want to have specific information on:

Information Reason

•Pore pressure of exposed formations Kill fluid requirements· •Fracture pressure of exposed formations Bullheading requirements •Permeability of exposed formations Kill fluid specification •Accessibility to tailpipe nipple(s) Barrier considerations •Integrity of packer Procedures to control the well •Current wellhead annuli info on pressures Procedures to control the well •Hydrate formation Procedures to control the well

And from an operational safety point of view.

Prevalence/likelihood of hydrogen sulphide (H2S) and Low Specific Activity (LSA) scale (radioactivity hazard). In particular: • Disposal of contaminants • Personnel protection

Blowout Preventers

As discussed earlier, careful consideration should be given to the BOP configuration with respect to the workover objective and anticipated problems.

The following statements also apply:

All pressure control equipment, i.e. BOPs, risers, lubricators should: • Be rated to at least the maximum anticipated surface pressure • Be suited to the working environment allowing for - temperature, e.g. BOP electromeric components

- corrosive effects, e.g. CO2, H 2S, and brines • Allow passage of all completion and workstring components • Be able to close around all completion and workstring components At all times during workover operations a stab in valve or TIW valve , with appropriate x/ over, should be available on the rig floor to make up to the completion/workstring in the event of a kick. Other x/overs should be available for making up lubricators, cement lines etc.

X/overs should be easily identifiable with respect to:

• Thread size • Thread type • Internal diameter

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Allowance should be made for the possibility of operations such as bullheading. Typically the pressure rating of the BOPs will be the same as the Xmass tree, unless there has been considerable reservoir pressure depletion during the life of the well.

In higher pressure wells additional considerations should be given to preference for pipe rams over variable bore rams as they provide a more reliable seal.

4.8.3 Well Control Problems During Workover

The following are typical causes of well control problems during workover:

1. Different workover philosophies within the same company for different fields can lead to subtle changes in procedures which in turn can lead to errors.

2. Brine densities can be affected considerably by downhole temperature effects, which is particularly hazardous where low overbalance margins exists.

3 .In some cases there is no test of mechanical barriers from below the barrier.

4. Removing a packer when the well has not been adequately stabilised, by sealing off the formation and overbalancing with a suitable fluid.

5. Attempting to remove a tool string from a well having insufficient length of riser to isolate the tool string and isolate to depressurise the lubricator section.

6. Isolating a water producing zone by squeeze cementing, setting a bridge plug and running a new completion – loss rate leading to a gain – shutting in the well – both tubing and annulus pressures being zero. Diagnosis – flow between higher and lower pressures zone.

7. Differentially depleted reservoir as in 6, leading to hydrocarbons from a lower high pressure zone to a higher low pressure zone. Losses can occur with brine flowing into low pressure zones and formation fluids flowing into the well bore from high pressure zones.

In many cases the procedures initially proposed will fail because they may have to be modified in the light of new facts uncovered during the process of the workover operation. Many aspects must be considered before developing procedures.

• Does the well need to be killed • Magnitude of formation pressures • Casing burst and formation breakdown pressure • Evidence of tubing holes, packer leaks and sand bridges

A problem relating to reworking sub-normal pressure zones is the loss of fluid to the producing interval. The slight overbalance which is used to prevent kicks may force workover fluids to enter the producing interval. Any swabbing by the work string can cause the well to flow – this effect is of course common in any normally pressured formation.

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The most feasible solution is to plug the producing zone with calcium carbonate or some other material that can be dislodged or dissolved later.

4.8.4 Troubleshooting Well Problems

In any event, information at the wellhead can indicate what the problems are likely to be before the decision is taken to work over the well. The following example illustrates conclusions drawn from examining tubing and annulus pressures.

1. With tubing pressure (Figure 3.19) • tubing full of produced fluids

2. With no tubing pressure (Figure 3.20) • sand or scale bridging • produced fluids overcome formation pressure • plug stuck in completion • tubing collapse

3. With tubing and tubing casing/annulus pressure (Figure 3.21) • failed side pocket mandrel or sliding sleeve • hole in tubing • failed production packer • leaking tubing hanger pack-off

4. With tubing and casing/casing annulus pressure (Figure 3.22) • communication with abnormally pressured formations • hole in tubing and casing

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5.1 GENERAL 5-1

5.2 SNUBBING/HYDRAULIC WORKOVER UNITS (HWO) 5-2

5.2.1 Wireline Unit 5-7 5.2.2 Wireline Units 5-8 5.2.3 Types of Wirelines 5-10 5.2.4 Wireline Lubricators and Accessories 5-11

5.3 COILED TUBING UNITS 5-13

5.3.1 Power pack 5-14 5.3.2 Tubing 5-16 5.3.3 C/T Unit Accessories 5-17 5.3.4 C/T Tooling RILLIN N D G S EE CH D O R O E L B S A •

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5. WELL INTERVENTION SERVICES

5.1 GENERAL

Well interventions are servicing operations conducted through the Xmas tree (through-tree) on live wells. These are carried out by the following methods:

• Wireline (both electric line and slickline). • Coiled tubing. • Snubbing.

Well service operations or workovers on dead wells where the Xmas tree is replaced by well control equipment, are carried out by:

• Drilling rigs. • Workover rigs. • Hydraulic workover units.

During workovers, it is probable that well interventions with wireline and/or coiled tubing are required as part of the work programme to prepare the well for tree removal or establish production post workover.

Many offshore installations have drilling rigs onboard used for the drilling phase of a development. These units are often retained to conduct well servicing operations on fields which frequently have wells requiring servicing although it is becoming more common for the drilling units to be demobilised and dead well servicing to be accomplished by a Hydraulic Workover Unit. Where a drilling rig is available for well servicing, it is obviously more economic for it to be used than mobilising an HWO unit.

On installations which have not retained the drilling rig, or on small platforms (drilling performed with a jack-up rig), the HWO unit is commonly used. This is due to their easy deployment and their small footprint.

On subsea wells, normally the only means of conducting a well intervention is to use a semi- submersible vessel (drilling unit, DSV or specialised well servicing unit) from which a workover riser can be deployed. However, if the work programme can be conducted solely with wireline, this can be successfully carried out by subsea wireline systems deployed from well servicing vessels (for example the Stenna Seawell). These vessels also have the capability to carry out subsea tree change outs once appropriate barriers have been installed by wireline.

Well control equipment used on well interventions in live wells is specific to the particular service being used for the intervention, albeit BOPs and strippers all operate under the same principles. The main differences in the systems usually lie in the design of BOP ram elements, strippers or stuffing boxes, grease heads used in wireline braided line operations and the configuration of these above the Xmas tree.

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BOPs are usually compact for manipulation into position above the Xmas tree or onto a riser often used in platforms arrangements. They are fitted with flexible hoses to enable ease of installation and to reach between the BOP hydraulic control system and the BOPs when in situation. The connections on the BOP must be compatible with the riser/tree connection and lubricator or be supplied with appropriate crossovers.

Well intervention pressure control procedures are addressed in Section 7.

5.2 SNUBBING/HYDRAULIC WORKOVER UNITS (HWO)

The Snubbing/HWO Unit is a well service unit utilised for both snubbing and dead well servicing. Snubbing is the process of ‘tripping pipe in a well which has a surface pressure great enough to eject the pipe if no restraining force is applied’; this is termed the ‘pipe light’ mode. Stripping is the term for moving pipe through a rubber element to contain pressure whether it is in the snubbing mode or ‘pipe heavy’ mode (where the pipe is too heavy to be ejected). In practice, however, snubbing has come to mean all of the operations conducted in a live well.

The HWO unit is also used in place of a conventional drilling or workover rig on dead well servicing as it is easily mobilised, has a small footprint and is cost effective in comparison to mobilising a workover rig. They are also very useful when working in confined spaces and with small diameter (skinny) pipe where a drilling rig’s instrumentation is generally not sensitive enough.

An HWO unit would only be used before C/T on a snubbing job where:

• There is insufficient space above the wellhead or deck space. • When rotational torque required on the pipe is greater than that available from downhole motors. • Where pressures exceed the rating of C/T pipe i.e. circa 5,000 psi.

The first snubbing units were mechanical units using mechanical advantage in order to force the pipe in the hole against well pressure. In the development of the hydraulic type unit, the power to raise and lower the tubing was provided by a set of hydraulic rams through a set of bi-direction travelling slips or snubbers. The main elements of an HWO unit, See Figure 5.1, are as follows:

• Hydraulic jack assembly. • Guide tube. • Splined tube (only on Halliburton/Otis units). • Travelling slips. • Stationery slips. • Access window. • Rotary swivel. • Hanger Flange • Power tongs.

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• Work basket. • Control panel. • Hydraulic power pack. • Hose package. • BOP system. • Strippers. • Circulating system.

HWO units are supplied in a range of lifting capacities (lbs. in thousands), 60K, 90K, 120K, 200K, 250K, 400K and 600K. Snubbing capacity is half of this rating.

When used instead of a conventional drilling or workover rig, the well would be killed and plugged, the Xmas tree removed and BOPs installed on the casing head. It can also be used for re-completing wells as it has the capability to run and pull completion strings by running the downhole safety valve control line through the access window.

Hydraulic Jack Assembly

As described earlier, the jack assembly consists of one or more hydraulic cylinders that travel in a vertical direction to move pipe in or out of the hole. For higher snubbing or lifting power, more cylinders are added into the system which reduces running speed unless larger capacity pumps are used. The operator controls the hydraulic power to the jack as the weight of pipe changes or as the weight of pipe overcomes well pressure and changes from snubbing to lifting and visa versa.

Guide Tube

This is simply a tube which prevents the bucking of the pipe under snubbing forces. It should be sized to be just larger than the particular tubing to be run or pulled to constrain lateral movement. It travels up and down with the hydraulic jack.

Splined Tube

Some units have a splined tube which passes rotational torque force generated by the rotary table through to the bottom plate and hence to the wellhead. If a splined tube is not used, the forces are transmitted through the hydraulic cylinders possibly reducing the operating life.

Travelling Slips

The travelling slips, or snubbers, are attached to the upper end of the jack and grip the pipe to push it into or pull it from the hole. There are two sets, one for snubbing and one for lifting. As a pipe is snubbed into the hole, it comes to a balance point which changes from pushing to holding back weight, the point the lifting slips take over.

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Stationary Slips

The stationary slips hold the pipe while the travelling slips are released for the next stroke. Like the travelling slips, there are two sets, one for hold upward force and one for holding downward weight. In high well pressures, the second set can be used as back-up to the primary slips. These would be changed at or around the balance point.

Access Window

The access window (work window) is installed at the base of the jack between the stationary slips and the stripper and is the access for stripper rubber change out or for installing tools in the string. It must also help guide the pipe like the guide tube.

Power Swivel

The power swivel (or Rotary Head) is used for rotating the pipe for drilling or milling operations. It, like the other systems, are hydraulically powered and controlled from the control pane.

Hanger Flange

A hanger flange (also known as a tubing hanger assembly) is a pressure containing component sometimes used in the blowout preventer stack to hold pipe and toolstring in both the 'light' and 'heavy' directions. It is usually incorporated near the top of the BOP stack between the stripper bowl and the upper stripping ram or annular BOP. It is commonly used when changing the stripper rubber element or adding a tool joint which might be damaged if run through the slips. The hanger flange is also a useful aid in fishing operations with its ability to hold varying diameter toolstrings such as wireline tools. Vertical tooth type dogs can be used in the hanger flange to prevent pipe or tool rotation.

Power Tongs

Power tongs are used to make up and break out the pipe connections. They are located in the workbasket and controlled hydraulically from the control panel.

Work Basket

The workbasket is the work platform of a HWO unit and is located at the top of the hydraulic jack and on which the operator and assistant perform the manual functions including the picking up, laying down, stabbing, making up or breaking out of the pipe joints.

Control Panel

The control panel is mounted in the work basket and is usually in two sections, one for the operator’s use and one for his assistant. From here, all of the unit functions are controlled, generally shared between them with the exception of the BOP shear rams which are normally operated from the deck.

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Work Basket

Fluid Storage And Gin Processing Pole Choke System

Stationary Slips Hoses

Work Window Stripper Bowl Tool House Hanger Flange Mud Pump Fill Line Drain Line

Bleed Line Equalise Tool Box Line Ground Based BOP Control Units

Spares Choke Upper Kill Line Line Power Unit

Fuel

Figure 5.1 - Typical Snubbing/HWO Unit

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Power Pack

The power pack and it’s accessories consist of a diesel engine and hydraulic pumps. The output from the pumps is regulated to the various pressure ratings of the hydraulic functions. It displays the various function pressure on gauges.

Hose Package

The hose package transports the hydraulic fluid to and from the various functions, some of which are high up on the unit and are therefore of considerable length. Some of the hoses can experience very high pressures and must be thoroughly tested before use.

BOP System

The BOP configuration is dependent upon whether the HWO unit is being used as a rig on a well which has been killed, or in the snubbing mode rigged up above the Xmas tree. If on the former, the BOP configuration will be like that in a drilling situation and may be covered by the operator’s well control policies and procedures. If on a snubbing job, the configuration is quite different being rigged up above the Xmas tree. Refer to Section 7 for all well control equipment and procedures.

Strippers

The strippers control well pressure when snubbing or any time surface well pressure is encountered. There is a variety of stripper rubber materials for different pressure regimes and well fluids. These will vary in well life according to their resistance to the well fluids, gas or erosion due to roughness of the wall of the pipe being run, or pulled.

Circulating System

Pumps, chiksans, Kelly hose and a circulating swivel are the main components of the circulating system. The pumps are generally high pressure in order to cope with the maximum anticipated circulating and surface pressure.

If nitrogen is to be used, the hose and chiksans should be suitably rated for such service.

A safety valve or Kelly cock must always be installed between the Kelly and the swivel to allow safe changing of the hose or swivel, if necessary.

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5.2.1 Wireline Unit

Wireline is the oldest and most common type of well servicing method. It is extremely efficient, economic and relatively easy to rig up and deploy.

Electric line services provide essential information about the reservoir and the completion and performs many services, typically:

Logging - depth determination, cement bonding, sonic, nuclear, temperature, pressure, spinner, caliper, density, dipmeter, profile and so on.

• Calipering. • Downhole sampling. • Perforating. • Setting bridge plugs, packers and cement retainers. • etc.

This is achieved by communicating with the tools through the conductor cable.

Mechanical wireline also known as slickline (as the line has a smooth OD), is used to conduct mainly mechanical operations such as:

• Installing flow controls. • Installing gas lift valves. • Depth finding. • Plugging. • Bailing. • Paraffin cutting. • Tubing gauging. • Setting bridge plugs. • Fault finding. • Fishing. • Logging - through-tubing BHP gauges or the latest electronic solid state logging tools such as spinners, CCLs, etc.

The slickline unit can also be rigged up with braided line for heavy duty wireline operations such as running heavy, large tools or performing heavier duty fishing operations.

A more recent development in wireline services is the Heavy Duty Wireline Unit used mainly for fishing jobs where regular fishing methods have failed. These units, in conjunction with heavy duty tooling, are so powerful they can destroy normal wireline tools and devices, if desired.

Although wireline conducts most tasks required for well servicing, it is obviously limited in its abilities. It also has a role in dead well servicing as it is normally required for plugging the well to make it safe prior to Xmas tree removal and BOP installation. It is also used to conduct

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remedial operations such as setting bridge plugs, re-perforating etc. It’s greatest limitation, due to using gravity as it’s motive force, is in working in high angle or horizontal wells with inclination angles higher than 70˚.

5.2.2 Wireline Units

As pointed out earlier, there are two types of wireline unit - the electric line or logging unit and the mechanical or slickline unit. Both types of unit are constructed similarly in that they have:

• Power pack. • Operator’s/engineer’s cabin. • Winch, including a wireline drum or reel. • Spooling or measuring head. • Weight indicator and pulleys.

Wireline units must be self contained and able to be mounted on a truck (or trailer) or portable to enable trucking and/or shipping to the well site. A typical wireline unit is shown in Figure 5.2.

Power Pack

The power pack is normally a diesel driven hydraulic unit and provides hydraulic power through supply and return hoses to the winch. Power packs are normally fireproofed and certified for division 1, zone 2 hazardous areas.

Operator’s/Engineer’s Cabin

The cabin is an integral part of the winch unit situated directly behind the drum for direct observation and monitoring of the wireline spooling. It contains the winch and possibly the power pack operating controls. In an electric line unit, it also contains all of the electronic instrumentation, computing and log printing equipment. Electric line units have fine smooth controls for accurate logging operations whereas the slickline unit has a wide range of speeds for both fine and very fast operation when jarring.

Winch The winch consists of the wireline reel driven by a hydraulic motor controlled from the console in the cabin all of which is mounted in the unit frame. Hydraulic power is supplied from the power pack.

The reel controls have a forward and reverse directional valve, a number of gear ratios to cover a wide range of speeds and a hydraulic bypass valve for fine control within each gear range. The reel is driven by chain drive from the gearbox and has a brake band. If there is two reels on the winch, slickline and braided, there is an additional manual operated clutch system for reel selection.

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Spooling Head

The spooling or measuring head controls the winding of the wire off and onto the reel and also measures the length of wire spooled off the drum. The depth measurement is given on a odometer via a cable drive and a precisely machined measuring wheel (one for each size wire). The wire is held against the measuring wheel by pressure wheels to eliminate slippage. Electric line units usually have electronic type depth measurement devices.

Weight Indicator and Hay Pulley

The weight indicator can be mounted on the hay pulley or be an integral part of the spooling head.

If mounted at the hay pulley, the weight sensor is a load cell placed between the hay pulley and the tie down chain. The cell is connected to the indicator situated in the unit with a long hydraulic hose. The system is graduated for the wire to pass around the hay pulley at an included angle of 90˚ If this angle is not maintained, there will be an error in the readings. Correction tables are available which correct for varying angles.

Modern units usually have more sophisticated type weight indicators, some hydraulic and others electronic. These units must be regularly serviced and checked for accuracy as this is fundamental to wireline service especially using relatively low strength wire.

The hay pulley is the device used to turn the wire from the horizontal plane to the vertical up to the lubricator stuffing box sheave. As well as turning the wire it also moves the forces generated on the wire into the same axis as the lubricator reducing any possible bending moments. It has been known for a hay pulley failure due to severance of the tie down chain, causing the lubricator to break off the well.

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Figure 5.2 - Typical Wireline Rig Up

5.2.3 Types of Wirelines

Electric line

Cable used on electric line units can be either monoconductor, coaxial or multiconductor braided line and supplied for various service conditions. Each particular type has a range of sizes and specific uses according to the required service or tool being run. Careful handling of electric line is essential, especially with the smaller sizes and when rigging up, to prevent line damage and penetration of the core insulation leading to subsequent loss of signal.

Slickline

Slickline is a high strength monofilament steel line and is available in common sizes of 0.082 ins., 0.092 ins., 0.108 ins. and 0.125 ins. These are also supplied for various services conditions. Being slick the OD of the wire is easy to seal around using a simple packing device called a stuffing box where as the cable requires a grease seal arrangement.

Braided Line

3 7 Braided wireline used for heavier duty wireline operations is supplied in /16 ins. and /32 ins. sizes.

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The wireline lubricator when assembled acts like pressure vessel on top of the Xmas tree into which the wireline tools are ‘lubricated’. It consists of:

• Wellhead adapter. • Wireline BOPs or wireline valve. • Lower lubricator section(s). • Upper lubricator section(s). • Stuffing box or grease head. • Line wiper.

It is extremely important that a wireline lubricator pressure rating meets the maximum anticipated surface well pressure. Lubricators must be designed, not only to withstand the stress caused by internal pressure but also from stresses caused by jar action or high pulling forces.

To install the tools, the lubricator must first be isolated from well pressure at the Xmas tree, usually the swab valve, and all pressure bled off through the bleed-off valve. The lubricator is then broken out at the connection immediately above the BOPs and the tools, after attaching to the toolstring, are pulled up into the lubricator bore and the lubricator re-installed. The lubricator should then be pressure tested before opening the tree and running in the hole.

Wellhead Adapter

This is basically a crossover to mate the BOP to the tree cap and is usually a quick type connection named a ‘quick union’. In some cases the adapter may be from a quick union to a tree flange.

Wireline BOPs

Wireline BOPs (sometimes referred to as wireline valve) are installed immediately above the wellhead adapter or on top of a wellhead riser. In some situations for ease of operation and safety, a BOP may be placed both above the tree and on top of a riser.

On slickline operations in low pressure wells, a single BOP is installed dressed with slickline rams to close and seal around the wire. On high pressure wells a dual BOP is used, the lower rams dressed for slickline and the uppers with blind. The injection point is used to pump grease if there is leakage past the rams.

When running cable, a dual BOP is used with both rams dressed for the particular cable size and a grease injection point also available between the rams.

In a situation where slickline and braided line are both being used, a triple BOP would be installed with the lower and middle rams dressed for the braided line and the upper for slickline.

On electric line jobs, triple BOPs are used, the upper rams being blind.

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These are sections of thick wall tube usually between 8 to 10 ft. long with quick union connections at each end and made up in a total length to accommodate the longest tool to be run. They are installed immediately above the BOPs and usually have the same bore size as the Xmas tree. The section above the BOPs must have two bleed-off valves (contingency for one being plugged by debris or hydrates).

Riser sections, used in offshore platforms to reach from the wellhead deck to another working deck, are similar to lubricator sections except they are generally much longer in length and may be installed between the wellhead adapter and the BOPs. They may also be of even thicker section to support the increased weight being carried.

Upper Lubricator Sections

These accommodate the toolstring which has a smaller OD than the toolstrings which are normally 1 ins., 11/2 ins. and 2 ins., although larger sizes are available for heavy duty work. The section connecting to the lower lubricator will have a connection to mate with that of the lower lubricator sections (or visa versa).

Stuffing Box or Grease Head

The stuffing box or grease head terminates the top of the lubricator.

The stuffing box contains packing which is squeezed to seal around the line. The packing is squeezed by an adjustable packing nut which is hand adjusted although most stuffing boxes are now being supplied by remote hydraulic actuated packing nuts so that they can be adjusted from the deck eliminating the need for personnel to be lifted up to the top of the lubricator and, hence, is safer. The stuffing box also incorporates a sheave which turns the wire through 180˚, from the outside of the lubricator into the bore.

The grease head is used on braided line, electric line or plain cable. It seals around cable by grease being pumped, at higher pressure than that inside the lubricator, into the small annulus space between a set of flow tubes and the cable filling the cable interstices. The grease, being at higher pressure, tends to flow downwards into the lubricator and also upwards out of the tubes.

The upward flow is forced out through a return line for disposal by activating a cable pack off above the tubes. Downward flow is only constrained by the differential pressure applied between the grease and the lubricator pressure. Adjustments must be made to maintain the optimum conditions between grease lost to the hole, amount of gas entrained in the grease returns and differential pressure.

Line Wiper

This is a tool which attaches to the hay pulley when the wire is being pulled to remove all contaminants from the wire before it is spooled.

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5.3 COILED TUBING UNITS

Well servicing using coiled tubing (C/T) has grown significantly with the development of tooling and tubing technology. In recent years the size of tubing available has increased from 1 1 3 the original 1 ins. through 1 /4 ins., 1 /2 ins., 1 /4 ins. and now 2 ins. Even larger sizes are now being used as siphon strings etc. but these are not yet generally used as workstrings. Along with this increase in size of tubing has come material improvements to give higher performance.

C/T units have largely replaced snubbing units for operations on completed wells and their versatility, due to new tooling developed, has extended their range of capabilities in recent years. The range of services now provided includes:

• Drilling and milling using hydraulic motors. • Casing cutting. • Circulating. • Tubing clean outs (sand or fill). • Cementing. • Through-tubing operations. • Tubing descaling. • Running, setting, pulling wireline pressure operated type tools. • Fishing wireline tools. • Logging (stiff wireline). • Nitrogen lifting. • Selective zonal acidising. • Perforating.

Much of the recent increase in capability is due to the increased performance of downhole motors which provided the ability to rotate enabling drilling and milling operations etc.

The limitation of C/T is usually the pressure rating of circa 5,000 psi. and the depth to which it can be run, constrained by it’s relative low strength. It is also limited in it’s service life due to the bending cycles over the reel, and to a lesser extent the goose neck, in conjunction with the service conditions it encounters.

These bending cycles force the tubing to exceed it’s elastic limit inducing fatigue, and, therefore, reducing the working life before failure. Tubing under pressure while passing over the reel and goose neck, dramatically decreases this cycle time to failure. Most C/T service companies have developed computer programmes, using logging databases, to determine the time to failure for each tubing size and type of material to which a factor of safety is applied. This is an inexact science but, due to the safety factor, there is actually very few recorded well site incidents due precisely to tubing failure. More than likely, service life is much shorter than actual life.

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All C/T units, See Figure 5.3, are constructed similarly and consist of:

• Operator’s control cabin. • Tubing reel. • Power pack. • Goose neck. • Injector head. • Stripper. • BOP system.

Operators Control Cabin

The cabin houses all of the controls for the reel and the injector head, and also all electronic logging systems and instrumentation. The controls operate the hydraulic valves and pressure supplied from the power pack. It is placed directly behind the reel to provide the operator with a full view of all activities especially the spooling of the tubing off and on the reel.

Tubing Reel

The reel stores the tubing which is coiled around the core of the reel. Ideally the core should be as large a diameter as possible to prevent severe bending of the tubing but must be of a manageable size for transporting to and from well sites. The radius of the core of the reel is 1 sharper than that of the goose neck e.g. 24 ins. (4 ft. dia.) versus 72 ins. for 1 /4 ins. tubing, hence most tubing fatigue is caused at the reel.

The reel is driven by chain from a hydraulic motor controlled from the control cabin. The tubing is pulled off the reel up over the gooseneck by the injector. The reel holds constant back tension to prevent the spool unravelling and to keep the tubing steady.

5.3.1 Power pack

The power pack is the provider of all hydraulic power. It consists of a skid mounted diesel engine and hydraulic pumps and supplies regulated pressure for all the systems in the reel, injector head, BOPs and the control cabin.

Goose Neck

The gooseneck is simply a guide which accepts the tubing coming from the reel and leads it into the injector chains in the vertical plane. The goose neck guides the pipe using sets of rollers in a frame spaced on the recommended radius for the tubing being run i.e. 72 ins. with 1 1 /4 ins. tubing etc.

Injector

The injector is the motive device which imparts upward or downward movement to the tubing and is mounted above the BOPs on the wellhead. It must be supported as the connection to the BOPs is not designed to absorb the weight and lateral forces caused by the tension in

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Figure 5.3 - Typical Coiled Tubing Unit

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the tubing from the reel. This support can be a crane for land wells (providing the lifting gear and pad eyes are rated for the weight of equipment and forces encountered) or to a mast or derrick offshore. Free standing frames with hydraulic jacking legs are also available where no other means of rigging up is available.

Movement is imparted to the tubing by sets of travelling chains equipped with gripper blocks which are hydraulically driven. The gripper blocks grip by friction which is adjustable through a hydraulic piston applying pressure across the chains. This pressure must be sufficiently high enough to grip the tubing eliminating slippage but not excessively high enough to crimp the tubing.

Stripper

The stripper is situated below the injector head in the injector head frame. It is designed to be as close as possible to the gripper chains to prevent buckling due to snubbing forces. The stripper is hydraulically controlled to press the rubber element against the tubing to create a seal. The stripper rubber is exposed to wear from the roughness of the pipe OD and will need to be changed from time to time which can be done on the wellhead by closing the BOPs and removing well pressure.

BOP System

The BOPs are very similar in function to wireline BOPs and are mounted above a wellhead adapter. They usually have four sets of rams dressed as follows, top to bottom:

• Blind. • Shear. • Slip. • Pipe.

The shear rams usually have the ability to cut stiff wireline i.e. C/T with electric line cable inside it, used on C/T logging operations.

In some areas of the world, an additional Shear/Seal valve is installed between the BOPs and the wellhead adapter as a tertiary barrier. The shear seal valve has the ability to cut the tubing and effect a seal. It is generally tied into a higher volume hydraulic pressure supply than available from the C/T unit such as a rig Koomey or independent system etc.

5.3.2 Tubing

There are a number of coiled tubing manufacturers but they are mainly US or Japanese companies. Some of the US companies use Japanese supplied steel for tubing manufacture. The normal method of tubing manufacture is to produce rolled plate steel which is cut into long flat strips. Each strip is then progressively folded round with rollers and formed into a

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long spiral. When it is completely formed into a round tube, the edges, now abutting, are welded. These individual lengths are then welded together to produce the length required to be contained on a shipping reel. Continuously milled tubing has now been introduced but is much more costly.

The common steel used is an American alloy grade A606 type 4 modified, suitably quenched and tempered, which provides the best economic combination of ductility and strength to combat the cyclic bending stresses. By specially selecting billets from the furnace to meet particularly tight tolerances of chemistry, higher grades can be produced such as QT-800. More exotic pipe materials are also being manufactured but have corresponding cost penalties.

5.3.3 C/T Unit Accessories

In conjunction with the C/T unit, many of the services require additional auxiliary equipment such as pumping or nitrogen services. These may require cryogenic converter pumps, tankage, hoppers, filtration units and interconnecting piping. These are connected up to the tubing reel inlet swivel which allows the reel to rotate while still pumping. Any hazardous materials must be handled appropriately by ensuring that they are located in a safe area and all necessary safety handling precautions taken. For instance when using nitrogen, the deck below the equipment should be covered with wood and trays to contain and protect the deck from damage due to spillage, and water available to wash down the deck if nitrogen does breach the barriers.

5.3.4 C/T Tooling

Tooling can be categorised into standard toolstrings and specialist tools. These toolstrings contain the standard tools used in all applications to which the specialist tools are attached. The complete assembly is referred to as the Bottom Hole Assembly (BHA).

A typical toolstring contains:

• Tubing connector. • Dual flapper valves. • Emergency release sub.

Optional standard tooling:

• Circulating subs. • Swivels. • Bull noses.

Specialist tooling:

• Downhole motors. • Jetting nozzles. • Wireline type hydraulic operated tools.

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• Through tubing packers. • Bridge plugs. • Perforating guns. • Logging tools. • etc.

The dual flapper valves are an integral element in well control as they contain well pressure from the inside of the tubing. The dual flappers give double isolation and meets most legislative requirements. Therefore, when the BOP tubing rams are closed well pressure is contained to both below the rams and from the tubing, hence the well is safe for corrective actions. A split in the tubing below the BOPs circumvents the dual flappers seals and, in this situation, the shear rams would be closed to contain well pressure.

5-18 © ABERDEEN DRILLING SCHOOLS 2002 6. PREVENTION OF FORMATION DAMAGE 6-1

6.1 FORMATION DAMAGE 6-1

6.1.1 Drilling/Casing 6-2 6.1.2 Completing 6-2 6.1.3 Producing 6-3 6.1.4 Well Intervention 6-4

6.2 DAMAGE PREVENTION 6-4

6.2.1 Well Plugging 6-4 6.2.2 Workover Fluids 6-5 6.2.3 Clear Fluids 6-5 RILLIN N D G S EE CH D O R O E L B S A •

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6. PREVENTION OF FORMATION DAMAGE

Damage to the formation can be caused by many mechanisms. Although some of these may be due to well conditions, the majority are through contamination of the formation by foreign substances not only during the drilling, completing and producing phases but also during the servicing of a well. These damage mechanisms are described in Section 6.1 below.

To prevent damage which reduces the productivity of a well, it is essential to be able to prevent or reduce formation damage by preferably isolating the formation from the contaminants or, if not possible, reducing the amount of contaminants in the fluids or conducting remedial stimulation operations. These are discussed in Section 6.2.

6.1 FORMATION DAMAGE

The types of damage which can occur during the different phases of a well’s life are described in the following section. See Figure 6.1 for the effects of skin damage to the well pressure profile.

Figure 6.1 - Formation Damage Pressure Drop

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6.1.1 Drilling/Casing

Drilling fluids usually contain chemicals and/or solids as bridging agents to control the loss of drilling fluids. Fluid losses can lead to well control problems and are also expensive to replenish especially when using the more exotic mud systems such as Pseudo or Oil based muds etc.

Drilling fluids cause the following types of damage:

• Solids plugging of pores, vugs or fractures both natural or induced. • Clay swelling reducing permeability. • Filtrate penetration detrimentally changing the relative permeability to producing fluids.

Similar damage can be caused during the casing cementing process for the production casing by cement pre-flushes and cement slurries.

Non-damaging drilling fluids are often used to penetrate the producing formations when the wells are to be completed with open hole, barefoot or gravel pack type completions. In the main, however, damage done during the drilling is not a serious problem in most wells as they are usually to be perforated. The perforating depths, under normal circumstances, exceed the depth of any damage areas. They also generally have a total flow area greater than the tubing area, hence there is little impediment to achieving maximum production rates. Perforating is usually carried out in a clear non-damaging fluid such as brine or fresh water so that minimal post perforating damage is caused.

When damage exceeds the perforating depth or occurs in an open hole type completion, this may be reduced by acidising or fracturing.

6.1.2 Completing

The damage caused during the completing phase, compared to drilling, is generally minimal if good completion designs and practices are employed. Most damage caused would be through contamination by fluids or pills used containing loss control materials (LCM) and other foreign bodies.

Possible damage may be:

• Plugging of pores, vugs and fractures by LCM. • Clay swelling due to incompatible well fluids. • Deposition of mill scale, rust or thread dope. • Perforating tunnels plugged by perforating debris from the shaped charges. • Perforating tunnel compaction or crushing caused during the perforating process. • Cleaning up at too high a rate causing movement of formation fines to plug pores.

With current technology it is easy to complete wells and displace to clean filtered brines or fresh water before perforating, thereby reducing the risks of any damage occurring. Also, most perforating is done with an underbalance pressure in the tubing which reduces the amount of invasion. This underbalance is created by displacing the tubing (fully or partially) to a lighter

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gravity fluid such as diesel, base oil or fresh water. If a fluid cannot provide sufficient underbalance or if a very high underbalance is demanded, nitrogen can be used although is much more costly.

All completion and service equipment, especially the tubing should be thoroughly cleaned before being installed and thread dope used sparingly.

If the well is to have an open hole type completion, then the well fluids programme should be designed to prevent formation damage. However, in practice this is difficult and most engineers acknowledge damage will be caused to some extent. In the situation where LCMs need to be used to support the workover fluid, the engineer must select a material which can be easily removed afterwards. Sized salt or calcium carbonate are examples where the former is cleared by flushing with water and the later with an acid wash.

6.1.3 Producing

Although it maybe of some surprise, damage can occur during the producing phase of a well. This is normally due to the production of asphalt, wax or scales but can also be due to other chemicals contacting the formation.

Common types of damage:

• Reduced permeability if formation is in contact with corrosion, scale or paraffin inhibitors. • Formation or perforation blocking with precipitated scale. • Asphalt deposition around the wellbore can cause plugging and oil wetting which in turn can cause emulsion blocking. • Permeability reduction due to movement of fines through the reservoir. • Altering relative permeability detrimental to production due to increasing water production. • Clay swelling due to contamination with incompatible brines or water. • Plugging due to contamination with fill, silt or crud.

Many of these can be remedied or reduced by clean-out or stimulation operations.

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6.1.4 Well Intervention

Damage will be caused by some well interventions and most notably when fluids are placed against the formation.

Typical damage is:

• Pore, vug or fracture plugging by solids in circulating or well kill fluids. • Permeability reduction through filtrate invasion by circulating or kill fluids. • Sand face/cement breakdown due to effects during acid stimulation. • Permeability reduction due to insoluble precipitates formed during acid stimulation with hydrofluoric acid. • Formation blocking with long string molecules in high viscous fluids or diverting agents. • Clay swelling from incompatible brine or water contamination. • Pore plugging due to using non-damaging fluids. • Pore or perforation plugging due to bullheading with scale or debris in the tubing and casing.

To prevent the risk of any of these occurring, it is obviously that well interventions require thorough planning to minimise formation damage.

6.2 DAMAGE PREVENTION

It should be an aim in any programme to prevent any damaging fluid from contacting the formation, if possible. If this cannot be achieved, then the use of clear non-damaging filtered brines should be adopted. In some cases where it is necessary to use LCM or similar materials then a post servicing stimulation should be considered to reduce the damage.

6.2.1 Well Plugging

The best means of preventing formation damage is to isolate the fluids entirely from the formation by installing a barrier in the form of a mechanical plug but this is only possible if the well programme does not require work below the lowest plugging point. The most common method of installing a barrier is by setting a plug in a packer tailpipe nipple on wireline leaving well fluid or gas across the formation. The plug can then be inflow tested to confirm there is no leak. If the tubing is to be removed from the well, wireline plugs can only be installed in completions with permanent or permanent retrievable style packers. An alternative when working on monobore type completions, is to install a retrievable through-tubing bridge plug close to the top of the formation. This has an advantage in that the packer or liner hanger packer above can be removed without disturbance of the barrier.

Whatever type of device is used for plugging, it must be designed so that it can be recovered from the well after the work is completed. The plug will likely be covered by some scale, rust and other debris and although most of it can be removed by washing or bailing, some will remain. Most devices used generally have a long mandrel with a fishneck which stands above the plug enabling washing and latching with a pulling tool. Other devices such as pump- through plugs, allow the plug to be opened by application of tubing pressure above it where 6-4 © Aberdeen Drilling Schools 2002 RILLIN N D G S EE CH D O R O E L B S A •

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after the well can be opened up to clean out the fill first before recovering the plug. Once the tubing is successfully plugged and plug tested, the well can be circulated to the workover fluid, i.e. brine, etc.

6.2.2 Workover Fluids

Fluids used in completing or servicing operations have many applications. They are employed in perforating, cementing, fracturing, acidising, well killing, re-completing, milling, drilling, cleaning out and preventing fluid losses. They may also have an important long term function as an annulus packer or completion fluid.

To provide the properties required for each of the above, many types of fluids are utilised, e.g. drilling muds, milling fluids, brines (including seawater), salt saturated brines, diesel and dead oil. Some like the drilling or milling fluids, must have cuttings carrying capability, cool the bit or mill and reduce friction to deliver hydraulic energy downhole. Others used, say for circulating purposes or to provide an overbalance only, may be clear brines or seawater etc. Completion or packer fluids are usually solids free to prevent drop out and sticking but are also dosed with biocide, corrosion and/or scale inhibitors for long term protection of the formation and tubulars exposed to the fluid. However, one important function of them all, whether used as a completion fluid or in a re-completion, is that they must provide an overbalance at the packer depth in case of a leak to control well pressure.

Generally, the most economic fluid which meets all of the criteria is used and, if possible, it should be solids free and non-damaging. This criteria would tend to result in clear brines being used as they are cheap, readily obtainable, easily transportable and easily filtered in normal weight ranges. However the points which makes them desirable are also their worst features in that they have no bridging capability and are easily lost into the formation (unless the well is plugged). In this case, an LCM pill is usually placed against the formation to prevent or reduce the losses.

The solids in the LCM pill are often designed to be removed by post re-completion flushing or acidising. The use of a high viscous pill as an LCM is not recommended as the long chain molecules which plugs the pores cannot be removed by these methods.

6.2.3 Clear Fluids

At one time it was felt that poor well performance was due to other reasons other than by damage from drilling muds and other fluids. When it was recognised that some formations were sensitive to invasion by foreign fluids and particles that operators began to look closely at this subject, observing that fresh water was the biggest culprit. After this revelation, the use of low water loss muds, cements and non-aqueous fluids became the norm.

Clear brines have become the commonest workover fluids as they not only meet most of the criteria but are also a good medium in which to run and install tools and equipment. They are weighted by salts to achieve the desired densities. Brines are available in weights ranges from 8.3 to 21.0 lbs./gal. The heavier brines can be very corrosive to metals and hazardous to personnel, hence require special handling. Personnel

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must use appropriate safety workwear and be aware of the hazards. They are also more difficult to prepare to prevent crystallisation or freezing.

Composition of Brines

The following list shows the various types of brines, composition and weight ranges:

Potassium Chloride KCl 8.3 - 9.7 lbs./gal. Sodium Chloride NaCl 8.3 - 10.0 lbs./gal.

Calcium Chloride CaCl2 8.3 - 11.8 lbs./gal.

Calcium Chloride CaCl2/ CaBr2 11.8 - 15.2 lbs./gal. /Calcium Bromide

Calcium Chloride CaCl2/ CaBr2/ ZnBr2 14.5 - 19.2 lbs./gal. /Calcium Bromide /Zinc Bromide

Calcium Bromide CaBr2/ ZnBr2 14.5 - 19.2 lbs./gal. /Zinc Bromide

Zinc Bromide ZnBr2 13.5 - 21.0 lbs./gal.

Brine Selection

Selection of the brine is not simply by picking the brine best fitting the particular weight range required or by cost. For instance, the weight range of sodium chloride may provide the hydrostatic pressure required in a well (say 9 ppg) but it causes shales and clays to swell reducing permeability. Therefore if clays were present, as observed from cores etc., the brine selected should be potassium or calcium chloride. Potassium chloride is corrosive and an inhibitor should be added to maintain a pH of 7 to 10.

Fluid compatibility is essential in the fluids design.

Preparation of Brines

Brines are normally supplied in stored liquid form at the higher end of the weight range available and is transported in bulk to the well site. The density is normally adjusted by adding water. In some rare circumstances where a higher weight was desired or if the liquid had been accidentally contaminated with water, salt supplied in sacks would be added to build to the correct weight.

Field mixing is not recommended as the handling systems usually are not able to meet the high standard of cleanliness required to prevent contamination of the brine from incompatible liquids or solids.

When brine densities reach saturation point, the salt will either crystallise or settle out and pose a real hazard to operations. Temperature changes in the well can also cause crystallisation

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or solids fall out. Crystallisation is sometimes called freezing as it appears to form like ice. Filtration and Cleanliness

Brines are usually filtered to a predetermined level of cleanliness, selected to meet the demands, by a filtration unit or a centrifuge. There are two main types of filtration units used are a DE Filtration Unit and a Cartridge Unit.

The former uses Diatomaceous Earth formed as a cake on the faces of plates pressed together through which the fluid is pumped.

Health and Safety

The health of personnel and protection of the environment is paramount. The lower density brines such as sodium chloride are not harmful but the higher density brines are exceedingly toxic. These should be handled carefully and all personnel involved in mixing, storage and handling should wear protective clothing and goggles. An emergency dousing shower should also be easily accessible close to the workplace.

Some brines are also very corrosive to workwear such as leather boots and all precautions should be taken to avoid contact or to ensure they are thoroughly washed after contact.

Pollution Control

In most countries, there is legislation regarding the use of hazardous materials, therefore, disposal should be in accordance to the local laws and the well site appropriately constructed to capture and retain leakage or spillage. All movement or spillage of these materials should be recorded and the appropriate authorities notified.

7.1 FUNDAMENTALS OF FLUIDS AND PRESSURE 7-1

7.1.1 Fluid Pressure 7-1 7.1.2 Specific Gravity 7-3 7.1.3 API Gravity 7-3 7.1.4 Hydrostatic Pressure 7-4 7.1.5 Gas Correction Factors 7-6

7.2 FORMATION PRESSURE 7-10

7.2.1 Sub-normal Formation Pressure 7-10 7.2.2 Normal Formation Pressure 7-10 7.2.3 Abnormal Pressure 7-11

7.3 FORMATION FRACTURE PRESSURE 7-14

7.4 FORMATION INTEGRITY TESTS 7-15

7.5 MAXIMUM ALLOWABLE ANNULUS SURFACE PRESSURE - MAASP 7-18

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7. PRESSURE BASICS

7.1 FUNDAMENTALS OF FLUIDS AND PRESSURE

Understanding pressures and pressure relationships is important in understanding well control. Pressure is defined as the force per unit area exerted by a fluid i.e.:

Force Pressure =Area ––––

Therefore, the formula can be changed to calculate the force from a given pressure and a unit area:

Force = Pressure x Area

In the oilfield, pressure is usually expressed as the pounds of force that is applied against a one square inch area, i.e. pounds per square inch (psi.). Therefore, when a gas is placed in a pressure tight container, it exerts a pressure on all sides of the container. If the gas pressure is 100 psi., it exerts a force of 100 pounds (lbs.) on each square inch of the container area. Similarly, if a liquid is placed in a can, it exerts a pressure on the sides and bottom of the container due to the weight of the liquid which is also expressed as psi. In well control, both of these effects are of the utmost importance.

Pressure can be expressed as absolute or as gauge pressure. Absolute pressure includes atmospheric pressure which is also applied due to the weight of the atmosphere and is 14.7 psi. Some gauges, especially BHP gauges, are calibrated in absolute terms, but regular gauges showing psig. indicate they have been calibrated at atmospheric pressure and the 14.7 psi. is excluded. Although this is a relatively small amount and can be ignored in most instances, it is important when gathering data for reservoir analysis.

7.1.1 Fluid Pressure

A fluid is any substance that is not solid and can flow. Liquids, like water and oil are fluids. Gas is also a fluid. Under certain conditions, salt, steel and rock can become fluid and in fact almost any solid can become fluid under extreme pressure and temperature. In well control, fluids such as gas, oil, water and completion fluids, brines and mud are encountered.

Fluids exert pressure which is caused by the density, or weight of the fluid. This is normally expressed in pounds per gallon (ppg) or pounds per cubic foot ( lbs./ft.3 ). Other abbreviations for these are lbs/gal and ppf 3 . As the pressure developed by a fluid is relative to the true vertical depth, it is often expressed as psi. per foot (psi./ft.). This is termed the fluid’s pressure gradient. The pressure gradient for a fluid is relative to the fluid’s weight or density. The higher the density, the higher the pressure gradient. To understand this relationship, it is helpful to visualise a cubic foot of fluid; See Figure 7.1.

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Figure 7.1 - Fluid Pressure Diagram

A cubic foot contains 7.48 US gallons.

Therefore, a fluid weighing 1 ppg would weigh 7.48 lbs.

The pressure exerted on the base (area) is:

7.48 lbs. 2 1––––––– ft.2 = 7.48 lbs./ft.

1 ft.2 = 12 ins. x 12 ins. area = 144 ins.2, therefore the pressure per ins.2 is

7.48 lbs. 144––––––– ins.2 = 0.052 psi.

This relationship between a fluid weight in ppg and gradient pressure in psi./ft. is always the same, therefore 0.052 is a constant.

Example:

The pressure gradient of a 10 ppg fluid = 10 ppg x 0.052 = 0.52 psi./ft.

Example:

The weight of a fluid (fresh water) which has a gradient of 0.433 psi./ft.

0.433 psi./ft –––––––––– 0.052 = 8.33 ppg.

This constant is probably the most useful constant used in calculations.

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7.1.2 Specific Gravity

Many fluids in the oilfield are also expressed in specific gravity (SG) as well as weight in ppg. It is also necessary to be able to convert SG to pressure gradient in order to calculate hydrostatic pressures.

SG is the ratio of the weight of a fluid (liquid) to the weight of fresh water. Fresh water weighs 8.33 ppg and salt water is nominally valued at 10 ppg. Therefore, the SG of salt water is:

SG of Salt Water =10ppg ––––– = 1.2 8.3ppg

The SG of fresh water is 1.0. As the gradient of fresh water is known to be 0.433 psi./ft., to obtain the gradient of a fluid, it is simply necessary to multiply its SG by 0.433 psi./ft.

Example:

What is the hydrostatic pressure (HP) exerted by a true vertical 5,000 ft. column of brine with an SG of 1.17?

HP of brine = 1.17 x 0.433 psi./ft. x 5,000 ft.

= 2,533 psi.

7.1.3 API Gravity

API gravity is another value used to express relative weight of fluids and was introduced by the American Petroleum Institute to standardise the weight of oilfield fluids at a base temperature of 60˚ F. Water in this case was also used as the standard and assigned the value of 10 API gravity.

To convert from specific gravity to API gravity, the following formula is used.

141.5 SG = –––––––––– 131.5 + API

Example:

What is the SG of 30˚ API oil?

141.5 SG =131.5 ––––––––– + 30˚ = 0.876

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7.1.4 Hydrostatic Pressure

Hydrostatic pressure (HP) is the pressure developed by a fluid at a given true vertical depth in a well. ‘Hydro’ means water, or fluids which exert pressure like water and ‘static’ means motionless. So hydrostatic pressure is the pressure created by a stationary column of fluid. The hydrostatic pressure of any fluid can be calculated at any true vertical depth (TVD) provided the pressure gradient of the fluid is known.

The previous calculations have dealt with fluid pressure with a gradient of one foot depth but it is now simple to determine the pressure exerted by a fluid at any true vertical depth by multiplying that pressure gradient by the true vertical height of the column in feet. The true vertical height of the column is the important factor in the equation, as it’s volume or shape is irrelevant.

The equation is: HP = PG x TVD where:

HP = Hydrostatic pressure, psi. PG = Pressure gradient, psi./ft. TVD = True Vertical Depth, ft.

Figure 7.2 - Measured Depth verses True Vertical Depth

Example:

A 500 ft. TVD column of fresh water, what is the hydrostatic pressure ?

HP = 0.433 psi./ft. x 500 ft.

= 216.5 psi.

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Example:

What is the hydrostatic pressure of a 6,750 ft. well, filled with a 0.478 psi./ft. pressure gradient fluid which has a TVD of 6,130 ft. ?

HP = 0.478 psi./ft. x 6,130 ft.

= 2,930 psi.

Example: A 12,764 ft. TVD well is filled with a 15 ppg fluid, what is the BHP?

HP = 15 ppg x 0.052 x 12,764 ft.

= 9,956 psi.

Equipped with this knowledge, it is now easy to calculate the hydrostatic pressure with two of more fluids in a well provided the depths (TVD) of the fluid interfaces are known. Using the same formula, the HP for each fluid section is calculated in the same way and the sum of the individual calculations gives the HP at the bottom hole or well.

Example:

A 10,500 ft. TVD well has two fluids in the well, a 15 ppg fluid from TD to 7,125 ft. and 8.33 ppg fluid to surface, what is the HP at the bottom of the well ?

HP of 15 ppg fluid = 15 ppg x 0.052 x (10,500 - 7,125) ft.

= 15 ppg x 0.052 x 3,375 ft.

= 2,633 psi.

HP of 8.33 ppg fluid = 8.33 ppg x 0.052 x 7,125 ft.

= 3,086 psi.

Total HP = 2,613 psi. + 3,086 psi.

= 5,719 psi.

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7.1.5 Gas Correction Factors

Most well servicing operations entails working with live wells whether using a through- tubing method or rig intervention. Even with a rig operation, the well must be prepared by being killed prior to the intervention. This involves dealing with gas in the well.

Production wells with gas in the fluids will exert a static surface pressure equal to the formation pressure less the hydrostatic pressure in the production bore. The gas entrained in the productions fluids will segregate from the liquids as shown in Figure 7.3. In a static situation, the closed in tubing head pressure (CITHP) and hydrostatic pressure will balance the formation pressure.

As discussed earlier, gas is also a fluid and exerts a hydrostatic pressure. Being compressible pressure affects the density of the gas. A set of correction factors are used which are used to calculate hydrostatic pressures at varying TVDs with a range of gas gravities, refer to Table 7.1. The correction factor, according to the TVD of the gas column and the gas gravity, is multiplied by the CITHP:

HP = (Correction factor-1) x CITHP or

Total Gas Pressure = Correction Factor x CITHP i.e. surface pressure + gas hydrostatic

Example:

What is the HP of a 5,000 ft. TVD column of 0.7 SG gas with a closed in tubing head pressure of 1,650 psi?

HP of gas = (1.129-1) x 1,650 psi.

= 212.85psi.

Using the calculations already given in earlier sections and the gas correction factors, hydrostatic pressures in relatively complicated systems can now be determined.

Example:

What is the differential pressure between the annulus and tubing at a circulation device installed at a depth of 8,200 ft. TVD in the tubing string ?

• The following are the well conditions: • The tubing/casing annulus is filled with a 10.29 ppg brine. • The well is shut in at surface with a CITHP of 600 psi. • There is a gas cap of 0.6 SG gas from 4,000 ft. • There is 32 API oil from 4,000 ft. to 12,000 ft.

To help in the calculation, it is sometimes better to make a sketch; See Figure 7.3.

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600 CITHP

0.6 SG Gas

Annulus Fluid 77 lbs/cu ft

Gas/Oil Interface @ 4000 ft

32 API Oil

Circulating Point @ 8,200 ft

Packer

Figure 7.3 - Example of Production Well

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Well Depth Correction Factors 0.6 Gravity 0.7 Gravity 0.8 Gravity 0.9 Gravity 3,000 1.064 1.075 1.087 1.098 3,500 1.075 1.089 1.102 1.115 4,000 1.087 1.102 1.117 1.133 4,500 1.098 1.115 1.133 1.151 5,000 1.110 1.129 1.149 1.169 5,500 1.121 1.143 1.165 1.187 6,000 1.133 1.157 1.181 1.206 6,500 1.145 1.171 1.197 1.224 7,000 1.157 1.185 1.214 1.244 7,500 1.169 1.204 1.232 1.264 8,000 1.181 1.214 1.248 1.282 8,500 1.193 1.239 1.266 1.304 9,000 1.206 1.244 1.282 1.324 9,500 1.218 1.259 1.302 1.345 10,000 1.232 1.275 1.320 1.366 10,500 1.244 1.289 1.338 1.388 11,000 1.257 1.306 1.357 1.410 11,500 1.270 1.322 1.376 1.433 12,000 1.282 1.338 1.395 1.455 12,500 1.297 1.354 1.415 1.477 13,000 1.311 1.371 1.434 1.500 13,500 1.324 1.388 1.455 1.523 14,000 1.338 1.405 1.475 1.548 14,500 1.352 1.422 1.495 1.573 15,000 1.366 1.438 1.515 1.596

Table 7.1 - Gas Correction Factors

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HP of brine in annulus at circulation device:

= 10.29 ppg x 0.052 x 8,200 ft.

= 4,387 psi.

HP of gas cap: = (1.087 (from table)-1) x 600 psi.

= 52 psi.

HP of oil column 141.5 Oil SG = –––––––– 131.5 + 32

= 0.865

HP of oil column = 0.865 SG x 0.433 psi./ft. x (8,200 - 4,000) ft.

= 1,575 psi.

Total HP in tubing = HP of gas + HP of oil

= 52 psi. + 1,575 psi.

= 1,627 psi.

BHP in tubing = surface + HP of gas + HP of oil

= 600 + 1,627

= 2227 psi

Differential pressure across circulation device

= HP of annulus - HP of tubing

= 4,387 psi. - 2,227 psi.

= 2,160 psi. If the circulation device were to be opened, then the opening toolstring would be exposed to 2,160 psi. differential pressure. If using wireline, this pressure differential would need to be equalised before opening the device.

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7.2 FORMATION PRESSURE

Some rocks contain fluids like water, oil and gas which are contained in tiny openings or pores. In a rock with pores, the measurement of the ratio of the pore volume to volume of the rock material is termed ‘porosity’. The linkage between pores is the flowpath for any fluids and is extremely important, e.g. a rock with many large pores which are not interconnected will not have any flow potential to the hole drilled into the formation, i.e. the fluids would be locked in place. The interconnection of pores make the rock permeable and the measurement of this factor is termed ‘permeability’.

Formation pressure is the pressure of the fluids contained in the pores of a formation rock and are classified into three categories:

• Normal • Subnormal • Abnormal.

Formation pressure or pore pressure is said to be normal when it is caused solely by the hydrostatic head of the sub-surface water contained in the formations and there is pore to pore pressure communication with the atmosphere.

Dividing this pressure by the true vertical depth gives an average pressure gradient of the formation fluid, normally between 0.433 psi./ft. and 0.465 psi./ft. The North Sea area pore pressure averages 0.452 psi./ft. In the absence of accurate data, 0.465 psi./ft., which is the average pore pressure gradient in the Gulf of Mexico, is often taken to be the ‘normal’ pressure gradient.

NOTE: The point at which atmospheric contact is established may not necessarily be at sea-level or rig site level.

Prior to a well intervention, all the well’s parameters are generally well known and the risk of encountering unexpected formation pressures is small. If there is any doubt over formation pressure, a BHP survey should be conducted as the first operation in the programme.

7.2.1 Sub-normal Formation Pressure

Subnormal pressures occur in formations where the pressure gradient is less than ‘normal’. These are found mainly in mountainous areas or in producing formations where fluids have been extracted reducing the formation pressure.

7.2.2 Normal Formation Pressure

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For example, formation water with a salinity of 80,000 ppm sodium chloride (common salt) at a temperature of 25˚C has a pressure gradient of 0.465 psi./ft. Fresh water (zero salinity) has a pressure gradient of 0.433 psi./ft.

Temperature also has an effect as hydrostatic pressure gradients will decrease at higher temperatures due to fluid expansion.

In formations deposited in an offshore environment, formation water density may vary from slightly saline (0.44 psi./ft.) to saturated saline (0.515 psi./ft.). Salinity varies with depth and formation type. Therefore, the average value of normal formation pressure gradient may not be valid for all depths. For instance, it is possible that local normal pressure gradients as high as 0.515 psi./ft. may exist in formations adjacent to salt formations where the formation water is completely salt-saturated.

7.2.3. Abnormal pressure

A pressure which is higher than the definition given for normal pressure is abnormal. The principal causes of abnormal pressures are:

Under-compaction in shales

When first deposited, shale has a high porosity. More than 50% of the total volume of uncompacted clay-mud may consist of water in which it is laid. During normal compaction, a gradual reduction in porosity accompanied by a loss of formation water occur as the thickness and weight of the overlaying sediments increase. Compaction reduces the pore space in shale, as compaction continues water is squeezed out. As a result, water must be removed from the shale before further compaction can occur. Not all of the expelled liquid is water, hydrocarbons may also be flushed from the shale.

Salt Beds

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Mineralisation

Tectonic Causes

This is a compacting force that is applied horizontally in sub-surface formations. In normal pressure environments water is expelled from clays as they are being compacted with increasing overburden pressures. If however an additional horizontal compacting force squeezes the clays laterally and if fluids are not able to escape at a rate equal to the reduction in pore volume the result, will be an increase in pore pressure; See Figure 7.4.

Faulting

Faults may cause abnormally high pressures. Formation slippage may bring a permeable formation laterally against an impermeable formation preventing the flow of fluids. Non- sealing faults may allow fluids to move from a deeper permeable formation to a shallower formation. If the shallower formation is sealed then it will be pressurised from the deeper zone.

Diapirism

A salt diapirism is an upward intrusion of salt to form a salt dome. This upthrust disturbs the normal layering of sediments and over pressures can occur due to the folding and faulting of the intruded formations.

Extension Extension

Compression Compression

Compression Compression Amount of Shortening

Possible Overpressured Zones

Figure 7.4 - Abnormal Formation Pressure Caused by Tectonic Compressional Folding

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Reservoir Structure

Abnormally high pressures can develop in normally compacted rocks. In a reservoir in which a high relief structure contains oil or gas, an abnormally high pressure gradient as measured relative to surface will exist as shown in the following Figure 7.5.

Figure 7.5 - Reservoir Structure

Figure 7.5a Shows how the anticline differs from a dome in that it’s shape is long and narrow.

Figure 7.5b Shows a simple structural trap.

Figure 7.5c Shows stratigraphic trap. The size of the stratigraphical trap on the left is limited only by it’s hydrocarbon content while the one on the right is self limiting.

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7.3 FORMATION FRACTURE PRESSURE

The amount of pressure a formation can withstand before it splits is termed the fracture pressure. The pressure of fluid in a well must exceed formation pressure before the fluid can enter a formation and cause a fracture. Fracture pressure is expressed in psi., as a gradient in psi./ft., or as a fluid weight equivalent in ppg.

In order to plan a conventional rig well intervention, it is necessary to have some knowledge of the fracture pressures of the formation to be encountered. If wellbore pressures were to equal or exceed this fracture pressure, the formation would break down as the fracture was initiated, followed by loss of workover fluid, loss of hydrostatic pressure, loss of primary well control and irreparable damage to the formation. Most operating companies have strict policies and procedures to ensure the fracture pressure is never exceeded (unless the formation was to be deliberately fractured for reservoir productivity improvement through sand fracing operations, etc.). Unless the service is to conduct remedial operations on or in the casing across the formation, it is preferred to isolate the formation from the kill fluid by installing a barrier or plug.

Fracture pressures are related to the weight of the formation matrix (rock) and the fluids (water/oil) occupying the pore space within the matrix, above the zone of interest. These two factors combine to produce what is known as the overburden pressure. Assuming the average density of a thick sedimentary sequence to be the equivalent of 19.2 ppg then the overburden gradient is given by:

0.052 x 19.2 = 1.0 psi./ft.

Since the degree of compaction of sediments is known to vary with depth, the gradient is not constant.

Onshore, since the sediments tend to be more compacted, the overburden gradient can be taken as being close to 1.0 psi./ft. Offshore, however the overburden gradients at shallow depths will be much less than 1.0 psi./ft. due to the effect of the depth of seawater and large thickness of unconsolidated sediment.

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7.4 FORMATION INTEGRITY TESTS

To determine the fracture pressure of a formation, a leak-off test (LOT) or a formation integrity test (FIT) may be performed with a solids carrying fluid or mud. Where solids free workover fluids are used, a formation integrity test cannot be conducted and in these cases the formation is protected solely by a MAASP which is set at a safe percentage of the original casing pressure rating; Refer to Section 7.5.

LOTs and FITs determine if the cement seal between the casing and the formation is adequate and the maximum pressure or fluid weight that the formation(s) can withstand without fracturing. As the leak-off test actually causes a fracture to determine the fracture gradient, it is rarely used in well servicing operations and the FIT is adopted.

Whichever is to be performed, it must be ensured that the well is fully circulated to the correct weight workover fluid and the pump deliverability is sufficient.

Leak-Off Test

A typical procedure is as follows:

• Before starting, gauges should be checked for accuracy. The upper pressure limit should be determined. • The casing should be pressure tested before well operations commence. • Circulate and condition the mud, check mud density in and out. • Close BOPs. • With the well closed in, the pump is used to pump a small volume at a time into the well typically a 1/4 or 1/2 bbl per min. Monitor the pressure build up and accurately record the volume of mud pumped. Plot pressure versus volume of mud pumped. • Stop the pump when any deviation from linearity is noticed between pump pressure and volume pumped. • Bleed off the pressure and establish the amounts of mud, if any, lost to the formation.

Examples of leak-off test plot interpretation:

In non-consolidated or highly permeable formations fluid can be lost at very low pressures. In this case the pressure will fall once the pump has been stopped and a plot such as that shown in Figure 7.6a will be obtained. Figure 7.6b and Figure 7.6c show typical plots for consolidated permeable and consolidated impermeable formations respectively.

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a) Unconsolidated Formations b) Consolidated Permeable Formations Pressure Pressure

Cumulative Volume Cumulative Volume

c) Consolidated Impermeable Formations

Final Pumping Pressure After Volume Increment

Final Static PressureAfter Each Volume Increment

Leak-Off Point Pressure

Cumulative Volume

Figure 7.6 - Idealised Leak-Off Test Curves

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Formation Integrity Test

An FIT can be performed when it is not acceptable to fracture a formation. In a FIT, fluid is pumped into the shut in well until a predetermined pressure is reached that is determined to be below the pressure to break down the formation. This value used is usually obtained by assessing information from well’s completion report and nearby well data.

The procedure is:

1. Before starting, gauges should be checked for accuracy. 2. The casing should be pressure tested before well operations commence. 3. Circulate and condition the mud, check mud density in and out. 4. Close BOPs. 5. With the well closed in, the pump is used to incrementally raise the pressure in the well to the test pressure and monitor the pressure to ensure that there is no leak off.

7.5 MAXIMUM ALLOWABLE ANNULUS SURFACE PRESSURE - MAASP

With data from the formation integrity test, the maximum pressure which can be applied without fracturing the formation and the maximum fluid weight can be determined.

The formation breakdown pressure

= Applied surface pressure + hydrostatic pressure of fluid in the casing

The applied surface pressure at which leak-off occurred or at FIT pressure, is the maximum allowable annulus surface pressure with the fluid weight in use at that time. MAASP is the maximum surface pressure that can be tolerated before reaching the formation fractures.

MAASP = Formation breakdown pressure - HP of fluid in use at the formation

or re-written as:

MAASP = (Fracture gradient - Fluid gradient) x TVD of formation

or as:

MAASP = (Max. equivalent fluid weight - Fluid weight in well) x (0.052 x TVD of formation).

MAASP is only valid if the well is full of the original fluid during the LOT or FIT; if the fluid weight in the well is changed, MAASP must be recalculated.

The calculated MAASP is no longer valid if influx fluids enter into the well.

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However, in practise MAASP is calculated as a percentage of the original casing burst pressure rating. This percentage is derived from experience and the age of the well casings, i.e. if the well is old and it is suspected there is casing corrosion or wear, the percentage will be lower than that of a more recently developed well. In general, the pressure rating is 80% of original burst. This pressure is used in the equation in place of the formation breakdown pressure.

7.6 CIRCULATING PRESSURE LOSSES

Friction is resistance to movement. A force is required to overcome friction of a body or substance from a position of rest to movement. The amount of friction to overcome this resistance is dependent upon a number of factors:

• Density of the body or substance. • Type of substance. • Roughness of the surfaces making contact. • Surface area in contact. • Thermal and electrical properties. • Direction of movement. • Velocity. • The force required to overcome friction is termed frictional loss.

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8.1 WELL PREPARATION 8-1

8.2 REVERSE CIRCULATION 8-2

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8. PRODUCTION WELL KILL PROCEDURES

The most likely involvement of the use of well kill procedures during a live well intervention is to prepare it for a dead well workover. This entails killing the well by displacement of the well fluids from the completion tubing and sump to workover fluid. There are a number of kill procedures that are available depending on the circumstances that prevail such as tubing and casing integrity, ability to circulate the fluid in the annulus, formation pressure and characteristics of the completion methods and formation parameters that may control techniques such as reverse pumping into the formation. Individual wells must be evaluated to determine the most effective procedure. The most common well control methods are:

• Reverse circulation • Bullheading • Lubricate and bleed. • Deploying Coiled Tubing and displacing tubing.

As the completion tubing is normally full of well fluids and the tubing/casing annulus full of completion or packer fluid, then it is easier to conduct a reverse circulation kill as the gravities of the fluids will tend to keep them segregated as they are pumped up the tubing. The preferred method is to install a wireline set plug as low as possible in the well below the packer (e.g. packer tailpipe), if possible, to isolate the formation from the kill fluid, and then reverse circulate to kill the well.

Bullheading is only recommended where it causes no damage to the formation and some operators have strict policies stating if, and under what conditions, this method may be used.

Lubricate and bleed is the least preferred and is only used when there is some obstacle to conducting the other methods. For instance, it may be a combination of an obstruction in the tubing which prevents the running of wireline to open a circulating path (e.g. a partially closed valve) and a blockage or tight formation preventing bullheading.

8.1 WELL PREPARATION

Prior to initiating well killing operations, several safety precautions must be exercised. The well must be shut-in in advance of operations to stabilise bottomhole pressure and allow time to inspect and service the Xmas tree. The tree valves and sub-surface safety valves should be tested to ensure they comply with API criteria. Where practicable, each annulus should be checked for H2S and any found dealt with.

The well shall then be isolated from all external control systems, the lines isolated by double barrier isolation and depressurised. The only exception is during kill operations when hydrocarbons are being flowed to the production system.

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8.2 REVERSE CIRCULATION

This kill method is the safest, and probably the simplest, as it uses the natural U-tubing effect, of the different gravities of fluids in the annulus and tubing, to flow the well fluids out through the Xmas tree choke and existing flowlines to the production facilities. The only pump pressure required is to equalise across the circulation device before opening and, when the kill fluid is near in balance tubing-to-tubing/casing annulus and circulating friction losses need to be overcome.

This method requires a circulation path between the tubing and tubing/casing annulus to be opened by operating a circulation device in the completion string or punching a hole with wireline. The procedure is even more effective if a plug can be installed to isolate the completion/ packer and kill fluid from the formation, but this is dependent upon the whether or not operations are to be carried out below this point. If there is no plug, the old dirty completion/ packer fluid may contaminate the formation if losses occur before the clean kill fluid gets around into the tubing. The well is circulated with a back pressure maintained on the tubing so that a constant bottomhole pressure can be maintained so as to eliminate any further flow of reservoir fluids into the well. In other words, maintaining a hydrostatic head on a formation that is greater than the actual formation pressure, but obviously one that is not too much greater, otherwise there will be excessive fluid loss, or even fracturing of the formation. To prevent any further inflow of formation fluids it is common practice to maintain a tubing pressure that is some 200 psi. higher than the shut-in pressure. This will ensure that when pumping is started, the kill fluid pressure on the formation will be higher than the formation pressure. As the kill fluid is pumped to the tubing the surface pressure can be slowly reduced in proportion to the amount of fluid rise in the tubing.

One of the main reasons for using the reverse circulation method is that it is easier to pump maintaining oil and/or gas on top of the kill fluid than it is to force the oil and gas down below the kill fluid. There is as a result far less contamination of the kill fluid with well fluids, and there is less of a problem in establishing a clean kill fluid for circulation.

The slightly higher hydrostatic head on a formation is maintained during the kill operation reducing the chance of influx of the formation fluids. As the kill fluid moves up the tubing, the back pressure held on the tubing head is reduced. This can be shown in the form of a graph with tubing head pressure against time (assuming a constant pumping rate) or tubing head pressure against quantity pumped; See Figure 8.1.

The operator on the choke will reduce pressure in accordance with the graph which is based on tubing capacity and the pumping rate. If there is a fluctuating pump rate then there will have to be communication between the pump operator and the operator on the tubing head so that the pressure is reduced at the correct rate.

The reverse circulation method can be used for all types of wells except possibly those with very high production rate and very low reservoir pressure. In this case it is not possible to have a kill fluid of sufficiently low hydrostatic head to kill the well without heavy losses or where it is not possible to fill the tubing without exceeding the reservoir pressure.

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An alternative method of using a circulation kill method is to use coiled tubing which can be run into the well under pressure. The well can then be killed by pumping mud down the small bore coiled tubing and back up the tubing/coiled tubing annulus. The procedure is the same as for the reverse circulation kill though, of course, this is actually a forward circulation procedure. The back pressure is held as before on the tubing to control the bottomhole pressure. This method would be used where it was not possible to establish communication around the tubing shoe or through a sliding sleeve, and where it is not desirable to bullhead.

Tubing Volume TUBING PRESSURE (PSI)

BARRELS PUMPED

Figure 8.1 - Typical Reverse Circulation /Tubing Pressure Chart

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8.2.1 Example Of A Reverse Circulation (No Tubing Plug Installed)

Consider the following scenario:

• Vertical land well completed 7 years previous. • Closed in tubing head pressure 1,725 psi. • Closed in annulus head pressure 1,725 psi. • Inhibited water in annulus of gradient 0.435 psi./ft. • Production casing 7 ins, 38 lbs./ft. C75 • HC-Packer at 8,000 ft. 1 • Production tubing 3 /2 ins. 12.6 lbs./ft. C75 VAM. • Gas lift mandrel installed at 5,600 ft. for gas lift assist. • Perforations at 8,250 ft. just below packer.

The annulus gas lift pressure was bled off to zero in preparation for the annulus to be filled with water. However, the annulus pressure increased again to its initial value in 18 hours indicating a leak in the tubing. Wireline services retrieved the sub-surface safety valve (SCSSV) and run a gauge ring to the landing nipple below the production packer.

A dummy safety valve was set in the SCSSV landing nipple and no increase in annulus pressure was observed when the annulus pressure was bled down indicating the leak was at the SCSSV.

Attempts to set a plug below the packer failed possibly due to corroded tubing.

Wireline identify the location of tubing fluids as follows:

• Gas (0.1 psi./ft.) - 5,250 ft. to surface. • Oil (0.4 psi./ft.) - 8,250 to 5,250 ft.

Generate an appropriate procedure to kill the above well ensuring that the BHP does not exceed the reservoir pressure by 150 psi. and construct a kill graph.

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Step 1: Calculate The Annulus and Tubing Capacities

Using tables:

a) Capacity of 7 ins. casing (38 lbs./ft.) = 0.034 bbls./ft.

1 b) Closed end displacement of 3 /2 ins. tubing = 0.0119 bbls./ft.

1 c) Capacity of 7 ins. x 3 /2 ins. annulus = 0.0340 – 0.0119 = 0.0221 bbls./ft.

1 d) Capacity of 3 /2 ins. tubing (12.7 lbs./ft.) = 0.0073 bbls./ft.

Step 2: Calculate The Well Volumes

a) Tubing volume above packer = 8,000 x 0.0073 = 58.4 bbls. b) Annulus volume above packer = 8,000 x 0.0221 = 176.8 bbls. c) Total well volume above packer = 58.4 + 176.8 = 235.2 bbls. d) Volume of oil in tubing above packer (8,000 – 5,250) x 0.0073 = 20.07 bbls. e) Volume of oil in tubing to perfs. (8,250 – 5,250) x 0.0073 = 21.90 bbls.

NOTE: It is expected that most of the tubing oil below the packer will be displaced by annulus fluid (0.435 psi./ft.) filtering through to the perforations.

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1725 psi

5250 ft 1725 psi 5600 ft

8000 ft

gas lift valve in SPM

0.1 Gas 0.433 Brine 0.435 Brine 0.4 Oil

(Gradients in psi / ft)

Figure 8.2 - Initial Well Status

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Step 3: Calculate The Required Kill Fluid Weight To Balance Reservoir Pressure

a) Pres = 1,725 + 5,250 x 0.1 +3,000 x 0.4 = 3,450 psi. at perforation. 3,450 b) Kill fluid gradient = ––––– = 0.418 psi./ft. 8,250

and hence fresh water (gradient 0.433 psi./ft.) can be used to kill the well as it provides a hydrostatic pressure of 3,572psi

Step 4: Determine The Kill Plan

Since it takes 18 hours for pressure equalisation between the tubing and annulus, the tubing leak must be small. Since a gas lift mandrel was set at 5,600 ft. it seems likely that the fluid level in the annulus is at this depth.

The preferred method to kill the well is a reverse kill method. Therefore holes must be punched in the tubing as close as possible to the packer; this can be performed using wireline techniques using explosive tubing perforators.

Tentative well kill plan:

1. Connect one side outlet of the tubing head spool (THS) to a pump with a pressure rating of at least 5,000 psi.; this can be a cement pump. 2. Connect the other side outlet of the THS to a choke manifold. 3. Install a wireline lubricator on to the Xmas tree. 4. Pressure test all surface equipment as per company policy. 5. Connect the suction line of the pump to the kill fluid tank of sufficient capacity; in this case a minimum of 300 bbls. will be required. 6. Connect the outlet of the choke manifold to a separator and the outlet of this separator to the kill fluid tank. 7. Calibrate the brine tank and install a level indicator. 8. Start the pump and open the choke. Manipulate the choke in such a way that the annulus pressure remains initially at 1,725 psi.

Every barrel of kill fluid pumped into the annulus represents an equivalent height of: 1 –––––– = 45.2 ft. 0.0221

which provides a hydrostatic head of 45.2 x 0.433 = 20 psi.

The increase in hydrostatic pressure in the annulus will be 20 – 45.2 x 0.1 = 15 psi.

The volume of kill fluid to fill the annulus (assumed initial level of 5,600 ft.) will be

5,600 x 0.0221 = 124 bbls.

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This implies that the annulus pressure will need to be reduced by 15 psi. for every barrel of kill fluid that fills the annulus.

9. Monitor the volume of kill fluid in the tank continuously. The choke must be manipulated such that the annulus pressure (pump pressure) will drop by the calculated amount (15 psi.) for every barrel lost to the annulus. 10. Keep circulating and manipulating the choke until the entire annulus is filled with kill fluid. 11. Connect the choke manifold to the production side outlet of the Xmas tree. 12. Pressure test all connections as per company policy. 13. Connect the outlet of the separator to an empty tank of sufficient capacity. In this case a minimum of 100 bbls. will be sufficient. 14. Perforate the tubing just above the packer.

Hydrostatic pressure in annulus at tubing holes:

5,600 x 0.433 + (8,000 – 5,600) x 0.435 = 3,469 psi.

Hydrostatic head in tubing at holes:

1,725 + 5,250 x 0.1 + (8,000 – 5,250) x 0.4 = 3,350 psi.

Differential pressure will be 3,469 – 3,350 = 119 psi. which could cause problems during wireline operations.

15. Start pumping kill fluid into the annulus such that the THP follows the calculated kill graph which ensures that the bottomhole pressure will be equal to or slightly above the reservoir pressure. 16. Continue circulating until the well is filled with kill fluid. 17. Check for fluid losses. If severe losses are observed then consideration should be given to acid degradable LCM materials as a kill fluid additive or a cement plug installed. 18. Check that the well does not flow.

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1725 psi

5250 ft 0 psi 5600 ft

8000 ft

0.1 Gas 0.433 Brine 0.435 Brine 0.4 Oil

(Gradients in psi / ft)

Figure 8.3 - Circulating Start Point

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Step 5: Constructing The Kill Graph

The THP at the start of the kill operation will be 1,725 psi. and this pressure should drop off fairly rapidly as water (0.435 psi./ft.) enters the tubing and gas leaves the tubing at surface.

Calculate the pressure when oil reaches the surface.

a) Height of oil in tubing = 3,000 ft o

b) Height of water (0.435 psi./ft.) in tubing above packer = 5,000 ft.

c) Volume of water (0.435 psi./ft.) in the tubing above packer

= 5,000 x 0.0073 = 36.50 bbls.

d) Hydrostatic pressure of tubing contents at perforations

= 5,250 x 0.435 + 3,000 x 0.4

= 3,484 psi.

which is higher than the reservoir pressure (but not higher than 150 psi.) indicating that the well should be dead before the oil reaches the surface.

e) Height of water in the tubing above perforations = 8,250 – 3,000 – Htgas

= 5,250 – Htgas.

Total hydrostatic head in the tubing

= 0.1 x Htgas + 3,000 x 0.4 (5,250 – Htgas) x 0.435

which should equal the reservoir pressure.

0.1 x Htgas + 3,000 x 0.4 + (5,250 – Htgas) x 0.0345 = 3,450 psi.

Solving for Htgas yields Htgas = 64 ft.

The height of the water in the tubing will be 5,250 – 64 = 5,186 ft.

The volume of water in the tubing will be 5,186 x 0.0073 = 37.86 bbls.

Thus the well will be dead after pumping 37.86 bbls. of kill fluid into the annulus and the choke at the tubing outlet can be fully opened and circulation of the entire well performed with fresh water of volume 242.5 bbls.

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0 psi

0 2750 ft psi

8000 ft

0.1 Gas 0.433 Brine 0.435 Brine 0.4 Oil

(Gradients in psi / ft)

Figure 8.4- Oil at Surface

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The graph for the annulus reduction in pressure and the kill graph for the tubing pressure are shown in Figure 8.4.

2000 Annulus 2000 Tubing

1725 1725 1500 1500 psi psi 1000 1000

500 500 20 30 10 70 80 90 10 20 30 40 50 60 110 100 130 120 124 bbls bbls 37.86

Figure 8.5 - Annular Pressure Reduction and Tubing Pressure Kill Graphs

8.2.2 Bullheading or Squeeze Kill

This method consists of pumping kill fluid to the well and forcing the well fluids back into the formation without pumping at a rate which will fracture the formation, the latter being somewhat difficult when trying to kill a well with fracture production. This method is the only method possible when a well has been completed without tubing. It can also be used when the tubing has been landed in a packer and the circulation devices, such as a sliding sleeve, has jammed. This would mean that it is not possible to establish circulation around the tubing shoe or near the tubing shoe (other than by perforating the tubing).

In this method the pump rate has to be high enough to ensure that the rate the kill fluid is moving down the tubing is faster than it will free fall. This will prevent the contamination of the kill fluid by oil in an oil well, and gas cutting in a gas well. In effect, a piston effect is required so that the kill fluid is going down the tubing as a piston sweeping all the well fluids before it: An example of a bullhead/squeeze kill is shown in Figure 8.5.

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Normally this method only finds use in wells with small tubings and with high permeabilities 1 allowing adequate pumping rates. In larger tubings (3 /2"+) and in low permeability wells, this method is time consuming and difficult, resulting in gas cutting of the kill fluid especially in gas wells and wells with high gas/oil ratios. This method also has the potential draw back in that some of the kill fluid is inevitably pumped away to the formation.

Displaced Tubing Tubing Burst Limit 10570

10000

8000

7013 Maximum Allowable Static Tubing Pressure for Formation Fracture psi 6000

4000 3457 Static Tubing Displacement Pressure

2000 10 40 50 60 20 30 bbls

Figure 8.6 - Typical Bullheading Pressure Chart

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8.2.3 Lubricate and Bleed

For a gas well, or gas filled tubing, an alternative method is to use the lubrication kill. In this method varying amounts of mud are lubricated into the well, and the well pressure is bled off after each batch of mud has been lubricated into the well.

The method consists of the following steps:

Calculate the capacity of the tubing and pump half this volume of kill fluid to the well.

1 Observe the well ( /2 to 1 hour), the tubing head pressure will drop due to the hydrostatic head of the initial kill mud pumped. When the tubing head pressure is constant, the next step is taken.

Pump kill fluid for about 3 - 5 minutes, and not more than about 10 barrels, and making sure that the tubing head pressure does not go more than 200 psi. above the observed static pressure taken in step 2.

Bleed off gas from the tubing at a high rate immediately after pumping the batch of kill fluid. The amount of drop in tubing head pressure could be equal to the amount of hydrostatic head of the mud pumped. If the bleeding off is not carried out quickly, the additional pressure due to the extra hydrostatic head will cause mud losses and the sooner the tubing head is reduced, the smaller the loss will be.

Repeat the pump and bleed and observe the tubing head pressure after each step. If necessary, reduce the quantity of kill fluid if the amount of gas being bled off is excessive. After repeated pumping of batches of mud and the well is deemed dead, observe the well for a considerable period before starting and further work.

If the fluid level is too low, then the kill fluid has been too heavy and additional lighter fluid should be added until the well is full of fluid.

Alternatively, if the well will not die, it could be that too much gas was bled off or some of the kill fluid was blown out of the well during the bleed off cycle, resulting in gas flowing into the well bore. Wait for the well to settle and after re-appraising the situation, carry on with the batch and bleed procedure until the well is completely dead.

8-14 © Aberdeen Drilling Schools 2002 9. Well control equipment 9-1

9.1 GENERAL 9-1

9.2 SNUBBING OPERATIONS 9-1

9.2.1 Snubbing Operations 9-1 9.2.2 Snubbing BOP Arrangements - 0 - 5,000 psi. WP 9-2 9.2.3 Snubbing BOP Stack Arrangements - 5,000 - 10,000 psi. WP 9-4 9.2.4 Snubbing BOP Stack Arrangements - Over 10,000 psi. WP 9-6 9.2.5 Snubbing BHA Arrangements 9-8

9.3 WIRELINE OPERATIONS 9-11

9.3.1 Slickline Lubricator/Single BOP Stack Arrangement 9-11 9.3.2 Slickline Lubricator/Dual BOP Stack Arrangement 9-11 9.3.3 Braided Line Lubricator/Dual BOP Stack Arrangement 9-14 9.3.4 Electric Line Lubricator/Triple BOP Stack Arrangement 9-16

9.4 COILED TUBING OPERATIONS 9-18

9.4.1 C/T Standard BOP ConfiguratIon 9-18 9.4.2 C/T BOP Configuration with Shear/Seal BOP 9-18

9.5 SUBSEA WELL INTERVENTIONS 9-21

9.5.1 Conventional Subsea Well Interventions 9-21 9.5.2 Spool Subsea Tree Interventions 9-21 RILLIN N D G S EE CH D O R O E L B S A •

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9. WELL CONTROL EQUIPMENT

9.1 GENERAL

This section illustrates the various well control systems and equipment used with the various well intervention methods described in Section 3 and well control methods in Section 6.

9.2 SNUBBING OPERATIONS

An HWO unit is utilised on both live well interventions and dead well workovers. When utilised on workovers, the well control is similar to a rig operation, requiring the well to be killed and plugged and the Xmas tree replaced by a BOP stack on the casing head. The only difference in well control equipment may be in the workstrings used where check valves may be installed to the BHA as additional primary well control.

In place of the rig circulation system, pumps, tankage, mixing hoppers and hard piping would have to be provided unless the operation was rig assisted.

However, when used in snubbing operations, the pressure control systems are significantly different. The equipment used for snubbing operations is described in the sub-section below.

9.2.1 Snubbing Operations

Snubbing operations with an HWO unit entails installation of the well control equipment onto the top of the Xmas tree for ‘through-tubing’ work. BOP configurations for snubbing operations are shown in Section 9.2.2 overleaf. The arrangements shown illustrate stripping pipe rams for running collared pipe but an annular preventer can be used when running non- upset or tapered connections such as Hydril PH6, etc.

Workstring BHAs also contain barrier systems for primary and secondary pressure control.

NOTE: The snubbing configurations shown are generic and may not conform to individual service companies’ policy and procedures. There is no API standard for snubbing well control equipment and development of the method has been driven by the users. The configurations listed meet the absolute minimum and it would be common practice for additional safety to be added.

An equalising loop must be used when stripper rams are being used but is not necessary when using annular preventers on non-upset pipe or pipe with tapered upset connections. Equalising loops should be constructed with flanged connections.

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9.2.2 Snubbing BOP Arrangements - 0 - 5,000 psi. WP

Operating features:

1. This is the very minimum arrangement for 0 - 5,000 psi. WP and one size of pipe only. 2. If a leak occurs to either of the strippers, both pipe rams would be closed to allow repair and re-instatement of the strippers. Two pipe rams provide block and bleed. 3. Two tree valves must be available to be closed when stripping in the BHA, therefore spacing out to have enough distance to accommodate the BHA is crucial. 4. The pipe rams should not be used for stripping unless in an emergency situation. 5. When the upper pipe rams are closed, the flow line and chokes can be used.

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1 Minimum 4 /6” 10M BOP Snubbing Stack For 0 -5000 psi One Pipe Size Only

Bleed Off Threaded pipe loops Acceptable Strippers To Pump Line Safety

Choke

The Wellhead must have a minimum of two functional blind BOP’s, gate valves or a combination of both

Figure 9.1 - Example Snubbing BOP RAM Configuration

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9.2.3 Snubbing BOP Stack Arrangements - 5,000 - 10,000 psi. WP

Operating features:

1. This is the very minimum arrangement for 5,000 - 10,000 psi. WP and one size of pipe only. 2. If a leak occurs to either of the strippers, both the pipe rams would be closed to allow repair and re-instatement of the strippers. 3. Two tree valves or a combination of both tree valves and blind rams must be available to be closed when stripping in the BHA, therefore spacing out to have enough distance to accommodate the BHA is crucial. 4. When the upper-pipe or blind rams are closed, the flow line and chokes can be used. 5. The pipe rams should never be used for stripping unless in an emergency situation. 6. With drill pipe in the hole, the blind rams can be changed to pipe rams and the drill pipe can be reciprocated through the upper rams while retaining the two bottom rams in reserve. 7. The combination of shear and blind rams provide ultimate safety, if secondary well control fails.

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Minimum BOP stack for 5000 - 10,000 psi One pipe size use All flanged valves and loop

Bleed Off

Strippers

To Pump Line

Safety

Safety To Kill Line Choke

Shear Sensor Hydraulic Controlled Safety

The Wellhead must have a minimum of two functional blind BOP’s, gate valves or a combination of both

Figure 9.2 - Example Snubbing BOP RAM Configuration

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9.2.4 Snubbing BOP Stack Arrangements - Over 10,000 psi. WP

Operating features:

1. This is the very minimum arrangement for over 10,000 psi. WP and one size of pipe only. 2. If a leak occurs to either of the strippers, both the pipe rams would be closed to allow repair and re-instatement of the strippers. 3. Two tree valves or a combination of both valves and blind rams must be available to be closed when stripping in the BHA, therefore spacing out to have enough distance to accommodate the BHA is crucial. 4. When the upper pipe or blind rams are closed, the flow line and chokes can be used. 5. The upper pipe rams can be used for stripping in an emergency situation. 6. The combination of shear and blind rams provide ultimate safety, if secondary well control fails.

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Minimum BOP stack for pressure over 10,000 psi One pipe size use All valves and loop are flanged

Bleed Off

Strippers

To Pump Line Safety

Blind To Kill Line

Hydraulic Shear Choke Controlled Sensor Safety

Safety

The Wellhead must have a minimum of two functional blind BOP’s, gate valves or a combination of both

Figure 9.3 - Example Snubbing BOP RAM Configuration

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9.2.5 Snubbing BHA Arrangements

The BHA shown is typical and must be accompanied by having a safety valve on hand in the work basket.

Operating features:

1. There should be a minimum of two check valves. 2. At least one wireline nipple must be installed for secondary well control. If a leak occurs to either of the check valves, a wireline run check valve can be installed in this nipple. 3. Enough distance must be provided, especially in sandy conditions so the both check valves can be plugged. 4. Spacing out of the check valves must be such that they can be snubbed into the well above two closed barriers. 5. A tubing leak above the check valves, secondary control is provided by stabbing on the safety valve in the work basket.

Various configurations may be used for differing applications providing they meet with the minimum requirements outlined above.

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Minimum BOP stack for pressure over 10,000 psi One pipe size use (With Restrictor spool for 1”) All valves are flanged

Bleed Off

Strippers

To Pump Line Safety

Blind To Kill Line Choke

Hydraulic Controlled Sensor

Shear

Safety Safety The Wellhead must have a minimum of two functional blind BOP’s, gate valves or a combination of both

Figure 9.4 - Example Snubbing BOP RAM Configuration

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A B C D E WORK STRING WORK WORK WORK STRING STRING STRING WORK STRING NIPPLE NIPPLE NIPPLE NIPPLE LANDING NIPPLE LANDING LANDING LANDING LANDING SECONDARY SECONDARY SECONDARY SECONDARY SECONDARY BPV SINGLE JOINT SINGLE JOINT SINGLE JOINT SINGLE JOINT BPV BPV SINGLE JOINT PRIMARY BPV PUMP OUT BPV SINGLE JOINT PRIMARY PRIMARY PRIMARY PUP JOINT 6 FT LONG PRIMARY BPV BPV BPV BPV BHA BHA BHA BHA

STANDARD BPV NON-STANDARD BPV CONFIGURATIONS CONFIGURATION

Figure 9.5 - BHA Configurations

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9.3 WIRELINE OPERATIONS

Most well servicing is accomplished using wireline methods which are relatively simple to rig up and conduct operations, compared to other methods. The development of wireline pressure control systems have made this service one of the safest in the industry.

Braided line (i.e. electric line and swab line) and slickline pressure control equipment is similar in design and operation but do have some differences which are outlined below.

9.3.1 Slickline Lubricator/Single BOP Stack Arrangement

Operating features:

1. The stuffing box is adjustable (manually, or more commonly hydraulically) to cater for packing wear. 2. The lubricator is an intrinsic part of the primary well control system along with the stuffing box. 3. If the stuffing box leaks, the wireline BOP wire/blind rams can be closed on the wire to repair the packing. 4. If the rams leak, the wire can be cut with a wire cutting actuator or the upper master valve, although this may lead to valve damage.

9.3.2 Slickline Lubricator/Dual BOP Stack Arrangement

Operating features:

1. The stuffing box is adjustable (manually, or more commonly hydraulically) to cater for packing wear. 2. The lubricator is an intrinsic part of the primary well control system along with the stuffing box. 3. If the stuffing box leaks, the upper wireline BOP wire/blind rams can be closed on the wire to repair the packing. 4. If the upper rams leak, the lower rams can be used. 5. If the wire is broken and expelled from the lubricator, both rams can be closed to provide double isolation. 6. If the rams leak, the wire can be cut with a wire cutting actuator or the upper master valve, although this may lead to valve damage.

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SHEAVE

STUFFING BOX

LUBRICATOR SECTIONS

SLICKLINE LUBRICATOR AND BOP

Figure 9.6 - Slickline Lubricator and BOP

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SHEAVE

STUFFING BOX

LUBRICATOR SECTIONS

BLIND RAMS

WIRELINE RAMS

Figure 9.7 - Slickline Lubricator and Dual BOP

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9.3.3 Braided Line Lubricator/Dual BOP Stack Arrangement

Operating features:

1. The grease seal pressure is adjustable for varying well pressures. 2. The lubricator is an intrinsic part of the primary well control system along with the grease seal. 3. If the grease seal fails, both the wireline BOP wire rams can be closed on the wire. The lower ram is inverted so that grease can be injected to create a seal. 4. If the wire is broken and expelled from the lubricator, two Xmas tree valves must be closed to provide double isolation. 5. If the rams leak, the wire can only be cut with a wire cutting actuator.

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HYDRAULIC PACKING NUT STUFFING BOX

FLOW TUBE

FLOW TUBE GREASE CONNECTION

LUBRICATOR SECTIONS

BLIND RAMS

INVERTED WIRELINE RAMS

Figure 9.8 - Braided line Lubricator and Dual BOPs

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9.3.4 Electric Line Lubricator/Triple BOP Stack Arrangement

Operating features:

1. The grease seal pressure is adjustable for varying well pressures. 2. The lubricator is an intrinsic part of the primary well control system along with the grease seal. 3. If the grease seal fails, both the wireline BOP wire rams can be closed on the wire. The lower ram is inverted so that grease can be injected to create a seal. 4. If the wire is broken and expelled from the lubricator, the blind ram plus a Xmas tree valves must be closed to provide double isolation (or two tree valves). 5. If the rams leak, the wire can only be cut with a wire cutting actuator.

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LINE WIPER PACK OFF HYDRAULIC CONNECTION

GREASE CONNECTION (GREASE OUT)

GREASE CONNECTION (GREASE IN)

FLOW TUBE

TOOL CATCHER

LUBRICATOR SECTION

HYDRAULIC TOOL TRAP

QUICK UNION

TRIPLE BOP

WELLHEAD ADAPTER

Figure 9.9 - Electric Line Lubricator and Triple BOP

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9.4 COILED TUBING OPERATIONS

Coiled tubing operations are very similar in method to snubbing operations, except that the C/T unit uses an injector head with travelling chains instead of a hydraulic jacking unit. The BOP stack, however is simplified due to the coiled tubing being of smaller diameter and non- upset allowing a stripper to be used. Specialised BOPs have also been developed with gripper rams to cater for easier pipe retrieval if ever the pipe is sheared.

C/T operations are generally limited to a maximum of 5,000 psi., although this may be increased in future through new tubing technology.

Most C/T operations now use quad BOPs.

All C/T BHAs include double check valves for inside primary pressure control except in very special circumstances.

9.4.1 C/T Standard BOP Configuration

Operating features:

1. The stripper is adjustable for well pressure up to 5,000 psi. 2. If the stripper fails, the pipe rams can be closed to allow repair. 3. If the tubing is broken and falls downhole, the blind ram are closed with an Xmas valve provided the tubing is clear of the tree. 4. If the rams leak, the tubing can be cut with the shear rams and the blind rams closed. The tubing is held in place with the slip rams to aid in recovery, hence the tree valves cannot be used.

9.4.2 C/T BOP Configuration with Shear/Seal BOP

Operating features:

1. The stripper is adjustable for well pressure up to 5,000 psi. 2. If the stripper fails, the pipe rams can be closed to allow repair. 3. If the tubing is broken and falls downhole, the blind rams are closed with an Xmas valve providing the tubing is clear of the tree. 4. If the rams leak, the tubing can be cut with the shear rams and the blind rams closed. The tubing is held in place with the slip rams to aid in recovery, hence the tree valves cannot be used. 5. Tertiary well control is provided by the shear/seal BOP and is the final and last resort in the event of secondary well control failure.

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Figure 9.10 - Standard C/T BOP Configuration

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Figure 9.11 - C/T BOP Configuration with Shear Seal BOP

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9.5 SUBSEA WELL INTERVENTIONS

Subsea wells can be serviced by means of subsea workover systems. There are two systems in current use, one for conventional susbsea trees and the other for the newer generation of spool trees. The former is described in Section 9.5.1 below and the latter in 9.5.2.

9.5.1 Conventional Subsea Well Interventions

Conventional subsea well interventions are conducted through a subsea workover riser systems which are deployed from floating vessels or from jack-up rigs in shallower waters. Riser systems are attached to the top of subsea Xmas trees and, after completing the appropriate test procedures, allow live well servicing by wireline or coiled tubing methods.

Pressure control is provided at surface by a Xmas tree fitted with a lift frame which accommodates the pressure control equipment installed on the top of the tree. Other than this, pressure control is exactly the same as that described in the previous sections except that vessel movement gives additional rigging up and operational problems. However, the workover riser system must also have subsea pressure control capabilities in the event of a emergency disconnection or a riser failure. Subsea pressure control is provided by a subsea lower riser assembly (LRA) and an emergency disconnect package (EDP) which can safely close in the well and disconnect the riser, with or without wireline or coiled tubing through the subsea tree, in the event of an emergency.

These systems maintain the well in a safe condition until the problems arisen are overcome and the riser can be re-attached. Operations can then be recommenced and fishing operations initiated, if required.

A typical subsea workover riser system is shown in Figure 9.12

9.5.2 Spool Subsea Tree Interventions

Due to the capital costs of conventional workover riser systems, and the incompatability between the various manufacturer’s designs, this drove the industry to develop the spool tree and associated intervention systems utilising standard drilling rig subsea BOP riser systems. The subsea BOPs were utilised for connection to the tree and to provide pressure control in conjunction with a subsea test tree which latches onto the spool tree tubing hanger. Pressure is contained within the subsea tree and it’s riser to the surface which is terminated with a surface test tree in the conventional well test fashion. The BOP rams are closed on the subsea test tree slick joint to provide a barrier to any well pressure below the BOPs. In the event of an emergency, the subsea tree can be closed, the subsea riser disconnected before the BOP shear/blind rams are closed above the tree valve section and the drilling riser disconnected.

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Subsea test tree systems must have a cutting capability to sever any wireline or coiled tubing run through the BOPs.

See Figure 9.13 for typical spool tree workover system.

Figure 9.12 - Typical Subsea Workover Riser System

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Figure 9.13 - Typical Subsea Spool Tree Workover System

10.1 introduction 10-1 10.2 classification of completions 10-2

10.2.1 Classification by reservoir 10-4 10.2.2 Classification by Mode of Production 10-10 10.2.3 Classification by Number of Zones Completed 10-18 10.2.4 Horizontal Completions 10-22 10.2.5 Subsea Completions 10-26

10.3 subsea well interventions 10-30

10.4 completion equipment 10-35

10.4.1 Wireline Re-entry Guide 10-37 10.4.2 Tubing Protection Joint 10-38 10.4.3 Wireline Landing Nipples 10-38 10.4.4 Perforated Joints 10-40 10.4.5 Blast Joints 10-40 10.4.6 Packers 10-40 10.4.7 Permanent Packer Accessories 10-44 10.4.8 Sliding Side Doors (SSDs) 10-48 10.4.9 Flow Couplings 10-50 10.4.10 Side Pocket Mandrels 10-50 10.4.11 Travel Joints 10-54 10.4.12 Sub-Surface Safety Valves 10-55 10.4.13 Annulus Safety Valves 10-65 10.4.14 Surface Control Manifolds 10-67 10.4.15 Control Lines 10-68 10.4.16 Tubing 10-68 10.4.17 Tubing Hangers 10-69 10.4.18 Wellheads 10-75 RILLIN N D G S EE CH D O R O E L B S A •

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10. OVERVIEW OF COMPLETIONS

10.1 INTRODUCTION

In combination with the disciplines of geology, geophysics, and geochemistry, the usual purpose of drilling a well is to establish the subsurface location of hydrocarbon reservoirs. The term ‘completion’ is derived from the operation to complete a well for production after it has been successfully drilled. Dependent upon the reason for a well to be drilled (i.e. wild cat exploration, appraisal or production) and the results of logging and/or well test results, the well will then be:

i. Plugged and abandoned (as it has no further use i.e. a duster). ii Suspended as a future or possible production well. iii. Completed as a production well.

In the early days, if the well was to be ‘completed’ (as in iii) above, the hardware installed, i.e. packer, tubing, Xmas tree and other accessories, was termed the ‘completion’. The purpose of completing a well is to produce hydrocarbons to surface production facilities. Commercial reasons demand that this is achieved in an efficient, cost effective and safe manner throughout the producing life of the well.

Completing a well consists of a series of operations that are necessary to enable a well to produce (and to sustain the production of) hydrocarbons following the installation and cementing of the casing. Well completion operations include:

• Perforating. • Sand control. • Production packer installation. • Tubing (completion) string / tubing hanger installation. • Downhole safety valve installation. • Xmas tree installation. • Bringing the well onto production.

Well servicing methods must be considered as a fundamental element in the planning and completion design process. For example, early measurement of formation parameters (porosity, permeability) may indicate the need to stimulate (fracturing, acidising) a well to enhance the production rate. An appropriate completion design must cater for these and any future possible well servicing operations, both planned and unplanned. Similarly, subsea completions will necessitate operations such as flowline and surface safety valve installations. It should be emphasised here that such completion operations are not independent and the engineer needs to understand the basics in every area to be most effective in producing a completion design to cater for all contingencies.

An engineer, when considering completion options, should adopt a realistic approach to the overall project economics i.e. the cost of the equipment, service life, type of servicing and respective rig time etc. In general, the ideal completion is the lowest cost completion which will meet the demands placed on it during its producing life.

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In reality, many unforeseen problems can arise due to the initial available data being deficient and it is commonly seen that subsequent completion designs on a field are developed as the data base increases.

10.2 CLASSIFICATION OF COMPLETIONS

Even though different types of wells present distinct design and installation problems for the engineer, most completion types are simply variations on a few basic designs, therefore the equipment installed is generally similar. Completions may be classified with respect to the following.

Reservoir/Wellbore Interface

In the absence of formation damage, this determines the rate at which well fluid is transferred from the formation to the wellbore.

The types of completion involved here are:

• Open hole completions. • Uncemented liner completions. • Perforated liner completions. • Perforated casing.

Mode of Production

This relates to the way well fluid is transferred from the wellbore at the formation depth to the surface, i.e.:

• Flowing. • Artificial lift.

Number of Zones Completed

This effectively governs the volume of hydrocarbons recoverable from a single bore hole:

• Single. • Multiple.

Figure 10.1 indicates the types of completions and various methods used to produce well fluid to surface.

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Interval segregation Concentric String Multiple Strings

Twin String, Dual Completion Multiple Zone Multiple

Single String, Dual Completion Completed

Number of Zones of Number Interval Co-Mingling

Standard Single Zone Single

Electric Submersible Pump Plunger Lift Gas Lift

Hydraulic Pump ArtificialLift

Rod Mode of Mode

Production High Rate Liner

COMPLETIONS HighPressure

Temporary, simple, low cost Flowing

(Single String) (Single Tubingless

Internal Gravel Pack

Standard

PerforatedCasing

ells

tical/ Deviated tical/

Ve PerforatedLiner

External Gravel Pack

InterfaceBetween ellbore and Reservoir and ellbore

W Pre Packed Screen Wire Wr apped Screen

Uncemented Liner Uncemented Slotted Pipe

Horizontal Wells Horizontal

(See figure 1.13) figure (See Open Hole Open

Figure 10.1- Classification of Completions for Vertical or Deviated Wells

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10.2.1 Classification by Reservoir/Wellbore Interface

Open Hole Completions

In this type of completion the casing is set in place and cemented above the productive formation(s). Further drilling extends the wellbore into the reservoir(s) and the extended hole is not cased; See Figure 10.2.

This completion method is used where it is desirable to expose all zones to the wellbore. Producing formations must be of firm rock which will remain in place during production. Open hole completions are also referred to as ‘barefoot’ completions.

Advantages of Open Hole Completions are:

• The entire pay zone is open to the wellbore. • Perforating cost is eliminated. • Log interpretation is not critical since the entire interval is open to flow. • Maximum wellbore diameter is opposite the pay zone(s), hence gives reduced drawdown. • The well can easily be deepened. • Is easily converted to liner or perforated casing completion. • Minimal formation damage is caused by cement.

Cement Cement

Production Casing

Formation Formation

Figure 10.2 - Open Hole Completion Schematic

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Disadvantages of Open Hole Completions are:

• The formation may be damaged during the drilling process. • Excessive gas or water production is difficult to control because the entire interval is open to flow. • The casing may need to be set before the pay zone(s) are drilled and logged. • Separate zones within the completion cannot be selectively fractured or acidised. • Requires frequent clean out if producing formations are not consolidated. • May be difficult to kill if installed in a horizontal well for well servicing or workover or abandoned purposes.

Limitation of Open Hole Completions are:

• Unsuitable to produce pay zones with incompatible fluid properties and pressures. • Mainly limited to Limestone formations.

Uncemented Liner Completions

In some formations hydrocarbons exist in regions where the rock particles are not bonded together and sand will move towards the wellbore as well fluids are produced, this formation is usually referred to as being ‘Unconsolidated’. The use of uncemented liners (slotted or screened) act as a strainer stopping the flow of sand. Liners are hung off from the foot of the production casing and usually sealed off within it to direct any well flow through the liner bore.

Var ious examples of uncemented liner operations implementing sand control are as follows:

Advantages of Uncemented Liner Completions are:

• Entire pay zone open to the wellbore. • No perforating cost. • Log interpretation is not critical. • Adaptable to special sand control methods. • No clean out problems. • Wire wrapped screens can be placed later.

Disadvantages of Uncemented Liner Completions are:

• The formation may be damaged during the drilling process. • Excessive water or gas is difficult to control. • Casing is set before pay zones are drilled and logged. • Selective stimulation is not possible.

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Var ious examples of uncemented liner operations implementing sand control are as follows:

a) Slotted Liner

Slot widths depend on the size of the sand grains in the formation and are typically 0.01 ins. - 0.04 ins. (0.254 - 1.016 mm) wide; See Figure 10.3a

b) Wire Wrapped Screens

Liner is drilled with 3/8 ins - 1/2 ins. (9.53 - 12.7 mm) holes along its length and then lightly wrapped with a special V-shaped wire; See Figure 10.3b

Uncemented liner completions are not used very often since:

• Sand movement into the wellbore causes permeability (flow rate) impairment. • Screen erosion can occur at high production rates.

These problems may be overcome by filling the annulus between the open hole and screen with graded coarse sand, i.e. gravel packing, which acts to support the open hole section as well as prevent formation sand movement.

c) External Gravel Pack

The open hole is enlarged to about twice its diameter and a liner is run. Correctly sized gravel is placed between the outside of the screen and the formation by using special gravel pack running equipment; See Figure 10.3c

d) Pre-packed Screen

A Pre-packed screen is constructed of an outer and inner wrapped screens with resin coated gravel placed between the screens. This gives a performance better than a wire wrapped screen but less that an open gravel pack.

These are used when there may be difficulty in installing a gravel pack.

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Cement

Liner Hanger Production Casing

Slotted Liner

Unconsolidated Sand Formation Unconsolidated Sand Formation

a) Slotted Pipe

Slotted Liner Slotted Liner

Graded Gravel Resin Coated Gravel

b) Wire Wrapped Screen c) External Gravel Pack d) Pre-packed Screen

Figure 10.3 - Uncemented Liner Completion Schematics

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Perforated Cemented Liner Completions

In perforated cemented liner completions, the casing is set above the producing zone(s) and the pay section(s) drilled. Liner casing is then cemented in place which is subsequently punctured (perforated) by bullet-shaped explosive charges.

These perforations are designed to penetrate any impaired regions around the original wellbore to provide an unobstructed channel to the undamaged formation. By using various depth measuring devices (i.e. casing collar locator, CCL) various sections of pay zone can be perforated accurately (excluding unproductive regions), avoiding the production of undesirable fluids (gas or water), or production from unconsolidated sections that might produce sand.

The various methods of completing a well using perforated cemented liner operations are:

• Single, See Figure 10.4, or multiple pay zones. • Single or multiple pay sections.

Cement

Production Casing

Liner Liner Hanger Cement Perforations

Formation Formation

Figure 10.4- Perforated Cemented Liner Schematic

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Perforated Cemented Casing Completions

In a perforated cemented casing completion, sometimes referred to as the ‘set through’ completion, the hole is drilled through the formation(s) of interest and production casing is run and cemented across the section. Again, this requires that perforations be made through the casing and cement to reach the zone(s) of interest and allow well fluids to flow into the wellbore.

Methods of completing a well in perforated cemented casing completions are:

a) Standard Perforated Cemented Casing

See Figure 10.5a for a multiple pay zone completion.

b) Internal Gravel Packs

This is where the production casing is cemented. Perforation of the producing interval(s) is then performed and the perforations cleaned out. A screen is run and gravel is pumped into the casing/screen annulus and the perforation tunnels; See Figure 10.5b.

NOTE: Cased and perforated completions are the most common types of completions performed today since they offer selective pay zone (or pay section) perforating and enable selective stimulation.

Advantages of Perforated Casing or Liner Completions are:

• Is safer during well completion operations. • Effect of formation damage is minimal. • Excessive water or gas production may be controlled or eliminated. • The zones can be selectively stimulated. • The liner impedes sand influx. • The well can be easily deepened. • Is easier to plan for completing.

Disadvantages of Perforated Casing or Liner Completions are:

• The wellbore diameter through the pay zone(s) is restricted. • Log interpretation is critical. • Liner cementation is more difficult to obtain than casing cementation. • Perforating, cementing and rig time incurs additional costs.

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Cement Liner Hanger Perforations Production Casing Screened Liner

Graded Gravel Formation Formation

Formation Formation Formation

a) Standard b) Internal Gravel Pack

Figure 10.5- Perforated Cemented Casing Schematics

10.2.2 Classification-by Mode Of Production

When the hydrocarbon reservoir can sustain flow due to its natural pressure, flow may be up the production casing string, up the tubing string, or both.

Tubingless Completions

Casing flow completions are a particularly low-cost method in marginal flow conditions such as low rate gas wells; See Figure 10.6a.

NOTE: Casing flow completions are not normally used by most operators, primarily because the production casing is exposed to well pressure and/or corrosive fluids. Tubingless completions are potentially hazardous especially in offshore installations. As there is an increased risk of collision damage offshore and there is no facility to install downhole safety valves. The use of casing flow production methods are discouraged both offshore and onshore.

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Tubing Flow Completions

Tubing flow completions utilise the tubing to convey well fluids to surface. Flow rate potential is much lower in tubing flow than in unrestricted casing flow completions. As well as for production, the tubing string can be utilised as a kill string or for the injection of chemicals. Tubing strings may also accommodate gas lift valves which essentially ‘gas assist’ well liquids to surface; these valves would be installed if formation pressure diminished considerably and natural drive ceased.

By far the most common methods of completing a well is to use a single tubing string/packer system where the packer is installed in the production casing to offer casing protection, sub- surface well control, and an anchor for the tubing. Examples of such completions methods are:

• Simple low cost (temporary); See Figure 10.6b • High pressure; See Figure 10.6c.

Other equipment commonly installed in the tubing string to facilitate a safer production system may be:

• Wireline Nipples - Permits The Installation Of Flow Controls Or Plugs.

• Tubing Retrievable - For Emergency Well Shut-In. Safety Valve

• Safety Valve Landing - Permits The Installation Of A Surface Controlled Sub-Surface Nipple Safety Valve (SCSSV) For Emergency Shut-In.

• Flow couplings - Absorbs Erosion Caused By Turbulence And Abrasion.

• Circulating Device - Fitted Above The Packer For Circulating Purposes

• Tubing Seal Device - To Allow Tubing Movement.

A polished bore receptacle (PBR) in a liner hanger is often used in place of a packer, e.g. in a high rate liner or monobore completion; See Figure 10.6d.

Refer to Section 10.4 for completion equipment.

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High Rate Liner or Monobore

These are utilised in deep wells where tubing/casing clearances are small and for high productivity wells where the use of a packer would restrict the flow of well fluids; See Figure 10.6d.

In general, tubing and packer installations depend on the completion requirements and economic considerations. The completion engineer should consider the following factors for tubing/packer type completion installations:

• Simplification of the completion for future well servicing operations (i.e. wireline, coiled tubing, snubbing etc.). •Optimum tubing size for maximum long term flow rate. • Future artificial lift needs. • Bottom hole pressure and temperature gauge survey hang off system. • Seal movement device to accommodate tubing elongation or contraction. •Availability of downhole circulating device. • Requirements for downhole corrosion inhibitor injection. • Requirements for downhole hydrate inhibitors. •Tubing-conveyed perforating (TCP) guns and/or through tubing guns for underbalanced perforating. • Fluids to be used i.e. drilling muds, completion fluid, wellbore fluid. •Well killing.

The monobore completion was developed primarily for the North Sea area by operators to reduce the high cost of well servicing operations. The monobore, termed from the production liner and tubing having the same or similar size bores, allows much improved servicing capability by the use of ‘through tubing’ tools and services to conduct many operations which had previously required the tubing to be pulled from the well.

A liner packer and PBR is used in place of the conventional type packer to maintain the fullest bore size. Some versions are ‘full bore’ completions to retain maximum bore size which are serviced with retrievable through tubing bridge plugs or nippleless wireline locks (such as the Halliburton Monolock system) that can be set in the tubing or liner bore.

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Small Diameter Casing Production Tubing or Large Diameter Tubing Production Casing Gas Lift Valve Cement

Cement Retrievable Packer No Go Wireline Perforations Seating Nipple

Formation

a) Tubingless b) Temporary Tubing

Chemical Injection Valve

Permanent Packer Polished Large Diameter Bore Tubing Sliding Sleeve Receptacle

Millout Extension Sliding Sleeve

Perforated Joint Liner Hanger No Go Nipple Cement Liner

c) High Pressure d) High Rate Liner

Figure 10.6 - Flowing Wells (Single String) Schematics

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Artificial Lift

When a reservoir’s natural pressure is insufficient to deliver liquids to surface production facilities, artificial lift methods are necessary to enhance recovery. Various artificial lift completions methods, See Figure 10.7, and their key completion considerations are:

a) Rod Pump Lift

These pumps consist of a cylinder and piston with an intake and discharge valve. Vertical reciprocation of the rod will displace well fluid into the tubing; See Figure 10.7a. These are utilised in low to moderate wells which deliver less than 2,000 BPD (318 m3/day).

Key considerations are:

• The annulus is open. • A tubing anchor may be required. • The pump diameter must be adequate. • The rods must be properly sized.

b) Hydraulic Pump Lift

Hydraulic pump lift is utilised in crooked holes, for heavy oils and variable production conditions that cause problems for conventional rod pumping. Three types of hydraulic pump exist to lift liquid:

Piston Consists of a set of coupled pistons, one driven by a power fluid and the other pumping the well fluid; systems exist for production up the annulus, See Figure 10.7b, or up the tubing.

Jet Converts power fluid to a high velocity jet which pulls the well fluid up into the flow stream.

Turbine Power fluid rotates a shaft on which a centrifugal or axial pump is mounted; See Figure 10.7c.

Key considerations are:

• The number of flow conduits (production and power). • Pressure losses in the power and return lines. • Whether produced liquid can return up the casing. • Lubricator access to pump-in jet or piston units. • The large casing size required for turbine units. • The power fluid/oil separation facilities required. • The higher initial costs.

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c) Plunger Lift

The plunger lift system, See Figure 10.7d, is a low rate lift system in which annulus gas energy is used to drive a plunger carrying a small slug of liquid up the tubing when the well is opened at surface. Subsequent closing of the well allows the plunger to fall back to bottom. Plunger lift is useful for de-watering low rate gas wells.

Key considerations are:

• The tubing must be drifted prior to installation. • The annulus is open to store lift gas. • A nipple/collar stop must be installed to support a catcher and shock absorber.

d) Electric Submersible Pump (ESP)

An ESP is used for moving large liquid volumes of low gas/liquid ratio from reservoirs with temperatures below 250˚F, e.g. water supply wells, high water cut producers and high deliverability undersaturated oil wells; See Figure 10.7e.

Key considerations are:

• The annulus is open to atmosphere for gas venting (but not offshore). • A special wellhead is required for cable sealing. • Some cable protection is needed. • Motor cooling must be adequate. • The tubing size must be adequate to handle large volumes with minimum back pressure on the pump.

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Rod

Tubing

Plunger

Tubing Anchor / Packer Pump

Housing Travelling Valve Standing Valve Fluid Level Standing Valve Pump Seat Nipple

a) Rod Pump b) Piston Pump

Turbine Electric Liquid Load Cable

Pump Standing Valve

Bumper Spring Pump Packer Intake Tubing Stop Protector Motor

c) Turbine d) Plunger Lift e) Electric Submersible Pump

Figure 10.7 - Pump and Plunger Artificial Lift Methods

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e) Gas Lift

Gas lift supplements the flow process by the addition of compressed gas which lightens the liquid head, reduces the liquid viscosity, reduces friction and supplies potential energy in the form of gas expansion; See Figure 10.8.

Continuous gas lift is used to lift liquid from reservoirs that have a high productivity index (PI) and a high bottom hole pressure BHP. Intermittent lift is used in reservoirs that exhibit low PI/low BHP, low PI/high BHP, or high PI/low BHP.

Liquid production can range from 300 - 4,000 bbls/day (48 - 636 m3/day) through normal size tubing strings. Casing flow can lift up to 25,000 bbls/day (3,975 m3/day).

Key considerations are:

• Tubing size. • The need for a packer. • Setting depths for gas-lift valves.

Gas In

Gas Lift Valves

Packer

b) Piston Pump

Figure 10.8 - Gas Lift

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10.2.3 Classification-by Number of Zones Completed

Single Zone Completions

Flowing wells that are equipped with a single tubing string are usually completed with a packer. Single zone completions include the downhole co-mingling of production from several intervals within a pay zone. Examples of single zone completions are shown in Figure 10.9, i.e.:

a) Standard

See Figure 10.9a.

b) Interval Co-mingling

See Figure 10.9b.

At the design stage, the following options should be considered and possibly built into the completion:

• The optimum tubing size for maximum long term flow rate. • Future artificial lift needs. • Future well servicing operations.

Tubing

Packer

a) Standard b) Interval Co-mingling

Figure 10.9 - Single Zone Completion Schematics

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Multiple Zone Completions

When a well encounters multiple pay zones a decision must be made either to:

• Produce the zones individually, one after the other, through a single tubing string and the annulus.

• Complete the well with multiple tubing strings and produce several zones simultaneously.

• Co-mingle several zones in a single completion.

• Produce only one zone from that well and drill additional wells to produce from the other pay zones.

Examples of multiple zone completions are shown in Figure 10.10.

a) Single String Dual Completion

This is the most basic dual completion where production of the lower zone is up the tubing and production of the upper zone is up the casing/tubing annulus; See Figure 10.10a.

b) Twin String Dual Completion

Separate flow from each zone is maintained by the use of two tubing strings and two packers; See Figure 10.10b.

NOTE: With the installation of gas lift valves in the two tubing strings, artificial lift can be initiated at a later date.

c) Multiple String Completions

Separate flow from each zone can be maintained by the use of three tubing strings and three packers; See Figure 10.10c.

Such completions provide a method of individual zone production and can improve some field economics. However, in general, such completions are difficult to install and are usually too restrictive in regard to total well production, due to the small tubing sizes, to be economically attractive in most cases. Furthermore, the difficulty of carrying out future remedial well operations of such wells prevent their widespread use.

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d) Concentric String Completions

Concentric strings require less clearance and can often achieve a higher overall flow capability; See Figure 10.10d . The advantages of Multiple Zone Completions:

• Some individual zone production. • Reduced well cost.

Disadvantages of Multiple Zone Completions are:

• Production casing is exposed to well pressure and corrosive fluids. • Tubing can be stuck in place due to solids settling from the upper zone. • The lower zone must be killed or plugged off before servicing can be done on the upper zone. • The lower zone must be plugged off to measure any flowing bottomhole temperature associated with the upper zone.

NOTE: Multi-zone completions not only provide the separation of various zones but also the separation of individual pay sections within a thick pay zone.

e) Annulus Configurations

It is normal practice to identify an annulus configuration by an alphabetic progression from internal to external casing strings. The ‘A’ annulus is defined as the annulus within the production/liner casing.

An active annulus refers to any annulus being used for circulation purposes. An inactive annulus refers a non-circulatable annulus e.g. any annulus formed between two strings of cemented casings.

In the case of a well having an extra annulus between the production casing and the tubing, this annulus is identified separately e.g. a well on artificial lift using hydraulic pumping will have a ‘drive’ annulus.

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Dual Packer Packer

a) Single String Dual b) Twin String Dual

Concentric Tubing Strings

Triple Packer Single Packers Blast Joint

c) Multiple String d) Concentric String

Figure 10.10 - Multiple Zone Completion Schematics

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10.2.4 Horizontal Completions

In a vertical wellbore, the state of technology is such that it can be successfully cased, cemented, completed, producing zone or zones perforated and cleaned up, produced and, if the level of production is not economical, various means of stimulation (hydraulic fracturing, acidisation) used on the formation to increase productivity. By contrast, the drilling of horizontal wells and their subsequent study has indicated substantial increases in production rates as compared to unfractured vertical wells. As a result, there is now great incentive to investigate the technology required to drill, complete, test, stimulate and properly produce horizontal wells which, due to increased production, can lead to significant improvements in field economics.

From the drilling point of view, horizontal wells are classified as having ultra-short, short, medium or long turning radii into a horizontal plane. The geometrical characteristics of such horizontal wells are given in Table 10.1.

NOTE: ‘Multi-zonal’ wells are prime candidates for horizontal completions as are formations that have naturally fractured networks from which large production increases can be expected; See Figure 10.11.

Figure 10.12 shows some of the methods used to complete horizontal wells. A classification of completions for horizontal wells is shown in Figure 10.13.

Type Drilling Method Turning Radius Horizontal Length (Build-Up Radius)

Ultrashort Waterjet 1 - 2 f 100 - 200 ft. (drainhole) (-)

Whipstock. Curved drilling entry 20 - 40 ft 200 - 700 ft. Short guide flexible drilling collars (-)

Downhole mud motor. 300 - 500 ft. 700 - 2,000 ft. Medium Flexibleheavy weight drill pipe (19 - 11 deg./100 ft.)

Long Conventional drilling tools 600 - 2,000 ft > 2,000 ft. (10 - 3 deg./100 ft.)

Table 10.1 - Geometrical Characteristics of Horizontal Well Completions

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Oil Accumulations Wellbore

Figure 10.11 - Naturally Fractured Formations

Open Hole

This is the most economical type of completion where removal of mud and debris from the horizontal section is the primary stimulation performed. If additional stimulation is required, tubing or coiled tubing can be run to TD, stimulation fluid spotted into the horizontal section and then pumped into the formation; See Figure 10.12a.

Slotted Liner

This type of completion is used in the possible event of hole collapse. It is used in reservoirs that will flow naturally and where no stimulation treatments are necessary; See Figure 10.12b.

External Casing Packers

These are used for control of a single interval in the whole horizontal section of a reservoir that has different zones producing hydrocarbons. They also control water production from selective zones. External casing packers and closeable ported subs are useful in controlling unwanted production from formations along the horizontal section; See Figure 10.12c.

Packers of this type are commonly used to separate productive zones, either with or without cement. Similarly, because of the difficulty in cementing horizontal liners, many horizontal production strings are run without cementing.

For uncemented liner completions, the application of rotation can be utilised to deflate the packer for retrieval.

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a) Open Hole b) Slotted Liner

c) Uncemented Liner d) Cement Liner

Figure 10.12 - Some Methods of Completing Horizontal Wells

Fracture Stimulation

In this type of completion production casing or liner is cemented into the horizontal section. After perforating, controlled stimulation treatments (matrix and fracture) can be performed efficiently; See Figure 10.12d.

In a horizontal hole, the completion problems are more complex than in vertical wells. For example, any debris in the horizontal well bore will remain in situ and create an obstacle for moving tools or instruments. Similarly, gravity will have a profound effect on various tools in the horizontal section of the wellbore and effective centralisation and friction reduction is necessary by using roller stem.

Completion equipment currently available is capable of working satisfactorily in a horizontal well with little or no modification. The main area requiring development is in coiled tubing conveyed tools (equivalent to wireline tools). Some advance has been made with the development of sliding sleeves, mounted in the horizontal section of wells, which can be opened and closed using a coiled tubing conveyed shifting tool. Similarly, coiled tubing manipulation tools exist for packer setting in horizontal sections.

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Interface Between Wellbore and Reservoir

Horizontal Vertical / Deviated Wells Wells

See Figure 1.1

(l,m,s) (l,m) (l)

Open Uncemented External Cemented Hole Liner Casing Casing or Plaster Liner

l - long

m - medium

s - short

Slotted Pre-packed Gravel Packed (l,m,s) (l,m) (l,m)

Figure 10.13 - Classification of Completions for Horizontal Wells

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10.2.5 Subsea Completions

Offshore fields are increasingly being developed with subsea wells. In the early days subsea wells were extensively used as satellite wells only, usually located a distance away from the main production platform outside the normal reach limitations for deviated wells. Today entire fields can be produced through subsea wells to floating production systems or to nearby platforms on other fields. Subsea well top hole locations are generally clustered together (sometimes in a subsea manifold) to share production and control line facilities although single satellites are still occasionally used.

Developing an offshore field with subsea wells is a very economic method but has a drawback from the completions point of view in that vertical access requirements for well servicing intervention will inevitably be high with the need to use a MODU (Mobile Offshore Drilling Unit) or other type of well servicing vessel. Some wells have been clustered under the floating production facilities to allow vertical re-entry from the vessel, thereby reducing servicing costs. Nowadays, the availability of long-service life tubing retrievable sub-surface safety valves (TRSVs) with all metal-to-metal technology minimise the need for mechanical servicing. 'Through flowline' (TFL) servicing (see Figures 10.14 &10.15) also reduces servicing costs and is especially useful on highly deviated wells. However, no matter the attractiveness of utilising TFL systems in completion design the operational complexity, rate restriction and cost, should not be underestimated and through experience most users of TFL have now abandoned it's use due to its associated problems.

In a completed subsea well, high pressure losses can occur in the flowlines connected to surface production facilities and it is common to minimise this by incorporating gas lift valves or hydraulic pumping equipment in the completion. Subsea flowlines are also subject to substantial cooling which may result in poor oil flow properties and the requirement to install methanol injection systems in subsea components to minimise the risk of hydrate formation . Figure 10.16 shows a typical subsea wellhead arrangement.

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Fig. 10.14 - Dual String, Driver-Assist Flowlines, TFL, Satellite Tree

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Fig. 10.15 - TFL Pumpdown Components

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Alternative Arrangement Running Corrosion 128.4" Cap On Drill Pipe (3.3m)

14 Scrap view of corrosion cap running tool / corrosion cap stinger interface. (Scale 1:2) 4

12 Corrosion Cap Running Tool 128.4" P.No. 541081-A (3.3m)

10 114.3" 3 (2.9m)

2 6

Injection Tree Assy 1 P.No. 541010-A 1. 2. 3. I.L.M. 2

0 Feet Datum 0 Meter Datum Top Of Wellhead

-2

-1 Permanent Guide Base -4 P.No. 540869

-6

Fig. 10.16 Typical Subsea Wellhead System

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10.3 SUBSEA WELL INTERVENTIONS

Subsea wells can be serviced by means of subsea workover systems. There are two systems in current use, one for conventional subsea trees (Figure 10.17) and the other for the newer generation of spool trees (horizontal tree, Figure 10.18). Each of these is described below :

Conventional Subsea Well Interventions

A typical subsea workover riser system is shown in Figure 10.19.

Spool Subsea Tree Interventions

Due to the capital costs of conventional workover riser systems, and the incompatibility between the various manufacturer's designs, this drove the industry to develop the spool tree and associated intervention systems utilising standard drilling rig subsea BOP riser systems.

The subsea BOPs were utilised for connection to the tree and to provide pressure control in conjunction with a subsea test tree which latches onto the spool tree tubing hanger. Pressure is contained within the subsea tree and it's riser to the surface which is terminated with a surface test tree in the conventional well test fashion. The BOP rams are closed on the subsea test tree slick joint to provide a barrier to any well pressure below the BOPs. In the event of an emergency, the subsea tree can be closed, the subsea riser disconnected before the BOP shear/ blind rams are closed above the tree valve section and the drilling riser disconnected.

The main problem thrown up by this method of well intervention was the lack of bore size in standard subsea test tree riser systems initially available which has driven the design of systems with bores sizes now up to 7 inches in diameter. Subsea test tree systems must have a cutting capability to sever any wireline or coiled tubing run through the BOPs.

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High Pressure Cap Production Swab Valve

Annulus Swab Valve Crossover Valve

Production Wing Valve Annulus Wing Valve Production Upper Master Valve

Annulus Master Valve Production Lower Master Valve

Wire Line Plug Profiles

Fig. 10.17 - Classic Conventional Tree Configuration

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DEBRIS CAP WIRELINE PLUGS

INTERNAL ISOLATION CAP

WORKOVER VALVE CROSSOVER VALVE PRODUCTION MASTER VALVE

PRODUCTION ISOLATION VALVE ANNULUS ISOLATION VALVE

ANNULUS MASTER VALVE

Fig. 10.18 - Typical Horizontal tree Configuration

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Fig. 10.19 - Typical Subsea Workover Riser System

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Figure 10.20 - Typical Subsea Spool Tree Workover System

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10.4 COMPLETION EQUIPMENT

In general, a well completion should provide a production conduit which:

• Maximises the safe recovery of hydrocarbons from a gas or oil well throughout its producing life. • Gives an effective means of pressurising selected zones in water injection wells.

Downhole accessories used should be designed to provide the safe installation and retrieval of the completion, and flexibility for sub-surface maintenance of the well using wireline, coiled tubing or other methods.

Even though different types of wells present distinct design and installation problems for engineers, most completions are just variations on a few basic designs types and, therefore, the equipment used is fairly standard. An overview of the equipment commonly used in single and dual string completions is given in the following sections.

The detailed operation of some the items such as sliding side doors (SSDs), side pocket mandrels (SPMs) and packers will not be covered in this manual. However, the relative location of these tools in a completion and their functions in intervention work or workovers will be addressed.

Figure 10.21 shows a schematic drawing illustrating the location of equipment in a typical oil well completion. Each common item in the completion string is described in the following sections.

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Tubing Hanger Tubing SCSSV Control Line Flow Coupling Production Casing SCSSV Landing Nipple Flow Coupling

Side Pocket Mandrel (SPM)

SPM

Flow Coupling

Sliding Side Door (SSD)

Flow Coupling

Landing Nipple Pup Joint

Packer

Cross-Over

Landing Nipple Perforated Joint Landing Nipple Pup Joint Wireline Re-Entry Guide

Figure 10.21 - Typical Oilwell Completion

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10.4.1 Wireline Re-entry Guide

A wireline entry guide is used for the safe re-entry of wireline tools from the casing or liner back into the tubing string. It attaches to the end of the production string or packer tailpipe assembly and has a chamfered lead in with a full inside diameter.

Wireline re-entry guides are generally available in two forms:

Bell Guide

This guide has a 45 degree lead in taper to allow re-entry into the tubing of wireline tools. This type of guide, See Figure 10.22a, is used in completions where the end of the tubing does not need to pass through any casing obstacles such as liner laps.

Mule-Shoe Re-entry Guide

This type of guide is essentially the same as the Bell Guide but incorporates a large 45 degree angle cut on one side of the guide; See Figure 10.22b. Should the guide hang up on any casing item such as a liner lip while being run, rotation of the tubing will cause the 45 degree shoulder to slide past the liner lip and enter the liner.

45 Chamfer

45 Taper

a) Bell Guide b) Mule Shoe Guide

Figure 10.22 - Wireline Re-entry Guide

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10.4.2 Tubing Protection Joint

This is a normally a single joint of tubing installed for the particular purpose of providing protection for wireline installed bottomhole pressure and temperature gauges from buffeting in the flow stream. This protection joint is installed directly below the gauge hanger landing nipple in the tailpipe below the packer and must be long enough to accommodate the longest BHP toolstring which may be run.

10.4.3 Wireline Landing Nipples

Landing nipples, See Figure 10.23, are short profiled tubulars installed in strategic positions in the tubing string into which various wireline retrievable flow controls can be set and locked. These can seal within the nipple bore, if required dependent upon the tools function. The most common tools run are plugs, chokes, and pressure and temperature gauges. The main features of a landing nipple are:

• Locking groove or profile. • Polished seal bore. • No-Go shoulder (only on non-selective nipples).

Landing nipples are supplied in ranges to suit most tubing sizes and weights with API or premium connections and are available in two basic types:

• No-Go or Non-Selective. • Selective.

No-Go or Non-Selective

The non-selective nipple receives a locking device which uses a No-Go principle for the purposes of location. This requires that the OD of the locking device is slightly larger than the No-Go diameter of the nipple. The No-Go diameter is usually a small shoulder located below the packing bore (bottom No-Go) but in some designs, the top of the packing bore itself is used as the No-Go. Only one No-Go landing nipple of a particular size should be used in a completion string. In most completions other than monobores, it is common practice to use a bottom No-Go nipple as the last nipple in the packer tailpipe to prevent dropped tools falling into the sump.

As the No-Go provides a positive location, they are widely used in high angle wells where wireline tool manipulation is difficult and weight indicator sensitivity reduced.

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Selective

In the selective system, the locking devices are designed with the same key profile as the nipples and the means of nipple selection is determined by operation of the running tool and the setting procedure. The selective design is full bore and allows the installation of several nipples of the same size.

Uses of landing nipples:

• Well plugging from above, below or from both directions.

• Pressure testing the tubing, leak finding.

• Safety valves, chokes and other flow control devices.

• Installation of bottomhole pressure and temperature gauges.

Orientation Orientation Groove Groove Key Profile Key Profile

Seal Bore

Trash Groove No-Go Shoulder

'X' Selective Landing 'XN' No Go Landing Nipple Nipple

Figure 10.23- Halliburton Wireline Landing Nipples

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10.4.4 Perforated Joints

In wells where flowing velocities are high, a restriction in the tubing, such as a gauge hanger, can cause false pressure and temperature readings. Also, vibrations in the tool can cause extensive damage to delicate instruments. To provide an alternative flow path, a perforated joint is installed above the gauge hanger nipple which allows unrestricted flow around the gauge toolstring eliminating these hazards. The perforated joint is normally a full tubing joint which is drilled with sufficient holes to provide a flow area greater than that in the tubing above.

10.4.5 Blast Joints Blast joints are installed opposite perforations (non gravel packed) where external cutting or abrasive action occurs caused by produced well fluids or sand. They are heavy-walled tubulars available usually in 10, 15, and 20 ft. lengths . They should be long enough to extend at least 4 ft. on either side of a perforated interval.

10.4.6 Packers

A packer is a device used to provide a seal between the tubing and the casing. With a suitable completion string, this seal allows the flow of reservoir fluids from the producing formation to be contained within the tubing up to the surface. This protects the casing from being exposed to well pressure and to corrosion from well or injection fluids.

A packer is tubular in construction and consists basically of:

• Case hardened slips to bite into the casing wall and hold the packer in position against pressure and tubing forces. • Packing elements which seal against the casing.

Figure 10.24 gives examples of typical packer installations and Figure 10.19 shows common types of packer.

In general, packers are classified in three groups:

• Retrievable. • Permanent. • Permanent/Retrievable.

Packers may be further classified according to the number of bores required for production i.e.

Single One concentric bore through the packer for use with a single tubing string. Dual Two parallel bores through the packer for use with two tubing strings. Tr iple Three parallel bores through the packer for use with three tubing strings.

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5 1 1 A typical packer description, therefore, might be: 9 /8 ins. Dual 3 /2 ins. x 3 /2 ins. Hydraulic- set Retrievable Packer.

Retrievable Packers

These are generally run into the wellbore on the production tubing string. As the name implies, retrievable packers can be recovered from the well after setting by pulling it with the tubing.

Permanent Packers

These are installed in the wellbore usually independent of the production tubing string. A permanent packer may be considered as an integral part of the casing. Permanent packers can only be removed from the well by milling operations.

Permanent/Retrievable Packers

As their name may suggest, these packers have the same characteristics as permanent packers but can be released and recovered from the well without milling. They will generally have a smaller bore than a permanent packer to accommodate the addition of some type of releasing mechanism.

Packers, both retrievable and permanent versions, are installed in the production casing by one of the following methods:

Mechanically ; Run on a workstring, is set by manipulation of the tubing i.e. by applying compression or tension in combination with rotation depending on the particular setting mechanism of the packer.

NOTE: Packers having rotation set/release mechanisms should not be used in highly deviated wells since the application of tubing torque may not be transferred downhole.

Hydraulically ; Can be run on a workstring or on the tubing string. When the desired setting depth is reached the tubing is plugged below the packer with a check valve, standing valve or a wireline plug and hydraulic pressure applied to the tubing to set the packer. Generally, a predetermined upward pull on the tubing string will release the seal unit from the packer with a Hydraulic Permanent packer system.

On Electric Wireline ; This is generally restricted to permanent packers. The packer is attached to a wireline setting adapter, connected to a setting gun on the end of the wireline and run in the wellbore. On reaching the desired depth an electrical signal transmitted to the gun activates an explosive charge and, through a hydraulic chamber, provides the mechanical forces to set the packer.

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Casing

Annulus

Production Tubing

Packer

Producing Formation

Single Zone Completion Production Casing Dual Packer

Short Tubing String Long Tubing String

Upper Formation

Single Packer

Lower Formation

Packer 1 Dual Completion

Zone 1

Packer 2

Zone 2

Packer 3

Zone 3

Single String Multi Zone Completion

Figure 10.24 - Examples Of Packer Installations

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a) 'RDH' Dual Bore b) 'RH' Single Bore c) Permanent Packer Retrievable Packer Retrievable Packer

Figure 10.25 - Examples Of Common Types of Packers

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10.4.7 Permanent Packer Accessories

An important aspect in a completion with a permanent packer is the tubing/packer seal. As the packer in effect becomes part of the casing after it is set, the tubing must connect to the packer in a fashion so that it can be released. This connection whether it be a straight stab in, latched or otherwise, must have a seal to isolate the annulus from well fluids and pressures. This seal usually consists of a number of seal elements to cater for some wear and tear. These seal elements are classified into two groups; premium and non-premium. The premium group

are those used in severe or sour well conditions i.e. H2S, CO2 etc. and are normally ‘V’ type packing stacks containing various packing materials resistant to the particular environment. The non-premium seals are for sweet service and can be either ‘V’ type packing stacks or moulded rubber elements.

Locator Tubing Seal Assemblies Locator tubing seal assemblies, See Figure 10.26a and Figure 10.26b, are fitted with a series of external seals providing an effective seal between the tubing and packer bore. They also have a No-Go type locator for position determination within the packer. Locator seal assemblies are normally space out so that they can accommodate both upward and downward tubing movement induced by changes in temperature and pressure.

Seal Bore Extensions A seal bore extension is used to provide additional sealing bore length when a longer seal assembly is run to accommodate greater tubing movement. The seal bore extension is run below the packer and has the same ID as the packer.

Anchor Tubing Seal Assemblies Anchor tubing seal assemblies, See Figure 10.26c and Figure 10.26d, are used where it is necessary to anchor the tubing to a permanent packer while retaining the option to unlatch when required. Anchor latches are normally used where well conditions require the tubing to be landed in tension or where insufficient weight is available to prevent seal movement.

Polished Bore Receptacles (PBRs) A PBR is simply a seal receptacle attached to the top of a permanent packer or liner hanger packer in which the seal assembly lands instead of the packer bore. As the PBR bore can be made larger than the packer, this provides a larger flow area through the seal assembly. See Figure 10.23

Tubing Seal Receptacles A TSR is an inverted version of a PBR where by a polished OD male member is attached to the top of the packer and the female (or overshot) is attached tubing. The seals are contained in the female member so that they are recovered when pulling the tubing. See Figure 10.24

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"G" Locator Seal Sub No-Go Shoulder

"E" Spacer Seal "E" Spacer Seal Sub Sub

a) Locator Tubing Seal b) Seal Extension Assembly

"E" Anchor Seal Anchor Latch Sub

Anchor Latch

"E" Spacer Seal Sub

c) “K-22” Anchor Seal d) “EBH-22” Anchor Nipple Seal Assembly

Figure 10.26 - Permanent Packer Seal Accessories

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Connection

Debris Barrier Unit

Shear Ring (Closed Position)

Seal Units

Debris Barrier Unit

Connection

Figure 10.27 - Polished Bore Receptacle

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Figure 10.28 - Tubing Seal Receptacle

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10.4.8 Sliding Side Doors (SSDs)

Sliding Side Doors (SSDs) or Sliding Sleeves are installed in the tubing during well completion to provide a means of communication between the tubing and the annulus when opened; See Figure 10.29.

SSDs are used to:

•Bring a well into production after drilling or workover by circulating the completion fluid out of the tubing and replacing it with a lighter underbalanced fluid. • Kill a well prior to pulling the tubing in a workover operation. •Provide selective zone production in a multiple zone well completion.

SSDs are available in versions which open by shifting an inner sleeve either upwards or downwards. A number of SSDs can be installed in a completion string and selectively opened or closed by the use of the appropriate wireline shifting tool.

CAUTION: Tubing and annulus pressures must be equalised before an SSD sleeve is opened to prevent wireline tools being blown up or down the tubing.

A common fault of sliding sleeves is that the seal failure usually leads to a workover although a pack-off can be installed as a temporary solution.

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Top Sub 1

Female Adapter 5

Packing 6 Closing Sleeve 2 Nipple 3 O-Ring 7 O-Ring 4

Female Adapter 5 Split Ring 8 O-Ring 9 Female Adapter 5 Female Adapter 10 O-Ring 7 Packing 6 O-Ring 4

Bottom Sub 11

Figure 10.29 - Sliding Side Door (SSD)

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10.4.9 Flow Couplings

Flow couplings, which are heavy-walled tubulars, are installed above and below any completion component which may cause flow turbulence such as wireline nipples, SSDs, SCSSV landing nipples etc., to cater for internal erosion. Although the same amount of erosion is experienced, the added thickness of the flow coupling provides enough material to prevent weakening over the projected life of the well. In lower velocity wells, such as low GOR oil wells, a flow coupling may only be needed to be placed above restrictions.

10.4.10 Side Pocket Mandrels

Side Pocket Mandrels (SPMs) were originally designed for gas lift completions to provide a means of injecting gas from the casing-tubing annulus to the tubing via a gas lift valve. However in recent times, they have also been commonly used in place of an SSD as a circulating device because seal failure can be rectified by pulling the dummy gas lift valve (or kill valve) with wireline and replacing the seals. SPMs are installed in the completion string to act as receptacles for the following range of devices:

• Gas lift valves • Dummy valves • Chemical injection valves • Circulation valves • Differential dump kill valves • Equalising valves.

It is essential to understand the operation of the device installed in an SPM before conducting any well intervention as it may affect well control. See Figure 10.24 for a typical SPM and Figure 10.31 for types of valves.

Gas Lift Valves

There are many different designs for gas lift valves for various applications. They range from being simple orifice valves to pressure operated bellows type valves. However, they all contain check valves to prevent tubing to annulus flow. These check valves may leak after a period of use and they should never be relied on as barriers in a well control situation. These should be replaced with dummy valves and the tubing pressure tested to confirm integrity.

Dummy Valves

These are tubing/annulus isolation valves. They are installed in place of the valves in order that the completion tubing string can be pressure tested from both sides during installation or when well service operations are required.

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Chemical Injection Valves

The injection valve is designed to control the flow of chemicals injected into the production fluid at the depth of the valve. A spring provides the force necessary to maintain the valve in the fail-safe closed position. Reverse flow check valves, which prevent backflow and circulation from the tubing to the casing, are included as an integral part of the valve assembly.

Injection chemicals enter the valve from the annulus in an open injection system. (This requires the annulus to be full of the desired chemical. An alternative method is to run an injection line from surface to the SPM.) When the hydraulic pressure of the injected chemicals overcomes the pre-set tension in the valve spring plus the pressure in the tubing, the valve opens. Chemicals then flow through the crossover seat in the valve and into the tubing.

Circulating Valves

These are recommended to be installed in the SPM whenever any circulating is to carried out. The circulating valve is designed to enable circulation of fluid through the SPM without damaging the pocket. The valve allows fluid to be dispersed from both ends allowing circulation of fluid at a minimal pressure drop. Some valves permit circulation from the casing into the tubing only and others to circulate fluid from the tubing into the casing only.

If a circulating valve is not used and the pocket is flow cut a workover would be necessary to replace the SPM.

Differential Dump Kill Valves

Differential dump/kill valves are designed to provide a means of communication between the casing annulus and the tubing when an appropriate differential pressure occurs. Below a pre- set differential pressure, the valve acts as a dummy valve since it uses a moveable piston to block off the circulating ports in the valve and the side pocket mandrel.

The differential pressure necessary to open the valve will depend on the type and number of shear screws installed. The valve will only open when the casing annulus pressure is increased by the differential (of the shear screw rating) above the tubing pressure. An increase in tubing pressure above the casing annulus pressure will not open the valve. After opening, the piston is locked in the up position and fluids can flow freely in either direction. The hydrostatic pressure from the column of annulus fluid will kill the well and remedial operations can be planned.

Equalising Valves

The equalisation valve is designed to equalise pressure between tubing and casing and/or to circulate fluid before pulling the valve from the SPM.

The valve has two sets of packing which straddle and pack off the casing ports in the SPM. The tubing and annulus are isolated from each other until the equalising device is operated by a pulling tool. Pressures equalise through a port before the valve and latch are retrieved.

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"KBUG"

Orienting Sleeve

Tool Discriminator

Latch Lug

Upper Packing Bore

Pocket

Lower Packing Bore

Section A - A

Figure 10.30- Side Pocket Mandrel (SPM)

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Running Neck

Pulling Neck

Tangential Shear Pin Spring

Latch Ring

['RKP' Latch]

Packing Stack

Reverse Flow Check Spring

Communication Packing Stack Port Packing Stack Shear Screw Packing Stack Communication Port Communication Piston Port Reverse Packing Stack Flow Check Reverse Packing Stack Flow Check

[’DCR-1’] [’LK - 3’] [’RG - 2’]

Figure 10.31 - Types of SPM Valves

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10.4.11 Travel Joints

A travel joint is used to compensate for tubing movement due to temperature and/or pressure changes during treating or production. It is normally used with a seal assembly anchored to a permanent packer. Figure 10.32 shows a Travel Joint commonly used on the short string in dual string completions.

NOTE: Alternative names for travel joints are Telescoping or Expansion joints.

Polished Bore Receptacles (PBRs) and Extra Long Tubing Seal Receptacles (ELTSRs) are other devices commonly installed above a permanent packer to compensate for tubing movement; Refer to Section 10.4.7.

Packing

Inner Sleeve

Outer Sleeve

Figure 10.32 - Travel Joint

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10.4.12 Sub-Surface Safety Valves

The modern sub-surface safety valve has been developed from the earliest versions produced in the 1930’s. The initial demand was for a downhole valve that would permit flow during normal conditions, but would isolate formation pressure from the wellhead to prevent damage or destruction. This valve would be installed downhole in the production string.

The valve that was developed was a Sub-Surface Controlled Safety Valve (SSCSV) and was a poppet type valve with a mushroom shaped valve/seat system. Compared with today’s valves, this simple poppet type valve had several disadvantages; restricted flow area, tortuous flow paths, low differential pressure rating and calibration difficulties. Despite these limitations the valve operated successfully and other versions were developed with less tortuous flow paths such as the ball and flapper valve.

From this beginning, the Surface Controlled Sub-Surface Safety Valve (SCSSV) was developed in the late 1950’s. This moved the point of control from downhole to surface; See Figure 10.33. This design provided large flow areas, remote control of opening and closing, and responsiveness to a wide variety of abnormal surface conditions (fire, line rupture, etc.). Initial demand for this valve was slow due to it’s higher cost and the problems associated in successfully installing the hydraulic control line, hence it’s usage was low until the late 1960’s.

The SCSSV is controlled by hydraulic pressure supplied from a surface control system which is ideally suited to manual or automatic operation, the latter of which pioneered the sophisticated emergency shut-down systems required today. The versatility of the valve allows it to be used in specialised applications as well as in conventional systems.

SCSSVs are available in two variants - Tubing Retrievable Safety Valves (TRSV) and Wireline Retrievable Safety Valves (WRSV). SCSSVs are available with ball or flapper type closure mechanisms.

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Nipple Adapter

Stainless Steel Set Screws Top Sub Jam Nut O-Ring Lock Open Ring Stainless Steel Set Screws

O-Ring Brass Shear Screws

T-Seals Housing Locking Mandrel Piston O-Ring T-Seal Stainless Steel Set Screws Intermediate Sub Stainless Steel Set Screws O-Ring Stainless Steel Set Screws Piston Coupling C-Ring Flow Tube Power Spring Housing

Spring Stop O-Ring Stainless Steel Set Screw O-Ring Flapper Flapper Base Seat Resilient Seal Flapper Pin Torsion Spring Flapper Flapper Housing O-Ring Stainless Steel Set Screw

Bottom Sub

Figure 10.33 - Example of Downhole Safety Valve

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Sub-Surface Safety Valve Applications

Fail-safe Sub-Surface Safety Valves, whether directly or remotely controlled, are installed to protect personnel, property and the environment in the event of an uncontrolled well flow (or blow-out) caused by collision, equipment failure, human error, fire, leakage or sabotage. Whether safety valves are required in a particular operating area, depends on the location of the wells and in some cases on company operating policy and/or government legislation.

In general, each application must be considered separately due to varied well conditions, locations, regulations, depth requirements etc.

Table 10.2 shows the various applications of WRSVs and TRSVs.

WRSV Applications TRSV Applications

General application: where intervention by General application: where larger flow area is wireline is available desired for the tubing size

High pressure gas wells High volume oil and gas wells

Extreme hostile environments where well Subsea completions fluids or temperature tend to shorten the life of component materials

High velocity wells with abrasive Multiple zone completions where several flow production control devices are set beneath the TRSV

Greater depth setting capabilities

Table 10.2 - Sub-Surface Safety Valve Applications

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Sub-Surface Controlled Sub-Surface Safety Valves

These valves are installed in regular wireline type nipples on a lock mandrel.

a) Pressure-Differential Safety Valves

This type of direct-controlled safety valve is a ‘normally open’ valve that utilises a pressure- differential to provide the method of valve closure. Normally a spring holds a valve off-seat until the well flow reaches a pre-determined rate.

This rate can be related to the pressure differential generated across an orifice or flow bean. When this differential is reached or exceeded, a piston moves upwards against a pre-set spring force closing the valve. Valves of this type are termed ‘storm chokes’.

There are two closing mechanisms available with these valves, i.e.:

• Ball-type closure. • Flapper-type closure.

The valve is held open by a spring force which may be increased by adding spacers or changing the spring. The relationship between flow rate and differential may be adjusted by changing the bean size. The valve when closed will remain in the this position until pressure is applied at surface to equalise across it when the spring will return to the open position . NOTE: This type of valve should never be attempted to be pulled unless it has been equalised and is open.

These valves are rarely in use today but a derivative, the Injection Valve, which is normally closed is widely used in injection wells. This injection valve opens when fluid or gas is injected and travels to the fully open position when the predetermined minimum injection rate is reached; See Sub Section c) Injection Valve.

b) Ambient Type Safety Valves

This type of direct-controlled safety valve is a fail safe closed valve which is pre-charged with a calibrated dome (chamber) pressure prior to running. Ambient controlled valves will open when the well pressure reaches the set point of the dome calibration. The valve will close when the flowing pressure of the well, at the point of installation, drops below the predetermined dome pressure. Ambient type safety valves are also generally referred to as a ‘storm chokes’.

This type of valve is usually a ball valve and is not limited by a flow bean which gives it a large internal diameter and, hence, a large flow area making it suitable for high volume installations possibly producing abrasive fluids.

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Ambient type safety valves are run with an equalising assembly to allow equalisation across the valve should it close, and a lock mandrel to locate and lock the valve in the landing nipple.

NOTE: Both pressure differential and ambient controlled sub-surface safety valves close on pre-determined conditions. They do not offer control until these conditions exist. Also valve settings may change if flow beans become cut. Surface controlled safety valves should be considered in such cases.

c) Injection Valve

Injection valves are normally closed valves installed in injection wells. They act like check valves allowing the passage of the injected fluid or gas but close when injection is ceased.

The closure mechanism is either a ball or flapper type which opens when the differential pressure from the injected medium equalises that below the valve. As the injection rate is increased to the precalculated rate, the differential acts on a choke bean and overcomes a spring to move the mechanism to the fully open mode. If the injection rate is insufficient or fluctuating, the mechanism will be damaged and possibly flow cut . The flapper-type valve is the most popular as its operation is less complicated and is also less prone to damage if the injection rate is not high enough.

d) Bottom Hole Regulators

Bottom hole regulators are essentially throttling valves installed downhole to enhance the overall safety in wells where high surface pressures or hydrate formation present problems. Bottomhole regulators are designed to reduce surface flowline pressures to safe, workable levels and to keep surface controls from freezing.

In gas wells, the pressure drop across a regulator will occur downhole where the gas and surrounding well temperature is higher than at surface. The higher gas temperature and surrounding well temperature tend to prevent hydrate formation when a pressure drop occurs across the regulator. The cooler gas immediately above the regulator will usually increase due to the downhole ambient temperature.

In oil wells, the installation of a bottomhole regulator is used to facilitate the liberation of gas from solution downhole and consequently lighten the oil columns to increase flow velocity . The regulator has a stem and seat which are held closed by a spring and at a pre-set differential pressure the valve opens.

If high reductions in pressure are necessary, more than one regulator can be installed, providing stepped reductions reducing the risk of hydrate formation and flow cutting.

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NOTE: An equalising sub should be installed between the lock mandrel and the regulator to facilitate the equalisation of pressure.

Surface Controlled Sub-Surface Safety Valves

The SCSSV is a downhole safety device that can shut in a well in an emergency or provide a barrier between the reservoir and the surface. As the name suggests, the valve can be controlled from the surface by hydraulic pressure transmitted from a control panel through stainless steel tubing to the safety valve; See Figure 10.34

The remote operation of this type of valve from the surface can also be integrated with pilots, emergency shut down (ESD) systems, and surface safety control manifolds. This flexibility of the surface controlled safety valve design is its greatest advantage . In the simplest system an SCSSV is held open by hydraulic pressure supplied by a manifold at the surface, the pressure being maintained by hydraulic pumps controlled by a pressure pilot installed at some strategic point at the wellhead. Damage to the wellhead or flowlines causes a pressure monitor pilot to exhaust pneumatic pressure from a low pressure line which in turn causes a relay to block control pressure to a 3-way hydraulic controller resulting in hydraulic pressure loss in the SCSSV control line. When this pressure is lost, the safety valve automatically closes, shutting off all flow from the tubing.

There are two main categories of SCSSVs:

• Wireline Retrievable SCSSV. • Tubing Retrievable SCSSV.

SCSSVs utilise the ball or flapper type closure mechanisms.

Both categories are supplied with or without internal equalising features. This allows the pressure to equalise across the valve so as it can be re-opened. Valves without this feature need to be equalised by pressure applied at surface. The former is more prone to failure due to having more operating parts whereas for the latter equalisation pressure is often difficult to provide and possibly time consuming.

a) Wireline Retrievable SCSSV

Wireline retrievable sub-surface safety valves are located and locked, using standard wireline methods, in a dedicated safety valve landing nipple (SVLN). The SVLN is connected to a 1 hydraulic control line pressure source at the surface normally by a /4 ins. OD stainless steel tubing.

When the safety valve is set in the nipple, the packing section seals against the bore of the nipple below the port. The packing section of the lock mandrel forms a seal above the port in the nipple. Control pressure, introduced through the control line, enters the valve through the port in the housing and allows pressure to be applied to open the valve. Figure 10.34 shows a typical surface-controlled, wireline retrievable safety valve.

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Top Sub for Installation of Lock mandrel c/w Upper Packing Set

Valve Assembly Hydraulic Control Line

Hydraulic Port Lock Mandrel

Piston

Packing Stack

Packing Sack Safety Valve Landing Nipple

Spring Packing Stack

Piston

Power Spring

Secondary Valve Seat

Equalisation Port Secondary Valve Seat

Primary Valve Seat with Ball Ball Seat Ball

Figure 10.34 - Typical Wireline Retrievable SCSSV (WRSV) and Installation

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Because a wireline retrievable SCSSV seats in a landing nipple installed in the production string, it offers a much smaller bore than a tubing retrievable SCSSV for the same size of tubing. Frequently, WRSVs have to be pulled prior to wireline operations being carried out.

Compared to a tubing retrievable SCSSV, the wireline retrievable SCSSV is easy to replace in the case of failure. Most failures can be prevented by introducing a planned maintenance schedule in which valves are regularly pulled and serviced. However, during wireline entry operations there is also a safety risk and care must be maintained at all times.

The components required for the installation of a wireline retrievable SCSSV are:

• Hydraulic control line. • Control Line Protectors. • Hydraulic control manifold. • Wireline retrievable safety valve. • Safety valve landing nipple. • Locking Mandrel. • Wireline installation and retrieval tools for the locking mandrel.

b) Tubing Retrievable SCSSV

Tubing retrievable safety valves operate by the same principle as wireline SCSSVs except all the components are incorporated in one assembly which is installed in the completion string; See Figure 10.35. Some models have rod pistons instead of the more normal concentric piston designs.

Should the tubing retrievable valve need to be locked out, a wireline retrievable can be installed and operated, although with a reduced internal bore.

The components required are:

• Hydraulic control line. • Control line protectors. • Hydraulic Control Manifold. • Tubing retrievable safety valve.

and additionally for insert capability:

• Wireline safety valve. • Locking mandrel. • Wireline installation and retrieval tools for the locking mandrel. • Lock-out tool for the tubing retrievable valve.

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Hydraulic Port

Tubing Connection

Hydraulic Port

Hydraulic Line Metal Seat Upper Piston (Upper Static Seal) Assembly

Rod Piston (Upper Assembly)

Opposing Metal Cups (Dynamic Seals) Lower Piston Rod Piston Assembly (Lower Assembly) Flow Tube b) Open Position

Hydraulic Port Metal Seal (Lower Static Seal) Upper Piston Assembly

Power Spring

Flow Tube

Flapper Spring

Flapper Lower Piston Assembly Spring Loaded Debris Barrier

Flow Tube

a) TRDP-5 TRSV Power Spring c) Closed Position

Figure 10.35 - Typical Tubing Retrievable SCSSV (TRSV)

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Safety Valve Leak Testing

A test performed on Sub-Surface Safety Valves immediately after installation, and on a regular schedule, is the leak test. A typical leak test entails the production, kill and swab valves are closed on the Xmas tree and control line pressure bled off to close the valve. Tubing pressure is bled off slowly above the valve to zero for a tubing retrievable valve and in 100 psi. (6.9 bar) stages for a wireline retrievable valve.

The system is closed in again and tubing pressure monitored. If there is a rapid build up, a major leak is indicated or improper functioning of the valve; in this case the valve should be cycled and the test repeated. After a specified shut-in period the tubing head pressure should be below a maximum allowable pressure as specified by the operator’s leak off criteria although there is an API standard.

NOTE: It is extremely important that pressure data is fully and accurately recorded.

After initial installation, leak tests should be carried out periodically; this accomplishes three functions:

1. To test the integrity of the seal in the safety valve. 2. To test that the lock mandrel in a wireline retrievable valve is still properly locked. 3. To cycle the valve to prevent ‘freezing’ in wells where they have been sitting in either fully open or fully closed position for extended periods of time.

NOTE: All the above tests should be conducted on all Sub-Surface Safety Valves by authorised personnel.

a) API Leakage Limit in Gas Wells

For gas wells, leakage rates can be compiled from a surface pressure build-up from the formula (low pressure application) 4(∆p)V Q = ––––– ∆t where:

Q Is the leakage rate (in standard cubic ft/hr.) ∆t Is the build-up time in minutes to reach a stabilised pressure V Is the volume of the tubing string above the SSSV (ft3) ∆p Is the change in pressure (psi.)

If the leakage rate is in excess of 900 SCft./hr. (25.5 m3/hr.), the SCSSV should be cycled opened and re-tested. If the leakage rate is greater than API or Group specifications, which ever is the most stringent, then corrective action must be taken.

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b) API Leakage limit - Oil Wells

For oil wells, the pressure depends on the static fluid level and the amount of gas in the oil. If the liquid level is below the SCSSV, the formula for gas wells can be used. If the liquid level is above the SCSSV then the leakage rates are determined from the build-up of surface pressure which is converted to a liquid volume.

If the leakage rate is in excess of 6.3 gal/hr (0.4 m3/min) then the SCSSV should be cycled and re-tested. If the leakage rate is still in excess of 6.3 gal/hr (0.4 m3/min) then corrective action should be taken.

10.4.13 Annulus Safety Valves

The sub-surface safety valves discussed so far, i.e. tubing retrievable and wireline retrievable, only provide tubing flow control. In these systems, no annular flow control exists.

Annulus safety valve systems are usually associated with completions where artificial lift or secondary recovery methods are employed e.g. gas venting in electric submersible pump (ESP), hydraulic pump, and gas lift installations. There application is to remove the potential hazard of a large gas escape in the event there is an incident where the tubing hanger seal is breached.

There are a number of designs of such systems on the market and the variety of mode of operation is too wide to be covered in this document, however the basic concepts are the same. With any annulus system, there must be a sealing device between the tubing and the casing through which the flow of gas can be closed off. This is generally a packer but may also be a casing polished bore nipple in some designs into which a packing mandrel will seal. In the sealing device there is a valve mechanism operated by hydraulic pressure similarly to an SCSSV. The valve mechanism opens the communication path from the annulus below to the annulus above the valve and is fail safe closed.

The closure mechanism may be a sliding sleeve, poppet or flapper device. Figure 10.30 shows a typical annulus safety valve.

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Tubing Hanger

Production Casing

Baker Multi-Purpose Hydraulic Connection Expansion Joint

Annulus Port

Tubing Valve TRSV Hydraulic Control Line

Flow Coupling

Tubing Retrievable Power Spring SCSSV

Flow Coupling

Spacer

Baker "AVLDEM" Annulus Safety Valve

Baker "FLX-2" Pack-Off Tubing Anchor c/w Concentric Tubing Anchor

Figure 10.36 - Typical Annulus Type Safety Valve System

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10.4.14 Surface Control Manifolds

Surface control manifolds are designed to provide and control the hydraulic pressure required to hold an SCSSV open. The manifold has one or more air powered hydraulic pumps to maintain the hydraulic operating pressure for the safety valve.

The hydraulic pressure is through a 3-way control valve which is controlled by remote pressure pilots and fire sensors. Pilot, sensor or manual activation removes the hydraulic pressure, closing the safety valve.

NOTE: Activation can occur from the operation of remote-control pressure sensing pilots, fusible plugs, plastic line, sand probes, level controllers or emergency shut down (ESD) systems.

Surface control manifolds are generally supplied as complete systems containing a reservoir, pressure control regulators, relief valves, gauges, and a pump with manual override.

Manifolds, in combination with the various pilot monitors, have many different applications, e.g. controlling multiple wells using individual control, multiple wells using individual pressures and any combination of these.

Other additional features have been incorporated into surface control manifolds when the system is integrated with other pressure operated devices. A control panel, designed to supply hydraulic pressure to a surface safety valve (SSV) and hydraulic pressure to an SCSSV, contains a circuit logic for proper sequential opening and closing of the safety valves, i.e.

• Sequential closing: - SSV first - SCSSV second.

• Sequential re-opening: - SCSSV first - SSV second.

Sequential logic is incorporated to increase the service life of hydraulic master valves and SCSSVs to prevent SCSSVs becoming flow cut by high velocity wells.

Improvements have also been made in the monitoring systems, e.g.

• Sand erosion probes installed on a flowline to monitor sand flow production. • Quick exhaust valves which allow rapid exhausting of control line pressure to speed up valve closures.

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10.4.15 Control Lines

The conduit which supplies the hydraulic fluid to the SCSSV is the control line. The control 1 line is normally a /4 ins. OD tubing attached to the sub-surface valve (TRSV) or nipple (WRSV) with a compression fitting, and run up the outside of the tubing to the tubing hanger. The method of termination at the hanger is dependent on the type wellhead and hanger system being deployed.

Some control lines on land wells are simply fed out through a packing element in a port (often a tie-down bolt hole) which is tightened to seal around the tubing. Other systems have drilled ports in the hanger, into which the control line is fitted again with a compression fitting, and the spool sealed off from the annulus and the Xmas tree bore by concentric weight set or pressure energised seals.

Subsea wellheads have different methods of termination so the tree can be installed subsea without diver assistance.

The control line material is selected to meet the environment into which it is to be installed and be compatible with both the safety valve and the hanger materials from the point of corrosion due to being of dissimilar materials. Their is a large choice of control lines materials from 316 ss for sweet service to Inconel and Elgiloy alloys for more demanding service. They are also supplied in hard durable plastic coatings for added protection from corrosion and against crushing damage during installation which at one time was one of the major problems during completing. Two lines can be encased for dual control line safety valves.

Control lines are held flat to the tubing by control line protectors usually placed across a coupling or connection and sometimes also in the middle of a joint. The protector has a slot into which the control line plastic outer coating fits. Simple banding can be used but it is not strong and is easily ripped off. Protectors are now metal clamp types as earlier rubber versions were easier detached and caused major problems while retrieving the completion string.

10.4.16 Tubing

The purpose of using tubing in a well is to convey the product from the producing zone to the surface, or in some cases to convey fluids from the surface to the producing zone. It should continue to do this effectively, safely and economically for the life of the well, so care must be taken in its selection, protection and installation.

1 1 Tubulars up to and including 4 /2 ins. are classified as tubing, over 4 /2 ins. is casing. In large capacity wells, casing size tubulars may be run as the production conduit.

Tubing selection is governed by several factors. Anticipated well peak production rate, depth of well, casing sizes, well product, use of wireline tools and equipment, pressures, temperatures, and tubing/annulus differential pressures are among those which must be considered.

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To meet various completion designs, there is a wide range of tubing sizes, wall thickness (weights) and materials to provide resistance to tubing forces and differing well environments. The best tubing selection is the cheapest tubing which will meet the external, internal and longitudinal forces it will be subjected to, and resist all corrosive fluids in the well product. This is not practical in every instance and often compromises have to be made.

For ease of identification, tubing is colour coded to API specification. Some specialist suppliers steels are not covered by the code and provide their own codes. Refer to codes to ensure the tubing is according to requirements.

10.4.17 Tubing Hangers

a) Bowl Type Tubing Head/Mandrel Type Tubing Hanger

A Tubing Head/Tubing Hanger combination unit is attached to the uppermost casing head on the wellhead. The main functions of this unit are to:

• suspend the tubing • seal the annular space between the tubing and the casing • lock the tubing hanger in place • provide a base for the wellhead top assembly (Xmas Tree) • provide access to the annular space (‘A’ annulus).

Suspension of the tubing is accomplished usually by threads, slips or any other suitable device i.e.. rams.

The tubing head consists of a spool piece type housing where the internal profile of the top section is a straight or tapered cylindrical receptacle (bowl) into which the tubing hanger is landed, suspending the tubing and sealing off the volume between the tubing and the casing. A tapered type tubing hanger system is shown in Figure 10.37

The important features of tubing hangers are:

Top and Bottom The size and pressure ratings of these connections (usually flanged) Connections must be compatible with the size and pressure rating of the joining connections.

Upper Bowl Provides the seal area for various tubing hangers and a load shoulder to support the production tubing.

Lower Bowl This is provided to house some type of isolation seal.

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Set Screws Set screws or hold-down screws are found in most tubing heads and have two important functions.

• retain the tubing hanger and prevent any upward tubing movement due to pressure surges. • activate (energise) the body seals on the tubing hanger.

Outlets These provide access to the annulus (e.g.. for pressure monitoring or gas lift) during production.

Test Port Permits the pressure testing of the hanger seal assembly, lockdown screw packing connection between flanges, and the secondary (isolation) seal.

Landing Threads These are the uppermost threads on the hanger and they must support the entire weight of the tubing string.

Bottom Threads These must support the entire weight of the tubing string and seal the producing zone from the annulus.

Sealing Area These provide compression type sealing between the outside diameter of the hanger body and the inside diameter of the hanger bowl. Sealing is accomplished by energising elastomer seals or metal-to-metal seals by the action of tubing weight on various load bearing surfaces.

Tubing hangers are sized according to the upper bowl of the tubing head and the tubing size 7 7 the hanger will be supporting. Thus, a 7" x 2 /8" tubing hanger means a 2 /8" production 1 string suspended from a tubing head 7 /16" top bowl.

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Figure 10.37- Cameron ‘F’ Tubing Head and Hangers

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b) Ram Type Tubing Head

Ram Type Tubing Heads find their application in completions where manipulation of the tubing is necessary to locate and latch into a packer and to maintain tension in the tubing when landed.

Figure 10. 38 shows a ram type tubing head which comprises a housing with two side outlets in which are located retractable rams. These rams, when closed, support the hanger nipple which is screwed on to the top of the tubing string. The seal between the annulus and the tubing is provided by a seal assembly which is located around the hanger nipple above the rams.

With the ram type tubing hanger installed on the wellhead and the packer set, production tubing is run and spaced out so that the final position of the hanger nipple is that distance below the tubing head corresponding to the amount of stretch required to give the appropriate tension. The tubing is latched into the packer and tension applied to the tubing so that the hanger nipple is just above its final hang off position. The rams are closed, the tubing weight is set on the rams and the handling string removed. The seal assembly is then installed, bolted down, and the seal system energised by the injection of plastic packing. Finally, the BOPs are removed and the Xmas Tree installed.

NOTE: Like mandrel type hangers, landing nipple hangers are provided with a top thread for the landing joint, an internal left hand thread or wireline profile for the installation of a back pressure valve, and can be supplied with extended necks to facilitate secondary sealing. Also, ram type tubing heads are available with control line outlets to allow an SCSSV to be incorporated in the tubing string.

The disadvantages of ram type tubing hangers are:

• After long service periods, it may be difficult to re-open the rams • The tubing pick-up weight must be overcome prior to opening the rams otherwise the rams will be difficult to open • They are bulky, heavy and expensive.

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HANGER NIPPLE

HANGER SEALS

RETRACTABLE RAM

Figure 10.38 - Cameron Single Ram Tubing Head (‘SRT’)

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c) Multiple Tubing Heads/Hangers

The purpose of a multiple completion is to produce reservoirs simultaneously without any pressure or reservoir fluid combining during the transfer of fluid from the production zones to the production facilities.

For multiple string completions two or three segments, one for each production string, are used to form a hanger assembly which, when installed in the appropriate tubing head, resembles a mandrel type tubing hanger. Figure 10.39 shows a tubing head/hanger arrangement for use in a dual completion. An important characteristic of this tubing head is the support wedges (or in other heads support pins) used to guide and align the two segmented hangers in their proper positions in the upper bowl. The segmented hangers are locked in place with the tie- down screws. A disadvantage of this type of hanger is that seals are often damaged while installing the second segment.

NOTE: Segmented hangers are available to accommodate a back pressure valve and are also manufactured with control line outlets to allow an SCSSV to be installed in the production tubing.

Figure 10.39- Multiple Tubing Heads/Hangers

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10.4.18 Wellheads

At the drilling stage, casing is run and cemented in a well to line the well to protect against collapse of the borehole, to prevent unwanted leakage into or from rock formations and to provide a concentric bore for future operations. Various strings of casing are run, i.e. conductor, surface string (which provides a base for the wellhead) followed by one or more intermediate strings depending on the target depth and expected conditions in the well. At the completion stage, production tubing is run to act as a flowline between the formation and surface. Unlike casing, production tubing is not cemented in the hole so the entire tubing weight must be supported by a suspension system suitably installed in a tubing head. The tubing head is positioned on top of the uppermost casing head of a well and is used to suspend the production tubing and to produce an effective seal between tubing and casing.

Tubing heads are composed of a body, a hanger-sealing device (tubing hanger), and a mechanism which retains the hanger.

The wellhead equipment installed on top of the tubing head serves to control and direct the flow of well fluids from the production tubing string. Such surface equipment may range from a simple flow cross with stuffing box to an elaborate Xmas tree. Choice of surface tree depends on well fluid production method (natural flow or artificial) and the wellhead pressure encountered. In general, most surface trees are comprised of at least one master valve, at least two wing or flow valves (one of which may be hydraulically operated), and one swab valve utilised in wireline operations; See Figure 10.40.

Wellhead equipment (spools, valves, chokes) is either screwed, flanged or a combination of both. Wellheads with screwed connections are used for pressures not exceeding 1,000 psi. (69 bar); those with screwed valves and chokes not exceeding 5,000 psi. (345 bar). However, most operators specify, even for low pressure wellheads, flanged connections since they are less susceptible to leakage, easier to orientate and, especially in the larger sizes, easier to manipulate.

With regard to subsea wellheads, there is no API standard and manufacturers all have their own specific designs which includes some means of orientation in order to align the subsea tree inlets and outlets to the flowlines or indeed in a subsea manifolding system.

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Figure 10.40 - Typical Surface Xmas Tree

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Xmas Trees

An Xmas Tree is an assembly of valves and fittings used to control the flow of tubing fluids at surface and to provide access to the production tubing and on some subsea completions to the annulus string. In general, an Xmas Tree is essentially a manifold of valves which is installed as a unit on top of a tubing head or subsea wellhead.

Similarly to the tubing hanger the range of trees available is wide and are not all addressed in this manual. However the valving of surface Xmas trees is similar throughout and typically contains the following valves and tree cap:

Lower Master Gate Valve (LMG)

The Lower Master Valve is utilised on all Xmas trees to shut in a well. This valve is usually operated manually. As its name implies, the master is the most important valve on the Xmas tree. When closed, this valve should keep the well pressure under full control and therefore should be in optimum condition - it should never be used as a working valve.

In moderate to high pressure wells, Xmas trees are often furnished with a valve actuator system for automatic or remote controlled operation (i.e. surface safety valve system). This is often a regulatory requirement in sour gas or high pressure wells.

Upper Master Gate Valve (UMG)

The Upper Master Valve is used on moderate to high pressure wells as a emergency shut-in 2 system where the valve should be capable of cutting at least 7 /3 ins. braided wireline. This valve can be actuated pneumatically or hydraulically. The UMG valve is a surface safety valve and is normally connected to an emergency shut-down (ESD) system.

Flow Wing Valve (FWV)

The Flow Wing Valve permits the passage of well fluids to the choke valve. This valve can be operated manually or automatically (pneumatic or hydraulic) depending on whether a surface safety system is to be included in the production wing design.

Choke Valve

The Choke Valve is used to restrict, control or regulate the flow of hydrocarbons to the production facilities. This valve is operated manually or automatically and may be of the fixed (positive) or adjustable type. It is the only valve on the Xmas tree that is used to control flow.

NOTE: All other valves used on Xmas trees are invariably of the gate valve type providing full bore access to the well, that is, such valves must be operated to the fully open or closed position.

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Kill Wing Valve

The Kill Wing Valve permits entry of kill fluid into the completion string and also for pressure equalisation across tree valves e.g. during wireline operations or prior to the removal/opening of a sub-surface safety valve. This valve is usually manually operated.

Swab Valve

The Swab Valve permits vertical entry into the well for wireline (e.g. running BHP/BHT gauges, tubing conditioning) or for well interventions such as coiled tubing operations and logging. This valve is operated manually.

Xmas Tree Cap

The Xmas Tree Cap provides the appropriate connection for well control equipment when conducting well interventions and is installed directly above the swab valve.

The Xmas Tree cap normally includes a quick union type connection and should be strong enough to support the well control equipment. The bore of the cap flange should be compatible with the tree and permit the running of service tools.

Sometimes the Cap is removed and replaced by tertiary well control equipment.

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A. APPENDIX - FORMULAE AND CONVERSION FACTORS COMMONLY USED IN WELL CONTROL A-1

A.1 CONVERSION FACTORS A-2

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A. APPENDIX - FORMULAE AND CONVERSION FACTORS COMMONLY USED IN WELL CONTROL

Pressure Gradient psi/ft. Mud/Brine Weight ppg x 0.052

Mud/Brine Weight ppg Pressure Gradient psi/ft ÷ 0.052

Hydrostatic Pressure psi Mud/Brine Weight ppg x 0.052 x True Vertical Depth ft

Formation Pressure psi Hydrostatic Pressure (in string & sump) psi + Shut In Tubing Head Pressure psi

Equivalent Mud Weight ppg Pressure psi ÷ True vertical Depth ft ÷ 0.052

Pump Output bbls/min Pump Output bbls/stk x Pump Speed spm

Annulus Velocity ft/min Pump Output bbls/min ÷ Annulus Volume bbls/ft

Boyle’s Law

P1V1 = P2V2

Conversion of pipe diameter to bbls/ft

A.1 CONVERSION FACTORS

Acre = 43,560 square feet = 4,047 square metres Atmosphere = 33.94 feet of water = 29.92 inches of mercury = 760 millimetres of mercury = 14.70 pounds per square inch Bar = 14.504 pounds per square inch = 100 Kilo Pascal’s Barrel = 5.6146 cubic feet = 42 gallons (US) = 35 gallons (Imperial)

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Barrel of water @ 60˚F = 0.1588 metric ton Barrel (36˚ API) = 0.1342 metric ton Barrel per hour = 0.0936 cubic feet per minute = 0.700 gallon per minute = 2.695 cubic inches per second Barrel per day (bopd) = 0.2917 gallon per minute British Thermal Unit = 0.2520 kilogram calorie = 0.2928 watt hour BTU per minute = 0.02356 horse power Centimetre = 0.3937 inch Centimetre of mercury = 0.1934 pound per square inch Cubic centimetre = 0.06102 cubic inch Cubic foot = 0.1781 barrel = 7.4805 gallons (US) = 0.02832 cubic metre = 0.9091 sacks cement (set) Cubic foot per minute = 10.686 barrels per hour = 28.800 cubic inches per second = 7.481 gallons per minute Cubic inch = 16.387 cubic centimetres Cubic metre = 6.2897 barrels (US) = 35.314 cubic feet = 264.20 gallon (US) Cubic yard = 4.8089 barrels = 46,656 cubic inches = 0.7646 cubic metre Feet = 30.48 centimetres = 0.3048 meters Feet of water @ 60˚F = 0.4331 pound per square inch Feet per second = 0.68182 mile per hour Foot pound = 0.001286 British Thermal Unit

Foot pound per second = 0.001818 horse power Gallon (US) = 0.2318 barrel = 0.1337 cubic feet = 231.00 cubic inches = 3.785 litres = 0.003785 cubic metres Gallon (Imperial) = 1.2009 gallons (US) = 277.274 cubic inches Gallon per minute = 1.429 barrels per hour = 34.286 barrels per day Gram = 0.03527 ounce

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Horsepower = 42.44 BTUs per minute = 33,000 feet/pounds per minute = 550 feet/pounds per second = 1.014 horsepower (metric) = 0.7457 kilowatt Horsepower hour = 2,547 British Thermal Units Inch = 2.540 centimetres Inch of mercury = 1.134 feet of water = 0.4912 pound per square inch Inch of water @ 60˚F = 0.0361 pound per square inch Kilogram = 2.2046 pounds Kilogram calorie = 3.968 British Thermal Units Kilogram per square centimetre = 14.223 pounds per square inch = Kg/cm2 x 98.1 gives Pascals (KPa) Kilometre = 3,281 feet = 0.6214 mile Kilo Pascal = 0.145 pounds per square inch Kilowatt = 1.341 horse power Litre = 0.2462 gallon = 1.0567 quarts Mega Pascal = 145.03 pound per square inch Metre = 3.281 feet = 39.37 inches Mile = 5,280 feet = 1.609 kilometres Miles per hour = 1.4667 feet per second Ounce (Avoirdupois) = 28.3495 grams Part per million = 0.05835 grain per gallon = 8.345 pounds per million gallons Pascal = 0.000145 pound per square inch Pound = 7,000 grains = 0.4536 kilogram Pound per square inch = 2.309 feet of water @ 60˚F = 2.0353 inches of mercury = 51.697 millimetres of mercury = 0.703 kilograms per square centimetre = 0.0689 bar = 0.006895 mega Pascal (MPa) = 6.895 kilo Pascal (KPa) = 6895 Pascal (Pa) Pressure = psi x 6.895 gives Kilo Pascals (KPa) Quart (Liquid) = 0.946 litre Sack cement (Set) = 1.1 cubic feet Square centimetre = 0.1550 square inch Square foot = 0.929 square metre Square inch = 6.452 square centimetres

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Square kilometre = 0.3861 square mile Square metre = 10.76 square feet Square mile = 2.590 square kilometres Temp Centigrade = 5/9 (Temp ˚F - 32) Temp Fahrenheit = 9/5 (Temp ˚C) + 32 Temp Absolute (Kelvin) = Temp ˚C + 273 Temp Absolute (Rankine) = Temp ˚F + 460 Ton (long) = 2,240 pounds Ton (metric) = 2,205 pounds Ton (short or net) = 2,000 pounds Ton (metric) = 1.102 tons (short or net) Ton (metric) = 1,000 kilograms = 6.297 barrels of water @ 60˚F = 7.454 barrels (36˚ API) Ton (short or net) = 0.907 ton (metric) Watt per hour = 3.415 BTUs Yard = 0.9144 metre

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B. API GUIDELINES (API RP53) B-1

B.1 RAM BOWOUT PREVENTERS - CAMERON U BOP B-10

B.2 ANNULAR PREVENTERS B-38

B.3 DIVERTERS B-57

B.4 GASKETS, SEALS & WELLHEADS B-68

B.5 MANIFOLDS, VALVES, SEPARATORS AND FLOW GAIN SENSORS B-80

B.6 INSIDE BOP'S B-98

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W R E T L N L E C C O G N IN TROL TRAIN APPENDIX B : API GUIDELINES (API RP53)

BLOWOUT PREVENTER STACK ARRANGEMENTS SURFACE INSTALLATIONS

CLASSIFICATION OF BLOWOUT PREVENTERS

API classification of example arrangements for blowout preventer equipment is based on working pressure ratings. Example stack arrangements shown in Figs. C.1 to C.9 should prove adequate in normal environments, for API Classes 2M, 3M, 5M, 10M and 15M. Arrangements other than those illustrated may be equally adequate in meeting well requirements and promoting safety and efficiency.

STACK COMPONENT CODES

The recommended component codes for designation of blowout preventer stack arrangements are as follows:

A = annular type blowout preventer. G = rotating head. R = single ram type preventer with one set of rams, either blank or for pipe, as operator prefers. Rd = double ram type preventer with two sets of rams, positioned in accordance with operator’s choice. Rt = triple ram type preventer with three sets of rams, positioned in accordance with operator’s choice. S = drilling spool with side outlet connections for choke and kill lines. M = 1000 psi rated working pressure.

Components are listed reading upward from the uppermost piece of permanent wellhead equipment, or from the bottom of the preventer stack. A blowout preventer stack may be fully identified by a very simple designation, such as:

5M -13 5/ - SRRA 8 This preventer stack would be rated 5000 psi working pressure, would have throughbore of 13 5/ inches, and would be arranged as in Fig. C.5. 8 RAM LOCKS

Ram type preventers should be equipped with extension hand wheels hydraulic locks.

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W R E T L N L E C C O G N IN TROL TRAIN SPARE PARTS

The following recommended minimum blowout preventer spare parts approved for the service intended should be available at each rig:

a. a complete set of drill pipe rams and ram rubbers for each size drill pipe being used, b. a complete set of bonnet or door seals for each size and type of ram preventer being used, c. plastic packing for blow out preventer secondary seals, d. ring gaskets to fit flange connections, and e. appropriate spare parts for annular preventers, when used.

PARTS STORAGE

When storing blowout preventer metal parts and related equipment, they should be coated with a protective coating to prevent rust.

DRILLING SPOOLS

While choke and kill lines may be connected to side outlets of the blowout preventers, many operators prefer that these lines be connected to a drilling spool installed below at least one preventer capable of closing on pipe. Utilisation of the blowout preventer side outlet reduces the number of stack connections by eliminating the drilling spool and shortens the overall preventer stack height. The reasons for using a drilling spool are to localise possible erosion in the less expensive spool and to allow additional space between rams to facilitate stripping operations.

Drilling spools for blowout preventer stacks should meet the following minimum specifications:

a. Have side outlets no smaller than 2" nominal diameter and be flanged, studded, or clamped for API Class 2M, 3M, and 5M. API Class 10M and 15M installations should have a minimum of two side outlets, one 3" and one 2" nominal diameter. b. Have a vertical bore diameter at least equal to the maximum bore of the uppermost casinghead. c. Have a working pressure rating equal to the rated working pressure of the attached blowout preventer.

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W R E T L N L E C C O G N IN TROL TRAIN For drilling operations, wellhead outlets should not be employed for choke or kill lines Such outlets may be employed for auxiliary or back-up connections to be used only if a failure of the primary control system is experienced. S* R R RS*R FIG C.4 ARRANGEMENT R S* A S*RR FIG C.3 ARRANGEMENT S* R R FIG C.2 Rd Optional. ARRANGEMENT S*RR Double Ram Preventers, EXAMPLE BLOWOUT PREVENTER ARRANGEMENTS FOR EXAMPLE BLOWOUT PREVENTER 2M RATED WORKING PRESSURE SERVICE – SURFACE INSTALLATION – SURFACE WORKING PRESSURE SERVICE 2M RATED S* A FIG C.1 ARRANGEMENT S*A

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A A

R R

R S*

S* R

FIG C.5 FIG C.6 ARRANGEMENT S*RRA ARRANGEMENT Double Ram Type Preventers, RS*RA Rd Optional.

EXAMPLE BLOWOUT PREVENTER ARRANGEMENTS FOR 3M AND 5M RATED WORKING PRESSURE SERVICE – SURFACE INSTALLATION

* Drilling spool and its location in the stack arrangement is optional

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G**

A** A** A**

R R R

S* R S*

R S* R

CASING CASING CASING SPOOL SPOOL SPOOL

FIG C.7 FIG C.8 FIG C.9 ARRANGEMENT RS*RRA** ARRANGEMENT S*RRRA** ARRANGEMENT RS*RRA**G** Double Ram Type Preventers, Double Ram Type Preventers, Double Ram Type Preventers, Rd Optional. Rd Optional. Rd Optional.

EXAMPLE BLOWOUT PREVENTER ARRANGEMENTS FOR 10M AND 15M WORKING PRESSURE SERVICE – SURFACE INSTALLATION

* Drilling spool and its location in the stack arrangement is optional. ** Annular Preventer A, and rotating head G, can be of a lower pressure rating.

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BLOWOUT PREVENTER STACK ARRANGEMENTS - SUBSEA INSTALLATIONS

VARIANCE FROM SURFACE INSTALLATIONS

The arrangements of subsea blowout preventer stacks are similar to the example preventer surface installations with certain differences. The differences are:

a. Choke and kill lines normally are connected to ram preventer body outlets.

b. Spools may be used to space preventers for shearing tubulars, hanging off drill pipe, or stripping operations.

c. Choke and kill lines are manifolded for dual purpose usage.

d. Blind/shear rams are normally used in place of blind rams.

e. Ram preventers are usually equipped with an integral or remotely operated locking system.

STACK COMPONENT CODES

The recommended component codes adopted for designation of subsea blowout preventer stack arrangements use the same nomenclature as surface installations with the addition of remotely operated connectors:

C =remotely operated connector used to attach wellhead or preventers to each H other (connector should have a minimum working pressure rating equal to the preventer stack working pressure rating).

C = low pressure remotely operated connector used to attach the marine riser to L the blowout preventer stack.

Example subsea blowout preventer stack arrangements are illustrated in Figs. D.1 through D.8.

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W R E T L N L E C C O G N IN TROL TRAIN A H H H R R A* C C RRC FIG D.4 H C Rd, Optional. ARRANGEMENT Double Ram Type Preventers, Double Ram Type L L H R R A C C RRAC FIG D.3 H Rd, Optional. ARRANGEMENT Double Ram Type Preventers, Double Ram Type L L H R A C C RAC FIG D.2 H SERVICE – SUBSEA INSTALLATION – SUBSEA SERVICE ARRANGEMENT 2M AND 3M RATED WORKING PRESSURE AND 3M RATED 2M L EXAMPLE BLOWOUT PREVENTER ARRANGEMENTS FOR EXAMPLE BLOWOUT PREVENTER SAC H L H S A C C FIG D.1 ARRANGEMENT C (2m rated working pressure only.) (2m rated working pressure

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W R E T L N L E C C O G N IN TROL TRAIN A* H A*C H H R R R R d A* A* C C R FIG D.8 d R H C ARRANGEMENT L A*C L H d R R R R A* R C C d FIG D.7 R H ARRANGEMENT A* H H H R R R A* A* C C RA*C SERVICE – SUBSEA INSTALLATION – SUBSEA SERVICE FIG D.6 d R H ARRANGEMENT 5M, 10M AND 15M RATED WORKING PRESSURE AND 15M RATED 5M, 10M EXAMPLE BLOWOUT PREVENTER ARRANGEMENTS FOR EXAMPLE BLOWOUT PREVENTER L RA*C d R H L H R R R A* C C Optional FIG D.5 d R Triple Ram Type Preventers, Ram Type Triple ARRANGEMENT C

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A A

R R

R S*

S* R

FIG C.5 FIG C.6 ARRANGEMENT S*RRA ARRANGEMENT Double Ram Type Preventers, RS*RA Rd Optional.

EXAMPLE BLOWOUT PREVENTER ARRANGEMENTS FOR 3M AND 5M RATED WORKING PRESSURE SERVICE – SURFACE INSTALLATION

* Drilling spool and its location in the stack arrangement is optional

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W R E T L N L E C C O G N IN TROL TRAIN B.1 RAM BLOWOUT PREVENTERS - CAMERON U BOP

The Cameron U BOP is the most widely used ram-type BOP for land, platform and subsea applications worldwide and offers the widest range of sizes of any Cameron ram-type BOP. Like all other Cameron preventers, the rams in the U BOP are pressure-energized. Wellbore pressure acts on the rams to increase the sealing force and maintain the seal in case of hydraulic pressure loss. Seal integrity is actually improved by increased well bore pressure.

Other features of the U BOP include:

• Hydraulic stud tensioning available on larger sizes to ensure that stud loading is consistently accurate and even.

• Bonnet seal carrier is available to eliminate the need for high makeup torque on bonnet studs and nuts.

• Hydraulically operated locking mechanisms, wedgelocks, lock the ram hydraulically and hold the rams mechanically closed even when actuating pressure is released. The operating system can be interlocked using sequence caps to ensure that the wedgelock is retracted before pressure is applied to open the BOP.

• For subsea applications, a pressure balance chamber is used with the wedge locks to eliminate the possibility of the wedgelock becoming unlocked due to hydrostatic pressure.

Other features include hydraulically opening bonnets, forged body and a wide selection of rams to meet all applications.

Figure B.1.2 U Blowout Preventer Wedgelock Assembly

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Figure B.1.3 Figure Cameron U - Type BOP

Bonnet Seal Groove

Side Entry Port

Bonnet Seals

Body, Single

Seal Rings, Connecting Rod

Rams Assembly

Intermediate Flange

Cylinder, Ram Change

Plastic Injection Port

Cylinder, Operating Piston, Ram Change

Piston, Operating

'O' Rings, Operating Cylinder

Lip Seal, Operating Piston Bonnet

Locking Screw

Housing, Locking Screw

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W R E T L N L E C C O G N IN TROL TRAIN PIPE RAMS

Cameron pipe rams are available for use in Cameron ram-type BOPs to fit all commonly used sizes of tubing, drill pipe, drill collar or casing.

• Cameron pipe rams are self-feeding and incorporate a large reservoir of packer rubber to ensure a long-lasting seal under all conditions.

• Ram packers lock into place and are not dislodged by well flow

• All Cameron pipe rams are suitable for H2S service per NACE MR-01-75.

• CAMRAM™ top seals are standard for all Cameron pipe rams (except 3 U BOPs larger than 13- /4”).

• CAMRAM 350™ packers and top seals are available for high temperature service and for service in which concentrations of H2S are expected.

Top Seal Top Seal

Packer Packer Ram Ram

U BOP Pipe Ram U II BOP Pipe Ram

CAMRAM Top Seal CAMRAM Packer

Wear Pads Ram

T BOP Pipe Ram

Figure B.1.4 - PIPE RAMS

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W R E T L N L E C C O G N IN TROL TRAIN VARIABLE BORE RAMS

One set of Cameron variable bore rams (VBRs) seals on several sizes of pipe or hexagonal kelly, eliminating the need for a set of pipe rams for each pipe size. Features include:

• VBR packer contains steel reinforcing inserts which rotate inward when the rams are closed so the steel provides support for the rubber which seals against the pipe.

• All VBRs are suitable for H2S service per NACE MR-01-75.

• CAMRAM™ top seals are standard for all Cameron VBRs.

Ram Body Top Seal CAMRAM Packer Ram Body CAMRAM Packer

VBR Packer Wear Pads

U and U II BOP Variable Bore Ram T BOP Variable Bore Ram

Figure B.1.5 - VBR'S

Shearing Blind Rams

Cameron shearing blind rams (SBRs) shear the pipe in the hole, then bend the lower section of sheared pipe to allow the rams to close and seal. SBRs can be used as blind rams during normal drilling operations. Features include:

• Large frontal area on the blade face seal reduces pressure on the rubber and increases service life.

• Cameron SBRs can cut pipe numerous times without damage to the cutting edge.

• The single-piece body incorporates an integrated cutting edge.

• CAMRAM™ top seals are standard for all Cameron SBRs.

• H2S SBRs are available for critical service applications and include a blade material of hardened high alloy suitable for H2S service.

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W R E T L N L E C C O G N IN TROL TRAIN DVS rams are shearing blind rams which are similar to SBRs with the following features:

• DVS (double V shear) rams fold the lower portion of the tubular over after shearing so that the lower blade can seal against the blade packer

• DVS rams include the largest blade width available to fit within existing ram bores.

CAMRAM Top Seal Ram Slide Packer Body

Blade Packer CAMRAM Top Seal Upper Lower SBR SBR Blade Insert Slide Packer U and U ll BOP Shearing Blind Ram

Blade Blade Packer Insert Upper SBR Lower SBR

CAMRAM U and U ll H S BOP Shearing Blind Ram Blade Packer Top Seal 2 Upper Blade Insert Screw

Slide Packer

Wear Pads Lower Blade Insert Upper Lower SBR SBR Top Seal Upper Ram Body T BOP Shearing Blind Ram Lower Ram Body

Side Blade Packer Packer

DVS Shear Ram

Figure B.1.6 - SHEAR RAMS

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W R E T L N L E C C O G N IN TROL TRAIN SECONDARY SEAL

The secondary seal is activated by screwing down on the piston which forces plastic through the check valve and into the space between the two swab cup seals. Further piston displacement causes pressure to build up between the swab cups, forcing them to flare out and provide a seal. When the pressure exerted by the plastic packing reaches the proper valve, additional displacement of the piston will overcome the spring tension in the relief valve and plastic packing will begin to extrude from it.

The secondary seal should be activated only if the primary connecting-rod seal leaks during and emergency operation. The secondary seal is designed for static conditions and movement of the connecting rod causes rapid seal and rod wear.

PROTECTOR

PACKING PISTON

PLASTIC PACKING

CHECK VALVE

RAM SIDE

PRIMARY SEAL SECONDARY SEALS

PACKING REGULATOR VALVE Figure B.1.7 - SECONDARY SEAL

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W R E T L N L E C C O G N IN TROL TRAIN

U II Blowout Preventer

The Cameron U II BOP takes all of the features of the U BOP and adapts them for subsea use in the 18-3/4-10,000 and 15,000 psi WP sizes. Like all other Cameron preventers, the rams in the U II BOP are pressure- energized. Wellbore pressure acts on the rams to increase the sealing force and maintain the seal in case of hydraulic pressure loss. Seal integrity is actually improved by increased well bore pressure.

Other features of the U II BOP include:

• Internally ported hydraulic stud tensioning system ensures that stud loading is consistently accurate and even.

• Bonnet seal carrier is available to eliminate the need for high makeup torque on bonnet studs and nuts.

• A pressure balance chamber is used with the wedgelocks to eliminate the possibility of the wedgelock becoming unlocked due to hydrostatic pressure. Other features include hydraulically opening bonnets, forged body and a wide selection of rams to meet all applications.

Figure B.1.8 - 18-3/4" DOUBLE U II BLOWOUT PREVENTER

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W R E T L N L E C C O G N IN TROL TRAIN Optional Equipment

Bonnet Seal Carriers for TL, U, UL and U 11 BOPS The bonnet seal carrier is a bore-type sealing assembly which replaces the face seal used as the previous bonnet seal. Sealing capability is not dependent upon bonnet bolt torque. One seal is captured in a machined bore in the BOP body while the other seal is captured in a machined bore in the intermediate flange.

The seal carrier was designed, developed and performance-verified for use in newly manufactured BOPs or as a replacement seal assembly for BOPs where either the BOP body or the intermediate flange requires weld repair on the sealing surfaces.

Large Bore Shear Bonnets Cameron developed large bore shear bonnets to increase the available shearing force required to shear high strength and high quality pipe. In order to achieve this the large bore shear bonnet design increased the available closing area by 35% or more. Cameron recommends large bore shear bonnets when larger shearing forces are required. As an alternative to purchasing new large bore shear bonnets, some old shear bonnets can be converted. This process requires reworking and replacing several existing components.

Tandem Boosters for U BOPS A BOP equipped with tandem boosters can deliver increased shearing force while not increasing the wear and tear on the packers. Tandem boosters approximately double the force available to shear pipe. Since the tail rod of the tandem booster has the same stroke as the BOP operating piston, the standard shear locking mechanism can be installed on the outside end of the booster.

Large Bore Shear Bonnet Assembly Exploded View

Figure B.1.9 Tandem Booster Exploded View

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W R E T L N L E C C O G N IN TROL TRAIN Figure B.1.10 UII BOP Hydraulic Control System

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W R E T L N L E C C O G N IN TROL TRAIN Figure B.1.11 UII BOP Part Numbers

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W R E T L N L E C C O G N IN TROL TRAIN SHAFFER SL RAM BLOWOUT PREVENTERS

Shaffer Model SL ram blowout preventers are the product of more than 50 years of experience in building ram BOP’s to meet the changing demands of the petroleum industry. SL designated models incorporate the improvements made in the LW S preventer line over the past 20 years—improvements resulting from a continuing research program to ensure that Shaffer preventers meet or surpass the latest industry requirements.

Special Features

• Flat doors simplify ram changes. To change the rams, apply opening hydraulic pressure to move the rams to the full open position. Remove the door cap screws and swing the door open. Remove the ram from the ram shaft and replace it. It is not necessary to apply closing hydraulic pressure to move the rams inward to clear the door.

• Door seals on most sizes have a hard backing moulded into the rubber. This fabric and phenolic backing prevents extrusion and pinching at all pressures to assure long seal life.

• Internal H2S trim is standard. All major components conform to API and NACE H2S requirements.

• Maximum ram hardness Is Rc22 to insure H2S compatibility of pipe and blind rams. Shear rams have some harder components.

• Manual-lock and Poslock pistons can be interchanged on the same door by replacing the ram shaft, piston assembly and cylinder head.

• Wear rings eliminate metal-to-metal contact between the piston and cylinder to increase seal life d virtually eliminate cylinder bore wear.

• Lip type piston seals are long-wearing polyurethane with molybdenum disulfide moulded in for lifetime lubrication..

• Lip-type ram shaft seals hold the well bore pressure and the opening hydraulic pressure. No known failures of this highly reliable high pressure seal have occurred.

• Secondary ram shaft seals permit injection of plastic packing if the primary lip-type seal ever fails. Fluid dripping from the weep hole in the door indicates that the primary seal is leaking and the secondary seal should be energised.

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W R E T L N L E C C O G N IN TROL TRAIN • Rams are available which will support a 600,000 pounds when a tool joint is lowered onto the closed rams. These rams conform to H2S requirements.

• Shear rams cut drill pipe and seal in one operation. Most common weights and grades of drill pipe are sheared with less than 1,500 psi hydraulic pressure.

• Poslock operators automatically lock the rams each time they are closed. This eliminates the cost of a second hydraulic function to lock. It also simplifies emergency operation because the rams are both closed and locked just by activating the close function.

Figure B.1.12 - SHAFFER SL-RAM BOP

Ram shaft seal Roundhead ram shaft Piston seals Cylinder

Weep hole

Flat door

Cylinder head Ram Wear rings Ram shaft Piston assembly packing retainer Secondary ram shaft seal

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W R E T L N L E C C O G N IN TROL TRAIN Figure B.1.13 - LOCKING SYSTEMS

Poslock adjustment thread

Piston

Locking segment

Locking shoulder

Ram shaft Ram

1) Poslock in open position

Cylinder

Piston Locking segment Locking cone

2) Poslock piston in closed position

Ram shaft Ram

1) Manual-lock piston in open position

Cylinder Head

3) Manual-lock piston in closed position

Locking shaft

2) Manual-lock piston in closed and locked position

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W R E T L N L E C C O G N IN TROL TRAIN MODEL SL MANUAL-LOCK SYSTEM

Manual-lock pistons move inward and close the rams when closing hydraulic pressure is applied. If desired, the rams can be manually locked in the closed position by turning each locking shaft to the right until it shoulders against the cylinder head. Should hydraulic pressure fail, the rams can be manually closed and locked. They cannot be manually reopened.

The manual locking shafts are visible from outside and provide a convenient ram position indicator. Threads on the manual locking shaft are enclosed in the hydraulic fluid and are not exposed to corrosion from mud and salt water or to freezing.

Rams are opened by first turning both locking shafts to their “unlocked” position, then applying opening hydraulic pressure to the pistons, which move outward and pull the rams out of the well bore.

MODEL SL HYDRAULIC SYSTEM

OPERATION AND MAINTENANCE

Hydraulic power to operate a Model SL ram BOP can be furnished by any standard oil field accumulator system.

Hydraulic passages drilled through the body eliminate the need for external manifold pipes between the hinges. Each set of rams requires only one opening and one closing line. There are two opening and two closing hydraulic ports, clearly marked, on the back side of the BOP. The extra hydraulic ports facilitate connecting the control system to the preventer.

A 1,500-psi-output hydraulic accumulator will close any Model SL ram BOP with rated working pressure in the well bore except for the 11" and 13 5/8—15,000 psi BOP’s, which require 2,100 psi. However, these two will close against 10,000 psi well pressure with less than 1,500 psi hydraulic pressure.

A 3,000 psi hydraulic pressure may be used, but this will accelerate wear of the piston seals and the ram rubbers.

A 5,000 psi hydraulic pressure test is applied to all Model SL cylinders at the factory. However, it is recommended that this pressure not be used in the field application.

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W R E T L N L E C C O G N IN TROL TRAIN The hydraulic operating fluid should be hydraulic oil with a viscosity between 200 and 300 SSU at 100°F. If necessary, a water-soluble oil such as NL Rig Equipment K-90 and water can be used for environmental protection. Ethylene glycol must be added to the K-90 and water solution for freeze protection if equipment is exposed to freezing temperatures.

NOTE: Never use fuel oil of any kind as it causes the rubber goods to swell and deteriorate. Some water-soluble fluids do not give adequate corrosion protection or lubrication and should not be used.

MODEL SL POSLOCK SYSTEM

SL preventers equipped with Poslock pistons are automatically locked in the closed position each time they are closed. The preventers will remain locked in the closed position even if closing pressure is removed. Opening hydraulic pressure is required to reopen the pistons.

The hydraulics required to operate the Poslock are provided through opening and closing operating ports. Operation of the Poslock requires no additional hydraulic functions, such as are required in some competitive ram locking systems. When closing hydraulic pressure is applied, the complete piston assembly moves inward and pushes the rams into the well bore. As the piston reaches the’ fully closed position, the locking segments slide toward the piston O.D. over the locking shoulder as the locking cone is forced inward by the closing hydraulic pressure.

The locking cone holds the locking segments in position and is prevented by a spring from vibrating outward if the hydraulic closing pressure is removed. Actually, the locking cone is a second piston inside the main piston. It is forced inward by closing hydraulic pressure and outward by opening hydraulic pressure.

When opening hydraulic pressure is applied, the locking cone moves outward and the locking segments slide toward the piston l.D. along the tapered locking shoulder. The piston is then free to move outward and open the rams.

NOTE: Poslock pistons are adjusted in the factory and normally do not require adjustment in the field except when changing between pipe rams and shear rams. The adjustment is easy to check and easy to change.

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W R E T L N L E C C O G N IN TROL TRAIN

Figure B.1.14 - FLUID CIRCUIT - SL RAM

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W R E T L N L E C C O G N IN TROL TRAIN ULTRALOCK™ LOCKING SYSTEM

UltraLock, the most versatile locking system available, provides a maintenance- free and adjustment-free locking system that is compatible with any ram assembly that the blowout preventers can accommodate. Once the UltraLock is installed, no further adjustments will be needed when changing between Pipe Rams, Blind/ Shear or MULTI-RAM assemblies. BOPs that are equipped with the UltraLock are automatically locked in the closed position each time the BOPs are closed; no preset pressure ranges are needed. The BOPs will remain locked in the closed position, even if closing pressure is lost or removed. Hydraulic opening pressure is required to re-open the preventer, and this opening pressure is supplied by the regular opening and closing ports of the preventer. No additional hydraulic lines or functions are required for operations of the locks. Stack frame modifications are not required because all operational components are in the hydraulic operating cylinders. Existing BOPs with PosLock~ Cylinders can be upgraded to the UltraLock. U.S. patent number 5,025,708.

Secondary Unlocking Piston

Locking Plate

Locking Ram Locking Rod Plate Locking Rod Dog Load Ultra Lock Shaft Retaining Screw Locking Dog Spring Piston Locking Rod Plate Retainer

Figure B.1.15 - ULTRALOCK - UNIQUE POSITION LOCKING SYSTEM

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W R E T L N L E C C O G N IN TROL TRAIN TYPE 72 SHEAR RAMS

Type 72 shear rams shear pipe and seal the well bore in one operation. They also function as blind or CSO (complete shut-off) rams for normal operations.

The hydraulic closing pressure required to shear commonly used drill pipe is below 1,500 psi for BOP’s with 14'’ pistons. These pistons are standard in all BOP’s rated at 10,000 psi working pressure and higher. On lower pressure preventers, optional 14" pistons can be supplied for shearing instead of the standard 10" pistons.

When shearing, the lower blade passes below the sharp lower edge of the upper ram block and shears the pipe. The lower section of cut pipe is accommodated in the space between the lower blade and the upper holder. The upper section of cut pipe is accommodated in the recess in the top of the lower ram block.

Closing motion of the rams continues until the ram block ends meet. Continued closing of the holders squeezes the semicircular seals upward into sealing

contact with the seat in the BOP body and energises the horizontal seal. The closing motion of the upper holder pushes the horizontal seal forward and downward on top of the lower blade, resulting in a tight sealing contact. The horizontal seal has a moulded-in support plate which holds it in place when the rams are open.

Type 72 Shear Rams are covered by U.S. Patent No. 3,736,982. (Ref fig B.1.16)

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W R E T L N L E C C O G N IN TROL TRAIN

UPPER RUBBER LOWER RUBBER LOWER BLOCK

UPPER BLOCK

LOWER HOLDER

SHEAR BLADE

UPPER HOLDER

HORIZONRAL SEAL SEMICIRCULAR SEAL

SUPPORT PLATE

SHEAR RAMS OPEN

SHEAR RAMS CLOSING

HORIZONRAL SEAL SEMICIRCULAR SEAL

SUPPORT PLATE

SHEAR RAMS CLOSED

Figure B.1.16 - TYPE 72 SHEAR RAMS

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W R E T L N L E C C O G N IN TROL TRAIN HYDRIL RAM BLOWOUT PREVENTERS

Features: (Refer to Fig B.1.17 and B.1.18)

1. The Ram Body Casting has controlled and predictable structural hardness and strength throughout the pressure vessel. Hydril pressure vessel material has equal strength along all axes to provide reliable strength and resistance to sulphide stress cracking in hydrogen sulphide service.

2. The Ram Assembly provides reliable seal off of the wellbore for security and safety. The Ram accommodates a large volume of feedable rubber in the front packer and upper seal for long service life.

3. The Field Replaceable Seal Seat provides a smooth sealing surface for the ram upper seal. The seal seat utilises specially selected and performance effective materials for maximum service life.

4 Hinged Bonnet swing completely clear of overhead restrictions (such as another BOP) and provide easy access for rapid ram change to reduce downtime.

5. Load Hinges separate from the fluid hinge and are equipped with self- lubricated bearings to support the full weight of the bonnet for quick and easy opening of the bonnet.

6. Fluid Hinges, separate from the load hinges, connect the control fluid passages between the body and bonnets. This arrangement provides a reliable hydraulic seal and permits full pressure testing and ram operation with the bonnets open. The fluid hinges and bonnet hinges contain all the seals necessary for this function and may be removed rapidly for simple, economical repair.

7. Replaceable Cylinder Liner has a corrosion and wear resistant bore for reliable piston operation. The cylinder liner is easily field replaceable or reparable for reduced maintenance cost and downtime.

8. Piston and Piston Rod Assembly are one piece for strength and reliability in closing and opening the ram which results in a secure operating assembly.

9. Choice of Ram Locks—Automatic Multiple Position Locking (MPL) or Manual Locking is available on Ram BOPs.

10. Multiple-Position Locking (MPL) utilises a hydraulically-actuated mechanical clutch mechanism to automatically lock the rams in a seal off position.

11. Manual Locking utilises a heavy-duty acme thread to manually lock the ram in a sealed-off position or to manually close the ram if the hydraulic system is inoperative.

12. Fluid Connections and Hydraulic Passages are internal to the bonnets and body and preclude damage during moving and handling operations.

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W R E T L N L E C C O G N IN TROL TRAIN 13. Connector Ring Grooves are stainless steel lined for all connectors (top, bottom and side outlets) for corrosion resistance of the sealing surface.

14. Sloped Ram Cavity is self-draining to eliminate build-up of sand and drilling fluid.

15. Bonnet Seal utilises field proven material in an integrated seal design which combines the seal and backup ring for reliability and long life.

16. Piston Rod Mud Seal is a rugged, field-proven, integrally designed lip seal and backup ring retained in the bonnet by a stainless steel spiral lock ring.

17. Secondary (Emergency) Piston Rod Packing provides an emergency piston rod seal for use in the event of primary seal leakage at a time when repair cannot be immediately effected.

18. A Weephole to atmosphere isolates wellbore pressure, indicates when seal is achieved and possible leakage in the primary seat. (Shown out of position)

19. Piston Seals are of a lip-type design and are pressure-energized to provide a reliable seal of the piston to form the operating chambers of the BOP.

20. Side Outlets for choke/kill lines are available on all models. Two outlets, one on each side, may be placed below each ram. In single and double configurations, outlets may be placed below the upper and lower ram, below the bottom ram only, or below the top ram only, therefore providing great versatility in stack design.

21. Single and Double Configurations are available with a choice of American Petroleum Institute (API) flanged, studded or clamp hub connections. This allows for the most-economical use of space for operation and service. (Not shown)

22. Bonnet Bolts are sized for easy torquing and arranged for reliable seal between bonnet and body. This prevents excessive distortion during high pressure seal off.

23. Bonnet Bolt Retainers keep the bonnet bolts in the bonnet while servicing the BOP.

24. Guide Rods align ram with bonnet cavity, preventing damage to the ram, piston rod or bonnets while retracting the rams.

25. Ram Seal Off is retained by wellbore pressures. Closing forces are not required to retain an established ram seal off.

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W R E T L N L E C C O G N IN TROL TRAIN

6. FLUID HINGES

5. LOAN HINGES

12. FLUID CONNECTIONS AND HYDRAULIC PASSAGES

20. SLIDE OUTLETS FOR CHOKE/KILL

1. THE RAM BODY CASTING THE RAM BODY 1.

24. GUIDE RODS

13. CONNECTOR RING GROOVES 13. CONNECTOR

14. SLOPED RAM CAVITY

16. PISTON ROD MUD SEAL 16. PISTON

18. A 18. A WEEPHOLE

3. THE FIELD REPLACABLE 3. SEAL SEAT SEAL

7. REPLACABLE CYLINDER LINER

15. BONNET SEAL 15. BONNET

2. THE RAM ASSEMBLY

Figure B.1.17 - 13 5/8" - 10,000 PSI RAM BOP MANUAL LOCK

19. PISTON SEALS 19. PISTON

17. SECONDARY (EMERGENCY) (PISTON ROD PACKING) (PISTON

22. BONNET BOLTS 22. BONNET

11. MANUAL LOCKING MANUAL 11.

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W R E T L N L E C C O G N IN TROL TRAIN

1. THE RAM BODY CASTING THE RAM BODY 1.

20. SIDE OUTLETS FOR CHOKE KILL

13. CONNECTOR RING GROOVES 13. CONNECTOR

14. SLOPED RAM CAVITY

15. BONNET SEAL 15. BONNET

16. PISTON ROD MUD SEAL 16. PISTON

18. A 18. A WEEPHOLE

3. THE FIELD REPLACEABLE 3. SEAL SEAT SEAL

19. PISTON SEALS 19. PISTON

2. THE RAM ASSEMBLY 2. THE RAM

7. REPLACEABLE CYLINDER LINER

6. FLUID HINGES

5. LOAD HINGES

Figure B.1.18 - 18 3/4" - 15,000 PSI RAM BOP MULTIPLE POSITION LOCK (MPL) Figure B.1.18 - 18 3/4" - 15,000 PSI RAM BOP MULTIPLE

10. MULTIPLE-POSITION LOCKING (MPL)

8. PISTON AND PISTON 8. PISTON ROD ASSEMBLY ROD

22. BONNET BOLTS 22. BONNET

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MPL AUTOMATIC RAM LOCKING (Refer to Fig B.1.19) Hydril Ram Blowout Preventers are available with automatic Multiple-Position Ram Locking. Multiple-Position Locking (MPL) allows the ram to seal off with optimum seal squeeze at every closure. MPL automatically locks and maintains the ram closed with the optimum rubber pressure required for seal off in the front packer and upper seal.

Front packer seal wear (on any ram BOP) requires a different ram locking position with each closure to ensure an effective seal off. Multiple-Position Locking is required to ensure retention of that seal off position.

A mechanical lock is automatically set each time the ram is closed. Ram closure is accomplished by applying hydraulic pressure to the closing chamber which moves the ram to a seal off position. The locking system maintains the ram mechanically locked while closure is retained and/or after releasing closing pressure. The ram is opened only by application of opening pressure which releases the locking system automatically and opens the ram, simultaneously.

MPL is available on all Hydril Ram Blowout Preventers.

How MPL works

This figure shows the ram maintained closed and sealed off by the MPL. Hydraulic closing pressure has been released. The Hydril Ram Blowout Preventer with MPL automatically maintains ram closure and seal off. MPL will maintain the required rubber pressure in the front packer and upper seal to ensure a seal off of rating working pressure. MPL will maintain the seal off without closing pressure and with the opening forces created by hanging the drill string on the ram.

Locking and unlocking of the MPL are controlled by a unidirectional clutch mechanism and a lock nut. The unidirectional clutch mechanism maintains the nut and ram in a locked position until the clutch is disengaged by application of control system pressure to open the ram.

Hydraulic opening pressure disengages the front and rear clutch plates to permit the lock nut to rotate and the ram to open. As the ram and piston move to the open position, the lock nut and front clutch plate rotate freely.

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W R E T L N L E C C O G N IN TROL TRAIN

Figure B.1.19 - HYDRILL MULTI-POSITION LOCK (MPL)

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Figure B.1.20 Ram Preventer Opening and Close Ratios

Cameron U Shaffer 'SL' Hydril Ram

SIZE WP (psi) Open Close Open Close Open Close

7 1/16 in. 3,000 2.3 6.9 1.5 5.4 5,000 2.3 6.9 1.5 5.4 10,000 2.3 6.9 1.7 8.2 15,000 2.3 6.9 3.37 7.11 6.6 7.6

9 in. 2,000 3,000 2.6 5.3 5,000 2.6 5.3 10,000

11 in. 2,000 2.5 7.3 3,000 2.5 7.3 2.0 6.8 5,000 2.5 7.3 2.0 6.8 10,000 2.5 7.3 7.62 7.11 2.4 7.6 15,000 2.2 9.9 2.8 7.11 3.24 7.6

13 5/8 in. 3,000 2.3 7.0 3.00 5.54 2.1 5.2 5,000 2.3 7.0 3.00 5.54 2.1 5.2 10,000 2.3 7.0 4.29 7.11 3.8 10.6 15,000 5.6 8.4 2.14 7.11 3.56 7.74

16 3/4 in. 2,000 3,000 2.3 6.8 5,000 2.3 6.8 2.03 5.54 10,000 2.3 6.8 2.06 7.11 2.41 10.6

18 3/4 in. 10,000 3.6 7.4 1.83 7.11 1.9 10.6 15,000 4.1 9.7 1.68 10.85 2.15 7.27

21 1/4 in. 2,000 1.3 7.0 0.98 5.2 3,000 1.3 7.0 0.98 5.2 5,000 5.1 6.2 1.9 10.6 10,000 4.1 7.2 1.63 7.11

26 3/4 in. 2,000 3,000 1.0 7.0

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W R E T L N L E C C O G N IN TROL TRAIN EXAMPLE CLOSING FORCES IN RELATION TO AREA

a) When closing the well in on a floating rig the hard shut in method is usually applied. The string is picked up say 20’ off bottom, the rotary table or top drive is shut off and both pumps are shut down. The annular preventer is then closed and the fail-safe's opened against a closed choke.

b) The tool joint is then spaced out for the correct pipe rams.

c) The string is stripped down until the tool joint is "hung off’ on the rams. The correct operating pressure to set on the manifold regulator is directly related to the well bore pressure. For example. Operating ratio 10:56:1. Working pressure of BOP stack 10,000 psi.

F 10,000 psi P = ––– ∴ F = P x A ––––––––– = 947 psi A 10.56

This pressure does not include an allowance for friction losses so the minimum pressure would be say 1000 psi : 1000 psi x 10.56 = 10560 lbs closing force.

Figure B.1.21

➙ ➙ ➙ ➙ ➙ ➙ ➙ ➙ CLOSING CLOSING RAM SHAFT AREA PRESSURE ➙ ➙ AREA ➙ ➙ ➙ ➙ ➙ ➙

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W R E T L N L E C C O G N IN TROL TRAIN Figure B.1.22 RAM PREVENTERS -FLUID REQUIRED TO OPERATE

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W R E T L N L E C C O G N IN TROL TRAIN B.2 ANNULAR PREVENTERS

In the unique design of the Cameron DL annular BOP, closing pressure forces the operating piston and pusher plate upward to displace the solid elastomer donut and force the packer to close inward. As the packer closes, steel reinforcing inserts rotate inward to form a continuous support ring of steel at the top and bottom of the packer. The inserts remain in contact with each other whether the packer is open, closed on pipe or closed on open hole. Other features of the DL BOP include: • The Cameron DL BOP is shorter in height than comparable annular preventers. A quick-release top with a one-piece split lock ring permits quick packer change out with no loose parts involved. The design also provides visual indication of whether the top is locked or unlocked.

• The DL BOP is designed to simplify field maintenance. Components subject to wear are field-replaceable and the entire operating system may be removed in the field for immediate change-out without removing the BOP from the stack.

• Twin seals separated by a vented chamber positively isolate the BOP operating system from well bore pressure. High strength polymer bearing rings prevent metal-to-metal contact and reduce wear between all moving parts of the operating systems.

• Packers for DL BOPs have the capacity to strip pipe as well as close and seal on almost any size or shape object that will fit into the wellbore. These packers will also close and seal on open hole. Some annular packers can also be split for installation while pipe is in the hole. Popular sizes of the DL BOP are available with high-performance CAMULAR™ annular packing subassemblies.

ACCESS FLAPS

PACKING UNIT CONSISTING OF: LOCKING PACKER, GROOVES DONUT

PUSHER PLATE OPENING CHAMBER

PISTON OPENING CLOSING HYDRAULIC HYDRAULIC PORT PORTS

VENT

Figure B.2.1 DL ANNULAR BLOWOUT PREVENTER

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W R E T L N L E C C O G N IN TROL TRAIN

Figure B.2.2 CAMERON 20,000 PSI WP ANNULAR BLOWOUT PREVENTER SEALING ELEMENT

OPEN CLOSED ON PIPE CLOSED ON OPEN HOLE

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W R E T L N L E C C O G N IN TROL TRAIN

Figure B.2.3 HYDRIL “GK” ANNULAR

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W R E T L N L E C C O G N IN TROL TRAIN OPERATIONAL FEATURES

The Hydril GK Annular BOPs are particularly qualified to meet the industry’s needs for simple and reliable blowout protection. Over 40 years of operational experience provide the simplest, field proven mechanism in the industry.

Only Two Moving Parts (piston and packing unit) on the Hydril Annular BOP mean few areas are subjected to wear. The BOP is thus a safer, and more efficient mechanism requiring less maintenance and downtime.

A Long piston with a length to diameter ratio approaching one eliminates tendencies to cock and bind during operations with off-centre pipe or unevenly distributed accumulation of sand, cuttings, or other elements. This design ensures the packing unit will always reopen to full bore position.

Back to Front Feedable Rubber on the Packing Unit enables the packing unit to close and seal on virtually any shape in the drillstring or completely shut off the open bore and to strip tool joints under pressure. This feature permits confident closure of the BOP at the initial indication of a “kick” without delaying to locate the tool joint.

The Conical Bowl Design of the Piston provides a simple and efficient method of closing the packing unit. The piston serves as a sealing surface against the rubber packing unit; there is no metal-to-metal wear and thus longer equipment life results.

Utilisation of Maximum Packing Unit life is made possible with a piston indicator for measuring piston stroke. This measurement indicates remaining packing unit life and ensures valid testing.

A Field Replaceable Wear Plate In the BOP Head serves as an upper non-sealing wear surface for the movement of the packing unit, making field repair fast and economical.

Flanged Steel Inserts In the Packing Unit reinforce the rubber and control rubber flow and extrusion for safer operation and longer packing unit life.

Greater Stripping Capability is inherent in the design of the packing unit since testing (fatigue) wear occurs on the outside and stripping wear occurs on the inside of the packing unit. Thus, testing wear has virtually no affect on stripping capability and greater overall life of the packing unit results. The resulting ability to strip the drillstring to the bottom without first changing the packing unit means a safer operation, lower operating costs and longer service life for the packing unit.

The Packing Unit Is Tested to Full Rated Working Pressure at the factory and the tests are documented— before it reaches the well site—to ensure a safe, quality performance.

The Packing Unit Is Replaceable with Pipe In the Bore, which eliminates pulling the drillstring for replacement and reduces operating expenses with more options for well control techniques.

Large Pressure Energised Seals are used for dynamically sealing piston chambers to provide safe operation, long seal life, and less maintenance.

Piston Sealing Surfaces Protected by Operating Fluid lowers friction and protects against galling and wear to increase seal life and reduce maintenance time.

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W R E T L N L E C C O G N IN TROL TRAIN BOP CLOSURE SEQUENCE

All Hydril Annular Blowout Preventers employ the same time-tested design for sealing off virtually anything in the BOP bore or the open hole. During normal wellbore operations, the BOP is kept fully open by leaving the piston down. This position permits passage of tools, casing, and other items up to the full bore size of the BOP as well as providing maximum annulus flow of drilling fluids. The BOP is maintained in the open position by application of hydraulic pressure to the opening chamber, this ensures positive control of the piston during drilling and reduces wear caused by vibration. (See Fig B.2.4/A)

The piston is raised by applying hydraulic pressure to the closing chamber. This raises the piston, which in turn squeezes the steel reinforced packing unit inward to a sealing engagement with the drill string. The closing pressure should be regulated with a separate pressure regulator valve for the annular BOP. Guidelines for closing pressures are contained in the applicable Operator’s Manual. (See Fig B.2.4/B)

The packing unit is kept in compression throughout the sealing area, thus assuring a tough, v durable seal off against virtually any drill string shape—kelly, tool joint, pipe, or tubing to full rated working pressure. Application of opening chamber pressure returns the piston to the full down position allowing the packing unit to return to full open bore through the natural resiliency of the rubber. (See Fig B.2.4/C)

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W R E T L N L E C C O G N IN TROL TRAIN BOP CLOSURE SEQUENCE

Figure B.2.4/A - CLOSURE SEQUENCE (OPEN)

Figure B.2.4/B - CLOSURE SEQUENCE (PART CLOSED)

Figure B.2.4/C - CLOSURE SEQUENCE (SEALED OFF)

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Figure B.2.5 Complete shut off (CSO) of the well bore is possible with all Hydril Annular BOP’s. During CSO the flanges of the steel inserts form a solid ring to confine the rubber and provide a safe seal off of the rated working pressure of the BOP. This feature should be utilised only during well control situations, as it will reduce the life of the packing unit.

STRIPPING OPERATIONS

Drill pipe can be rotated and tool joints stripped through a closed packing unit, while maintaining a full seal on the pipe. Longest packing unit life is obtained by adjusting the closing chamber pressure just low enough to maintain a seal on the drill pipe with a slight amount of drilling fluid leakage as the tool joint passes through the packing unit. This leakage indicates the lowest usable closing pressure for minimum packing unit wear and provides lubrication for the drill pipe motion through the packing unit.

The pressure regulator valve should be set to maintain the proper closing chamber pressure. If the pressure regulator valve cannot respond fast enough for effective control, an accumulator (surge absorber) should be installed in the closing chamber control line adjacent to the BOP—precharge the accumulator to 50% of the closing pressure required. In subsea operations, it is sometimes advisable to add an accumulator to the opening chamber line to prevent undesirable pressure variations with certain control system circuits

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W R E T L N L E C C O G N IN TROL TRAIN TYPE GL 5000 PSI ANNULAR BLOWOUT PREVENTERS PATENTED

Hydril GL Annular Blowout Preventers are designed and developed both for subsea and surface operations. The GL family of BOPs represents the cumulation of evolutionary design and operator requirements. The proven packing unit provides full closure at maximum working pressure on open hole or on virtually anything in the bore - casing, drill pipe, tool joints, kelly, or tubing. Features of the GL make it particularly desirable for subsea and deep well drilling. These drilling conditions demand long-life packing elements for drill pipe stripping operations and frequent testing. The GL BOP offers the longest life packing unit for annular blowout preventers available in the industry today - especially for the combination of BOP testing and stripping pipe into or out of a well under pressure. The latched head permits quick, positive head removal for packing unit replacement or other maintenance with only minimum time required. The following outstanding features of the Hydril GL BOPs make these units particularly qualified to meet the industry’s needs for simple and reliable blowout protection. The Secondary Chamber, which is unique to the GL BOP, provides this unit with great flexibility of control hookup and acts as a backup closing chamber to cut operating costs and increase safety factors in critical situations. The chamber can be connected four ways to optimise operations for different effects:

1. Minimise closing/opening fluid volumes. 2. Reduce closing pressure. 3. Automatically compensate (counter balance) for marine riser hydrostatic pressure effects in deep water. 4. Operate as a secondary closing chamber.

Automatic Counter Balance can be achieved in subsea applications by selection of one of the optional hookups of the secondary chamber. The Latched Head provides fast, positive access to the packing unit and seals for minimum maintenance time. The latching mechanism releases the head with a few turns of the Jaw Operating Screws, while the entire mechanism remains inside the blowout preventer. There are no loose parts to be lost downhole or overboard. The Opening Chamber Head protects the opening chamber and prevents inadvertent contamination of the hydraulic system while the head is removed for packing unit replacement.

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PISTON INDICATOR HOLE INDICATOR PISTON WEAR PLATE PACKING UNIT PACKING LATCHED HEAD LATCHED

OPENING CHAMBER HEAD OPENING CHAMBER PISTON CHAMBER PISTON CLOSING CHAMBER

SECONDARY CHAMBER SECONDARY

Cutaway View of GL BOP shown in Midstroke. BOP of GL Cutaway View 5000 or 10,000 psi bottom connections are available in hub, API available in hub, flanged, or studded connection.

Figure B.2.6

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Figure B.2.7 GL 16 3/8" - 5000 PSI BLOWOUT PREVENTER

Item Part Name No Req'd Approx. Net No. Single Weight lb. BOP Assembly 1 28,400 1 BOP Head 1 6,641 2 "O" Ring 1 .75 3 "O" Ring 20 .06 4 Jaw Operating Screw 20 4 5 Sleeve Screw 20 .25 6 Spacer Sleeve 20 .25 7 Pipe Plug 20 .25 10 Jaw 20 12 11 Packing Unit - Natural 1 910 Packing Unit - Synthetic 1 920 12 Piston 1 5,380 13 Non-extrusion Ring, Middle 2 3 14 Double "U" Seal, Middle 1 3 15 Non-extrusion Ring, Lower 2 2 16 Double "U" Seal, Lower 1 2.5 17 Body 1 14,105 18 "O" Ring 1 .5 19 Capscrew 14 .75 20 Slotted Body Sleeve 1 300 21 Outer Body Sleeve 1 1180 22 Non-extrusion Ring, Inner 2 1 23 Double "U" Seal, Inner 1 2.3 24 Opening Chamber Head 1 839 27 "U" Seal 2 3 29 Head Gasket 1 2.5 32 Pull Down Bolt Assembly 4 1 33 Relief Fitting 1 .06 34 Pipe Plug 1 .06 Seal Set - Complete ACCESSORIES Chain Sling Assembly 1 202 Eye Bolts, Piston (1"-8NC x 17" LG) 2 6 Eye Bolts, Head (1 1/2"-6NC x 2" LG) 3 6.75 Eye Bolts, Opening Chamber Head - (7/8"-9NC x 2 1/4" LG) 3 1 Protector Plate 1 99 Protector Plate Screw 4 .13

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Figure B.2.8 HYDRIL 'GL' HYDRIL SECONDARY CHAMBER SECONDARY connected to MARINE RISER (CB) Subsea hook-up for water depths up to 800 ft. Subsea hook-up for water depths over 800 ft. SECONDARY CHAMBER SECONDARY connected to CLOSING CHAMBER (S - C) FIG. 1 FIG. 2 FIG. 3 CLOSING PRESSURE OPENING PRESSURE Standard surface hook-up requires least fluid so gives a faster closing time. SECONDARY CHAMBER SECONDARY connected to OPENING CHAMBER (S - O)

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Figure B.2.9 CONTRACTOR PISTON

differential area centre line exposed to mud column

opening pressure packing unit

opening area

closing operating area piston closing pressure

well pressure well pressure area

As the contractor piston is raised by hydraulic pressure, the rubber packing unit is squeezed inward to a sealing engagement with anything suspended in the wellbore. Compression of the rubber throughout the sealing area assured a seal-off against any shape.

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Figure B.2.10 Average Surface Closing Pressure (GL-16 3/4-5000 Standard Hook-up)

1500 CSO

1000 3 1/2" thru 7" Pipe

7 5/8" thru 13 3/8" Pipe 500 CLOSING PRESSURE - PSI

CAUTION : Due to limiting properties of casing, closure should NOTE : Pressures shown are be done carefully, using initial closing pressure to prevent average. Actual pressure collapse of casing. required to affect seal-off will vary slightly with each The closing pressures shown are initial closing pressures for individual packing unit. most casing at O (zero) well pressure. Slightly higher closing pressure may be required for seal-off at higher well pressures. SECONDARY CHAMBER CONNECTED TO OPENING CHAMBER TO CHAMBER CONNECTED SECONDARY 0 0 1000 2000 3000 4000 5000 WELL PRESSURE - PSI

Operating pressure for Subsea Annular Preventers

(0.052 x W x D ) - (0.45 x D ) m w w Adjustment Pressure (∆P) = ÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐ p Where:

W = drilling fluid density in lb./gal. m D = water depth in feet w 0.052 = conversion factor p = 2.13 = the ratio of closing chamber area to secondary chamber area for GL 16 3/4 - 5000. 0.45 psi/ft. = pressure gradient for sea-water using a specific gravity of sea water = 1.04 and 0.433 psi/ft. pressure gradient for fresh water.

The optimum closing pressure for the standard hookup is obtained using the following formula:

Closing Pressure = Surface Closing Pressure + Adjustment Pressure (∆P)

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Operating Pressure for Accumulator Bottles

Example 1

3 1/ " - 7" pipe, 3500 psi well pressure, 16 lb./gal. drilling fluid, 500 ft. water depth. 2 Closing Pressure = Surface Closing Pressure + Adjustment Pressure (∆P)

From the Surface Closing Pressure graph Figure B.5.13:

Surface Closing Pressure = 900 psi.

(0.052 x 16 Ib/gal x 500 ft) - (0.45 psi/ft x 500 ft) Adjustment Pressure (∆P) = ÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐÐ 2. 13

Adjustment Pressure (∆P) = 90 psi

Closing Pressure = 900 psi + 90 psi = 990 psi.

Pre-Charge Pressures - Surge Bottles

The pre-charge pressure for the closing chamber surge absorber can be calculated using the following example:

Example 2

3 1/ " - 7" pipe, 500 feet water depth. 2 Precharge = 0.80 [Surface Closing Pressure + (0.41 x D )] w

Where: D = water depth in feet. w 0.41 psi/ft. = pressure gradient for control fluid (water and water soluble oil) using a specific gravity of the mixture = 0.95 and 0.433 psi/ft pressure gradient for fresh water.

Surface Closing Pressure = 600 psi.

Precharge = 0.80 [600 psi + (0.41 psi/ft. x 500 ft)]

= 644 psi.

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Only packing elements which are supplied by the manufacturer of the annular preventer should be used. New or repaired units obtained from other service companies should not be used since the preventer manufacturers cannot be held responsible for malfunction of their equipment unless their elements are installed.

Figure B.2.11 Packing unit selection (from Hydril)

IDENTIFICATION PACKING UNIT OPERATING DRILLING FLUID TYPE Colour Code TEMP RANGE COMPATIBILITY

NATURAL Black NR -30°F Ð 225°F Waterbase Fluid RUBBER

NITRILE Red NBR 20°F Ð 190°F Oil base/Oil RUBBER Band Additive Fluid

NEOPRENE Green CR -30°F Ð 170°F Oil Base Fluid RUBBER Band

Figure B.2.12 Annular Preventers - Gallons of Fluid Required to Operate on Open Hole

Size and Hydril NL Shaffer Working Pressure GK GL Spherical Inches psi Close Open Close Open Balancing Close Open 6 3,000 2.9 2.2 4.6 3.2 6 5,000 3.9 3.3 4.6 3.2 7 1/16 10,000 9.4 8 3,000 4.4 3.0 7.2 5.0 8 5,000 6.8 5.8 11.1 8.7 10 3,000 7.5 5.6 11.0 6.8 10 5,000 9.8 8.0 18.7 14.6 11 5,000 11 10,000 25.1 12 3,000 11.4 9.8 23.5 14.7 13 5/8 3,000 13 5/8 5,000 18.0 14.2 19.8 19.8 8.2 23.6 17.4 13 5/8 10,000 34.5 24.3 47.2 37.6 16 2,000 17.5 12.6 16 3,000 21.0 14.8 16 3/4 3,000 16 3/4 5,000 28.7 19.9 33.8 33.8 17.3 33.0 25.6 16 3/4 10,000 18 2,000 21.1 14.4 18 3/4 5,000 44.0 44.0 20.0 48.2 37.6 20 2,000 32.6 17.0 20 3,000 20 5,000 58.0 58.0 29.5 61.4 47.8 30 1,000 30 2,000

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W R E T L N L E C C O G N IN TROL TRAIN SPHERICAL BLOWOUT PREVENTERS

Shaffer Spherical blowout preventers are compact, annular type BOP’s which reliably seal on almost any shape or size—kellys, drill pipe, tool joints, drill collars, casing or wireline. Sphericals also provide positive pressure control for stripping drill pipe into and out of

the hole. They are available in bolted cover, wedge cover and dual wedge cover models. There are also special lightweight models for airlifting and Arctic models for low temperature service.

Figure B.2.13 SHAFFER ANNULAR

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W R E T L N L E C C O G N IN TROL TRAIN OPERATION AND MAINTENANCE

INSTALLATION

A blowout preventer operating and control system is required to actuate the Spherical BOP. Several systems are available and those commonly used on drilling rigs work well. The recommended installation requires:

1. A control line to the closing (lower) port.

2. For stripping, an accumulator bottle in the closing line adjacent to the BOP. This bottle should be precharged to 500 psi for surface installations and to 500 psi plus 45 psi per 100' of water depth for subsea installations.

3. control line to the opening (upper) port.

4. A hydraulic regulator to allow adjustment of operating pressure to meet any given situation.

The hydraulic operating fluid should be hydraulic oil with a viscosity between 200 and 300 SSU at 100°F If necessary, a water-soluble oil such as Koomey K-90 and water can be used for environmental protection. If equipment is exposed to freezing temperatures, ethylene glycol must be added to the K-90 and water solution for freeze protection.

NOTE: Some water-soluble systems will corrode the metals used in BOP’s. If water-soluble oil is used, the user should ensure that it provides adequate lubrication and corrosion protection.

Accumulator bottle

(1-gal. capacity for 1 /16" - 10,00 psi bolted-cover model; 1 8 5-gal. capacity for all other bolted-cover models and 13 5/ "- 5,000 psi wedge-cover model; 10-gal. capacity for all other wedge-cover models)

Opening line

Hydraulic unit Closing line

Installation hookup for single Spherical BOP

Accumulator bottles Opening line

Closing line

Opening line

Closing line Station1 Station 2 Hydraulic unit

Figure B.2.14 Installation hookup for dual Spherical BOP

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W R E T L N L E C C O G N IN TROL TRAIN OPERATION AND MAINTENANCE

OPERATING REQUIREMENTS

Sphericals have relatively simple operating requirements compared to other annulars. When closing on stationary pipe, 1,500 psi operating pressure is sufficient in most applications. Recommended closing pressures for specific applications are given in the table at the bottom of the page.

Closing action begins when hydraulic fluid is pumped into the closing chamber of the Spherical BOP below the piston (upper right). As the piston rises, it pushes the element up, and the element’s spherical shape causes it to close in at the top as it moves upward.

The element seals around the drill string as the piston continues to rise (middle right). Steel segments in the element move into the well bore to support the rubber as it contains the well pressure below.

When there is no pipe in the preventer, continued upward movement of the piston forces the element to seal across the open bore (lower right). At complete shutoff, the steel segments provide ample support for the top portion of the rubber. This prevents the rubber from flowing or extruding excessively when confining high well pressure.

STRIPPING OPERATIONS

Stripping operations are undoubtedly the most severe application for any preventer because of the wear the sealing element is exposed to as the drill string is moved through the preventer under pressure. To prolong sealing element life, it is important to use proper operating procedures when stripping. The recommended procedures are:

1. Close the preventer with 1,500 psi closing pressure.

2. Just prior to commencing stripping operations, reduce closing pressure to a value sufficient to allow a slight leak.

3. If conditions allow, stripping should be done with a slight leak to provide lubrication and prevent

excessive temperature buildup in the element. As the sealing element wears, the, closing pressure will need to be incrementally increased to prevent excessive leakage.

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Figure B.2.15

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W R E T L N L E C C O G N IN TROL TRAIN B.3 DIVERTERS

Figure B.3.1 Typical Diverter System Installed on a Floating Rig

DIVERTER ELEMENT DIVERTER INSERT

PRESSURE LOCK

RELAX UNLOCK

ADJUST

CLOSED CLOSED

OPEN OPEN

STARBOARD PORT VENT VENT

RETURNS TO SHAKER

PRESSURE BELOW CLOSED DIVERTER BAG

OPEN UPPER "WORKING" PACKING ELEMENT SLIP JOINT UPPER ELEMENT

RIG AIR

BLEED LOWER PACKING ADJUST ELEMENT CLOSED WHEN DIVERTER IS OPERATED SLIP JOINT UPPER ELEMENT

PRESSURIZE

RELAX SLIP JOINT ANNULUS ADJUST PRESSURE

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Typical Operating Pressures

The diverter packer regulator will provide a maximum pressure of 1200 psi on the packer.

For normal pressure use 750 psi.

The manifold pressure regulator provides a maximum pressure of 1650 psi.

For insert packer lock down dogs. Diverter lock down dogs etc.

For normal operation do not exceed 1250 psi.

Recommended pressure settings generally are:

Hydraulic supply pressure 3000 psi Manifold pressure 1250 psi Diverter packer pressure 750 psi

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Figure B.3.2 Hydril FSP 28-2000 Diverter/BOP System Hydraulic Schematic

HOSE BUNDLE

LATCH

UNLATCH

HANDLING/TEST TOOL

REGULATED HYDRAULIC SUPPLY

PUSH AND HOLD TO UNLATCH

UNLATCH PORT

STBD LATCH

BELL NIPPLE SELECTOR LATCH

REGULATED HYDRAULIC SUPPLY PORT

OPEN

DIVERTER/BOP 5 GALLON ACCUMULATOR CERAMIC LINED

AUTOMATIC OPENING TO DIVERTER LINES AS BAG CLOSES.

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If an Annular Sequencing Device which requires lockdown of an insert packer is in use, the lockdown function should be included in the automatic sequencing.

Figure B.3.3

DIVERTER OPEN VALVE OPEN OPERATING PRESSURE VENT VALVE ACTUATOR DIVERTER CLOSE CLOSE

OPEN

FLOWLINE VALVE ACTUATOR

DIVERTED ANNULAR SEALING DEVICE OPERATING PRESSURE CLOSE

ANNULAR SEALING DEVICE OPEN

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Figure B.3.4 DERRICK FLOOR BELL NIPPLE FLOW LINE INSERT TYPE PACKER HYDRAULIC VALVE OPERATOR BLEED-OFF LINE VALVE

HEAVE COMPENSATOR LINE

INNER BARREL OF TELESCOPING JOINT

SEA LEVEL

OUTER BARREL OF TELESCOPING JOINT

RISER COUPLING

FLEXIBLE JOINT

GUIDE FRAME

HYDRAULIC LATCH PERMANENT GUIDE BASE TEMPORARY GUIDE BASE

When drilling surface hole from a template the cuttings are returned to surface for disposal to avoid spool build up on the template.

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Figure B.3.5

21 in HST RISER COUPLING PIN

MUD BOOST LINE CONNECTION

21 1/4 in – 2000 MSP ANNU-FLEX

FLEX JOINT

ANNULAR BOP

21in HYDRAULIC CONNECTOR

21 1/4 in – 2000 SHEAR RAM

OUTLET NOZZLE(S)

21 1/4 in – 2000 FSS SPOOL

BLIND FLANGE

C K VALVE

30 in LATCH

Sub-sea diverting stack (template operations).

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Figure B.3.6 (SURFACE DIVERTER)

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Figure B.3.7 (MSP DIVERTER/BOP)

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Figure B.3.8

TO SHALE TO SHAKER

16"¯

REGULATED HYDRUALIC SUPPLY

MUD PUMP

RISER BOOST LINE

RIG FLOOR

KILL DRAPE HOSE KILL

CHOKE DRAPE HOSE

RISER DIVERTER JOINT

VENT

ACCUMULATOR BANK ACCUMULATOR

TELESCOPIC JOINT

MOON POOL

INNER BARREL

OUTER BARREL

Bell

Flex

Joint

Riser

GPLG

Upper

Nipple

Diverter

3"¯

6"¯

PILOT CONTROL LINE PILOT CONTROL

TO DRILLING CONSOLE TO

COUPLING

6" DRAPE HOSE

6"¯

QUICK CONNECT

3"CHOKE

RISER CHOKE LINE

OPEN CONTROL LINE OPEN CONTROL

CLOSE CONTROL LINE CLOSE CONTROL

RISER DIVERTER MANIFOLD

(NEAR DRILLING MANIFOLD)

3"¯

6"¯

12"¯

FROM DRILLING

CHOKE MANIFOLD

VENT

MUD GAS

SEPERRTOR

12"¯ BELL NIPPLE DIVERTER OVERBOARD LINE 12"¯ BELL

6"¯ RISER DIVERTER OVERBOARD LINE

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Figure B.3.9 HYDRIL ANNULAR PREVENTER - TYPE “MSP” - 2000 PSI

Operating Features:

1. Will close on open hole and hold 2000 psi (but not recommended).

2. Primary usage is in diverter systems.

3. Automatically returns to the open position when closing is released.

4. Sealing assistance is gained from the well pressure.

5. Greater stripping capability of the packing unit since (fatigue) wear occurs on the outside of the packing unit.

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W R E T L N L E C C O G N IN TROL TRAIN ROTATING HEADS

When used, rotating heads are installed above the BOP stack. They provide a seal on the kelly or drillpipe. A drive unit, attached to the kelly, locates in a bearing assembly above the stripper rubber.

Some applications for rotating heads are:

• Drilling with air or gas, to divert the returns through a "Blooey line".

• To permit drilling with underbalanced mud, by maintaining a back pressure on the wellbore.

• As a diverter for surface hole.

• To keep gas away from the rotary table. This is especially important where Hydrogen Sulphide can be expected.

Realistic working pressures for rotating heads are 500 to 700 psi. It is recommended that they are not installed for routine gas cap drilling (unless sour gas is expected) since their use precludes observation from the rig floor of annulus fluid level.

Figure B.3.10

KELLY BUSHING

SWING-BOLT CLAMP ASSEMBLY

DRIVE BUSHING ASSEMBLY SHOCK PAD

DRIVE RING AND BOWL BEARING ASSEMBLY

STRIPPER RUBBER

OUTLET FLANGE

INLET FLANGE

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B.4 GASKETS, SEALS AND WELLHEADS

API Type 'R' Ring Joint Gasket

The type ‘R’ ring joint gasket is not energised by internal pressure. Sealing takes place along small bands of contact between the grooves and the gasket, on both the OD and ID of the gasket. The gasket may be either octagonal or oval in cross section. The type ‘R’ design does not allow face-to-face contact between the hubs or flanges, so external loads are transmitted through the sealing surfaces of the ring. Vibration and external loads may cause the small bands of contact between the ring and the ring grooves to deform the plastic, so that the joint may develop a leak unless the flange bolting is periodically tightened. Standard procedure with type ‘R’ joints in the BOP stack is to tighten the flange bolting weekly.

Figure B.4.1 Figure B..4.2

CL CL

ENERGISED

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Figure B.4.3

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API Type 'RX' Pressure-Energised Ring Joint Gasket

The ‘RX’ pressure-energised ring joint gasket was developed by Cameron Iron Works and adopted by API. Sealing takes place along small bands of contact between the grooves and the OD of the gasket. The gasket is made slightly larger in diameter than the grooves, and is compressed slightly to achieve initial sealing as the joint is tightened. The ‘RX’ design does not allow face-to-face contact between the hubs or flanges. However, the gasket has large load-bearing surfaces on the inside diameter, to transmit external loads without plastic deformation of the sealing surfaces of the gasket. It is recommended that a new gasket be used each time the joint is made up.

Figure B.4.4 Figure B.4.5 C L CL

ENERGISED

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API Type 'BX' Pressure-Energised Ring Joint Gasket

Sealing takes place along small bands of contact between the grooves and the OD of the gasket. The gasket is made slightly larger in diameter than the grooves, and is compressed slightly to achieve initial sealing as the joint is tightened. Although the intent of the ‘BX’ design was face-to-face contact between the hubs and flanges, the groove and gasket tolerances which are adopted are such that, if the ring dimension is on the high side of the tolerance range and the groove dimension is on the low side of the tolerance range, face-to-face contact may be very difficult to achieve. Without face-to-face contact, vibration and external loads can cause plastic deformation of the ring, eventually resulting in leaks. Both flanged and clamp hub ‘BX’ joints are equally prone to this difficulty. The ‘BX’ gasket frequently is manufactured with axial holes to ensure pressure balance, since both the ID and the OD of the gasket may contact the grooves.

In practice, the face-to-face contact between hubs or flanges is seldom achieved.

Figure B.4.B Figure B.4.7 Figure B.4.8

C C L L CL

ENERGISED

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API Face-to-Face Type ‘RX’ Pressure-Energised Ring Joint Gasket

The face-to-face ‘RX’ pressure-energised ring joint gasket was adopted by API as the standard joint for clamp hubs. Sealing takes place along small bands of contact between the grooves and the OD of the gasket. The gasket is made slightly larger in diameter than the grooves, and is compressed slightly to achieve initial sealing as the joint is tightened. Face-to-face contact between the hubs is ensured by an increased groove width, but this leaves the gasket unsupported on it’s ID. Without support from the ID of the grooves, the gasket may not remain perfectly round as the joint is tightened. If the gasket buckles or develops flats, the joint may leak.

This type of gasket has not been accepted by the industry and is seldom used.

Figure B.4.9 Figure B.4.10

C L CL

ENERGISED

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‘CIW’ Type ‘RX’ Pressure-Energised Ring Joint Groove

CIW modified the API face-to-face type ‘RX’ pressure-energised ring joint grooves to prevent any possible leaking caused by the buckling of the gasket in the API groove. The same API face-to-face type ‘RX’ pressure energised ring joint gaskets are used with these modified grooves. Sealing takes place along small bands of contact between the grooves and the OD of the gasket. The gasket is made slightly larger in diameter than the grooves, and is compressed slightly to achieve initial sealing as the joint is tightened. The gasket ID will also contact the grooves when it is made up. This constraint of the gasket prevents any possible leaking caused by the buckling of the gasket. Hub face-to-face contact is maintained within certain tolerances. The maximum theoretical stand-off from the stack-up of the tolerances of the gasket and the groove is 0.022 inches.

Face-to-face contact cannot be assured with this ring/groove combination. This ring is seldom found in use. The ‘CX’ ring accomplishes the intent of the ‘RX’ face- to-face design.

Figure B.4.13 Figure B.4.14 CL CL

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W R E T L N L E C C O G N IN TROL TRAIN

Type 'AX' and 'VX' Pressure-Energised Ring Joint Gasket

The ‘AX’ pressure-energised ring joint gasket was developed by Cameron Iron Works. The ‘VX’ ring was developed by Vetco.

Sealing takes place along small bands of contact between the grooves and the OD of the gasket. The gasket is made slightly larger in diameter than the grooves, and is compressed slightly to achieve initial sealing as the joint is tightened. The ID of the gasket is smooth and is almost flush with the hub bore. Sealing occurs at a diameter which is only slightly greater than the diameter of the hub bore, so the axial pressure load on the connector is held to an absolute minimum. The belt at the centre of the gasket keeps it from buckling or cocking as the joint is being made up. The OD of the gasket is grooved. This allows the use of retractable pins or dogs to positively retain the gasket in the base of the wellhead or riser connector when the hubs are separated. The gasket design allows face-to-face contact between the hubs to be achieved with minimal clamping force. External loads are transmitted entirely through the hub faces and cannot damage the gasket.

Figure B.4.13 Figure B.4.14 CL CL

ENERGISED

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‘CIW’ Type ‘CX’ Pressure-Energised Ring Joint Gasket

The ‘CX’ pressure-energised ring joint gasket was developed by Cameron Iron Works. Sealing takes place along small bands of contact between the grooves and the OD of the gasket. The gasket is made slightly larger in diameter than the grooves, and is compressed slightly to achieve initial sealing as the joint is tightened. The gasket is patterned after the ‘AX’ and ‘VX’ gasket, but is recessed, rather than being flush with the well bore, for protection against keyseating. The gasket seals on approximately the same diameter as do the ‘RX’ and ‘BX’ gaskets. The belt at the centre of the gasket keeps it from buckling or cocking as the joint is being made up. Since the ‘CX’ gasket is protected from keyseating, it is suitable for use through the BOP and riser system, except at the base of the wellhead and riser connectors. The gasket design allows face-to-face contact between the clamp hubs or flanges to be achieved with minimal clamping force. External loads are transmitted entirely through the hub faces and cannot damage the gasket.

Figure B.4.15 Figure B.4.16 C L CL

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Application of Type 'AX', 'VX' and 'CX' Pressure-Energised Ring Joint Gaskets

The ‘AX’, ‘VX’ and ‘CX’ face-to-face pressure-energised ring gaskets allow face-to- face contact between the hubs to be achieved with minimal clamping force. The ‘AX’ and ‘VX’ gasket is used at the base of the wellhead and riser connector when the hubs are separated. The ‘AX’/’VX’ design ensures that axial pressure loading on the connector is held to an absolute minimum. The ‘AX’ gasket also is suitable for side outlets on the BOP stack, since these outlets are not subject to keyseating. The ‘CX’ gasket is recessed for protection against keyseating. The ‘CX’ gasket is suitable for use throughout the BOP and riser system, except at the base of the wellhead and riser connector.

Figure B.4.17 HYDRIL DRILLING SPOOL DATA

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Figure B.4.18

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Figure B.4.19

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W R E T L N L E C C O G N IN TROL TRAIN Figure B.4.20 SPECIFICATIONS FOR BOP FLANGES, RING GASKETS, FLANGE BOLTS AND NUTS

S wells.

for high risk H

6BX w/Type BX Groove 6BX w/Type Groove or API TypeAPI Groove or 6BX Flange Type

S applications, ASTM A-193 Gr B/M with a maximum Rockwell hardness of 22 may be acceptable. ASTM S applications,

Sweet Oil - Low Carbon Steel

Sour Oil or Gas - 304 stainless steel acceptable except Type 316 stainless steel preferred but Type If used, flanges should be derated per Table 1.4B of API 6A. 1.4B of Table If used, flanges should be derated per

2000 psi wp 6B withType API TypeAPI ASTM Grade ASTM Grade and 3000 psi wp R Flat Bottom Type RX B-7 2H Installations Groove

5000 psi wp 6B withType API RX orType API ASTM Grade ASME Grade Installations R Flat Bottom Type BX wpType API B-7 2-H

10,000 psi wp 6BX withType API Type API ASTM Grade ASTM Grad Installations BX Groove Type BX B-7 2-H

All blowout preventers, drilling spools, adapter flanges will be furnished with the specific API ring joint flange All blowout preventers, drilling spools, adapter flanges will be furnished with the specific

RATING OF BOPRATING APPROVED * ** MAXIMUM BOLT MINIMUM NUT STACK APPROVED FLANGES RING GASKETS STRENGTH STRENGTH

* Equipment". API Spec 6A, "Wellhead Acceptable material for flange ring gaskets as per

** In some H

equipment listed below:

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W R E T L N L E C C O G N IN TROL TRAIN B.5 MANIFOLDS, VALVES, SEPARATORS AND FLOW GAIN SENSORS

1. MUD CONTROL AND MONITORING EQUIPMENT

Correct installation and operation of this equipment is fundamental to effective primary and secondary well control. The following are the most important aspects:

a) Pit Volume Measurement

A pit volume totalising (PVT) should be provided. A calibrated read-out and audio alarm should be installed at the Driller’s station.

The following measurement devices are required for all tanks:

• A float for the PVT system, to isolate other floats when the trip tank is in use. • An internal calibrated ladder-type scale. • A remote ladder-type scale, visible from the Driller’s station for the trip tank.

• A small wireline can be used to connect a float in the tank to the scale on the rig floor.

b) Flow line Measurement

A device should be provided for measurement of flow line and mud return rate. This (Flo Show) device should have a read-out and alarm at the Driller’s station.

c) Trip Tank

Trip tanks are used to fill the hole on trips, measure mud or water into the annulus when circulation has been lost, monitor the hole when tripping, logging or other similar type operations. There are two basic types of trip tanks - gravity feed and pump. The pump type system is better because it provides for safer and more expedient trip operation. The trip tank would be isolated from the surface mud system to prevent inadvertent loss or gain of mud from the trip tank due to valves being left open.

In the past, many blowouts occurred due to swabbing or not keeping the hole filled while tripping the drill string out of the hole. To provide exact fluid measurements for pipe displacement, trip tanks were developed to accurately measure within ± 1.0 barrel the influx or efflux of fluid from the wellbore. As the drill string is pulled from the hole, the mud level will drop due to the volume of metal being removed. If mud is not added to the hole as pipe is pulled, it is possible to reduce hydrostatic pressure to less than formation pressure. When this happens, a kick will occur. Swabbing can occur when pipe is pulled too fast and friction between the pipe and the mud column causes a reduction in hydrostatic pressure to a valve less than formation pressure.

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Figure B.5.1

MFC3 CONTROL CONSOLE MFS 3 - Series RETURN MUD FLOW SYSTEM

40 50 60 30 70 20 80 10 90 0 % 100 RETURN MUD FLOW MFT2 MUD FLOW SENSOR LO LO HI HI ADJUST FLOW FLOW ADJUST

MUD SMOOTHING FLOO MED 2 AMP HI ON LO

RECORDER RETURN RETURN FLOW FLOW HI-LO SENSOR 115 VAC WARNING WARNING

LINE

H1240 WARNING SYSTEM

WARNING LIGHTS 115 (Optional) VAC REMOTE INDICCTOR

FROM MVT4 MFR2 or MFRE2 RETURN MUD HORN RECORDER FLOW SYSTEM (Optional) (Optional)

Figure B.5.2

MVR2 ELECTRONIC MFTX2 FLOW SENSOR RECORDER (Optional) ASSEMBLY MFCX RETURN MUD FLOW AND PUMP STROKE SENSOR CONSOLE

40 50 60 30 70 20 80 10 90 0 100

H1268 WARNING SYSTEM HORN

H1234A PUMP H1267 WARNING SYSTEM STROKE SENSOR CONTROL BOX MFSX2 MUD FLOW FILL SYSTEM

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To prevent loss of hydrostatic pressure it is necessary to fill the hole on a regular schedule, or continuously, using a trip tank to keep the track of the fluid volume required. The metal volume of the pipe being pulled can be calculated, but mud additions necessary to replace hole seepage losses due to filtration effects can only be predicted by comparison with the mud volumes required to keep the hole properly filled on previous trips. For this reason, it is import that a record of mud volume required, versus number of stands pulled be maintained on the rig in a trip book for every trip made.

Typical Trip Tank Hook-up - On A Floating Rig

As illustrated in Figure B.5.3, a centrifugal pump takes suction from the trip tank and fills the hole through a line into the bell nipple. The pump runs constantly while the drill string is pulled from the hole. The hole stays full as each stand of pipe is pulled and excess mud returns to the trip tank through an outlet on the main flow line. A valve must be installed in the flow line downstream of this outlet to block all flow to the shale shakers while making a trip. A closed circulation system can be monitored by a float system and a digital read-out in 1-barrel increments on the Driller’s console.

Mud Gas Separator

The separator is installed downstream of the choke manifold to separate gas from the drilling fluid. This provides a means of safely venting the gas and returning usable liquid mud to the active system.

There are two types of mud gas separators: Atmospheric and Pressurised.

• The atmospheric type separator is standard equipment on nearly all rigs and is referred to in the field as a ‘gas buster’ or ‘poorboy' separator. The main advantage of this type of separator is its operational simplicity which does not require control valves on either the gas or mud discharge lines.

• A pressurised mud gas separator is designed to operate with moderate back pressure, generally 50 psi or less. Pressurised separators are utilised to overcome line pressure losses when an excessive length of vent line is required to safely flare and burn the hazardous gas an extended distance from the rig. The pressurised separator is considered special rig equipment and may not be provided by the contractor. This type of separator is installed on rigs drilling in high risk H S areas and for drilling underbalanced in areas 2 where high pressure, low volume gas continually feeds into the circulating fluid.

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During well control operations, the main purpose of a mud gas separator is to vent the gas and save the drilling fluid. This is important not only for economic reasons, but also to minimise the risk of circulating out a gas kick without having to shut down to mix additional mud volume. In some situations the amount of mud lost can be critical when surface volume is marginal and on-site mud supplies are limited. When a gas kick is properly shut in and circulated out, the mud gas separator should be capable of saving most of the mud.

There are a number of design features which affect the volume of gas and fluid that the separator can safely handle. For production operations, gas oil separators can be sized and internally designed to efficiently separate gas from the fluid. This is possible because the fluid and gas characteristics are known and design flow rates can be readily established. It is apparent that ‘gas busters’ for drilling rigs cannot be designed on the same basis since the properties of circulated fluids from gas kicks are unpredictable and a wide range of mixing conditions occur downhole. In addition, mud rheological properties vary widely and have a strong effect on gas environment. For both practical and cost reasons, rig mud gas separators are not designed for maximum possible gas release rates which might be needed; however, they should handle most kicks when recommended shut-in procedures and well control practices are followed. When gas low rates exceed the separator capacity, the flow must be bypassed around the separator directly to the flare line. This will prevent the hazardous situation of blowing the liquid from the bottom of the separator and discharging gas into the mud system.

Figure B.5.4 illustrates the basic design features for atmospheric mud gas separators. Since most drilling rigs have their own separator designs, the Drilling Supervisor must analyse and compare the contractor’s equipment with the recommended design to ensure the essential requirements are met.

The atmospheric type separator operates on the gravity or hydrostatic pressure principle. The essential design features are:

• Height and diameter of separator.

• Internal baffle arrangement to assist in additional gas break-out.

• Diameter and length of gas outlet.

• A target plate to minimise erosion where inlet mud gas mixture contacts the internal wall of the separator, which provides a method of inspecting plate wear.

• A U-tube arrangement properly sized to maintain a fluid head in the separator.

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Figure B.5.3

REMOTE TRIP TANK CONTROL VALVE RIG FLOOR LEVEL INDICATOR

OVERBOARD

ROTARY TABLE

DIVERTER RETURNS TO SHAKERS

FLOWLINE HOLE FILL UP LINE TELESCOPIC JOINT FROM MISSION PUMPS RISER

CHECK

VALVE

DRAIN TRIP TANK PUMP

Figure B.5.4 An Example Mud Gas Separator

GAS OUTLET 8" ID MINIMUM

GAS BACK PRESSURE REGISTERED AT STEEL THIS GAUGE (Typically 0 to 20 psi) TARGET PLATE INLET

INSPECTION COVER

30" OD SECTION A-A TANGENTIAL INLET APPROX 1/2 OF HEIGHT

A A 4" ID INLET-TANGENTIAL TO SHELL INSPECTION FROM CHOKE MANIFOLD COVER BRACE 10' MINIMUM HEIGHT

HALF CIRCLE BAFFLES ARRANGED IN A 'SPIRAL' CORFIGURATION

TO SHAKER HEADER TANK

MAXIMUM HEAD AVAILABLE DEVELOPED BY THIS HEIGHT OF FLUID eg 10 foot HEAD AT 1.5 SG

10' APPROX GIVES 6.5 psi MAXIMUM CAPACITY

8" NOMINAL 'U' TUBE

4" CLEAN-OUT PLUG 2" DRAIN OR FLUSH LINE

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The height and diameter of an atmospheric separator are critical dimensions which affect the volume of gas and fluid the separator can efficiently handle. As the mud and gas mixture enters the separator, the operating pressure is atmospheric plus pressure due to friction in the gas vent line. The vertical distance from the inlet to the static fluid level allows time for additional gas break-out and provides an allowance for the fluid to rise somewhat during operation to overcome friction loss in the mud outlet lines. As shown in Figure B.5.4, the gas-fluid inlet should be located approximately at the midpoint of the vertical height. This provides the top half for a gas chamber and the bottom half for gas separation and fluid retention. The 30 in. diameter and 16 ft minimum vessel height requirements have proven adequate to handle the majority of gas kicks. The separator inlet should have at least the same ID as the largest line from the choke manifold, which is usually 4 in. Some separators use tangential inlet, which creates a small centrifugal effect on the gas-fluid mixture and causes faster gas break-out.

The baffle system causes the mud to flow in thin sheets which assists the separation process. There are numerous arrangements and shapes of baffles used. It is important that each plate be securely welded to the body of the separator with angle braces.

A 8 in. minimum ID gas outlet is usually recommended to allow a large volume of low pressure gas to be released from the separator with minimum restriction. Care should be taken to ensure minimum back pressure in the vent line. On most offshore rigs, the vent line is extended straight up and supported to a derrick leg. The ideal line would be restricted to 30 ft in length and the top of the line should be bent outward about 30 degrees to direct gas flow away from the rig floor. If it is intended that the gas be flared, flame arresters should be installed at the discharge end of the vent line.

As stated previously, when the gas pressure in the separator exceeds the hydrostatic head of the mud in the U-tube, the fluid seal in the bottom is lost and gas starts flowing into the mud system. The mud outlet downstream of the U-tube should be designed to maintain a minimum vessel fluid level of approximately 3 1/2 ft in a 16 ft high separator. Assuming a 9.8 ppg mud and total U-tube height of 10 ft, the fluid seal would have a hydrostatic pressure equal to 5.096 psi. This points out the importance for providing a large diameter gas vent line with the fewest possible turns to minimise line frictional losses.

The mud outlet line must be designed to handle viscous, contaminated mud returns. As shown in Figure B.5.4 an 8 in. line is recommended to minimise frictional losses. This line usually discharges into the mud ditch in order that good mud can be directed over the shakers and untreatable mud routed to the waste pit.

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Degassers

If a fluid's viscosity does not allow gas to break out completely, a degasser may also be used. A degasser is not designed to handle large volumes of gas, because the volume of gas actually entrained in the fluid is small. Degassers separate entrained gas from fluid using a vacuum chamber, a pressurised chamber, a centrifugal spray, or a combination. The most commonly used degassers are vacuum tanks and centrifugal pump sprayers, but many others are available.

Properly maintaining degassers is not difficult. Primarily, it is a matter of correctly lubricating any pumps used in the system. In degassers that employ a float arm, joints must be kept lubricated. When a vacuum pump is used, the water knockout ahead of the compressor must be emptied daily.

In general, vacuum degassers are very effective with heavy, viscous muds from which it is difficult to extract gas with a separator alone. In any degassing operation, residence time and extraction energy requirements are increased as mud viscosity and gel strength increases.

Figure B.5.5

FLARE LINE

DISCHARGE SUCTION

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Choke Manifolds

The choke manifold is an arrangement of valves, fittings, lines and chokes which provide several flow routes to control the flow of mud, gas and oil from the annulus during a kick. Figure B.5.6

Adjustable choke

P To pit and/or mud/gas separators 2" Nominal 2" Remotely Operated Valve Blowout Preventer 2" Stack Outlet Bleed line P To pit

3" Nominal 4" Nominal Sequence 2" Optional

P To mud/gas separator and/or pit 2" Nominal Remotely operated or adjustable choke Typical Choke Manifold for 5,000 psi Working Pressure Service-Surface Installation

Figure B.5.7

Remotely operated choke

P To mud/gas separators and/or pit 2" Nominal 2" Adjustable Choke 2" To pit 2" Nominal Blowout Preventer 2" Stack Outlet CHOKE LINE Bleed line P To pit

3" Nominal 4" Nominal Sequence 2" Optional

Remotely Operated Valve 2"

P To mud/gas separator and/or pit 2" Nominal Remotely operated choke Typical Choke Manifold for 10,000 psi and 15,000 psi Working Pressure Service-Surface Installation

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Figure B.5.8

BYPASS TO POORBOY DEGASSER TO POORBOY TO MUD OR TRIP TANK DEGASSER PITS

2 4

2 3 1

BOP STACK 11 PRIMARY CHOKE LINE 1 1 1 2

CHOKE BYPASS LINE RESERVE PIT (DERRICK FLARE KILL OR OFFSHORE RIGS) SECONDARY 1 CHOKE LINE 1 2 3

BUFFER CHAMBER

FROM KILL PUMP TO GAUGE

2 4 MANIFOLD CHOKE LINE

FROM DST 2 CHOKE MANIFOLD DST LINE

1. 10,000 psi gate valves. 2. 5,000 psi gate valves. 3. Remote controlled chokes. BURNING LINE 4. Manually adjusted chokes. (PRODUCTION GAS SEPARATOR OFFSHORE RIGS)

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SPECIFICATION 1 13/ " THRU 2 9/ ", 10,000 PSI 16 16 Figure B.5.9 Figure B.4.10

10,000 lb Working Pressure (Inches) No of Turns Size WP A B C D E Wt to Open 13 13 1 11 5 1 1 /16" 10,000 1 /16 18 /4 5 /16 18 /8 8 206 12 /2 1 1 1 11 5 3 1 2 /16" 10,000 2 /16 20 /2 5 /16 18 /8 9 /4 218 13 /2 9 9 1 7 1 3 2 /16" 10,000 2 /16 22 /4 6 /8 19 /2 9 /4 292 16 Flange specifications conform to API standard 6A

National Gate Valves are available with flanged ends in standard API bore sizes and working pressures. Special trims are available for sour gas and oil service on request. National Gate Valves are also readily available to accept most pneumatic or hydraulic operators. National Gate Valves meet the applicable standards set forth by the American Petroleum Institute. When ordering, be sure to specify quantity, size, working pressure, end connection, body and trim materials, and service conditions (such as temperature, pressure, and composition of flow material).

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W R E T L N L E C C O G N IN TROL TRAIN .

13 1 Figure B.5.11 - Components 1 /16" thru 2 /16" 15,000 psi

Hex Nut

Handwheel

Bearing Stem Grease Fitting Bonnet Cap

Grease Seal Set Screw O-Ring

Flat Split Clevis Ring Nut Stem Bearing

Clevis Pin Shoulder Hub Seal Split Ring

Packing Gland

Gate Hex Nut Stem Packing Packing Header Ring Plastic Seat Stud Bolt Assembll Packing

Plastic Packing Injection Bonnet Fitting Body

Bonnet Gasket Grease Grease Fitting Fitting

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Figure B.5.12 - Type ‘HCR‘ pressure operated gate valve

The type ‘HCR‘ pressure operated gate valves is a flow line valve requiring relatively low operating pressures. This is a single ram, hydraulic gate valve packed with elements similar to the old ‘QRC‘ ram assembly. The closing ratio of well pressure to hydraulic operating pressure is approximately 8 to 1. Available sizes are 4-inch 3000 to 5000 psi working pressure, and 6-inch 3000 and 5000 psi working pressure with standard API flanges.

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W R E T L N L E C C O G N IN TROL TRAIN

Figure B.5.13 Figure B.5.14

Cameron type “F“ Gate Valve

The Cameron type “F“ gate valve is a commonly used valve on BOP system lines. The valve is conduit type with no pockets for solids to deposit and hardened rotating seats which distribute wear. Gates and seats may be replaced without disconnecting the valves. These valves may be equipped with either hydraulic or pneumatic operators. Control pressure is lower, especially at high operating pressures. Sizes from 1-13/16 to 6-6/8 inch are available in ratings of 2,000 to 10,000 working pressure.

Fail-safe type “F“ valves are opened and held open by control pressure in the operating cylinder. Line pressure tends to close the valve because the gate and stem move outward in closing. Closing force is supplied by valve body pressure acting on the stem area, plus the action of a coiled spring. Since operating pressure is low so that closing ratio is not a problem, “fail-safe“ models close automatically upon loss of pressure and are ideally suited for subsea use.

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Fail Safe Valves

High pressure choke and kill lines run from the stack to the choke manifold on the rig floor. To shut these lines off when not required, each is equipped with two fail safe valves. These can be opened hydraulically from the surface but when the opening pressure is released spring action automatically forces the gate closed. The valves are always rated at the same pressure as the stack and choke and kill lines.

Due to space limitations the first valve out from the stack (the inner valve) is a 90 degree type with a target to avoid sand cutting. The outer valve is straight through and must be able to hold pressure from on top as well as below when the choke and kill lines are tested.

In the Cameron type AF fail safe valve (fig B.5.15) flow line pressure acting against the lower end of the balancing stem assists in closing the valve. A port in the operator housing allows the hydrostatic pressure due to water depth to balance the hydrostatic head of the operating fluid. A resilient sleeve transmits the sea water pressure to an oil chamber on the spring side of the operating piston. Without this feature the hydrostatic head of the operating fluid acting on top of the piston would tend to open the valve itself, especially in deep water.

Liquid lock between the two valves in each line is eliminated by porting the fluid exhausted from the pressure chamber when opening the valve, away from the neighbouring valve.

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Figure B.5.15

Operator fluid inlet Woodruff key Retainer ring Locking ring Piston Sea water hydrostatic pressure Set screw "O" Ring

Spring cartridge assembly

Sea water hydrostatic pressure equalizing port Resilient sleeve

Sleeve Clamp Ring "J" Packing Vent "O" ring Ring Pipe plug "J" Packing Anti-extrusion ring Junk ring Bonnet stud Retainer ring Pin Bonnet nut Bonnet

Pipe plug Gate and seat assembly Bonnet gasket Body Pin

Adaptor stem

Balancing stem "O" ring

"J" packing "O" ring

"O" ring "J" packing Nut

"O" ring Gland

Pipe plug

CAMERON TYPE AF FAIL SAFE VALVE

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Figure B.5.16

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W R E T L N L E C C O G N IN TROL TRAIN

Figure B.5.17

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K Choke Beans and Wrenches

• Flared Orifice entrance reduces erosion on the entrance surface.

• Accuracy levels are maintained over extended periods of use.

• Choke beans save time and money because replacement intervals are extended.

Cameron K choke beans come in two styles, positive and combination. The positive bean has a fixed orifice diameter. The combination bean has a fixed diameter and a throttling taper at the entry. The combination bean is used with an adjustable choke needle to make incremental changes to orifice sizes smaller than the fixed orifice.

The part numbers of the positive and combination beans are determined by desired orifice size. K1 positive bean orifice sizes range from 4/64" to 64/64"/ Part numbers for K1 positive beans are available on request. K2 positive bean orifice sizes range from 4/64" to 128/64". The part number for K2 positive bean is 626397-( )-( ). The dash numbers indicate desired orifice size; for example, 626397-01-10 is a 110/64" diameter orifice. K3 positive bean orifice sizes range from 4/64" to 192/64". Part numbers for K3 positive beans are available on request.

K1 combination bean sizes range from 6/64" to 64/64". K2 combination bean sizes range form 6/64" to 128/64". The part number for the K2 combination bean is 626396-( )-( ). K3 combination bean sizes range from 6/64" to 192/64". Part numbers for the K1 and K3 combination beans are available upon request.

The part number of the K2 bean wrench is 626266-01. The part numbers of the K1 and K3 bean wrenches are available on request.

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W R E T L N L E C C O G N IN TROL TRAIN B.6 INSIDE BOP'S

Drill Pipe Float Valves

The drill pipe float valve and the flapper type of back pressure valve, serve essentially the same purpose, but differ in design.

These valves provide instantaneous shut-off against high or low back pressure and allow full fluid flow through the drill string. Another advantage is that it prevents cuttings from entering the drill string, thus reducing the likelihood of pulling a wet string. Abnormal pressures and anticipated subnormal pressure zones should be the deciding factor regarding what type of valve to run or the possibility of not running any valve at all. Expectations of abnormal pressures have shown the vented type of flapper valve to be the most popular because of the ease involved in recording shut-in drill pipe pressures. The disadvantages are that the pipe must be filled while tripping in, and reverse circulation is not possible.

Figure B.6.1

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Figure B.6.2 - Kelly Cock Figure B.6.3 - Gray Valve

RELEASE TOOL VALUE RELEASE ROD

Upper Seat Body

Crank VALVE SEAT Ball

Lower Seat VALVE SPRING

Figure B.6.4 Installing a Checkguard improves well control significantly. It serves as a check valve to prevent upward flow through the drill string while permitting downward mud pumping or flow from injectors.

While stripping drill pipe into the hole, Checkguard control upward pressure in the annulus and in the drill pipe. Latching the check valve into the landing sub contains the pressure in the drill pipe.

Prior to shearing drill pipe, install the check valve to protect against the release of well pressures. Installation of the check valve simplifies well control, since formation pressures cannot communicate up the drill string.

While tripping, Checkguard contains upward well bore pressure in the drill pipe, allowing the top connection to be open.

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Checkguard uses a spring and ball design. Fluid can be pumped through the valve from the top. But when fluid tries to flow from the bottom to the top, it is sealed by the spring-loaded ball against the seat.

A large rubber packer provides sealing when fluid attempts to flow around the valve. The packer is engaged by the tapered body. The body is driven upward by pressure from below. The more pressure from below, the tighter the seal is.

Installation and Retrieval

Install the landing sub in the drill string while tripping into the hole. Position the landing sub in the lower end of the drill string.

Install the check valve by dropping it into an open tool joint. Connect the kelly and pump the check valve into the landing sub. Use the drill pipe safety kelly guard and lower the kelly guard if excessive back flow exists.

Retrieve the check valve by installing a sinker bar above the retrieving tool and using a wire line. Use normal wire line procedure. Another way is to trip the drill string and remove the check valve from the landing sub with the retrieval tool.

Operating tips include ensuring the packer rubber is clean and pliable. Check for foreign substances such as paint, grease and dirt on the packer surface. Check for cracking and embrittlement of packer. Never oil rubber packer. Replace packer if condition requires.

The check valve should be disassembled, cleaned and lubricated (not packer) once it is retrieved from the landing sub after downhole use.

The valve should be stored in a protected area, away from sun and rain while not in use. This protects the working parts and packer.

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C. APPENDIX - PREVENTERS C-1

C.A INSPECTION & TESTING SURFACE INSTALLATIONS C-1

C.B INSPECTION & TESTING - SUBSEA INSTALLATIONS C-12

C.C SEALING COMPONENTS SURFACE INSTALLATIONS C-14

C.D SEALING COMPONENTS- SUBSEA INSTALLATIONS C-15

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SECTION C-A INSPECTION AND TESTING - SURFACE INSTALLATIONS

FIELD ACCEPTANCE INSPECTION AND TESTING

C.A.1 The field acceptance procedure should be performed each time a new or reworked blowout preventer or blowout preventer of unknown condition is placed in service.

Ram Type Preventers and Drilling Spools

C.A.2 Following are recommended inspections and tests for this equipment:

a. Visually inspect the body and ring grooves (vertical, horizontal, or ram bore) for damage, wear, and pitting.

b. Check bolting, both studs and nuts, for proper type, size, and condition. Refer to Section 8-A for bolting recommendations.

c. Check ring joint gaskets for proper type and condition. Refer to Section 8-A for ring joint gasket recommendations.

d. Visually inspect ram type preventers for:

1) Wear, pitting, and or damage to the bonnet or door seal area, bonnet or door seal grooves, ram bores, ram connecting rod, and ram operating rods.

2) Packer wear, cracking, and excessive hardness, Refer to Section 8-A for information on sealing components.

3) Measure ram and ram bore to check for maximum vertical clearance according to manufacturer’s specifications. This clearance is dependent on type, size, and trim of the preventers.

4) If preventer has secondary seals, inspect secondary seals and remove the plugs to expose plastic packing injection ports used for secondary sealing purposes. Remove the plastic injection screw and the check valve in this port. (Some preventers have a release packing regulating valve that will need to be removed.) Probe the plastic packing to ensure it is soft and not energising the seal. Remove and replace packing if necessary.

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e. Hydraulically test with water using the following procedure (refer to Para. C.A.5 for test precautions):

1) Connect closing line(s) to preventer(s).

2) Set preventer test tool on drill pipe below preventer(s) if testing preventer with pipe rams.

3) Check for closing chamber seal leaks by applying closing pressure to close the rams and check for fluid leaks by observing opening line port(s). Closing pressure should be equivalent to the manufacturer’s recommended operating pressure for the preventer’s hydraulic system.

4) Release closing pressure, remove closing line(s), and connect opening line(s).

5) Check for opening chamber seal leaks by applying opening pressure to open rams and check for fluid leaks by observing closing line port(s). Opening pressure should be equivalent to the manufacturer’s recommended operating pressure for the preventer’s hydraulic system.

6) Release opening pressure and reconnect closing line(s).

7) Check for ram packer leaks at low pressure by closing rams with 1500 psi operating pressure and apply pressure under rams to 200-300 psi with blowout preventer test tool installed (when testing preventer containing pipe rams). Hold for three minutes. Check for leaks. If ram packer leaks, refer to step 9. If ram packer does not leak, proceed to step 8.

8) Check for ram packer leaks by increasing pressure slowly to the rated working pressure of the preventer. Hold for three minutes. Check for leaks. If ram packer leaks, proceed to step 9.

9) If rams leak, check for worn packers and replace if necessary. If the preventer is equipped with an automatic locking device, check same for proper adjustment in accordance with manufacturer’s specifications. Continue testing until a successful test is obtained.

10) Test the connecting rod for adequate strength by applying opening pressure as recommended by the manufacturer with rams closed and blowout preventer rated working pressure under the rams.

11) Release opening pressure and release pressure under rams.

12) Repeat procedure (steps 1 through 9) for each set of pipe rams.

13) Test blind rams in same manner as pipe rams (step 1, steps 3 through 9) with test plug installed but test joint removed.

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Annular Blowout Preventers and Diverters

C.A.3 Following are recommended inspections and tests for this equipment:

a. Visually inspected:

1) Studded face of preventer head for pitting and damage, particularly in ring groove and stud holes.

2) Body for wear and damage.

3) Vertical bore for wear and damage from drill string and drill tools.

4) Inner sleeve for pitting and damage. Look through slots in base of inner liner for cuttings that might be trapped, thereby preventing full movement of the piston.

5) Packer for wear, cracking excessive hardness, and correct elastomer composition. Refer to Section 8-A for information on sealing components.

6) Bolting (both studs and nuts) for proper type, size, and condition. Refer to Section 8-A for bolting recommendations.

7) Ring-joint gaskets for proper type and condition. Refer to Section 8-A for ring-joint gasket recommendations.

b. Hydraulic test using the following procedure:

1) Connect closing line to preventer.

2) Set blowout preventer test tool on drill pipe below preventer.

3) Test the seals between the closing chamber and wellbore and between the closing chamber and opening chamber by closing preventer and applying manufacturer’s recommended closing pressure. If other chambers are located between the wellbore and operating chamber, this seal should also be tested.

4) a) If pressure holds, refer to step 13.

b) If pressure does not hold and no fluid is running out of opening chamber opening, the seal between the closing chamber and the wellbore or other operating chambers is leaking. Refer to step 11.

c) If fluid is coming out of the opening chamber opening, indicating the seal between the closing chamber and opening chamber is leaking, proceed to step 5.

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5) Release closing pressure.

6) Install plug in opening chamber opening, or if opening line is equipped with a valve install opening line and close valve.

7) Test seals between the closing chamber, operating chambers, and wellbore by applying manufacturer’s recommended closing pressure. Observe to see that pressure holds.

8) Release closing pressure.

9) Remove plug in opening chamber opening and install opening line or open valve in opening line.

10) Apply 1500 psi closing pressure.

11) Apply 1500 psi wellbore pressure.

12) Bleed closing pressure to 1000 psi.

13) To test the seal between the wellbore and the closing chamber. Close valve on closing line and disconnect closing line from valve on closing unit side of valve. Install pressure gauge on closing unit side of valve and open valve. If this seal is leaking, the closing line will have pressure greater than 1000 psi. Caution: If the closing line does not have a valve installed, the closing line should not be disconnected with pressure trapped in the closing chamber.

14) Release wellbore pressure.

15) Release closing pressure.

16) a) To test the seals between the opening chamber and the closing chamber and between the opening chamber and the piston, apply manufacturer’s recommended opening pressure. If pressure holds, refer to step 21.

b) If pressure does not hold and no fluid is running out of the closing chamber opening, the seal between the opening chamber and the piston is leaking. Verify this visually. Refer to step 21.

c) If fluid is coming out of the closing chamber opening, indicating the seal between the opening chamber and the closing chamber is leaking, proceed to step 17.

17) Release opening pressure.

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18) Install closing line and block flow (close valve in closing line, if available).

19) Apply 1500 psi opening pressure. If pressure does not hold, seal between the opening chamber and the preventer head is leaking. Verify this visually.

20) Release opening pressure and replace necessary seals. Refer to step 22.

21) Release opening pressure, replace closing line, and replace necessary seals.

22) If closing line has a valve installed, make certain that valve is open at the end of the test. NOTE: This procedure tests all seals except the seal between the wellbore and the opening chamber. This seal should be tested in the bottom annular preventer if two annular preventers are being used or if a stack is nippled up on an annular preventer (for snubbing. etc.). It can be tested as follows:

a) To rated working pressure by running a test joint and plug, closing an upper preventer, removing the opening line, and pressuring the preventer stack.

b) To 1500 psi maximum, or by closing an upper preventer and the annular preventer, removing the opening line, and pressuring up between preventers.

PERIODIC FIELD TESTING

Blowout Preventer Operating Test

C.A.4 A preventer operating test should be performed on each round trip but not more than once per day. The test should be conducted as follows while tripping the drill pipe with the bit just inside casing:

a. Install drill pipe safety valve.

b. Operate the choke line valves.

c. Operate adjustable chokes. Caution: Certain chokes can be damaged if full closure is effected.

d. Position blowout preventer equipment to check choke manifold. Open adjustable chokes and pump through each choke manifold to ensure that it is not plugged. If choke manifold contains brine, diesel or other fluid to prevent freeze-up in cold weather, some other method should be devised to ensure manifold, lines, and assembly are not plugged.

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e. Close each preventer until all pipe rams in the stack have been operated. Caution: Do not close pipe rams on open hole. If blind rams are in the stack, operate these rams while out of the hole.

f. Return all valves and preventers to their original position and continue normal operations. Record test results.

g. Annular preventers need not be operated on each round trip. They should, however, be operated at an interval not to exceed seven (7) days.

Blowout Preventer Hydraulic Tests

C.A.5 The following items should be checked each time a preventer is to be hydraulically tested:

a. Verify wellhead type and rated working pressure.

b. Check for wellhead bowl protector.

c. Verify preventer type and rated working pressure.

d. Verify drilling spool, spacer spool, and valve types and rated working pressures.

e. Verify ram placement in preventers and pipe ram size.

f. Verify drill pipe connection size and type in use.

g. Open casing valve during test, unless pressure on the casing or hole is intended.

h. Test pressure should not exceed the manufacturer’s rated working pressure for the body or the seals of the assembly being tested.

i. Test pressure should not exceed the values for tensile yield, collapse and internal pressure tabulated for the appropriate drill pipe as listed in API RP 7G: Recommended Practice for Drill Stem Design and Operating Limits*.

j. Verify the type and pressure rating of the preventer tester to be used.

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TABLE C-A

Test Pressure Recommendations Preventer Equipment Tested Blowout preventer stack rated working 1. Entire blowout preventer stack. pressure (or as specified in Notes below.) 2. All choke manifold components upstream of chokes. 3. All kelly valves, drill pipe, and tubing safety valves. 4. Drilling spools, intermediate casingheads, and side outlet valves. Rated working pressures of preventers or 1. Closing unit valves and manifold 3000 psi. whichever is less 2. All operating lines. Casing test pressure 1. Any blind rams below drilling spool. 2. Primary casinghead and side outlet valves. 3. Casing string. Fifty percent (50%) of rated working pressure 1. Choke manifold components downstream of chokes or components 200 - 300 psi. 1. All ram type preventers 2. Annular preventers 3. Hydraulically operated valve. Notes: 1. Initial test pressure for the blowout preventer stack, manifold, valves, etc., should be the lesser of the rated working pressure of the preventer stack, wellhead, or upper part of the casing string. 2. Optional test - a rated working pressure test on top flange of the annular preventer. A companion test flange will be required.

*Available from American Petroleum Institute. Production Department. 2535 One Main Place, Dallas TX 75202-3904.

C.A.6 An initial pressure test should be conducted on all preventer installations prior to drilling the casing plug. Conduct each component pressure test for at least three minutes. Monitor secondary seal ports and operating lines on each preventer while testing to detect internal seal leaks.

C.A.7 Subsequent pressure tests of blowout preventer equipment should be performed after setting a casing string, prior to entering a known pressure transition zone, and after a preventer ram and/or any preventer stack or choke manifold component change; but no less than once every 21 days. Equipment should be tested to at least 70 percent of the preventer rated working pressure, but limited to the lesser of the rated working pressure of the wellhead or 70 percent of the minimum internal yield pressure of the upper part of the casing string: however, in no case should these or subsequent test pressures be less than the expected surface pressure. An exception is the annular preventer which may be tested to 50 percent of its rated working pressure to minimise pack-off element wear or damage. After a preventer stack or manifold component change, hydraulically test in accordance with the provisions in Par. C.A.6 and Table C-A. Precautions should be taken not to expose the casing to test pressures in excess of its rated strength. A means should be provided to prevent pressure build up on the casing in the event the test tool leaks.

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Closing Unit Pump Capability Test

C.A.8 Refer to Par. 5.A.21 for closing unit pump capability test details.

Accumulator Tests

C.A.9 Refer to Paras. 5.A.22 and 5.A.23 for accumulator tests details.

Auxiliary Equipment Testing

C.A.10 The lower kelly valve, kelly, kelly cock, and inside blowout preventer should be tested to the same pressure as the blow out preventer stack at the same time the preventer assembly tests are made. This equipment should be tested with pressure applied from below.

MAINTENANCE PROCEDURES

C.A.11 Field welding on a blowout preventer or related equipment is not recommended.

C.A.12 The service life of annular preventer packing units can be extended by:

a. Closing on pipe rather than full closure.

b. Using closing pressures recommended by the manufacturer.

c. Utilising the type of elastomer packing unit that best suits the drilling fluid conditions and environment expected .

d. Proper use of a regulator or accumulator when stripping tool joints. Rapid movement of a tool joint through the preventer packing unit may cause severe damage and early failure of the packing unit.

C.A.13 If elastomer parts are to be stored for a long time period, sealed containers will help extend their useful life. Refer to Section 8-A for information on extending the life of elastomers for preventers and related equipment.

C.A.14 When a blowout preventer is taken out of service, it should be completed washed, steamed, and oiled. The rams (sealing element) should be removed and the ram bore washed inspected, and coated with a rust inhibitor. Flanged faces should be protected with wooden covers. Any burrs or galled spots should be smoothed.

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TEST PLUGS AND TEST JOINTS

C.A.15 Test Plugs. Several makes of test plugs are available for testing preventer stacks. The testing tool arrangement should provide for testing the bottom blowout preventer flange. Test plugs generally fall into two types, hanger type and cup type.

a. The hanger type test plug has a steel body with outer dimensions to fit the hanger recess of corresponding types of casinghead. An O-ring pressure seal is provided between the tester and the hanger recess (refer to Figs C.A.1 and C.A.2). The tester is available in various sizes depending on wellhead type and size and is equipped with tool joint connections. These plugs should be constructed with an upper bevel and/or bevelled groove (refer to Figs, C.A.1 and C.A.2) to facilitate the use of locking screws. The O-ring groove, if used, should be machined to permit a pressure seal from above or below the plug. Other types of seals should also be capable of holding pressure from above or below the plug. Weep holes may be drilled in the pin end of the test joint or may be installed in the test plug. These testers can be provided with a plug to test blind rams with the drill string removed. The tester can be retrieved with the drill string.

b. The cup type test plug (refer to Figs. C.A.3 and C.A.4) consists of a mandrel threaded with a box on top and a pin on bottom, for a tool joint connection. A cup type pressure element holds pressure from above. Some models (refer to Fig. C.A.1) contain a back pressure valve to bypass fluid when going in the hole. Also, a set of snap plugs (usually 4) can be provided integral to the mandrel so that the snap plugs can be broken off by dropping a bar inside the pipe, thereby allowing the annulus to be connected with the inside of the drill pipe to permit pulling the tool without swabbing the hole.

C.A.16 Test Joints. The test joint should be made of pipe of sufficient weight and grade to safely withstand tensile yield, collapse or internal pressures that will be placed on it during, testing operations Refer to API RP 7G: Recommended Practice for Drill Stem Design and Operating Limits* for tabulated data listed by pipe size, grade, weight, and class (condition of pipe). The test joint (refer to Fig. C.A.5), or a box and pin sub on top of a standard joint of drill pipe, should have a tapped or welded connection below the box end connection equipped with a valve, gauge, and fittings having a working pressure at least equal to the rated working pressure of the preventer stack. Weep holes may be drilled in the pin end of the test joint or may be installed in the test plug.

C.A.17 Casing Ram Test Sub. Fig. C.A.6 illustrates a casing ram test sub. Casing rams can be tested by connecting this test sub between the test joint and the test plug so that the sub can be placed in the casing rams to be tested. A casing ram test sub can be made by welding tool joint connections on the ends of a short length of casing of desired diameter.

*Available from American Petroleum Institute. Production Department. 2535 One Main Place, Dallas TX 75202-3904.

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LOCKING FLANGE MUST BE REMOVED BEFORE NEXT SECTION OF WELLHEAD IS INSTALLED

Figure C.A.1 Figure C.A.2 HANGER TYPE TEST PLUG HELD IN HANGER TYPE TEST PLUG HELD IN PLACE WITH LOCKING FLANGE PLACE WITH CASINGHEAD LOCK SCREWS LOCK SCREWS

EXAMPLE OF HANGER TYPE TEST PLUGS

MANDREL

SNAP PLUGS MANDREL 90° SPACING RETAINING NUT RETAINING PLATE

PRESSURE SEAL CUP SIZE PLATE TAPPED FOR 1" SNAP PLUGS 90° SPACING SUB

'O' RING LOWER VALVE SNAP BAR RETAINING SLEEVE

Figure C.A.3 Figure C.A.4

EXAMPLE CUP TYPE TEST PLUGS

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W R E T L N L E C C O G N IN TROL TRAIN WEEP HOLE WEEP CASING SUB OF TO LENGTH SUFFICIENT CASING RAMS TEST TOOL JOINT BOX TO BOX JOINT TOOL TEST JOINT MATCH TO PIN JOINT TOOL TEST PLUG MATCH FIG. C.A.6 EXAMPLE CASING RAM TEST SUB STEEL PLATE STEEL CASING SUB TO (WELDED BOX) JOINT TOOL AND STEEL PLATE STEEL CASING SUB TO (WELDED BOX) JOINT TOOL AND 1" OR LARGER VALVE FIG. C.A.5 WEEP HOLE WEEP EXAMPLE TEST JOINT

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SECTION C-B INSPECTION AND TESTING—SUBSEA INSTALLATIONS

SURFACE INSPECTION AND TESTING

C.B.1 Prior to delivery to an offshore drilling unit, visually inspect the preventers, spools, high pressure connector, and kill and choke valves for condition of bodies, machined surfaces, grooves, actuating rods, rams, seals, and gaskets. Inspect in accordance with procedures in Para. C.A.2.e.

C.B.2 Test each individual component of the blowout prevention system to be utilised in test facilities under shop conditions to rated working pressure utilising procedures outlined in Para.C.A.2.e. Following unitisation in the shop, test entire unit for proper operation using the hydraulic closing system. Test the closing system to 3000 psi. Pressure test each preventer and high pressure connector for low pressure (200 psi) leaks and to rated working pressure. Record the date and results of inspection and tests on the shipping tags.

C.B.3 After delivery to an offshore drilling unit, install the unitised blowout prevention system on a prepared test stump. A low pressure and rated working pressure test of each component as in the off-site procedure (Para. C.B.2) should be repeated and properly recorded in the well log. Test record should include opening and closing times and hydraulic fluid volumes required for each function. Subsequent pressure tests should be limited to 70% of the rated working pressure of the blowout preventer stack or the anticipated surface pressure, whichever is greater. Full rated working pressure tests should be limited to one test following any major ram cavity repair work.

C.B.4 The blowout prevention system should be visually inspected and pressure tested in accordance with Para. C.B.3 before returning on a well.

SUBSEA TESTING

C.B.5 The blowout prevention system should be operated on each trip but not more than once every 24 hours during normal operations. The annular preventers need not be operated on each trip. They must, however, be operated in conjunction with the required pressure tests and at an interval not to exceed seven days. The periodic actuation test is not required for the blind or blind shear rams. These rams need only be tested when installed and prior to drilling out after each casing string has been set. A record of these tests should be maintained in the well log and should include closing and opening times and pressures and volumes of hydraulic fluid for each function.

C.B.6 Pressure tests of the subsea system should be conducted after installation, after setting casing, and before drilling into any known or suspected high pressure zones. Otherwise, these tests should be conducted at regular intervals but not

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more than once every week. On installation of the blowout preventer stack, each component including the high pressure connectors should be individually pressure tested at a low pressure (200 psi) and to the greater of 70 percent of rated working pressure or the maximum pressure expected in the upper part of the casing. Subsequent pressure tests may be limited to the lesser of 70 percent of the rated working pressure of the blowout preventers or 70 percent of the minimum internal yield strength rating of the upper part of the casing, provided the test pressure equals or exceeds the maximum pressure expected inside the upper part of the casing. An exception is the annular preventer which may be tested to 50 percent of its rated working pressure to minimise pack-off element wear or damage. A test plug or cup type tester should be used (refer to Section C-A). Precautions should be taken not to expose the casing to test pressures in excess of its rated internal yield strength. A means should be provided to prevent pressure build up on the casing in the event the test tool seals leak. Actuation testing of pipe rams should not be performed on moving pipe.

C.B.7 The subsea blowout prevention system is dependent on surface actuated hydraulic, pneumatic, and electric controls. The design of this prevention system is dependent on water depth and environmental conditions and should have an adequate backup system to operate each critical function. It is equally important to pressure and operationally test this system concurrently with the blowout preventers and connectors.

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SECTION C-C SEALING COMPONENTS—SURFACE INSTALLATIONS

FLANGES AND HUBS

C.C.1 The following tabular data detail sizes in use on blow out preventers

Rated Working Flange or Minimum Ring-Joint Pressure Hub Size Vertical Bore Gaskets psi in. in. RX BX 500 (0.5 M) 29 1/ 29 1/ -- 2 2 2,000 (2 M) 16 16 3/ 65 - 4 20 21 1/ 73 - 4 26 3/ 26 3/ -- 4 4 3,000 (3 M) 6 7 1/ 45 - 16 8 9 49 - 10 11 53 - 12 13 5/ 57 - 8 20 20 3/ 74 - 4 26 3/ 26 3/ -- 4 4 5,000 (5 M) 6 7 1/ 46 - 16 10 11 54 - 13 5 / 13 5/ - 160 8 8 16 3/ 16 3/ - 162‡ 4 4 18 3/ 18 3/ - 163 4 4 21 1/ 21 3/ - 165 4 4 10,000 (10 M) 7 1/ 7 1/ - 156 16 16 9 9 - 157 11 11 - 158 13 5/ 13 5/ - 159 8 8 16 3/ 16 3/ - 162 4 4 18 3/ 18 3/ - 164 4 4 21 1/ 21 1/ - 166 4 4 15,000 (15 M) 7 1/ 7 1/ - 156 16 16 9 9 - 157 11 11 - 158 13 5/ 13 5/ - 159 8 8 20,000 (20 M) 7 1/ 7 1/ - 156 16 16 Notes:

* Replaces 20 1/ " subsequent to January 1974. 4 ‡ Replaces BX-161 subsequent to adoption of 5000 psi rated working pressure (10,000 psi test pressure) flange in lieu of 5000 psi rated working pressure (7500 psi test pressure) flange in June 1969.

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SECTION C-D SEALING COMPONENTS—SUBSEA-INSTALLATIONS

GENERAL

C.D.1 Operation of the subsea blowout preventer stack and marine riser system requires particular attention to the availability and correct usage of sealing components which are peculiar to subsea equipment. These non-API components are described in the following paragraphs. Manufacturers should be consulted for specifications and spare parts recommendations. Other sealing components are covered in Section C-C.

WELLHEAD CONNECTOR

C.D.2 The primary seal for the wellhead connector is a pressure energised metal- to-metal type seal. Initial seal requires that the metal seal be coined into contact with the mating seal surfaces. These seals are not recommended for reuse. Some wellhead connectors are equipped with resilient secondary seal which may be energised should the primary seal leak. This seal should be utilised under emergency conditions only.

MARINE RISER

C.D.3 The primary seal for the marine riser connector consists of resilient type O-Ring or lip-type seals. The primary seal for choke and kill line stab subs on the integral riser connector consists of pressure energised resilient seals or packing. Care should be taken to carefully clean and inspect all seals prior to running the marine riser.

C.D.4 The primary telescopic joint seal assembly consists of a hydraulic or pneumatic pressure energised resilient packing element.

SUBSEA CONTROL SYSTEM

C.D.5 Primary hydraulic system seal between the male and female sections of the control pods is accomplished with resilient seals of the O-ring, pressure energised, or face sealing types.

C.D.6 The hydraulic junction boxes consist of stab subs or multiple check valve type quick disconnect couplings. The primary seals are O-rings. These seals should be inspected each time the junction box is disconnected.

C.D.7 The primary pod valve seals vary according to the manufacturer with both resilient and lapped metal-to-metal type seals used.

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D. APPENDIX - CHOKES D-1

D.1 HP PRODUCTION CHOKES D-1

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D. APPENDIX - CHOKES

D.1 HP PRODUCTION CHOKES

K Choke Beans and Wrenches:

• Flared Orifice entrance reduces erosion on the entrance surface. • Accuracy levels are maintained over extended periods of use. • Choke beans save time and money because replacement intervals are extended.

The part numbers of the positive and combination beans are determined by desired orifice 4 64 size. K1 positive bean orifice sizes range from /64" to /64". K2 positive bean orifice sizes 4 128 4 192 range from /64" to /64". K3 positive bean orifice sizes range from /64" to /64". 6 64 K1 combination bean sizes range from /64" to /64". K2 combination bean sizes range form 6 128 6 192 /64" to /64". K3 combination bean sizes range from /64" to /64".

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Figure D.1 - Cameron Fixed Bean Choke System

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Figure D.2 - HP Production Chokes

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Figure D.3 - ‘K3’ Choke

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E. APPENDIX - WIRELINE SURFACE PRESSURE CONTROL EQUIPMENT E-1

E.1 INTRODUCTION E-1

E.2 WELLHEAD PRESSURE CONTROL EQUIPMENT E-1

E.2.1Quick Unions E-3

E.2.2Wellhead Adapter (Tree Adapter) E-5

E.2.3Pump-in Tee E-6

E.2.4Wireline Valve (BOP) E-7

E.2.5Lubricators - Bleed Off Valve E-11

E.2.6Stuffing Box E-16

E.2.7Hydraulic Packing Nut E-18

E.2.8Grease Injection Head E-19

E.2.9Flow Tubes E-23

E.2.10 Grease Injection System E-24

E.2.11 Safety Check Union E-27

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E. APPENDIX- WIRELINE SURFACE PRESSURE CONTROL EQUIPMENT

E.1 INTRODUCTION

Wells in which Wireline Services are performed may contain a wide range of wellhead pressures (WHP), for example from a few psi. up to several thousand psi. This pressure is normally due to the natural pressure of the producing formation into which the well has been drilled. Working in a pressurised well allows remedial or investigative work to be performed without ‘killing’ the well. Although killing the well is safer, it is a costly, time consuming exercise requiring a rig and perhaps damaging the producing formation in the process. Current Wellhead Pressure Equipment and practices allows a wire to be run in and out of the well. Various wireline tools can be run and retrieved with a high degree of safety. Despite this, wireline operations with pressure in the well require highly-qualified personnel and rigorous operating and safety procedures since the safety/control of the well is under their management.

E.2 WELLHEAD PRESSURE CONTROL EQUIPMENT

To enable the tools to be run into the well under pressure, the surface equipment shown below is required. Each component on the following list is discussed in the next sections. • Quick Unions • Wellhead Adapter • Pump-in Tee • Wireline Valve (BOP) • Lubricator - Bleed Off Valve • Safety Check Union • Stuffing Box • Hydraulic Packing Nut • Grease Injection Head • Flow Tubes • Grease Injection System • Hay Pulley • Weight Indicator • Wireline Counter • Wireline Clamps.

The relative positions of some of these components are shown in Figure E.1

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Figure E.1 - Example of a Wireline Rig Up E.2.1 Quick Unions

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The connections used to assemble the Lubricator and related equipment are referred to as Quick Unions; See Figure E.2. They are designed to be quickly and easily connected by hand. The box end receives the pin end which carries an O-ring seal. The collar has an internal Acme thread to match the external thread on the box end. This thread makes up quickly by hand and should be kept clean. The O-ring forms the seal to contain the pressure and should be thoroughly inspected for damage and replaced if necessary. A light film of oil or grease helps in the make up of the union and prevents cutting of the O-ring.

Pipe wrenches, chain tongs or hammers should never be used to loosen the collar of the union. If it cannot be turned by hand, all precautions must be taken to make sure that the well pressure has been completely released.

CAUTION: IN GENERAL, UNIONS THAT CANNOT BE LOOSENED EASILY INDICATE THAT HIGH PRESSURE MAY BE TRAPPED INSIDE. IF THIS PRESSURE IS NOT BLED OFF FIRST, UNSCREWING THE UNION COULD CAUSE A SUDDEN RELEASE OF PRESSURE, PROJECTING EQUIPMENT PARTS AT LETHAL SPEEDS.

The collar of the union will make up by hand when the pin end (with the O-ring) has been shouldered against the box end. When the collar bottoms out, it should be backed off approximately one quarter turn to eliminate any possibility of it sticking due to friction when the time comes to disconnect it. Rocking the lubricator to ensure it is perfectly straight will assist in loosening the quick union. In addition, ensure that tugger lines and hoists are properly placed to lift the lubricator assembly directly over the wellhead.

Figure E.2 -Quick Union

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E.2.2 Wellhead Adapter (Tree Adapter)

All Wellhead Adapters are crossovers from the Xmas tree to the bottom connection of the Wireline Valve or Riser. It is important to check that the correct type of threads with appropriate pressure ratings are used on the top and bottom of the adapter. Three types of Wellhead Adapter, See Figure E.3, are in common use:

• Quick Union to Quick Union • API Flange to Quick Union • Acme Thread to Quick Union.

Figure E.3 - Wellhead Adapters E.2.3 Pump-in Tee

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A Pump-In Tee; See Figure E.4, consists of three main parts:

• A Quick Union box end • A Quick Union pin end • A Chiksan/Weco type connection.

The Pump-in Tee, when rigged up, is placed between the Wellhead adapter and the wireline BOP. Therefore, Quick Union sizes and pressure ratings must be compatible with all surface equipment.

Pump-in Tees may be required as part of a wireline rig-up. By connecting a kill-line to the Chiksan/Weco connection, the well can be killed in an emergency situation. This line can also be used to pressure test or release pressure from the surface equipment. NOTE: On some locations, the pump-in tee will be part of the wellhead adapter.

Figure E.4 - Pump-in Tee

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E.2.4 Wireline Valve (BOP)

a) Description

A Wireline Valve; See Figure E.5, must always be installed between the Wellhead/ Xmas tree and Wireline Lubricator. This valve is a piece of safety equipment that can close around the wireline and seal off the well below it. This enables the pressure to be bled off above it, allowing work or repairs to be carried out on equipment above the valve without pulling the wireline tools to surface. A positive seal is accomplished by means of rams which are manually or hydraulically closed without causing damage to the wire.

Hydraulically actuated Wireline Valves are more commonly used because of the speed of closing action and ease of operation. During an emergency, often the valve is not easily accessible to allow fast manual operation and therefore remote actuation is preferred.

Single or dual ram valves are available in various sizes and in a full range of working pressure ratings. Dual rams offer increased safety during slick line work and allow the injection of grease to secure a seal on braided wireline. They are used particularly in gas wells, or wells with a gas cap.

Wireline Valves are fitted with equalising valves that allow Lubricator and well pressure to equalise prior to opening the rams when wireline operations are to be resumed. Without this, if the valve rams were to be opened without first equalising, the pressure surge could blow the toolstring or wire into the top of the Lubricator, causing damage or breakage.

WARNING: SINCE THEY ARE SUCH A VITAL COMPONENT CONTROLLING THE SAFETY OF THE WELL, IT IS IMPORTANT THAT WIRELINE VALVES ARE REGULARLY PRESSURE AND FUNCTION TESTED. TESTS SHOULD BE CARRIED OUT PRIOR TO TRANSPORT OFFSHORE, BEFORE EACH NEW WIRELINE OPERATION AND AFTER ANY REDRESS OR REPAIR OF THE VALVE.

b) Uses of Wireline Valves

• To enable well pressure to be isolated from the lubricator when leaks develop etc. without cutting wire by closing the master valve. • To permit assembly of a wireline cutter above the rams. • To permit dropping of wireline cutter or cutter bar. • To permit ‘stripping’ of wire through closed rams only when absolutely necessary.

A mechanical or hydraulic force is applied to close the rams to seal against well pressure. The sealing elements are arranged so that the differential pressure across them forces them closed and upwards, assisting in the sealing action. Figure E.6 shows the ram configuration of a Wireline Valve. Blind rams close without wire and will also close on 0.108 in. wire without damage. Both 3/16 in. and 7/32 in. rams have a semi circular groove in each of the two ram faces to permit the ram to close and seal on 3/16 in. or 7/32 in. braided line.

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Figure E.5- Typical Wireline Valve (BOP)

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Figure E.6 - Wireline Valve Ram Configuration

NOTE: Ensure that the correct guide is installed as an incorrect guide may damage or cut the wire.

CAUTION: WIRELINE VALVES WILL HOLD PRESSURE FROM BELOW ONLY.

d) Equalising Valves

Permits equalisation of pressure from below the closed rams, after bleed off of the lubricator. The equalising valve must be opened and closed prior to use.

A check should be made to ensure that the equalising assembly is not inverted and that the retainer screw is towards the bottom of the valve; See Figure E.5.

When operating with stranded/braided line, it is strongly recommended that a twin valve or two single valves (one on top of the other), be installed and equipped with the appropriate size moulded rams with the lower rams inverted to shut off from above. This enables grease injection between the rams to block off the interstices of the braided line, preventing leakage through the internal parts of the wire.

NOTE: If the BOP fails test, the equalising valve should be checked to confirm it is fully closed.

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E.2.5 Lubricators - Bleed Off Valve

The Lubricator is, in effect, a pressure vessel situated above the Xmas Tree, subject to the wellhead shut-in pressure and also test pressures. For this reason, it should be regularly inspected and tested in accordance with Statutory Regulations.

All Lubricator sections and accessories subject to pressure must be stainless steel banded; the band should be appropriately stamped with the following data:- maximum working pressure, test pressure, and date and rating of last hydrostatic test.

a) Description

A Lubricator allows wireline tools to enter or be removed from the well under pressure. It is a tube of selected ID. and can be connected with other sections to the desired length by means of Quick Unions; See Figure E.7.

The following factors govern the selection of Lubricators:

• Shut-in wellhead pressure • Well fluid • Wireline tool diameter • Length of wireline tools.

The lowermost Lubricator section normally has one or more bleed off valves installed; a pressure gauge can be connected to one of the valves to monitor pressure in the Lubricator. If the Lubricator has no facility to install valves then a Bleed-off Sub, a short Lubricator section with two valves fitted, should be connected between the Wireline Valve and Lubricator.

Quick Unions connect Lubricator sections together and to the Wireline Valve; these unions have Acme type threads and seal by means of an O-ring, thereby requiring only tightening by hand; See Figure E.8.

b) Construction

Lubricators for normal service (up to 5,000 psi.) can be made of carbon or manganese steel. Over 5,000 psi., consideration should be given to sour service as quantities of H2S can be absorbed into the steel of the Lubricator body and heat treatment becomes necessary. All Lubricator sections must have full certification from the manufacturer or test house. A standard colour code identifies different pressure ratings of lubricator.

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Figure E.8 - Lubricator Connectors

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A colour coding system is usually implemented. The colour coding system uses one or two bands of colour to identify the service. For example in the Shell Expro system, the pressure rating is identified by the base colour of the item (e.g. lubricator) or accessory and should satisfy the following:

MAXIMUM WORKING PRESSURE COLOUR (psi)

3,000 Red

5,000 Dark Green

10,000 White

15,000 Yellow

Table E.1 - Colour Coding and Pressure Rating of Pressure Control Equipment

The first band indicates if the service is Standard or Sour. Standard service has no band. Sour service has an orange band. The second band indicates the temperature of the service. Standard service (-30˚C to 250˚C) has no band. Low temperature service (below -30˚C) has a blue band. High temperature service (above 25˚C) has a purple band.

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W R E T L N L E C C O G N IN TROL TRAIN E.2.6 Stuffing Box

The Stuffing Box; See Figure E.9, is a sealing device connected to the top of the Lubricator sections and in conjunction with the lubricator is the primary pressure control on the well.

It allows the wireline to enter the well under pressure and also provides a seal should the wireline break and be blown out of the packing. The Stuffing Box will cater for all sizes of slickline but the size of the wire must be specified to ensure the correct packing rubbers are installed.

If the wireline breaks in the well, the loss of weight on the wire at surface allows well pressure to eject the wire from the well. To prevent well fluids leaking out the hole left by the wire, an Internal Blow Out Preventer Plunger is forced up into the Stuffing Box by well pressure and seals against the lower gland.

A packing nut and gland located at the top of the Stuffing Box can be adjusted to compress the packing and seal on the wireline. Hydraulically controlled Packing Nuts are available to ease operation should the packing require to be compressed during wireline operations. These are controlled remotely by a hand pump and this avoids the need for manual adjustment of the Packing Nut.

For slickline operations, the top sheave is normally an integral part of the Stuffing Box. This reduces the rig up equipment required and the large 10 or 16 ins. sheaves can handle the larger OD. wire with less fatigue and breakdown . Wireline sealing devices fulfil one of two functions:

• Pressure containment (sealing)

• High pressure containment on braided line.

For solid wirelines, only pressure containing Stuffing Boxes are utilised. The standard Stuffing Box is available in 5,000 psi. and 10,000 psi. pressure ratings although higher pressure ratings are now also available.

The essential function of the Wireline Stuffing Box is to ensure containment or sealing off around solid wirelines, whether stationary or in motion, at the upper end of the Lubricator during wireline operations. In addition, most Stuffing Boxes contain a BOP plunger which is forced out of the packing section to seal off flow in the event of wireline breakage. A swivel-mounted (360˚ free movement) sheave wheel and guard are fitted to the top half of the Stuffing Box. The wheel is positioned so as to maintain the passage of the wire through the centre of the packing rubbers.

The sheave guard on the Stuffing Box is designed to trap any wire which breaks on the surface before it drops downhole. The adjustment to the packing retainer nut at the top of the Lubricator is time consuming and a Hydraulic Packing Nut; See Section E2. E.2.7, can be installed so that control can be executed from the deck.

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Figure E.9 - Wireline Stuffing Box

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E.2.7 Hydraulic Packing Nut

The Hydraulic Packing Nut assembly, See Figure E.10, is designed for a standard Wireline Stuffing Box to allow remote adjustment of the packing nut. This method is a safe and convenient way of regulating the packing nut. Regulation is made from a ground position by means of a hydraulic hand pump and hose assembly.

a) Benefits The need for a person to climb the lubricator is eliminated. The hand pump is positioned away from the nut itself, and therefore possible escaping well fluid.

b) Operation The Hydraulic Packing Nut Assembly includes a piston which has a permissible travel of 0.4 in. enclosed in a housing. The housing has a 1/4" NPT connection for a hydraulic hose. The area above the piston is arranged so that when hydraulic pressure is applied to this area, the piston is forced downward against the force of the spring. This downward action of the piston is transmitted to the upper packing gland. This is designed to cause the Stuffing Box packing to be squeezed around the wireline, sealing off well fluids within the Stuffing Box.

Figure E.10 - Hydraulic Packing Nut

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E.2.8 Grease Injection Head

To supply grease under pressure the following equipment is required to rig up the Grease Injector Head:

• High pressure grease pump • Grease reservoir • Compressor • Hoses • Wiper box • Grease injector head assembly • Sheave • Crane or drawworks.

The Grease Injection Head; See Figure E.11, is designed to effectively seal off stranded wirelines, such as fishing and logging cables. The Grease Injection Head utilises grease or honey oil, pumped under high pressure from a grease pump, into a very small annular space between the outside of the wire and the inside of a tube covering it. The high pressure fluid provides two sealing mechanisms:

• Since stranded lines have interstices between the strands and between layers which cannot be packed off in a more direct, conventional manner, the sealing fluid fills these spaces, depriving the well fluid of escape paths inside and around the wire. • The sealing fluid in the small annular space is held at a higher pressure than that in the well, forming a barrier to the flow of wellhead fluids and gases.

This results in the complete sealing and also lubrication of the wireline which reduces friction.

NOTE: When calculating the amount of stem required to overcome the well pressure, a percentage must be added to compensate for friction.

The Grease Injection Control Head is composed of three flow tube sleeves, a flow tube sleeve coupling, a quick union pin end, a flow hose and a line rubber and hydraulic packing nut assembly at the upper end. The amount of flow tube sleeve used depends on the well pressure. For 3/16" Braided Line: 3 flow tubes 0 - 4,000 psi. 4 flow tubes 4,000 - 6,000 psi. 5 or 6 flow tubes 6,000 - 10,000 psi. The flow tubes are close-fitting around the wireline and they, along with the flow tube sleeves, form the main length of the grease head. This appreciable length affords sufficient length to form an effective pressure barrier. The flow tube sleeves are simplified body parts which hold the various other components rigidly together and seal them. In addition, they are made of a very hard metal and the wire predominantly bears on them, preventing wear on the other parts. The flow tube coupling forms a junction for the flow tubes and also as the point of entry for the grease.

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Grease Out

Flow Tube

Grease In

Flow Tube

Quick Union

Figure E.11 - Grease Injection Head

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The Hydraulic Packing Nut is a simple but efficient device which is remotely operated by a hydraulic hand-pump assembly. The Hydraulic Packing Nut is actuated by pumping pressure into the cylinder. When a complete seal is established, the pressure is maintained by closing the valve at the hand pump assembly. The pressure may be relieved by opening the valve and thus relaxing the seal. Thus, the piston in the packing nut is retracted by a strong spring when the pressure is relieved from the piston.

The body has a port into which is assembled a flow hose to lead off any seepage that migrates through the line and finds its way above the two flow tubes.

The optional differential pressure regulator valve, when used, controls the flow of grease to the control head which is supplied by the grease supply system. In all cases, the grease is delivered at a pressure of 350 psi. to 400 psi. greater than the wellhead pressure.

E.2.9 Flow Tubes

A range of flow tubes; See Figure E.12 are available with small increments of IDs so as to provide an effective seal over the life of a wireline which reduces in size with usage.

The OD. of the line should be measured and the size of the tubes selected for the closest fit (ID. of flow tubes should be 0.004 in. - 0.006 in. larger than OD. of wireline). Slip each tube in turn over the wire and physically check that they do not grip the wire as this can lead to ‘bird caging’ of the outer strands when running in the well. This is an effect where the drag on the outer strands gradually holds them back with regard to the inner strands so they become loose and spring out from the cable like a bird’s cage until they jam at the packing nut. If the packing nut is too tight it can also cause this same effect. (Alternatively, if the tubes are too big, they will not create an effective barrier and too much grease will be wasted.)

Figure E.12 - Flow Tube Schematic

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E.2.10 Grease Injection System

The system is designed to deliver grease as demanded under continuous operation within the parameters of a single pump unit.

There are two circuits on the unit for control/drive air and grease and both are described below:

a) Grease System The system pump draws grease from the grease reservoir through the pump suction tube and it is pumped to the outlet port which is split into two lines. One line delivers grease to the control panel vent valve which allows the operator to vent grease pressure to atmosphere via a short hose into an alternate grease reservoir which is not in use (this is normally permissible as grease from this source should be clean; however, care should be taken to isolate grease from airborne contamination). The other line is the grease supply line plumbed via a rotary valve to hose storage reels and then to the appropriate grease head; See Figure E.12.

The grease return line via the hose reel, rotary valve, and system pressure gauge leads to a system pressure control vent valve from which the vented grease flow rate is controlled. This grease is plumbed (now at atmosphere pressure) through a short flexible hose to a waste grease container and should not be re-used as this may be contaminated. Excessive grease returns will indicate incorrectly sized flow tubes.

NOTE: If a 5/16" line is used, the supply pump must be fitted with at least a 3/4" ID. hose to ensure adequate supply to retain seal.

b) Pneumatics The drive air enters the unit via a bulkhead quick connect to a pressure control valve which is pilot controlled from the control panel and also acts as a stop/start control. A separate supply is plumbed to the control panel into a three way, two position valve. Position one is where the supply is blocked with the reservoir vented to atmosphere, position two is where the supply air is directed to the reservoir via the reservoir lid pressure controller; both allow the operator an auto pre-set reservoir pressurisation or vent to atmosphere in one control valve.

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Figure E.13 - Grease Injection Rig Up

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WARNING: HIGH PRESSURE - Never allow any part of the human body to come in front of or in direct contact with the grease outlet. Accidental operation of the pump could cause an injection into the flesh. If injection occurs, medical aid must be immediately obtained from a physician. WARNING: COMPONENT RUPTURE - This unit is capable of producing high fluid pressure as stated on the pump model plate. To avoid component rupture and possible injury, do not exceed 75 cycles per minute or operate at an air inlet pressure greater than 150 psi. (10 bar). WARNING: SERVICING - Before servicing, cleaning or removing any component, always disconnect or shut off the power source and carefully relieve all fluid pressure from the system.

E.2.11 Safety Check Union

This device can be included in braided/stranded wireline Lubricator hook-ups just below the Grease Injection Head. The wire is threaded through both these units and in the event that the wire breaks and is blown out of the Grease Injection Head, the well pressure will automatically shut off by the Safety Check Union. Shut-off is accomplished by the velocity of the escaping well effluents causing a piston to lift a ball up against a ball seat; See Figure C.14. Well pressure holds the ball against the seat. This device does in fact fulfil the same function as the internal Wireline Valve in the solid wireline Stuffing Box. As with all Lubricator equipment, this Safety Check Union is furnished with Quick Unions.

Figure E.14 - Safety Check Union

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F. APPENDIX - COILED TUBING SURFACE WELL CONTROL EQUIPMENT F-1

F.1 INTRODUCTION F-1

F.2 BARRIER PRINCIPLES F-2

F.3 PRESSURE CONTROL EQUIPMENT F-2

F.3.1 Check valves F-2

F.3.2 Stripper/Packer F-2

F.3.3 BOPs F-9

F.3.4 Shear/Seal F-14

F.4 OPERATIONAL PLANNING AND SAFETY F-18

F.4.1 Introduction F-18

F.4.2 Operational Considerations F-18

F.4.3 Working Location F-18

F.4.4 Pressure Control Equipment Considerations F-20

F.5 EMERGENCY PROCEDURES F-22

F.5.1 Platform Shutdown F-22

F.5.2 Stripper/Packer Element Leak F-22

F.5.3 Leak Between the Top of the Tree and the Stripper/Packer F-22

F.5.4 Tubing Pinhole Leak F-22

F.5.5 Tubing Ruptures F-23

F.5.6 Tubing Separates Downhole F-23

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F. APPENDIX - COILED TUBING SURFACE WELL CONTROL EQUIPMENT

F.1 INTRODUCTION

When planning a Coiled Tubing operation, include a rough draft on well control requirements for the particular application. One of the main reasons for this is that it may be a significant factor regarding the amount of items required in the well equipment stack-up.

Both the well characteristics and the type of operation should be considered as they determine the minimum size and type of well control devices that need to be employed to safely and successfully conduct the programme.

In Coiled Tubing operations both internal and external pressure control must be assessed. ‘Internal’ refers to the inside of the coiled tubing and ‘External’ to the coiled tubing annulus. The typical Well Control Stack is:

• Stripper • BOP • Riser • Shear Seal

Starting from the top of the tree, many operators utilise a single shear/seal device which is flanged to the tree irrespective of well conditions and the operation to be carried out. This is generally a tertiary barrier. Other operators only use a shear/seal device when they deem it applicable. The bore diameter and cutting capabilities of the shear/seal will depend largely on the type of toolstring.

On top of the Xmas tree or a shear/seal, if used, is a crossover flange to quick union sectional riser continuing to the operating level, i.e. rig floor or platform deck, with any additional stick up height that is required.

The BOP is mounted directly on top of the riser using any crossovers which are required. The BOP can be either be a conventional quad BOP, or the later style Comb BOP’s. Combi’s were developed to be shorter and therefore have less stick up.

The stripper/packer or stuffing box attaches to the top of the BOPs. This piece of equipment is normally bolted to the underside of the injector head. A tandem stripper/packer or even an annular BOP can be installed between the standard stripper/packer and the BOP for additional safety particularly when the well conditions may cause premature stripper rubber wear.

Whichever combination of BOPs is selected in the stack-up for an operation, it should include a closed barrier to allow safe stripper/packer rubber replacement and a backup barrier.

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F.2 BARRIER PRINCIPLES

A combination of pressure control barriers are used in coiled tubing operations to provide both internal pipe and external pipe pressure control.

For external pressure control the barriers during normal operations are stripper/packers, annular BOPs and BOP pipe rams. Strippers or annular BOPs are considered as primary barriers and the BOPs as secondary barriers.

The internal barrier during normal operations are double BHA check valves. Both check valves together are considered as the primary barrier and the BOP cutter rams secondary. BOP shear/seal rams or cutter gate valves are barriers on both sides and are considered tertiary barriers.

F.3 PRESSURE CONTROL EQUIPMENT

F.3.1 Check valves

Check valves are installed in the coiled tubing BHA above the disconnect sub. They provide primary inside pressure control.

The four most common types used are shown in Figure F.1, Figure F.2, Figure F.3, and Figure F. 4

F.3.2 Stripper/Packer

The stripper/packer is located at the top of the pressure control stack-up attached to the injector head and is the primary pressure control barrier. It is constantly energised throughout the coil tubing operation to effect a seal against the tubing; See Figure F.5, Figure F.6, Figure F.7 and Figure F.8. As it is in constant use, on high pressure or gas wells, the elastomer sealing element can wear out quite rapidly, hence the contingency requirement for a back-up stripper or annular BOP.

An example of such a rig up is shown in Figure F.11. As stated above, this back-up unit would only be brought into use if the first packing element failed. Used in conjunction with the tubing rams in the BOPs, this provides an additional barrier and allows safer access to change the worn elastomers in the first stripper.

In other circumstances the back-up stripper may be used to allow operations to continue without having to repair the first stripper

Because of the increased height due to using tandem stripper/packers, a new development introduced is the radial stripper/packer; 4. This reduces the stack up height by about half and makes changing the elastomers a very simple task.

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Figure F.1 - Ball Check Valve

Figure F.2 - Dome Check Valve

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Figure F.3- Flapper Check Valve

Figure F.4 - Removable Cartridge Flapper Valve

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Figure F.5 - Stripper/Packer

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Figure F.6 - Side Door Stripper/Packer

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Figure F.7 - Tandem Sidedoor Stripper/Packer

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Figure F.8 - Radial Stripper/Packer

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F.3.3 BOPs

The BOP is the secondary barrier in pressure control. As a failsafe device, the BOP should only be operated as a safety device and with careful consideration and not used for any other use such as a means of “parking” the tubing while at depth.

A standard quad BOP is configured with four rams; See Figure F.9 and Figure F.10

From top to bottom:

• Blind Rams Blind rams only seals on open hole when the elastomers on each ram meet and seal. If there is pipe across the ram area the seal cannot be effected.

• Shear Rams Shear rams have the ability to cut tubing. When using C/T logging i.e. tubing with logging cable through it, the shear rams must have the capability to cut both. There is no seal on this function. Extreme caution should be taken when functioning any of the rams as accidental functioning of the shear rams could potentially be very dangerous and at best causes a fishing job.

• Slip Rams The slip ram is designed to hold the full tubing weight, and it too has no sealing function. The slip toolface can mark the tubing significantly and induce an area where premature cracking can occur. Caution should be used when considering the use of these rams as the slip toolface can significantly mark the tubing and induce an area where premature cracking can occur.

• Tubing Rams Tubing rams are used to effect a seal against the tubing. Wellbore pressure aids in the sealing of the ram when a differential is created, by bleeding off above. Both this ram and the blind ram do not hold pressure from above.

A Combi BOP incorporates the functions of two upper and the two lower types of rams into one unit and in so doing reduces rig up height and simplifies the controls system. However, it would be necessary to alter the well control procedures accordingly.

A triple Comb is a model which has two combination slip/tubing rams as well as the combination shear/blind rams. A triple Comb combined with two radial stripper/packers provides a shorter stack up than a conventional stack-up; See Figure F.11.

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Figure F.9 - Quad BOP

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Figure F.10 - EH34 Quad BOP

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F.3.4 Shear/Seal

1 This device is usually a 6 /8" bore Comb ram with single cut and seal rams; See Figure F.12. This provides a single cut/seal function for installation safety and is the tertiary barrier. In the event of a platform emergency, a designated person is responsible for it’s closure but normally the platform manager’s permission is sought time permitting.

To illustrate the main components of a typical hydraulic ram, a sectioned drawing of a shear/ seal actuator is illustrated; See Figure F.13.

Figure F.14 shows the height of a typical stack up arrangement using a dual Comb on the tree, a triple Comb BOP, a quick union connector, a tandem and standard stripper/packer.

Figure F.11 Pressure Control Stack Up

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Figure F.12 - Shear/Seal Single BOP

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Figure F.13 - Shear/Seal Actuator Assembly

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Figure F.14- Pressure Control Stack Up

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F.4 OPERATIONAL PLANNING AND SAFETY

F.4.1 Introduction

Initially look at the different factors which control any Coiled Tubing operation. These factors when combined in the right order, and planned properly, will see the completion of a successful coiled tubing operation.

F.4.2 Operational Considerations

Gas Well Gas wells cause undue wear to stripper rubbers and, hence, it may be necessary to provide an additional stripper/packer, to complement the standard package.

High Wellhead Pressure Use of coiled tubing in high pressure situations, require a thorough check of certain aspects pertaining to the well control equipment. For example, the pressure rating of the equipment, back-up stripper/packer or annulus preventer and the capability of the hydraulic system to, either, shear or effect a proper seal around the tubing

Toolstring Length The operation will dictate the length of the tool string which in turn may affect the rig up, e.g. length of riser, pick up height of the injector and stick up height of well control equipment. See Figure F

Toolstring Deployment Systems Novel deployment systems have been developed for the deployment of extra long toolstrings such as TCP type perforating guns. These systems provide barrier protection when the toolstring is being made up and lubricated into the well. Such systems may require the assistance of a wireline unit and crew.

F.4.3 Working Location

Type of Rig A semi-submersible drilling or workover vessel requires the addition of a heavy duty lifting frame installed between the block and the surface tree in which to support the injector and BOPs.

Drilling rigs can usually accommodate the width of injectors quite easily but in certain circumstances the “A” frame height can be restrictive.

Workover rigs tend to have smaller “V” doors than conventional drilling rigs, and dimensions of this should be checked against the injector size available.

On land well operations where there is no means of holding back the injector against the pull of the tubing from the reel, an adjustable stand is required to support the forces with the ground.

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Rig Floor Equipment There should be enough rig floor tuggers capable of pulling the injector into position for stabbing onto the BOP with sufficient lifting capacity. There should be two for the injector positioning, one to install the toolstring and one or more for man riding. The tie down points must be designed and certified for the job.

Rig floor working space should not be restricted with unnecessary items of equipment or tubulars in the derrick. The main access and emergency exit points should not be restricted.

Refer to Figure F.15

Figure F.15 - Radius of Safety

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F.4.4 Pressure Control Equipment Considerations

The style of stripper/packer in relation to the operation requires consideration. On a conventional stripper/packer it may take over 45 minutes to change the elastomers with pipe in the hole. To change the elastomers in a side door stripper/packer, may take as little as 5 minutes.

A tandem stripper/packer should be employed to serve as an additional well barrier in high wellhead pressure situations. A tandem stripper/packer it will add approximately 4 ft. to the stick up height which needs to be considered.

BOPs are now available in several different configurations. The standard is a quad, i.e.; with four separate ram functions. The trend now is to combine the rams to form Combi BOPs. The most common configuration is the Triple Combi. This BOP combines the two top functions and eliminates the need to pull pipe as is necessary after the shear on the quad.

The shear/seal is a large single cut and seal device. This is normally flanged on top of the wellhead and used only as a last resort. The shear/seal usually is of a size equal to the wellbore, and is capable of cutting the toolstring.

Control Hoses On a semi-submersible the injector and the BOPs may be a considerable height above the drillfloor. This must be considered with the position of the power pack and control house, whereby extensions to the control hoses may be required.

Similarly on a platform, if the coiled tubing is to be run from the pipe deck to the skid deck, the control hoses may again require extensions.

Support Stand The standard type support stand is manually operated and requires constant monitoring in live well situations. If the operation is performed with the well on production, and cold liquids introduced through the coiled tubing this will cause the riser to contract, the support stand may become trapped under the injector.

A hydraulic support type stand has built in relief valves to release the pressure should the riser shrink.

Tie Back Points The use of tie down points requires the need to have similar tie back points on the injector. Under normal circumstances injectors are not fitted with this facility. If the frame is to be used ensure that the attaching points are tested fit for the job. Pre-Job Saftey Checks • Have the BOPs been adequately pressure test? • What is the maximum expected well pressure? • Can the injector snub against this pressure without buckling the coiled tubing? • Will the shear rams cut the coiled tubing against this pressure? • Is a tandem stripper/packer required? • Is an extended tool, pressure deployed system required? F-18 © Aberdeen Drilling Schools 2002 RILLIN N D G S EE CH D O R O E L B S A •

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F.5 EMERGENCY PROCEDURES

All procedures are dependent on a combination of the position of the tool string in the well bore, and the wellhead pressure.

F.5.1 Platform Shutdown

In the event of a platform shutdown the well must be made safe. To carry out this operation does not require the full crew, and only one operator should remain to function the well control equipment, as outlined below:

• Stop the Coiled Tubing • Stop pumping fluids • Close the tubing rams • Close the slip rams • Await further instructions • A decision should be made to close the shear/seal on top of the wellhead.

F.5.2 Stripper/Packer Element Leak

The Stripper/packer should be energised sufficiently with hydraulic pressure, so that it will contain any well bore fluids, but not restrict the running of the coiled tubing. Should the element start leaking and it cannot be energised to stem the leak, the following should be implemented:

• Stop the coiled tubing • Close the tubing rams • Inform the company representative • Form a remedial plan.

F.5.3 Leak Between the Top of the Tree and the Stripper/Packer

In the above situation the following should be implemented:

• Stop the coiled tubing • Inform the company representative • Depending on the severity of the leak, a decision should be taken as to closing the shear seal.

F.5.4 Tubing Pinhole Leak

The tubing develops a leak at the surface. In this situation the procedure is quite simple:

• Stop the coiled tubing. • Inform the company representative.

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• Wait for the pressure in the tubing to bleed down. • If the pressure drops and the check valves are holding. • Pull out of the hole spooling the pinhole onto the reel.

F.5.5 Tubing Ruptures

The tubing ruptures as it comes over the gooseneck and separates. Initially this can be a potentially hazardous, and serious situation. The seriousness is dependant on the tubings internal pressure, the wellhead pressure, and the type of medium within the tubing:

• Stop the coiled tubing. • Inform the company representative. • Let the pressure in the tubing bleed down. • If the pressure drops and the check valves are holding, pull rupture to deck level and splice tubing. • If it appears that the check valves are not holding, the shear seal should be closed and the well secured. • Prepare to fish coiled tubing.

F.5.6 Tubing Separates Downhole

The tubing separates downhole. In this situation the procedure becomes a little more complicated, but less hazardous if handled correctly:

• Stop the coiled tubing. • Establish approximately at what point the tubing parted. • There is a need to consider the possibility of killing the well. • Assuming the well is in a safe condition POOH slowly to a pre-determined depth. • Start closing the swab valve counting the turns to establish when the coiled tubing is above the tree. • Once the end of the tubing is above the swab shut in the well using the upper and lower master valves. • Bleed down the riser and pull the end of the tubing to surface. • Prepare to fish coiled tubing.

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G. APPENDIX - HYDRAULIC WORKOVER/SNUBBING EQUIPMENT AND HAZARDS G-1

G.1 INTRODUCTION G-1

G.2 BARRIER PRINCIPLES G-1

G.3 PRESSURE CONTROL REQUIREMENTS G-1

G.4 SNUBBING EQUIPMENT G-2

G.4.1 Stripper Bowls G-2

G.4.2 Stripper Bops G-2

G.4.3 Annular Bops G-3

G.4.4 Safety Bops G-3

G.4.5 Shear/Blind Bops G-3

G.4.6 Testing Requirements G-3

G.5 BOTTOMHOLE ASSEMBLIES G-4

G.6 IDENTIFIED SNUBBING/HWO HAZARDS G-7

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G. APPENDIX - HYDRAULIC WORKOVER/SNUBBING EQUIPMENT AND HAZARDS

G.1 INTRODUCTION

It is essential that prior to any snubbing/HWO operation the safety issues are addressed. Reference should be made to relevant sections of the appropriate Safety Manual.

At the safety meeting all aspects of the operation and detailed contingency plans should be discussed. Snubbing/HWO emergency procedures will form the basis of these contingency plans. Of particular importance are the aspects of Well Control Procedures.

Under no circumstances should safety be compromised. Procedures should be observed, work permits strictly adhered to, and equipment operated within designed parameters.

Aspects of well control must be included in the planning and equipment selection process. Snubbing operations are performed on live wells and particular emphasis must be given to the required well control competencies and equipment to be used for each individual application.

G.2 BARRIER PRINCIPLES

A combination of pressure control barriers are used in snubbing operations to provide both internal pipe and external pipe pressure control similar to coiled tubing operations addressed in Appendix F.

For external pressure control the barriers during normal operations are stripper rams, annular BOPs and BOP pipe rams. The stripper rams or annular BOPs are considered as primary barriers and the safety BOPs as secondary barriers.

Internal barriers during normal operations are double BHA check valves. The lowermost check valve is considered the primary barrier with the upper being the secondary. An advantage of snubbing over coiled tubing is that a wireline installed check valve can be run into the BHA on failure of the other check valves and is the secondary barrier.

BOP shear/seal rams are barriers on both sides and are considered tertiary barriers.

G.3 PRESSURE CONTROL REQUIREMENTS

Pressure control requirements for workover operations are covered API RP 53. These documents do not, however, address snubbing operations. The expertise within the industry is with a small group of specialised contractors, who posses the required equipment and competence. However, it is incumbent upon the asset holder (or his delegated representative) to ensure that all activities carried out on the asset (the well) are conducted in a manner to provide for complete well control.

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G.4 SNUBBING EQUIPMENT

Most of the equipment used in snubbing operations consists of ram and annular type BOPs and chokes which are already described in Appendix A.

A typical snubbing rig ups for various well pressures, pipe sizes are shown in Section 7. They effectively consist of the equipment described in the following sections.

The configuration of a snubbing stack from top to bottom is generally:

• Stripper Bowl (Optional) • Stripper Rams/Annular BOPs Used to seal around the pipe when snubbing. If using more than one pipe size there must be a set of stripper rams for each pipe size. The rams are dressed with inserts to allow stripping of the pipe. • Safety Rams Safety rams are essentially the same as stripper rams except they are used solely for safety. Safety may also be situated below the blind and shear rams. • Blind Rams Blind rams are used to seal off the open hole. They seal when the elastomers on each ram meet. They will not seal when there is pipe across them. • Shear Rams Shear rams have the ability to cut the pipe. There is no seal on this function. Extreme caution should be taken when functioning any of the rams as accidental functioning of the shear rams could potentially be very dangerous and at best causes a fishing job.

G.4.1 Stripper Bowls

Stripper bowls are pressure containment devices for use during low pressure pipe moving operations, usually below 2,000psi. At these pressures, pipe running speed and efficiency can be increased by using these devices for the primary annular seal rather than the normal blowout preventers, since the airlock cycle operations are eliminated.

G.4.2 Stripper BOPs

For upset pipe two stripper pipe rams are used to effect a seal on the outside of the pipe. These rams are operated by the unit operator from a control panel located in the basket. They are regular ram type BOPs which are opened and closed in sequence to allow the upsets to pass into the well.

The pressure trapped between the two stripper rams when the lower stripper ram is closed is bled off through a choke in the bleed off line. To open the lower stripper ram after closing the upper ram, pressure is equalised across the lower ram by the equalising loop.

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When more than one pipe size is being run, a set of stripper BOPs for each size must be included in the rig up. To repair a damage stripper ram, normally two safety pipe rams are closed on the pipe to provide two barriers (in some areas of the world this convention is not recognised).

G.4.3 Annular BOPs

Tandem annular BOPs are normally used when running non upset pipe. One of the annulars is contingency for damage to the first annular. There is a great advantage when using annulars in that there is no requirement for a bleed off or equalising line and, therefore, running speed are faster.

G.4.4 Safety BOPs

Safety BOPs are used for safety only. They are closed on the pipe to effect a seal when there is either a leak downstream or when the stripper or annular rubbers need redressing. They differ from the stripper rams in that they may be dressed primarily for sealing against the pipe rather than stripping.

G.4.5 Shear/Blind BOPs

A set of shear and blind rams are installed as a tertiary barrier. To prevent the pipe dropping after severance, additional safeties are added below the shears.

G.4.6 Testing Requirements

After the snubbing unit is installed, the integrity of the wellhead and the well control equipment must be established before operations commence. This is accomplished by a series of pressure test procedures to sequentially:

• Test the tertiary pressure control system against a closed Xmas tree valve. • Test the secondary control system against the tertiary system. • Test the primary control system against the tertiary system.

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Work Basket

Fluid Storage And Gin Processing Pole Choke System

Stationary Slips Hoses

Work Window Stripper Bowl Tool House Hanger Flange Mud Pump Fill Line Drain Line

Bleed Line Equalise Tool Box Line Ground Based BOP Control Units

Spares Choke Upper Kill Line Line Power Unit

Fuel

Figure G.1 - Typical HWO/Snubbing Layout

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G.5 BOTTOMHOLE ASSEMBLIES

The configuration of BHAs with regard to check valve and back pressure valve location and function is essential for safety at the start of running or the end of pulling a workstring:

• BPVs used must be as strong as the tubing and are located at the bottom of the string for normal operations. However they may be placed higher if using gases for foam jetting or nitrogen lifting, reducing the inventory of gas which may blow back if there is a failure in the pumping equipment lines. • When using abrasive fluids such as cement, it is advisable to install pump-out type valves in the event of plugging or flow cutting. They are also used if reverse circulating is required. • Standard* back pressure valve configurations are shown in Figure G.2. The configurations in A and C are preferred. In B it must be closely checked to ensure the wireline plug can be set in the nipple. A long end cap may hold up on the top back pressure valve and prevent the lock mandrel from setting in the nipple. The non-standard configuration in D may be too long to allow closing in the well when the nipple is at the top of the mast. When using pump-out BPVs, the configuration in E should be used but the pump-out ball for expending the BPVs must first be passed through the nipple to check clearance.

* Standard in this context means a practise which has become a “standard” within the service companies who provide snubbing/HWO services to the industry and is not an institutionalised type standard.

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E is a special configuration when having to use a pump out check valve for operational reasons. Due to the check valve being expendable by pumping down a drop ball, another check valve cannot be installed above it. For this reason, primary inside well control is only the single check valve. If expended, the secondary system is a wireline check valve installed in the nipple by wireline.

Figure G.2 - BHA Configuration

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G.6 IDENTIFIED SNUBBING/HWO HAZARDS

There are three main areas involving HWO activities where hazards are identified:

• HWO operation. • Well control. • Use of HWO auxiliary equipment.

Figure G.3 - Stripper Assembly

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APPLICATION IDENTIFIED HAZARDS CONTROL MECHANISM

A. HWO Operation 1. Power Pack Failure Pre-Emptive: Engine Failure Conduct maintenance procedures and ensure engine is fully serviced with oil and fuel. Engine out of fuel Re-active: Immediately set Heavy slips on pipe in the hole, (Snubber stationery if in the light mode) close in pipe rams on tubing. 2. Hydraulic Failure Pre-Emptive: Hydraulic hose bursting Conduct proper check on all hose connection valves and pumps. Valve seizure Function test all Hydraulically moving parts. Insufficient oil in Ensure sufficient Hydraulic oil is in the reservoir. Hydraulic Reservoir Re-active:

Make sure unit is secure prior to shutting down engine for repairs. 3. Slip Failure Pre-Emptive: Tubing Sliding Through Slips Ensure correct pressures are maintained for opening and closure of slips. Ensure slip inserts are free from grease, pipe dope and scale whilst RIH or POOH.

Re-active: Close in all slips and secure with clamp prior to changing out worn slip inserts. 4. Stripper BOP Failure Pre-Emptive: Rams closing too slow Ensure correct preventer pump pressure is maintained for the rams being used. Valves sticking whilst Ensure equalise and bleed-off valves are functioning properly opening or closing (as BOP will not open if pressure is trapped between rams).

Re-active: Close in tubing rams below stripper BOP and manually lock in. Bleed off pressure. Open rams and change out stripper inserts. Ensure valves are greased properly with correct grease.

5. Jack Movement Pre-Emptive: Slow movement of jack Ensure all jack pumps are at correct settings.

Ensure sufficient hydraulic oil is in reservoir.

Check munsen tyson valve is functioning properly. Jack jumps when moving up Ensure counter balance valves are operational and free from grit. or down Re-active: Secure tubing in well in heavy slips.

Check all settings for pumps, and that pumps are all functional.

Open travelling slips and check movement on jack without pipe. Continued

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APPLICATION IDENTIFIED HAZARDS CONTROL MECHANISM

B. HWO Well 1. BPV Failure Pre-Emptive: control Gas or liquid flowing from Ensure back pressure valves are maintained properly. top of tubing Check springs ball and seats are not worn or corroded.

Ensure tool joints are made up to correct torque and seals are OK.

Pipe dope or scale falling on top of BPVs. Tubing is rabbited and clear Re-active: of debris Tool joints are doped When running or pulling under pressure ensure TIW valves properly are used at every joint whilst making up or breaking out tubing. Renew springs and ball and seats. If necessary, drop dart plug and pump into nipple. C. Use of HWO 1. Auxiliary Equipment - Pre-Emptive: Auxiliary Gin Pole, Counterbalance Equipment Winch Tongs

Equipment Failure Ensure equipment is properly rigged up and maintained.

Check for defective or worn Follow correct rig up and running procedures. tools and equipment

Slinging lifts Follow correct lifting and slinging procedures whilst rigging up equipment.

Ensure correct hydraulic system pressures are being used.

Re-active:

At the first sign of any wear or tear, secure unit and shut down power pack, if necessary and carry out repairs. All worn guy wires and winch cables should be changed-out. (These repairs should be done immediately.)

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H. APPENDIX - EQUIPMENT SPECIFIC REQUIREMENTS H-1

H.1 FLANGED END AND OUTLET CONNECTIONS H-1

H.1.1 General - Flange Types And Uses H-1

H.1.2 Design H-1

H.1.3 Ring Gaskets H-10

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H. APPENDIX - EQUIPMENT SPECIFIC REQUIREMENTS

H.1 FLANGED END AND OUTLET CONNECTIONS

H.1.1 General - Flange Types And Uses

Three types of end and outlet flanges are controlled by this specification:

• 6B, 6BX and segmented. • 6B and 6BX flanges may be used as integral, blind or weld neck flanges.

Type 6B may also be used as threaded flanges. Some type 6BX blind flanges may also be used as test flanges. Segmented flanges are used on dual, triple, and quadruple completion wells and are integral with the equipment.

H.1.2 Design

a) Pressure Ratings and Size Ranges of Flange Types.

Type 6B, 6BX, and segmented flanges are designed for use in the combinations of nominal size ranges and rated working pressure as shown in Table H.1.

b) Type 6B Flanges.

• General. API Type 6B flanges are of the ring joint type and are not designed for make-up face- to-face. The connection make-up bolting force reacts on the metallic ring gasket. The Type 6B flanges shall be of the through-bolted or studded design.

• Dimensions (1) Standard Dimensions. Dimensions for Type 6B integral, threaded, and weld neck flanges shall conform to Table H.2, Table H.3 and Table H.4 Dimension for Type 6B blind flanges shall conform to those referenced in Table H.1 Dimensions for ring grooves shall conform to Table H.5 and Table H.6

(2) Integral Flange Exceptions. Type 6B flanges used as end connections on casing and tubing head connections may have entrance bevels, counterbores or recesses to receive casing and tubing hangers. The dimensions of such entrance bevels, counterbores, and recesses are not covered by this specification and may exceed the B dimension of Table H.2 and Table H.4(3)

(3) Threaded Flanges. Threads shall conform to the requirementsof the manual.

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c) Weld Neck Flanges.

Bore Diameter and Wall Thickness. The bore diameter JL shall not exceed the values shown in Table H.2, Table H.3 and Table H.4. The specified bore shall not result in a weld-end wall thickness less than 87.5 percent of the nominal wall thickness of the pipe to which the flange is to be attached.

Weld End Preparation. Dimensions for weld end preparation shall conform to Table H.2

Taper - When the thickness at the welding end is 3/32" or greater than that of the pipe, and the additional thickness decreases the inside diameter, the flange shall be taper bored form the weld and at a slope not exceeding 3 to 1.

NOTE: Due to smaller maximum bore dimensions, Type 6B weld neck flanges are not intended to be welded to equipment in this specification. Their purpose is to bolt to another 6B flange and provide a transition to be welded to a pipe.

• Flange Face. Flange face may be flat or raised on the ring, joint side and shall be fully machined. Flange back face may be fully machined or spot faced at the bolt holes. The flange back face or spot faces shall be parallel to the front face within one degree and the thickness after facing shall conform to the dimensions of Table H.2, Table H.3 and Table H.4 • Gaskets. Type 6B flanges shall use Type R or Type RX Gaskets in accordance with Section IH.1.3. • Corrosion Resistant Ring Grooves. Type 6B flanges may be manufactured with corrosion resistant overlays in the ring grooves. Prior to application of the overlay, preparation of the ring grooves shall conform to the appropriate dimensions. Other weld preparations may be employed where the strength of the overlay alloy equals or exceeds the strength of the base materials. • Ring Groove Surface. All 23˚ surface on ring grooves shall have a surface finish no rougher than 63 RMS.

FLANGE SIZE RANGE

RATED SEGMENTED WORKING PRESSURE Type 6B Type 6BX Dual Triple or Quadruple 1 1 3 2,000 2 /16 thru 21 /4 26 /4 - - 1 3 3 3,000 2 /16 thru 20 /4 26 /4 - - 1 5 3 1 1 3 1 1 5,000 2 /16 thru 11 13 /8 thru 211/4 1 /8 thru 4 /16 x 4 /4 11 /16 thru 4 /16 x 4 /4 3 10,000 - 11 /16 thru 211/4 - - 3 15,000 - 11 /16 thru 183/4 - - 3 20,000 - 11 /16 thru 135/8 - -

Table H.1 - Rated Working Pressure and Size Ranges of API Flanges

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Figure H.1 - Type 6B Blind Flanges

Figure H.2- Weld End Preparation for Type 6B and 6BX Weld Neck Flanges

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RING GROOVE MUST BE CONCENTRIC WITH BORE WITHIN 0.010 TOTAL INDICATOR RUNOUT

BOLT HOLE CENTRELINE LOCATED WITHIN 0.03 OF THEORETICAL BC AND EQUAL SPACING

Figure H.3 - Type 6B Flanges

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BASIC FLANGE DIMENSIONS

Nominal Max. Outside Tolerance Max. Diameter Total Basic Diameter Size & Bore Diameter Chamfer of Raised Thickness Thickness of Bore of of Flange Face of of Hub Flange Flange Flange B OD OD C K T Q X

1 2 /16 2.09 6.50 +0.06 0.12 4.25 1.31 1.00 3.31 9 2 /16 2.59 7.50 +0.06 0.12 5.00 1.44 1.12 3.94 1 3 /8 3.22 8.25 +0.06 0.12 5.75 1.56 1.25 4.62 1 4 /16 4.28 10.75 +0.06 0.12 6.88 1.81 1.50 6.00 1 7 /16 7.16 14.00 +0.12 0.25 9.50 2.19 1.88 8.75 9 9.03 16.50 +0.12 0.25 11.88 2.50 2.19 10.75 11 11.03 20.00 +0.12 0.25 14.00 2.81 2.50 13.50 5 13 /8 13.66 22.00 +0.12 0.25 16.25 2.94 2.62 15.75 3 16 /4 16.78 27.00 +0.12 0.25 20.00 3.31 3.00 19.50 1 21 /4 21.28 32.00 +0.12 0.25 25.00 3.88 3.50 24.00 BOLTING DIMENSIONS

Diameter Number Diameter Diameter Bolt Hole Length of Ring of Bolt of Bolts of Bolts of Bolt Tolerance Stud Bolt number R Circle Holes or RX

BC LSSS 5 5.00 8 /8 0.75 +0.06 4.50 23 3 5.88 8 /4 0.88 +0.06 5.00 26 3 6.62 8 /4 0.88 +0.06 5.25 31 7 8.50 8 /8 1.00 +0.06 6.00 37 11.50 12 1 1.12 +0.06 7.00 45 1 13.75 12 1 /8 1.25 +0.06 8.00 49 1 17.00 16 1 /4 1.38 +0.06 8.75 53 1 19.25 20 1 /4 1.38 +0.06 9.00 57 1 23.75 20 1 /2 1.62 +0.09 10.25 65 5 28.50 24 1 /8 1.75 +0.09 11.75 73

HIUB AND BORE DIMENSIONS

Nominal Hub Length Hub Length Hub Neck Tolerance Maximum Size and Threaded Threaded Length Diameter Bore of Bore of Line Pipe Casing Welding Welding Welding Flange Flange Flange Neck Line Neck Line Neck Pipe Pipe Flange LL LC Flange Flange LN HL HL JL

1 2 /16 1.75 - 3.19 2.38 +0.09/-0.03 2.07 9 2 /32 1.94 - 3.44 2.88 +0.09/-0.03 2.47 1 3 /8 2.12 - 3.56 3.50 +0.09/-0.03 3.07 1 4 /16 2.44 3.50 4.31 4.50 +0.09/-0.03 4.03 1 7 /16 2.94 4.50 4.94 6.63 +0.16/-0.03 5.76 9 3.31 5.00 5.56 8.63 +0.16/-0.03 7.81 11 3.69 5.25 6.31 10.75 +0.16/-0.03 9.75 5 13 /8 3.94 3.94 - - - - 3 16 /4 4.50 4.50 - - - - 1 21 /4 5.38 5.38

Table H.2- Basic Flange, Bolt and Hub and Bore Dimensions for 2000psi Rated Working Pressure

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BASIC FLANGE DIMENSIONS

Nominal Max. Outside Tolerance Max. Diameter Total Raised Diameter Size and Bore Diameter of Chamfer of Raised Thickness Thickness of Hub Bore of Flange Face of Flange of Flange Flange

B OD OD C K T Q X

1 2 /16 2.09 8.50 +0.06 0.12 4.88 1.81 1.50 4.12 9 2 /16 2.59 9.62 +0.06 0.12 5.38 1.94 1.62 4.88 1 3 /8 3.16 9.50 +0.06 0.12 6.12 1.81 1.50 5.00 1 4 /16 4.09 11.50 +0.06 0.12 7.12 2.06 1.75 6.25 1 7 /16 7.09 15.00 +0.12 0.25 9.50 2.50 2.19 9.25 9 9.03 18.50 +0.12 0.25 12.12 2.81 2.50 11.75 11 11.03 21.50 +0.12 0.25 14.25 3.06 2.75 14.50 135/8 13.66 24.00 +0.12 0.25 16.50 3.44 3.12 16.50 3 16 /4 16.78 27.75 +0.12 0.25 20.62 3.94 3.50 20.00 3 20 /4 20.78 33.75 +0.12 0.25 25.50 4.75 4.25 24.50 BOLTING DIMENSIONS Ring Diameter of Number of Diameter of Diameter of Bolt Hole Length of Stud Bolts Number R or Bolt Circle Bolts Bolts Bolt Holes Tolerance RX

BC LSSS

7 6.50 8 /8 1.00 +0.06 6.00 24 7.50 8 1 1.12 +0.06 6.50 27 7 7.50 8 /8 1.00 +0.06 6.00 31 1 9.25 8 1 /8 1.25 +0.06 7.00 37 1 12.50 12 1 /8 1.25 +0.06 8.00 45 3 15.50 12 1 /8 1.50 +0.06 9.00 49 3 18.50 16 1 /8 1.50 +0.06 9.50 53 3 21.00 20 1 /8 1.50 +0.06 10.25 57 5 24.25 20 1 /8 1.75 +0.09 11.75 66 29.50 20 2 2.12 +0.09 14.50 74

HUB AND BORE DIMENSIONS

Nominal Hub Hub Hub Hub Neck Tolerance Maximum Size and Length Length Length Length Diameter Bore of Bore of Threaded Threaded Tubing Welding Welding Welding Flange Line Pipe Casing Flange Neck Line Neck Line Neck Flange Flange Flange Pipe Flange Pipe Flange

LL LC LT LN HL HL JL

1 2 /16 2.56 - 2.56 4.31 2.38 +0.09/-0.03 1.94 9 2 /16 2.81 - 2.81 4.44 2.88 +0.09/-0.03 2.32 31/8 2.44 - 2.94 4.31 3.50 +0.09/-0.03 2.90 1 4 /16 3.06 3.50 3.50 4.81 4.50 +0.09/-0.03 3.83 1 7 /16 3.69 4.50 - 5.81 6.63 +0.16/-0.03 5.76 9 4.31 5.00 - 6.69 8.63 +0.16/-0.03 7.44 11 4.56 5.25 - 7.56 10.75 +0.16/-0.03 9.31 5 13 /8 4.94 4.94 - - - - - 3 16 /4 5.06 5.69 - - - - - 1 21 /4 6.75 6.75 - - - - -

Table H.3 - Basic Flange, Bolt and Hub and Bore Dimensions for 3,000 psi. Rated Working Pressure

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BASIC FLANGE DIMENSIONS

Nominal Maximum Outside Tolerance Maximum Diameter Total Basic Ring Size & Bore Diameter Chamfer of Raised Thickness Thickness NumberR Bore of of Flange Face of Flange of Flange or RX Flange

BOD OD C K T QX

1 2 /16 2.09 8.50 +0.06 0.12 4.88 1.81 1.50 4.12 9 2 /16 2.59 9.62 +0.06 0.12 5.38 1.94 1.62 4.88 1 3 /8 3.22 10.50 +0.06 0.12 6.62 2.19 1.88 5.25 1 4 /16 4.28 12.25 +0.06 0.12 7.62 2.44 2.12 6.38 1 7 /16 7.16 15.50 +0.12 0.25 9.75 3.62 3.25 9.00 9 9.03 19.00 +0.12 0.25 12.50 4.06 3.62 11.50 11 11.03 23.00 +0.12 0.25 14.63 4.69 4.25 14.50 5 13 /8 13.63 ------3 16 /4 16.78 ------

BOLT DIMENSIONS

Diameter Number Diameter Diameter Bolt Hole Length of Ring of Bolt of Bolts of Bolts of Bolt Tolerance Stud Number Circle Holes Bolts R or RX BC Lsss 7 6.50 8 /8 1.00 +0.06 6.00 24 7.50 8 1 1.12 +0.06 6.50 27 1 8.00 8 1 /8 1.25 +0.06 7.25 35 1 9.50 8 1 /4 1.38 +0.06 8.00 39 3 12.50 12 1 /8 1.50 +0.06 10.75 46 5 15.50 12 1 /8 1.75 +0.09 12.00 50 7 19.00 12 1 /8 2.00 +0.09 13.75 54 ------

Table H.4 - Basic Flange and Bolt Dimensions for 5,000 psi. Rated Working Pressure

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H.1.3 Ring Gaskets

General

The section covers Type R, RX, and BX ring gaskets for use in flanged connections. Types R and RX Gaskets are interchangeable on 6B flanges. Only Type BX gaskets are to be used 6BX flanges. Type RX and BX gaskets provide a pressure energised seal but are not interchangeable.

Design • Dimensions. Ring gaskets shall conform to the dimensions and tolerances specified in Figure H.6 and Figure H.7 and must be flat within 0.2% of ring outside diameter to a maximum of 0.015 inches. • R and RX Gaskets. 1. Surface Finish. All 23( surface on Type R and RX gaskets shall have a surface finish no rougher than 63 RMS. 2. RX Pressure Passage Hole. Certain size RX gaskets shall have one pressure passage hole drilled through their height as shown in Table H.6. • BX Gaskets. 1. Surface Finish. All 23( surface on Type BX gaskets shall have a surface finish no rougher than 32 RMS. 2. Pressure Passage Hole. Each BX gasket shall have one pressure passage hole drilled through its height as shown in Figure H.8 • Re-use of Gaskets. Ring gaskets have a limited amount of positive interference which assures the gasket will be joined into sealing relationship in the flange grooves, these gaskets shall not be reused.

Materials • a. PSL 0. Gasket material for PSL 0 shall conform to appropriate standards. • b. PSL 1-4. Gasket material for these levels shall conform to appropriate standards. • c. Coating and Platings. 1. General. Coatings and platings are employed to aid seal engagement while minimising galling and to extend shelf life. Coating and plating thicknesses shall be 0.0005 inch maximum. 2. Metallic. Cadmium, zinc, copper and tin coatings or platings are acceptable for service temperatures up to 250(F. 3. Non-metallic. Non-metallic coatings are acceptable if they do not interfere with the sealing of the ring gasket.

Marking

Gasket shall be marked to conform to appropriate standard.

Storing and Shipping

Gaskets shall be stored and shipped in accordance with appropriate standards.

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TOLERANCES

A (WIDTH OF RING) +/-0.008 B&H (HEIGHT OF RING) +/-0.02 C (WIDTH OF FLAT ON OCTAGONAL RING) +/-0.008 E (DEPTH OF GROOVE) +/-0.02,-0 F (WIDTH OF GROOVE) +/-0.008 P (AVERAGE PITCH DIAMETER OF RING) +/-0.007 (AVERAGE PITCH DIAMETER OF GROOVE) +/-0.005 R1 (RADIUS IN RINGS) +/-0.02 R2 (RADIUS IN GROOVE) +/- MAX 23˚ (ANGLE) +/- 1/2 DEG

Figure H.4 - Type ‘R’ Ring Gaskets

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Ring No. Pitch Width of Height of Height of Width of Radius in Depth of Width of Radius in Approx. Dia. of Ring Ring Ring Flat of Octagonal Groove Groove Groove Distance Ring & Oval Octagonal Octagonal Ring between Groove Ring made up Flanges

PABHC R1 EFR1 S

R 20 2.688 0.313 0.56 0.50 0.206 0.06 0.25 0.344 0.03 0.16 R 23 3.250 0.438 0.69 0.63 0.305 0.06 0.31 0.469 0.03 0.19 R 24 3.750 0.438 0.69 0.63 0.305 0.06 0.31 0.469 0.03 0.19 R 26 4.000 0.438 0.69 0.63 0.305 0.06 0.31 0.469 0.03 0.19 R 27 4.250 0.438 0.69 0.63 0.305 0.06 0.31 0.469 0.03 0.19 R 31 4.875 0.438 0.69 0.63 0.305 0.06 0.31 0.469 0.03 0.19 R 35 5.375 0.438 0.69 0.63 0.305 0.06 0.31 0.469 0.03 0.19 R 37 5.875 0.438 0.59 0.63 0.305 0.06 0.31 0.469 0.03 0.19 R 39 6.375 0.438 0.69 0.63 0.305 0.06 0.31 0.469 0.03 0.19 R 41 7.125 0.438 0.69 0.63 0.305 0.06 0.31 0.469 0.03 0.19 R 44 7.625 0.438 0.69 0.63 0.305 0.06 0.31 0.469 0.03 0.19 R 45 8.313 0.438 0.69 0.63 0.305 0.06 0.31 0.469 0.03 0.19 R 46 8.313 0.500 0.75 0.69 0.341 0.06 0.38 0.521 0.06 0.13 R 47 9.000 0.750 1.00 0.94 0.485 0.06 0.50 0.781 0.06 0.16 R 49 10.625 0.438 0.69 0.63 0.305 0.09 0.31 0.469 0.03 0.19 R 50 10.625 0.625 0.88 0.81 0.413 0.06 0.44 0.656 0.06 0.16 R 53 12.750 0.438 0.69 0.63 0.305 0.06 0.31 0.469 0.03 0.19 R 54 12.750 0.625 0.88 0.81 0.413 0.06 0.44 0.656 0.06 0.16 R 57 15.000 0.438 0.69 0.63 0.305 0.06 0.31 0.469 0.03 0.19 R 63 16.500 1.000 1.31 1.25 0.681 0.06 0.62 1.063 0.09 0.22 R 65 18.500 0.438 0.69 0.63 0.305 0.06 0.31 0.469 0.03 0.19 R 66 18.500 0.625 0.88 0.81 0.413 0.06 0.44 0.656 0.06 0.16 R 69 21.000 0.438 0.69 0.63 0.305 0.06 0.31 0.469 0.03 0.19 R 70 21.000 0.750 1.00 0.94 0.485 0.06 0.50 0.781 0.06 0.19 R 73 23.000 0.500 0.75 0.69 0.341 0.06 0.38 0.531 0.06 0.13 R 74 23.000 0.750 1.00 0.94 0.485 0.06 0.50 0.781 0.06 0.19 R 82 2.250 0.438 - 0.63 0.305 0.06 0.31 0.469 0.03 0.19 R 84 2.500 0.438 - 0.63 0.305 0.06 0.31 0.469 0.03 0.19 R 85 3.125 0.500 - 0.69 0.341 0.06 0.38 0.531 0.06 0.13 R 86 3.563 0.625 - 0.81 0.413 0.06 0.44 0.656 0.06 0.16 R 87 3.938 0.625 - 0.81 0.413 0.06 0.44 0.656 0.06 0.16 R 88 4.875 0.750 - 0.94 0.485 0.06 0.50 0.781 0.06 0.19 R 89 4.500 0.750 - 0.94 0.485 0.06 0.50 0.781 0.06 0.19 R 90 6.125 0.875 - 1.06 0.583 0.06 0.56 0.906 0.06 0.19 R 91 10.25 01.250 - 1.50 0.879 0.09 0.69 1.313 0.09 0.16 R 99 9.250 0.438 - 0.63 0.305 0.06 0.31 0.469 0.03 0.19

Table H.5 - Type ‘R’ Ring Gasket

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A (WIDTH OF RING) +/-0.008 C (WIDTH OF FLAT) +/-0.006 - 0.000 E (DEPTH OF GROOVE) +/-0.02,-0 F (WIDTH OF GROOVE) +/-0.008 H˚ (HEIGHT OF RING) +/-0.008 - 0.000 R1 (RADIUS IN RINGS) +/-0.02 R2 (RADIUS IN GROOVE) +/- MAX 23˚ (ANGLE) +/- 1/2 DEG

* A PLUS TOLERANCE OF 0.008 INS FOR WIDTH A AND HEIGHT H IS PERMITTED PROVIDED THE VARIATION IN WIDTH OR HEIGHT OF ANY RING DOES NOT EXCEED 0.004 INS THROUGHOUT ITS ENTIRE CIRCUMFERENCE

Figure H.5 - API Type RX Pressure Energised Ring Gaskets

NOTE: The pressure passage hole illustrated in the RX Ring cross section in rings RX-82 through RX-91 only. Centreline of hole shall be located at mid point of dimension C. Hole diameter shall be 0.06 inches for rings RX-82 through RX-85, 0.9 inches for rings RX-86 and RX- 87, and 0.12 inches for rings RX-88 through RX-91.

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W R E T L N L E C C O G N IN TROL TRAIN

Ring Pitch Outside Width of Width of Height of Height Radius Depth of Width of Radius Approx. No. Dia. of Dia. of Ring Flat Outside of Ring in Ring Groove Groove in Distance Ring & Ring Bevel Groove between Groove made up Flanges P O D A C D H R E F R S RX 20 2.688 3.000 0.344 0.182 0.125 0.750 0.06 0.25 0.344 0.03 0.38 RX 23 3.250 3.672 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 24 3.750 4.172 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 25 - 4.313 0.344 0.182 0.125 0.750 0.06 0.25 0.344 0.03 - RX 26 4.000 4.406 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 27 4.250 4.656 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 31 4.875 5.297 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 35 5.875 5.797 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 37 5.875 6.297 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 39 6.375 6.797 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 41 7.125 7.547 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 44 7.625 8.047 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 45 8.313 8.734 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 46 8.313 8.750 0.531 0.263 0.188 1.125 0.06 0.38 0.531 0.06 0.47 RX 47 9.000 9.656 0.781 0.407 0.271 1.625 0.09 0.50 0.781 0.06 0.91 RX 49 10.625 11.047 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 50 10.625 11.156 0.656 0.335 0.208 1.250 0.06 0.44 0.656 0.06 0.47 RX 53 12.750 13.172 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 54 12.750 13.281 0.656 0.335 0.208 1.250 0.06 0.44 0.656 0.06 0.47 RX 57 15.000 15.422 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 63 16.500 17.391 1.063 0.582 0.333 2.000 0.09 0.63 1.063 0.09 0.84 RX 65 18.500 18.922 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 66 18.500 19.031 0.656 0.335 0.208 1.250 0.06 0.44 0.656 0.06 0.47 RX 69 21.000 21.422 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 70 21.000 21.656 0.781 0.407 0.271 1.625 0.09 0.50 0.781 0.06 0.72 RX 73 23.000 23.469 0.531 0.263 0.208 1.250 0.06 0.38 0.531 0.06 0.59 RX 74 23.000 23.656 0.781 0.407 0.271 1.625 0.09 0.50 0.781 0.06 0.72 RX 82 2.250 2.672 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 84 2.500 2.922 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 85 3.125 3.547 0.531 0.263 0.167 1.000 0.06 0.38 0.531 0.06 0.38 RX 86 3.563 4.078 0.594 0.335 0.188 1.125 0.06 0.44 0.656 0.06 0.38 RX 87 3.938 4.453 0.594 0.335 0.188 1.125 0.06 0.44 0.656 0.06 0.38 RX 88 4.875 5.484 0.688 0.407 0.208 1.250 0.06 0.50 0.781 0.06 0.38 RX 89 4.500 5.109 0.719 0.407 0.208 1.250 0.06 0.50 0.781 0.06 0.38 RX 90 6.125 6.875 0.781 0.479 0.292 1.750 0.09 0.56 0.906 0.06 0.72 RX 91 10.250 11.297 1.388 0.780 0.297 1.781 0.09 0.69 1.313 0.09 0.75 RX 99 9.250 9.672 0.469 0.254 0.167 1.000 0.06 0.31 0.469 0.03 0.47 RX 201 - 2.026 0.226 0.126 0.057 0.445 0.02** 0.16 0.219 0.03 - RX 205 - 2.453 0.219 0.120 0.072* 0.437 0.02** 0.16 0.219 0.02 - RX 210 - 3.844 0.375 0.213 0.125* 0.750 0.03** 0.25 0.375 0.03 - RX 215 - 5.547 0.469 0.210 0.167* 1.000 0.06** 0.31 0.469 0.03 - * Tolerance on these dimensions is +0 -0.015 ** Tolerance on these dimensions is +0.02 -0

Table H.6 - API Type ‘RX’ Pressure Energised Ring Gaskets

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A (WIDTH OF RING) +/-0.008 C (WIDTH OF FLAT) +/-0.06-0.000 D (DEPTH SIZE) NONE E (DEPTH OF GROOVE) +/-0.02,-0 F (WIDTH OF GROOVE) +/-0.008 G (OD OF GROOVE) +/-0.004 - 0. H˚ (HEIGHT OF RING) +/-0.008-0.00 R1 (RADIUS IN RINGS) +/-0.02 R2 (RADIUS IN GROOVE) SEE NOTE 23˚ (ANGLE) +/- 1/4 DEG

* A PLUS TOLERANCE OF 0.008 INS FOR WIDTH A AND HEIGHT H IS PERMITTED PROVIDED THE VARIATION IN WIDTH OR HEIGHT OF ANY RING DOES NOT EXCEED 0.004 INS THROUGHOUT ITS ENTIRE CIRCUMFERENCE

Figure H.6 - API Type BX Pressure Energised Ring Gaskets

NOTE: Radius ‘R’ shall be 8-12% of the gasket height ‘H’.

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W R E T L N L E C C O G N IN TROL TRAIN

0.450 0.466 0.498 0.554 0.606 0.698 0.921 1.039 1.149 1.279 0.786 0.930 0.750 1.006 1.290 1.071 1.373 0.902 1.018 0.666 0.705 0.705 0.705

Groove

Width of

2.893 3.062 3.395 4.046 4.685 5.930 9.521 11.774 14.064 17.033 16.063 19.604 18.832 22.185 22.752 24.904 25.507 30.249 30.48 16.955 8.696 10.641 13.225

Dia. of

Groove

Outside

0.22 0.22 0.23 0.27 0.30 0.44 0.33 0.50 0.56 0.62 0.67 0.56 0.33 0.72 0.72 0.75 0.75 0.84 0.84 0.38 0.33 0.33 0.33

Groove

Depth of

0.06 0.06 0.06 0.06 0.06 0.06 0.12 0.12 0.12 0.12 0.12 0.12 0.06 0.12 0.12 0.12 0.12 0.06 0.06 0.06 0.06 0.06 0.06

Hole Size

Flat

0.314 0.325 0.346 0.385 0.419 0.481 0.629 0.709 0.782 0.869 0.408 0.482 0.481 0.516 0.800 0.550 0.851 0.316 0.432 0.421 0.481 0.481 0.481

Width of

ODT

2.790 2.954 3.277 3.910 4.531 5.746 9.263 11.476 13.731 16.657 15.717 19.191 18.641 21.728 22.295 24.417 25.020 29.896 29.928 6.743 8.505 10.450 13.034

Dia of Flat

Ring

0.366 0.379 0.403 0.448 0.448 0.560 0.733 0.826 0.911 1.012 0.541 0.638 0.560 0.684 0.968 0.728 1.029 0.516 0.632 0.509 0.560 0.560 0.560

ype ‘BX’ Pressure Energisedype ‘BX’ Pressure Ring Gaskets

Width of

Ring

0.366 0.379 0.403 0.448 0.448 0.560 0.733 0.826 0.911 1.012 0.938 1.105 0.560 1.185 1.185 1.261 1.261 1.412 1.412 0.624 0.560 0.560 0.560

Height of

Table H.7 - API T Table

Ring

2.842 3.008 3.334 3.974 4.600 5.825 9.367 11.593 13.860 16.800 15.850 19.347 18.720 21.896 22.463 24.595 25.198 29.696 30.198 6.831 8.584 10.529 13.113

Dia. of

Outside

8 8 8 8 4

4 4 4 4

/ / / / /

/ / / /

/16

16 16 16

16 16

5 5 5

5 3 3 1

1 3 3

/ / / / /

1 9 1 1 1

Size

1 11 2 2 3 4 7 9 11 13

13 16 16 18 18 21 21 26 26 5 9 11 13

BX 150 BX 151 BX 152 BX 153 BX 154 BX 155 BX 156 BX 157 BX 158 BX 159 BX 160 BX 161 BX 162 BX 163 BX 164 BX 165 BX 166 BX 167 BX 168 BX 169 BX 170 BX 171 BX 172

Ring No. Nominal

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I. APPENDIX - HYDRATE FORMATION & PREVENTION I-1

I.1 FORMATION OF HYDRATES I-1

I.2 HYDRATE PREDICTION I-2

I.3 HYDRATE PREVENTION I-4

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I. APPENDIX - HYDRATE FORMATION & PREVENTION

I.1 FORMATION OF HYDRATES

Hydrates will only form if there is free water present in a system.

Hydrates are crystalline water structures filled with small molecules. In oil / gas systems they will occur when light hydrocarbons (or carbon dioxide) are mixed with water at the correct temperature and pressure conditions. A very open, cage-like structure of water molecules is the backbone of hydrates. This structure which bears some resemblance to a steel lattice in a building can theoretically be formed in ice, liquid water, and water vapour. In practice however, hydrates are only formed in the presence of liquid water. The crystal framework is very weak and collapses soon if not supported by molecules filling the cavities in the structures. Methane, Ethane, CO2 and H2S are the most suitable molecules to fill cavities. Propane and Isobutane can only fill the larger cavities. Normal butane and heavier Hydrocarbons are too big and tend to inhibit hydrate formation. Tests indicate that Hydrate formation is comparable with normal crystallisation. ‘Undercooling’ is possible, but the slightest movement within and undercooled mixture, or the presence of a few crystallisation nuclei will cause a massive reaction. Once the crystallisation has started, hydrates may block a flowline completely within seconds. The formation of hydrates is governed by the crude composition, water composition, temperature and pressure. In most cases the crude composition cannot be changed. Hydrates can be dissolved / prevented by a temperature increase or a pressure decrease. A chemical hydrate inhibition can be performed by changing the composition of the water. Under the correct conditions of temperature and pressure, hydrates will form spontaneously. At high pressures, hydrates may form at relatively high temperatures; e.g. at 2900 psi they can begin to form at about 77˚ F . Hydrates do not require a pressure drop to form. However, the refrigeration effect from a small pressure drop, such as a stuffing box leak, may be sufficient to produce optimum pressure and temperature conditions for hydrate formation. Hydrates can form under flowing or static conditions. The first indication of them forming in the tubing or annular flow string is a drop in flowing wellhead pressure followed by an initially slow then progressively rapid drop in wellhead flowing temperature. During well operations, the greatest danger posed by hydrates is the plugging of the tubing string downhole. The biggest risk area for this occurring is on offshore installations from the seabed upwards where temperatures are generally the lowest. A hydrate plug in the tubing string under flowing or static conditions results in; being unable to run or pull wireline tools, unable to squeeze or circulate the well dead, and unable to flow the well to remove the hydrates. Also, hydrates may prevent vital equipment, such as the Downhole Safety Valve from functioning correctly. Thus a downhole hydrate plug gives rise to a potentially dangerous situation and must be avoided at all costs. It is also hazardous when it forms in surface pressure control equipment preventing operation of valves, etc or plugging lubricators or risers. The latter may fool an operator into believing that the pressure has been bled off when may be trapped behind the plug.

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I.2 HYDRATE PREDICTION

Hydrate pressure / temperature formation conditions can be predicted for natural gas (Figure I.1). Hydrate prevention is normally accomplished by the injection of methanol or glycol downhole or at the Xmas Tree. The quantity of glycol or methanol required to suppress hydrates depends on pressure, temperature, water cut and flowrate. For the prevention of hydrates caused by the introduction of water whilst pressure testing for wireline entry, 60% glycol will have to be added to the water for use as a hydrate suppresser (See Table I.1, on freezing points of water/glycol mixes).

Glycol / Water Freezing Point SG (% v/v) (deg C)

100/0 -7 1.115 90/10 -28 1.109 80/20 -43 1.101 70/30 -60 1.091 60/40 -60 1.079 50/50 -44 1.068

Table I.1 - Freezing Points Of Mono-Ethylene Glycol/Water Mixes

After the glycol/water has been thoroughly mixed, no separation of the solution will occur. The glycol/water solution can therefore be left in the pump unit for the duration of the programme without the solution deteriorating. Mono-ethylene glycol may be mixed with fresh water or sea water without any adverse effect, although sea water id preferred as it in itself is less likely to cause a hydrate than fresh water.

NOTE: Incorrect mixes will significantly reduce the level of protection. Although methanol is a more effective hydrate inhibitor than Glycol, it is not, however a first choice for injection at the wireline lubricator or flowhead during well operations as it dissolves sealing greases and may cause loss of seal in grease head. Also injecting glycol without any form of atomisation may result in the glycol adhering to the wall of the tubing/lubricator, and will not effectively absorb free water being lifted through gas by the wireline.

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TEMPERATURE AT WHICH GAS HYDRATES WILL FREEZE

( From KAZT )

The purpose of this chart is to determine the temperature below which hydrates will form when sufficient liquid water is present.

4000

3000

2000

1000 900 800 700 600 METHANE

500

400

300

0.6 GRAV

200 0.7

0.8

PRESSURE FOR HYDRATE FORMATION PSIA FORMATION PRESSURE FOR HYDRATE 0.9

100 1.0 90 80 70 60

35 40 45 50 55 60 65 70 75 80 85

TEMPERATURE ûF

Example : with 0.7 specific gravity gas at 1000 psia, hydrates may be expected at 64˚F at 200 psia. This would be 44˚F.

Figure I.1 - Temperatures at Which Gas Hydrates Will Freeze

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I.3 HYDRATE PREVENTION

Present techniques for prevention of hydrates are mainly geared to a live well with a gas cap in the tubing. This allows methanol introduced at the Xmas Tree to gravitate down to the hydrate level, and therefore act directly on top of a hydrate, should it occur. Consideration must be given to a perforated well which has not yet been “cleaned up” as gas will migrate throughout the tubing during the completion of perforation activities. To minimise the risk of hydrate formation in the well bore and surface equipment, the following action points must be taken:-

• 1. The fluids used for well operations should be incapable of supporting a hydrate. For example, water free base oil, diesel or water glycol mixes may be selected. • 2. Prior to opening a well flow, methanol injection must be started at maximum rate and continued until the flowline temperature is high enough to prevent hydrate formation at that FTHP (see Fig I.2) • 3. Use only a 60/40 mono-ethylene/sea water mix when pressure testing • 4. Inject glycol at the grease injection head during wireline operations. Continually inject methanol at the Xmas Tree during all well operations.

Curing Hydrates

The main guidance for removal of a hydrate plug is to reduce the pressure or increase the temperature, or use methanol, or any combination of these.

WARNING:- IT IS HAZARDOUS TO BLEED DOWN PRESSURE ON ONLY ONE SIDE OF A HYDRATE PLUG IN ANY PIPEWORK.

NOTE:- The risk is that if pressure is bled down from one side of a hydrate it will begin to dissolve. As it dissolves, differential pressure can act upon one side of the plug and may cause it to be dislodged at considerable velocity. Bleeding down can be effective in dissolving a hydrate, but it is not recommended as a routine practice. However, once a full column of fluid (preferably methanol) has been established above the hydrate plug then bleeding down the pressure above to destroy the hydrate can be considered. The full column of liquid will act as a cushion and prevent the dissolved plug achieving high velocities caused by the differential pressure across it.

Curing a hydrate problem in particular sections of the system has been accomplished by the following measures:-

(1) Plug in at the surface:- Close in the well and depressurise the line, or apply steam or hot water externally. (2) Hydrate at the stuffing box during wireline operations:- Close BOP’s and bleed down the lubricator (3) Hydrate in the tubing:- Continue injecting methanol at maximum rate taking note of the THP at all times as this could begin to rise with the fluid injection.

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If during injection of methanol no increase in THP is observed (this will indicate that the tubing is not completely blocked) then begin to bleed down the tubing taking careful note of the volume and type of returns. If during injection of methanol an increase in THP is observed (this will indicate that the tubing is blocked) then only bleed down the THP to point below bubble point so as to create a gas cap above the hydrate. Methanol injected will then stand a better chance of reaching the hydrate.

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J. SURFACE BOP AND CONTROL SYSTEMS J-1

J.A CLOSING UNITS - SURFACE INSTALLATIONS J-7

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J.0 SURFACE BOP AND CONTROL SYSTEMS

Figure J.0.1 Land Rig Operation

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TYPICAL SURFACE BOP CONTROL SYSTEM T-SERIES

Figure J.0.2

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TYPICAL SURFACE BOP 17. Electric Pressure Switch - of the annular operating CONTROL SYSTEM Automatically stops pumps pressure. Adjustable from 0 to when accumulator pressure 1500 PSI. TR Regulator can 1. Accumulators - Precharge per reaches 3000 PSI and starts provide regulation up to 3000 label. Warning! USE pumps when pressure drops to PSI for Cameron Type D NITROGEN ONLY-DO NOT 2700 PSI nominal. annulars and contains a manual USE OXYGEN! Check every 30 override to prevent loss of days. 18. Electric Motor Starter - Keep operating pressure should starter switch in “Auto” position remote control pilot pressure be 2. Accumulator Bank Isolation except when servicing. TURN lost. Valve -Manually operated, OFF power at main panel when normally open. servicing. 31. Annular Pressure Gauge - 0 to 3000 PSI. (0-6000 PSI for 3. Accumulator Bank Bleed 19. Suction Valve, Triplex or Cameron D Annulars.) Valve - Normally closed. Duplex pump. Normally open. Close when servicing pump. 32. Annular Pressure 4. Accumulator Relief Valve - Transmitter - Hydraulic input, Set at 3300 PSI. 20. Suction Strainer, Triplex or 3-15 PSI air output. Duplex pump - Clean every 30 5. Air Filter - Automatic Drain. days. 33. Accumulator Pressure Clean every 30 days. Transmitter - 0 to 6000 PSI 21. Discharge Check Valve, hydraulic input, 315 PSI air 6. Air Lubricator -Fill with SAE Duplex or Triplex Pump. output. 10 lubricating oil, set for 6 drops per minute. Check oil level 22. High Pressure Strainer - 34. Manifold Pressure weekly. Clean every 30 days. Transmitter - 0 to 10,000 PSI hydraulic input,3- 15 PSI air 7. Air Pressure - Gauge - 0 to 23. Shut Off Valve - Normally output. (Transmitter converts 300PSI. close. Connection for separate hydraulic pressure to air operating fluid pump. pressure and sends a calibrated 8. Hydro-pneumatic Pressure signal to corresponding air Switch -Automatically stops air 24. Manifold Regulator - receiver gauges on the Driller’s operated pumps when pressure Regulates operating pressure to air operated remote control reaches 2900 PSI and starts ram preventers and gate valves. panel.) pumps when pressure drops Manually adjustable from 0 to approximately 400 PSI. 1500 PSI, TR™ Regulator 35. Air Junction Box - Used for contains internal by-pass for connecting the air cable from the 9. Air Supply Valves -Normally pressures up to 3000 PSI or 5000 air operated remote control open. Close when servicing air PSI. (See 39 option) panels. operated pumps. 25. Manifold Regulator Internal 36. Reservoir - Stores operating 10. Suction Valve, Air Operated Override Valve - Normally in fluid at atmospheric pressure. Pumps -Normally open. Close low-pressure (handle left) Fill to within 8 inches from top when servicing pumps. position. For operating pressures with Welkic™ 10 or SAE 10 oil. above l 500 PSI (ram preventers 11. Suction Strainer, Air and gate valves), move to high 37. Clean out man-way (T-Series Operated Pumps - clean every pressure position (handle right). units). 30 days. 26. 5,000 PSI W.P. Sub-Plate 38. Sight glass, fluid level 12. Air Operated Pump. Mounted Four-way Control (T-Series units). Valve - Direct the flow of 13. Discharge Check Valve, Air operating fluid pressure to the Option- Available on units with Operated Pump. preventers and gate valves. 5000 PSI working pressure NEVER leave in the centre manifold valves and piping. 14. Duplex or Triplex Pump - position. Fill crankcase with SAE 20 oil for 39. By-pass Valve - 40F to 115F ambient temperature 27. Manifold Bleeder Valve. Hydro-pneumatic pressure range. Check oil level monthly. switch. 28. Accumulator Pressure 15. Chain guard - Fill with SAE Gauge - 0 to 6000 PSI. 40. Normal Pressure Isolation 40 oil for operation above 20F Valve -Normally open. Close for ambient temperature. Check oil 29. Manifold Pressure Gauge - 0 pressure above 3000 PSI. This level monthly. to 10,000 PSI. feature can be used for shearing.

16. Explosion-Proof Electric 30. Annular Regulator - 41. Manifold Protector Relief Motor. Provides independent regulation Valve - Set at 5500 PSI.

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SYSTEM DESCRIPTION

GENERAL

A Blowout Preventer (BOP) Control System is a high pressure hydraulic power unit fitted with directional control valves to safely control kicks and prevent blowouts during drilling operations. A typical system offers a wide variety of equipment to meet the customer’s specific operational and economic criteria. The following text gives a brief description of the equipment and some of its major components.

Figure J.0.3 ACCUMULATOR UNIT MODULE

The primary function of the accumulator unit module is to provide the atmospheric fluid supply for the pumps and storage of the high pressure operating fluid for control of the BOP stack. It includes accumulators, reservoir, accumulator piping and a master skid for mounting of the air operated pumps, electric motor driven pumps and the hydraulic control manifold.

Accumulators

Accumulators are ASME coded pressure vessels for storage of high pressure fluid. These accumulators are available in a variety of sizes, types, capacities and pressure ratings. The two (2) basic types are bladder and float which are available in cylindrical or ball styles. The accumulators can either be bottom or top loading. Top loading means the bladder or float can be removed from the top while it is still mounted on the accumulator unit. Bottom loading accumulators must be removed from the accumulator unit to be serviced. Bladder and buoyant float type accumulators can be repaired in the field without destroying their stamp of approval.

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Reservoir

A rectangular reservoir is provided for storage of the atmospheric fluid supply for the high pressure pumps. It contains baffles, fill and drain ports and troubleshooting inspection ports. For filling and cleaning procedures see the Maintenance section. It should be able to store 2 times the capacity of the usable fluid capacity.

Accumulator Piping

This piping connects the high pressure discharge lines of the pumps to the accumulators and the hydraulic manifold. It is comprised of 1 or 1-1/2" Schedule 80 or 160 pipe, isolator valves and a 3300 psi relief valve to protect the accumulators from being over pressured. Cylindrical type accumulators are mounted on machined headers to minimise line restrictions and leaks.

AIR PUMP ASSEMBLY

The air pump assembly consists of one (1) or more air operated hydraulic pumps connected in parallel to the accumulator piping to provide a source of high pressure operating fluid for the BOP Control System. These pumps are available in a variety of sizes and ratios.

Figure J.0.4

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ELECTRIC PUMP ASSEMBLY

The electric pump assembly consists of a duplex or triplex reciprocating plunger type pump driven by an explosion-proof electric motor. It is connected to the accumulator piping to provide a source of high pressure operating fluid for the BOP Control System. It is available in a variety of horsepower and voltage ranges.

Figure J.0.5

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SECTION J.A CLOSING UNITS—SURFACE INSTALLATIONS

ACCUMULATOR REQUIREMENTS

General

J.A.1 Accumulator bottles are containers which store hydraulic fluid under pressure for use in effecting blowout preventer closure. Through use of compressed nitrogen gas, these containers store energy which can be used to effect rapid preventer closure. There are two types of accumulator bottles in common usage, separator and float types. The separator type uses a flexible diaphragm to effect positive separation of the nitrogen gas from the hydraulic fluid. The float type utilises a floating piston to effect separation of the nitrogen gas from the hydraulic fluid.

Volumetric Capacity

J.A.2 As a minimum requirement, all blowout preventer closing units should be equipped with accumulator bottles with sufficient volumetric capacity to provide the usable fluid volume (with pumps inoperative) to close one pipe ram and the annular preventer in the stack plus the volume to open the hydraulic choke line valve.

J.A.3 Usable fluid volume is defined as the volume of fluid recoverable from an accumulator between the accumulator operating pressure and 200 psi above the precharge pressure. The accumulator operating pressure is the pressure to which accumulators are charged with hydraulic fluid.

J.A.4 The minimum recommended accumulator volume (nitrogen plus fluid) should be determined by multiplying the accumulator size factor (refer to Table J-A) times the calculated volume to close the annular preventer and one pipe ram plus the volume to open the hydraulic choke line valve.

TABLE J. A

Minimum Accumulator Recommended Usable Fluid Accumulator Operating Precharge Volume* Size Pressure Pressure (fraction of Factor* psi psi bottle size)

1500 750 1/ 8 8 2000 1000 1/ 3 3 3000 1000 1/ 2 2 Notes: *Based on minimum discharge pressure of 1200 psi.

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Response Time

J.A.5 The closing system should be capable of closing each ram preventer within 30 seconds. Closing time should not exceed 30 seconds for annular preventers smaller than 18 3/4 inches and 45 seconds for annular preventers 18 3/4 inches and larger.

Operating Pressure and Precharge Requirements for Accumulators

J.A.6 No accumulator bottle should be operated at a pressure greater than its rated working pressure.

J.A.7. The precharge pressure on each accumulator bottle should be measured during the initial closing unit installation on each well and adjusted if necessary (refer to Para. J.A.4). Only nitrogen gas should be used for accumulator precharge. The precharge pressure should be checked frequently during well drilling operations.

Requirements for Accumulator Valves, Fittings, and Pressure Gauges

J.A.8 Multi-bottle accumulator banks should have valving for bank isolation. An isolation valve should have a rated working pressure at least equivalent to the designed working pressure of the system to which it is attached and must be in the open position except when accumulators are isolated for servicing, testing, or transporting (refer to Fig. J.A.1). Accumulator bottles may be installed in banks of approximately 160 gallons capacity if desired, but with a minimum of two banks.

J.A.9 The necessary valves and fittings should be provided on each accumulator bank to allow a pressure gauge to be readily attached without having to remove all accumulator banks from service. An accurate pressure gauge for measuring the accumulator precharge pressure should be readily available for installation at any time.

CLOSING UNIT PUMP REQUIREMENTS

Pump Capacity Requirements

J.A.10 Each closing unit should be equipped with sufficient number and sizes of pumps to satisfactorily perform the operation described in this paragraph. With the accumulator system removed from service. The pumps should be capable of closing the annular preventer on the size drill pipe being used, plus opening the hydraulically operated choke line valve and obtain a minimum of 200 psi pressure above accumulator precharge pressure on the closing unit manifold within two (2) minutes or less.

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Pump Pressure Rating Requirements

J.A.11 Each closing unit must be equipped with pumps that will provide a discharge pressure equivalent to the rated working pressure of the closing unit.

Pump Power Requirements

J.A.l2 Power for closing unit pumps must be available to the accumulator unit at all times, such that the pump will automatically start when the closing unit manifold pressure has decreased to less than 90 percent of the accumulator operating pressure.

J.A.13 Two or three independent sources of power should be available on each closing unit. Each independent source should be capable of operating the pumps at a rate that will satisfy the requirement described in Para. J.A.10. The dual source power system recommended is an air system plus an electrical system. Minimum recommendations for the dual air system and other acceptable but less preferred dual power source systems are as follows:

a. A dual air/electrical system may consist of the rig air system (provided at least one air compressor is driven independent of the rig compound) plus the rig generator (refer to Fig. J.A.2).

b. A dual air system may consist of the rig air system (provided at least one air compressor is driven independent of the rig compound) plus an air storage tank that is separated from both the rig air compressors and the rig air storage tank by check valves. The minimum acceptable requirements for the separate air storage tank are volume and pressure which will permit use of only the air tank to operate the pumps at a rate that will satisfy the operation described in the pump capacity requirements (refer to Para. J.A.10).

c. A dual electrical system may consist of the normal rig generating system and a separate generator (refer to Fig. J.A.3).

d. A dual air/nitrogen system may consist of the rig air system plus bottled nitrogen gas (refer to Fig.J.A.4).

e. A dual electrical/nitrogen system may consist of the rig generating system and bottled nitrogen gas (refer to Fig. J.A.5).

J.A.14 On shallow wells where the casing being drilled through is set at 500 feet or less and where surface pressures less than 200 psi are expected, a backup source of power for the closing unit is not essential.

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REQUIREMENTS FOR CLOSING UNIT VALVES FITTINGS, LINES, AND MANIFOLD

Required Pressure Rating

J.A.15 All valves and fittings between the closing unit and the blowout preventer stack should be of steel construction with a rated working pressure at least equal to the working pressure rating of the stack up to 3000 psi. Refer to API Spec 6A: Specification for Wellhead Equipment* for test pressure requirements. All lines between the closing unit and blowout preventer should be of steel construction or an equivalent flexible, fire-resistant hose and end connections with a rated working pressure equal to the stack pressure rating up to 3000 psi.

Valves Fittings and other Components Required

J.A.16 Each installation should be equipped with the following:

a. Each closing unit manifold should be equipped with a full-opening valve into which a separate operating fluid pump can be easily connected (refer to Fig. J.A.1).

b. Each closing unit should be equipped with sufficient check valves or shut-off valves to separate both the closing unit pumps and the accumulators from the closing unit manifold and to isolate the annular preventer regulator from the closing unit manifold.

c. Each closing unit should be equipped with accurate pressure gauges to indicate the operating pressure of the closing unit manifold, both upstream and downstream of the annular preventer pressure regulating valve.

d. Each closing unit should be equipped with a pressure regulating valve to permit manual control of the annular preventer operating pressure.

e. Each closing unit equipped with a regulating valve to control the operating pressure on the ram type preventers should be equipped with a bypass line and valve to allow full accumulator pressure to be placed on the closing unit manifold, if desired.

f. Closing unit control valves must be clearly marked to indicate (1) which preventer or choke line valve each control valve operates, and (2) the position of the valves (i.e., open, closed, neutral). Each blowout preventer control valve should be turned to the open position (not the neutral position) during drilling operations. The choke line hydraulic valve should be turned to the closed position during normal operations. The control valve that operates the blind rams should be equipped with a cover over the manual handle to avoid unintentional operation.

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g. Each annular preventer may be equipped with a full-opening plug valve on both the closing and opening lines. These valves should be installed immediately adjacent to the preventer and should be in the open position at all times except when testing the operating lines. This will permit testing of operating lines in excess of 1500 psi without damage to the annular preventer if desired by the user.

*Available from American Petroleum Institute. Production Department, 2535 One Main Place Dallas TX 75202-3904.

REQUIREMENTS FOR CLOSING UNIT FLUIDS AND CAPACITY

J.A.17 A suitable hydraulic fluid (hydraulic oil or fresh water containing a lubricant) should be used as the closing unit control operating fluid. Sufficient volume of glycol must be added to any closing unit fluid containing water if ambient temperatures below 32 F are anticipated. The use of diesel oil, kerosene, motor oil, chain oil. or any other similar fluid is not recommended due to the possibility of resilient seal damage.

J.A.18 Each closing unit should have a fluid reservoir with a capacity equal to at least twice the usable fluid capacity of the accumulator system.

CLOSING UNIT LOCATION AND REMOTE CONTROL REQUIREMENTS

J.A.19 The main pump accumulator unit should be located in a safe place which is easily accessible to rig personnel in an emergency. It should also be located to prevent excessive drainage or flow back from the operating lines to the reservoir. Should the main pump accumulator be located a substantial distance below the preventer stack, additional accumulator volume should be added to compensate for flow back in the closing lines.

J.A.20 Each installation should be equipped with a sufficient number of control panels such that the operation of each blowout preventer and control valve can be controlled from a position readily accessible to the driller and also from an accessible point at a safe distance from the rig floor.

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CLOSING UNIT PUMP CAPABILITY TEST

J.A.21 Prior to conducting any tests, the closing unit reservoir should be inspected to be sure it does not contain any drilling fluid, foreign fluid, rocks, or other debris. The closing unit pump capability test should be conducted on each well before pressure testing the blowout preventer stack. This test can be conveniently scheduled either immediately before or after the accumulator closing time test. Test should be conducted according to the following procedure:

a. Position a joint of drill pipe in the blowout preventer stack.

b. Isolate the accumulators from the closing unit manifold by closing the required valves.

c. If the accumulator pumps are powered by air, isolate the rig air system from the pumps. A separate closing unit air storage tank or a bank of nitrogen bottles should be used to power the pumps during this test. When a dual power source system is used, both power supplies should be tested separately.

d. Simultaneously turn the control valve for the annular preventer to the closing position and turn the control valve for the hydraulically operated valve to the opening position.

e. Record the time (in seconds) required for the closing unit pumps to close the annular preventer plus open the hydraulically operated valve and obtain 200 psi above the precharge pressure on the closing unit manifold. It is recommended that the time required for the closing unit pumps to accomplish these operations not exceed two minutes.

f. Close the hydraulically operated valve and open the annular preventer. Open the accumulator system to the closing unit and charge the accumulator system to its designed operating pressure using the pumps.

ACCUMULATOR TESTS

Accumulator Precharge Pressure Test

J.A.22 This test should be conducted on each well prior to connecting the closing unit to the blowout preventer stack. Test should be conducted as follows-

a. Open the bottom valve on each accumulator bottle and drain the hydraulic fluid into the closing unit fluid reservoir.

b. Measure the nitrogen precharge pressure on each accumulator bottle, using an accurate pressure gauge attached to the precharge measuring port, and adjust if necessary.

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Accumulator Closing Test

J.A.23 This test should be conducted on each well prior to pressure testing the blowout preventer stack. Test should be conducted as follows:

a. Position a joint of drill pipe in the blow out preventer stack.

b. Close off the power supply to the accumulator pumps.

c. Record the initial accumulator pressure. This pressure should be the designed operating pressure of the accumulators. Adjust the regulator to provide 1500 psi operating pressure to the annular preventer.

d. Simultaneously turn the control valves for the annular preventer and for one pipe ram (having the same size ram as the pipe used for testing) to the closing position and turn the control valve for the hydraulically operated valve to the opening position.

e. Record the time required for the accumulators to close the preventers and open the hydraulically operated valve. Record the final accumulator pressure (closing unit pressure). This final pressure should be at least 200 psi above the precharge pressure.

f. After the preventers have been opened, recharge the accumulator system to its designed operating pressure using the accumulator pumps.

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NOTE: PLUG VALVE IN CLOSING PLUG VALVE LINE ADJACENT LINE ADJACENT ANNULAR TO PREVENTER TO PREVENTER TO FACILITATE LOCKING CLOSING PRESSURE ON PREVENTER.

VALVE AND VALVE GAUGE

CONNECTION FOR ANOTHER PUMP

PRESSURE REGULATOR (0-1500 PSI)

BLOWOUT

PREVENTER

TO ANNULAR TO

FULL OPENING VALVE FULL

RELIEF VALVE

VALVE

CHECK

TO CHOKE TO

LINE VALVE

TO RAM TO

BLOWOUT

PREVENTERS

BANKS

VALVE AND GAUGE

ACCUMULATOR

NEEDLE VALVES

Figure J.A.1

VALVE

CHECK

CLOSING UNIT ARRANGEMENT

EXAMPLE BLOWOUT PREVENTER

FULL-OPENING VALVES

PRESSURE REGULATOR (1500-3000 PSI)

FOUR-WAY VALVES FOUR-WAY (NOTE: SHOULD NOT CONTAIN (NOTE: SHOULD NOT CHECK VALVE AND SHOULD CHECK VALVE BE IN POWER ON POSITION)

REGULATOR BY-PASS LINE BY-PASS

TEST LINE TEST

BLOWOUT

PREVENTER

PUMP

CONNECTION FOR ANOTHER PUMP

FULL-OPENING VALVE

TEST FLUID LINE

FLUID

RESERVOIR

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TO RIG

CHECK VALVE

AIR COMPRESSORS CLOSING TO CLOSING UNIT UNIT PUMPS MANIFOLD AND ACCUMULATORS

STORAGE TANK ELECTRICAL POWER SUPPLY FOR RIG AIR

Figure J.A.2 EXAMPLE REDUNDANT AIR/ELECTRIC SYSTEMS FOR OPERATING CLOSING UNIT PUMPS

RIG GENERATOR

CLOSING TO CLOSING UNIT UNIT PUMPS MANIFOLD AND ACCUMULATORS

SEPARATE GENERATOR

Figure J.A.3 EXAMPLE REDUNDANT ELECTRICAL SYSTEMS FOR OPERATING CLOSING UNIT PUMPS

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TO RIG CHECK CHECK VALVE VALVE CLOSING TO CLOSING UNIT UNIT PUMPS MANIFOLD AND ACCUMULATORS OPTIONAL STORAGE TANK FOR RIG AIR

NITROGEN

Figure J.A.4 EXAMPLE REDUNDANT AIR/NITROGEN SYSTEMS FOR OPERATING CLOSING UNIT PUMPS

RIG GENERATOR

CLOSING TO CLOSING UNIT UNIT PUMPS MANIFOLD AND ACCUMULATORS

OPTIONAL

NITROGEN Figure J.A.5 EXAMPLE REDUNDANT ELECTRIC/NITROGEN SYSTEMS FOR OPERATING CLOSING UNIT PUMPS

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Figure J.0.6 ACCUMULATOR SIZINGS

Calculation of Accumulator Size

The volume of the accumulator system as calculated by using “Boyle’s law”:

P1V1 = P2V2

where

P1 = Maximum pressure of the accumulator when completely charged P2 = Minimum pressure left in accumulator after use. (Recommended minimum is1200 psi) V = Total volume of accumulator (fluid and nitrogen) V1 = Nitrogen gas volume in accumulator at maximum pressure P1. V2 = Nitrogen gas volume in accumulator at minimum pressure P2. V2 = V, plus usable fluid maximum to minimum pressure. V2-V1 = Total usable fluid with safety factor usually 50% included.

3000 psi system precharged to 1000 psi; V = 3V1

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Surface Accumulators (Refer to Fig J.0.6)

For the purpose of simplicity, the effects of temperature and nitrogen gas compressibility will be ignored and Boyle’s gas law applied to determine the volume of nitrogen present in the accumulator bottle when fully charged and when usable hydraulic fluid has been expelled to operate the BOP functions.

In an 11 gallon accumulator bottle the volume of nitrogen it contains before any fluid is pumped in will be 10 gallons (the rubber bladder occupies a volume of 1 gallon).

According to Boyle’s gas law:

P x V = P x V and also P x V = P x V 1 1 2 2 1 1 3 3 where:- P = nitrogen precharge pressure of 1000 psi 1 P = minimum operating pressure of 1200 psi 2 P = maximum operating pressure of 3000 psi 3 V = bladder internal volume at precharge pressure (11 gal - 1 gal) 1 V = bladder internal volume at minimum operating pressure, P (in gals) 2 2 V = bladder internal volume at maximum operating pressure, P (in gals) 3 3 therefore:- 1000 psi x 10 gals = 1200 psi x V 2 and 1000 psi x 10 gals = 3000 psi x V 3 giving V = 1000 psi x 10 gals = 8.33 gals 2 1200 psi and V = 1000 psi x 10 gals = 3.33 gals 3 3000 psi

The usable volume of hydraulic fluid expelled from the bottle as the nitrogen expands from V3 (3.33 gals) at 3000 psi to V2 (8.33 gals) at 1200 psi will be equal to:-

V - V = 8.33 gals - 3.33 gals = 5 gals 2 3

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K. KILL SHEETS K-1

K.1 KILL SHEET FOR VERTICAL OR LOW ANGLE SUBSEA WELLS K 2-5

K.2 KILL SHEET FOR VERTICAL OR LOW ANGLE WELL WITH SURFACE BOPS K 6-9

K.3 KILL SHEET FOR VERTICAL OR LOW ANGLE WELL WITH SURFACE BOPS (UK UNITS) K10-13

K.4 KILL SHEET FOR HIGH ANGLE SUBSEA WELL K14-17

K.5 KILL SHEET FOR HIGH ANGLE SUBSEA WELL (UK UNITS) K18-21

K.6 KILL SHEET FOR HIGH ANGLE WELL WITH SURFACE BOPS K22-25

K.7 KILL SHEET FOR HIGH ANGLE WELL WITH SURFACE BOPS (UK UNITS) K26-29

K.8 BLANK VOLUMETRIC KILL SHEET K-30

K.9 COMPLETED VOLUMETRIC KILL SHEET K-31

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K.0 KILL SHEETS

Figure K.1 Kill Sheet For Vertical or Low Angle Subsea Wells

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Figure K.1 Kill Sheet For Vertical or Low Angle Subsea Wells

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Figure K.1 Kill Sheet For Vertical or Low Angle Subsea Wells

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Figure K.1 Kill Sheet For Vertical or Low Angle Subsea Wells

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K.2 Kill Sheet For Vertical or Low Angle Well With Surface BOPs

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Figure K.2 Kill Sheet For Vertical or Low Angle Well With Surface BOPs

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Figure K.2 Kill Sheet For Vertical or Low Angle Well With Surface BOPs

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Figure K.2 Kill Sheet For Vertical or Low Angle Well With Surface BOPs

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Figure K.3 Kill Sheet For Vertical or Low Angle Well With Surface BOPs (UK Units)

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Figure K.3 Kill Sheet For Vertical or Low Angle Well With Surface BOPs (UK Units)

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Figure K.3 Kill Sheet For Vertical or Low Angle Well With Surface BOPs (UK Units)

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Figure K.4 Kill Sheet For Vertical or Low Angle Well With Surface BOPs (UK Units)

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W R E T L N L E C C O G N IN TROL TRAIN

Figure K.4 Kill Sheet For High Angle Subsea Well

• & WORKOVER WELL CONTROL

W R E T L N L E C C O G N IN TROL TRAIN

Figure K.4 Kill Sheet For High Angle Subsea Well

WORKOVER WELL CONTROL • &

W R E T L N L E C C O G N IN TROL TRAIN

Figure K.4 Kill Sheet For High Angle Subsea Well

• & WORKOVER WELL CONTROL

W R E T L N L E C C O G N IN TROL TRAIN

Figure K.4 Kill Sheet For High Angle Subsea

WORKOVER WELL CONTROL • &

W R E T L N L E C C O G N IN TROL TRAIN

Figure K.5 Kill Sheet For High Angle Subsea Well (UK Units)

• & WORKOVER WELL CONTROL

W R E T L N L E C C O G N IN TROL TRAIN

K.5. Kill Sheet For High Angle Subsea Well (UK Units)

WORKOVER WELL CONTROL • &

W R E T L N L E C C O G N IN TROL TRAIN

Figure K.5 Kill Sheet For High Angle Subsea Well (UK Units)

• & WORKOVER WELL CONTROL

W R E T L N L E C C O G N IN TROL TRAIN

Figure K.5 Kill Sheet For High Angle Subsea Well (UK Units)

WORKOVER WELL CONTROL • &

W R E T L N L E C C O G N IN TROL TRAIN

Figure K.6 Kill Sheet For High Angle Well

• & WORKOVER WELL CONTROL

W R E T L N L E C C O G N IN TROL TRAIN

Figure K.6 Kill Sheet For High Angle Well

WORKOVER WELL CONTROL • &

W R E T L N L E C C O G N IN TROL TRAIN

Figure K.6 Kill Sheet For High Angle Well

• & WORKOVER WELL CONTROL

W R E T L N L E C C O G N IN TROL TRAIN

Figure K.6 Kill Sheet For High Angle Well

WORKOVER WELL CONTROL • &

W R E T L N L E C C O G N IN TROL TRAIN

Figure K.7 Kill Sheet For High Angle Surface Well (UK Units)

• & WORKOVER WELL CONTROL

W R E T L N L E C C O G N IN TROL TRAIN

Figure K.7 Kill Sheet For High Angle Surface Well (UK Units)

WORKOVER WELL CONTROL • &

W R E T L N L E C C O G N IN TROL TRAIN

Figure K.7 Kill Sheet For High Angle Subsea Well (UK Units)

• & WORKOVER WELL CONTROL

W R E T L N L E C C O G N IN TROL TRAIN

Figure K.7 Kill Sheet For High Angle Subsea Well (UK Units)

WORKOVER WELL CONTROL • &

W R E T L N L E C C O G N IN TROL TRAIN

Figure K.8 Blank Volumetric Worksheet

• & WORKOVER WELL CONTROL

W R E T L N L E C C O G N IN TROL TRAIN

Figure K.9 Completed Volumetric Worksheet