On the Dynamic Effects During Under-Balanced Drilling Operations

ON THE DYNAMIC EFFECTS DURING UNDERBALANCED DRILLING OPERATIONS AND THEIR PREVENTION

Z. Wang, R. Rommetveit, RF-Rogaland Research; R. Maglione, Agip; A. Bijleveld, KSEPL, Shell; D. Gazaniol, Elf Aquitaine Production

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Portions of this document may be illegible electronic image products. Images are produced from the best available original document. ABSTRACTS

In most underbalanced drilling (UBD) operations, the underbalanced condition must be generated artificially by injecting gas into the well. Due to the high compressibility nature of gaseous phase and interruptions to the system, the flowing system is a non-steady state one, especially when jointed pipes are used. This is experienced by the varying liquid and gas flow-out rates, and spikes in the bottomhole pressure. These dynamic pressures have been observed and documented in field UBD operations.

This paper will first present an extensive examination of the dynamic effects during an underbalanced operation. The dynamic effects are often associated with drilling operations, like starting/stopping circulation, gas injection kick-in, changing fluids circulation rates, making connections, tripping, and deployment of BHA and downhole tools.

Secondly, we discuss measures that are necessary to avoid the excessive peak loading of the surface facilities, the excessive wellhead pressures, and accidental overbalanced situations downhole. These are developed based on the field experience and simulation results from a dynamic underbalanced drilling simulator. We also demonstrate how a dynamic underbalanced drilling simulator can be used to improve the understanding of the physical process involved and be useful in designing operations.

1 - INTRODUCTION

Underbalanced drilling has been used increasingly to address many field and operational problems during the last several years. The advantages of applying underbalanced drilling are to reduce formation damage, avoid lost circulation, minimise problems with differential sticking, increase the penetration rate and bit life.

Formation damage can occur in various operational stages. There are several mechanisms that can cause formation damage or permeability impairment during drilling and completion operations [1,2]. Invasion of particulate matter into the formation is one of the most important mechanisms and it is often associated with the overbalanced pressure from wellbore towards formation in an overbalanced operation. Consequently, when underbalanced drilling is used to minimise formation damage due to solids and filtrate invasion, it is essential that the underbalanced condition is maintained throughout the drilling and completion operations at all times. Production while drilling may indicate that the well is underbalanced in some points/intervals. But it does not guarantee that the entire open hole section is underbalanced.

There are many factors that affect the effective pressure drawdown between the reservoir pressure and the bottomhole pressure. Fig 1 summarises the possible factors that may result in an undesired condition. These factors will be discussed later in details in the paper. Assuming that other parameters are constant, the pressure fluctuation during a UBD operation is the single most important factor that will cause uncertainty of the actual pressure conditions downhole.

In this paper, we will first illustrate the dynamic effects using some field recorded data. Then, we will present a comprehensive analyses of the system and the causes of the dynamic pressures. We will also show how we can use a dynamic simulator to simulate this effect, to improve the understanding of the physical process, and eventually to lead to the development of better procedures to minimise the effects. The results presented in this paper is obtained in a joint industry project at RF-Rogaland Research supported by Norske Shell, Norsk Agip, and Elf Petroleum Norge.

2 - UNDERBALANCED DRILLING OPERATIONS

If the underbalanced condition must be generated artificially, gas injection via either drillstring or a type of parasitic string is employed. Figure 2 shows a schematic of a UBD system representation. Since in an underbalanced drilling operation, production occurs simultaneously, a UBD operation becomes a combined drilling and production operation. Hence, it requires more elaborate planning and engineering.

Assuming a steady state flowing condition without significant drillstring movement, the average bottomhole pressure will be mainly determined by the following factors:

• Wellbore geometry, • Types of drilling fluid and injection gas, • Drilling fluid pump rate and gas injection rate, • Surface control procedures, • Injection methods, • Rate of reservoir production. • Reservoir fluids type, especially gas oil ratio.

Since a UBD operation involves a non-linear two phase flow system and the number of parameters needing to he considered -in the olanoincL^aaeUsJa^^ normally require the use of a dedicated simulator. There are a few steady-state underbalanced drilling software tools [5] [6] and a dynamic underbalanced drilling simulator available [7, 8],

The UBD operation must be designed such that it is possible to achieve underbalanced condition throughout the operation within the operational restrictions. Operational restrictions may include maximum possible fluids injection rates, hole cleaning, borehole stability, and operational window for the mud motor. The operation has to be in a stable operating range where the well pressures are not too sensitive to changes in normal control parameters such as gas injection rate, fluid rate, wellhead pressure, and reservoir pressure drawdown. It is equally important to be able to predict the amount of injection gas required for the operation, and the volume and the rate of production.

Operations like starting/stopping fluid/gas injection, drillstring movement, and pipe connections will interrupt normal flow conditions in the well and hence cause pressure fluctuation in the wellbore. Procedures have to be developed for such operations to avoid excessive wellhead pressures and accidental overbalance situations due to these operations.

3 - FIELD EXAMPLES OF DYNAMIC PRESSURE

In this section, we illustrate the dynamic well pressure by using the bottomhole pressure recorded while drilling. The first example is from a UBD operation in Parana Basin, Brazil [4], Well 1-FR-1-SC was vertical with 13 3/8” casing set at 744 m. The well was drilled using a conventional rig with jointed pipe and foam from 754m to 884 m. The use of foam is to increase the penetration rate. The bottomhole pressure was measured while drilling. In Figure 3 the gas injection rate, mud rate, and measured bottom hole pressure in terms of the equivalent circulating density (ECD) are shown for the period of drilling from 860 to 884m. We observed that the bottom hole pressure did not reach a steady state within the time required to drill one pipe joint. From Fig. 3 we also observed that the highest bottom hole pressure during the period is nearly 50% higher than the lowest bottom hole pressure during the period. The pressure oscillations vs. time were caused by interruption in flow condition due to operational requirements. For the period shown, gas and liquid injections were stopped to make connections.

Fig 4 plots bottomhole pressure against time for an oil well drilled underbalanced [3]. The bottomhole pressure during drilling has a variation of approximate 5 bar. However, during a drillstring connection, the bottomhole pressure first falls below the average due to the loss of the frictional pressure and then increases sharply above the average when the circulation starts again. This pressure spike repeats again when a drill pipe connection is required again. In this particular case, if one intends to maintain the underbalanced condition 100%, the minimum drawdown will be approximately 2100 kPa.

4 - FACTORS CAUSING DYNAMIC PRESSURES

In this section, we analyse the possible factors affecting the bottomhole pressures (BMP). By doing so, we may identify the causes that result in the dynamic pressures in a UBD operation and subsequently draw up measures to avoid the undesired pressure fluctuation. The flowing BMP may be expressed as:

Pwf=PH + Pf+ Pace + P«*

In the above equation, Ph is the hydrostatic pressure component which is a function of gas and liquid densities and gas void fraction. Gas density is strongly dependent on pressure and temperature. The gas void fraction depends on the gas and liquid flow rates. P, is the frictional pressure loss component. Pacc is the acceleration pressure due to fluid acceleration. Pwh is the wellhead back pressure depending on the surface control on the choke, gas and liquid rates, and surface pipe network. Therefore, all four components will be dynamic and dependent on time and the state of the system. When a disturbance is given to the system, e.g., changing in either gas or liquid rate, all four components will change accordingly. Depending on the design and the state of the system, a disturbance may be damped out quickly , or on the other hand, it maylead to the instability of the system.

In a UBD operation involving gas injection, the BMP will also be affected by the interaction of flowing system elements, i.e., gas injection line (parasitic string or drillstring), wellbore, and reservoir (Fig 2).

Due to the nature of the non-linear two-phase flow system, interactions between the system elements, and various disturbances during an operation, the wellbore pressure will be dynamic during a UBD operation as shown by field examples. If this dynamic system is not designed and controlled properly, the desired bottomhole pressure will not be achieved. In Figure 1, we illustrate the factors that may affect the bottomhole pressure and we will discuss them in details in this section. The major factors are:

• Non-linear two-phase flow system, • Drill string connection • Drilling and tripping operation • Full liquid column for MWD survey • Interrupted supply and equipment failure • Initial flash production

Simultaneously, the reservoir pressure in the vicinity of the wellbore will change with time due to production. This implies that even if we can maintain the bottomhole pressure relatively steady within small oscillation around the average BMP, the drawdown can still change with time.

4.1 - Non-linear Two Phase Flow System

If gas injection is used through either drillstring or a type of parasitic string, there will be interactions between the gas injection line, the wellbore, and the reservoir. This system is similar to a gas lift well. Instability in gas lift wells is a well recognised problem. Depending on the system geometry and design, the interactions among gas injection, wellbore, and reservoir may lead to an unsteady gas injection rate into the well, unsteady production from the formation, and unsteady wellbore pressures. There are well documented cases for gas lift instabilities. But there is a lack of documented cases in UBD operations. To illustrate the effects, we have used a dynamic underbalanced drilling simulator [7,8,9] to simulate a through completion underbalanced drilling operation. Tables 1 and 2 list the necessary data required for the simulation. The well is vertical to 994 m and then deviated to TD at about 8.5 degrees. Fig 5 shows the BMP as a function of gas injection rates under steady-state conditions with and without production from the reservoir. For the dynamic simulation, it is assumed that the system is filled with the drilling fluid and the bit is on the well bottom at 2170 m MD. The choke is set at certain opening to simulate the surface flow pipe resistance. The simulation starts with the mud pump at 150 l/min and the Nitrogen rate into the concentric annulus at 400 scf/min. Both rates are maintained constant throughout simulation. Fig 6 shows the bottomhole, compressor, and wellhead pressures and Fig 7 shows gas flow rate into the well from concentric annulus, and total gas flow out rate.

Before the injection gas breaks through into the well, the BMP and wellhead pressures are relatively steady and the compressor pressure increases steadily. At t=67 min, injection gas starts to enter the well with a sharp increasing rate and at the same time, both the BMP and compressor pressure start to drop rapidly and wellhead pressure starts to increase. Drilling starts at 60 ft/hr at t=76 min when the BMP is dropped to the reservoir pressure. During this period, no changes are made to any control parameters. We observe that the energy in the gas injection line is depleted quickly. The injection rate into the well peaks at t=76 min, then drops sharply, and becomes zero at t=90 min. The BMP starts to increase at t=84.5 min. From t=90 min, no gas is injected into the well from the concentric annulus, and the BMP increases rapidly due to fill-up of the top part by hydrostatic head. The gas injection line is pressured up again in this period.

At t=130 min, gas starts to enter the wellbore again, a similar trend is observed as in the first cycle. In order to avoid the kick-off problem, the wellhead pressure is increased to prevent the wellbore pressure from dropping too rapidly. This is done by closing the choke somewhat at t=136.5 min when we observe that BMP has dropped about 50 bar from the plateau of about 217 bar and the gas flow out rate is increasing. Although the wellhead pressure is increasing rapidly, the BMP continues to drop because the gas rate into the well is higher than gas flow-out rate and gas expands rapidly as it approaches the surface. This action has stabilised the system and the formation starts to produce again at t=150 min. A few minutes later, the choke is opened gradually to the originally setting. The system becomes stable and approaches a steady one under the designed condition.

This example demonstrates that how the system interacts among the various flowing units. A good understanding of the physical process and proper control can lead to better management of the wellbore pressure fluctuations.

4.2 - Drill String Connection

In jointed pipe drilling, drillstring connections are considered to be the most critical factor causing pressure fluctuations and spikes, in particular when drill string gas injection is used. This has been shown by field examples in an earlier section. The magnitude of the effect will depend on the gas injection method, i.e. drillstring injection or parasitic string injection.

Drillstring gas injection. During drillstring connection, both gas and liquid injections are stopped. The bottomhole pressure will be reduced due to the part loss of the frictional pressure in the well. This reduction in BMP may result in an increased oil and/or gas production. The extra production will depend on the type of the well, the reservoir productivity, and the designed reservoir drawdown. In horizontal wells with long exposed section, the extra production may be so much that it may lead to the difficulty in regaining the circulation without causing an overbalanced condition after a connection.

During the stoppage period, fluid separation will occur both in the drillstring and in the well. Although the hydrostatic pressure in the well is increased only by the extra production during connection, the profiles of hydrostatic pressures in the well and drillstring have been changed due to the accumulation of liquid slugs near the lower part of the well and drillstring. When the circulation is re-established, friction pressure is exerted on the bottomhole, liquid slugs in the drillstring will be first pumped into the well thus increasing the hydrostatic pressure in the well, in addition to the fluid acceleration. Consequently, a pressure spike is often observed with a short period of sustaining higher bottomhole pressure.

Parasitic (annulus) gas injection. When gas injection is facilitated with a parasitic string, the pressure spikes caused by drill string connection may be smaller or larger depending on the procedures used.

When circulation is stopped for connection, a drop in the BMP will occur due to loss of frictional pressure. If the annulus is left open during connection, the drop in BMP and the stoppage of pump will lead to (i) an increased production from the reservoir, (ii) an increased gas rate into the well from the parasitic string, and hence (iii) high gas liquid ratio in the gas lifted top part of the well. If caution is not exercised, the gas energy in the gas injection line may be depleted quickly and considerably.

During the stoppage period, fluid separation will occur in the top part of well if the annulus is closed. The hydrostatic pressure will not be increased probably much due to extra production during connection if the annulus is left open. But the profile of hydrostatic pressure gradient in the top part of the well may change somewhat due to the accumulation of liquid slugs.

When the circulation is re-established, friction pressure is exerted on the bottomhole, plus fluid acceleration. If the gas energy is properly preserved during connection, large pressure spikes may be avoided. Otherwise, a pressure spike may be observed with a long period of sustaining higher bottomhole pressure.

Unlike in the caseof drillstring gas injection, the BHP depends mainly upon the liquid hold-up in the top part of the well and the gas injection rate into the well from the gas injection line. The interaction between the well and gas injection is more important in this case.

4.3 - Drilling and Tripping.

Drilling along itself will not cause much pressure spikes. Tripping is considerably more challenging in maintaining the desired underbalanced conditions. When a coiled tubing unit is used, circulation may be facilitated while tripping in and out in the most part of the operation. The availabilityof circulation while tripping will lead to a much better management of the underbalanced condition, especially when drillstring gas injection is used. However, caution must be exercised when it comes to BHA deployment during which period, circulation is not available.

On the other hand, when the conventional rig is used, circulation is not normally available continuously during tripping although the well may be circulated at some intervals. If the drillstrinq is not to be tripped with pressure on thn well, the well stould-ha-killEd-hlt hydrostatic pressure before tripping. This will cause an overbalanced condition, especially when re-establishing circulation when new bit is tripped in. Even when the string is snubbed out with well pressure and production, the underbalanced condition may become lost due to depleted reservoir pressure and the flowing well killing itself.

When parasitic string gas injection is used, a similar situation will occur unless the string is snubbed in and out under pressure. But if the string is snubbed out, the underbalanced condition can be maintained since the gas injection can be maintained during tripping.

4.4 - Full Liquid Column for MWD Survey

If drillstring gas injection is used, full liquid column may be required for conducting conventional mud pulsed MWD logging. This may lead to large liquid slugs into the well during and after the data logging, hence creating a large pressure spike. With the increasing use of and improvement in EMWD, this restriction may be removed. When parasitic string gas injection is used, full liquid column is available inside the drillstring and this does not present any problems.

4.5 - Interrupted Supply and Equipment Failure

When gas injection is used, there are many reasons that the continues supply will be interrupted. During an UBD operation, more dedicated surface equipment and downhole tools are used. This increases the probability of equipment failure. When equipment failure and/or interruption in gas injection supply occur, the drilled portion may be exposed to an overbalanced condition either by hydrostatic pressure or in a shut-in condition. After stoppage, the subsequent re-establishment of circulation will result in the undesired bottomhole pressure fluctuations.

4.6 - Localised Reservoir Pressure Depletion

By conventional definition, the pressure underbalance is defined as the difference between reservoir pressure and the flowing bottomhole pressure. In a UBD operation, when the well is underbalanced and has produced for a while, localised reservoir pressure depletion may occur. This will be more significant in the cases of low permeability reservoir, high underbalance pressure, and limited reservoir drainage area. A reservoir pressure profile will form during production as illustrated in Fig 1. When this situation occurs, the dynamic wellbore pressure fluctuation will cause somewhat fluid invasion even if the largest spike is still within the nominal reservoir pressure.

5 - STEPS TO MINIMISE THE DYNAMIC PRESSURE EFFECTS

Two major factors affect the wellbore pressure changes. One is the nature of the non-linear two phase flow system and the other is the interruptions to the system. Some of the interruptions are required by the normal operations and the other are due to limitations of current technology and other unforeseen situations. Consequently, we can approach the problem from the following aspects:

Improving the understanding of the UBD physical process and training of personnel. Proper operational procedures for cnAnifin operations ------• Good pre-job planning to minimise uncertainties and to have proper contingency plan in place. • Continuing technology development to improve the reliability and applicable range.

5.1 - Physical Process and Training of Personnel

Underbalanced drilling combines drilling and production operations. The objective of a UBD job is to ensure the safety of the operation as well as minimum damage to the formation. The UBD operation typically involves a multiphase flow circulating system, reservoir production while drilling. A successful operation will require the good understanding of the multiphase flow circulating system, reservoir, interactions between various flowing elements, operational and technological restrictions.

One important step to improve the understanding is training. This will involve training UBD personnel in multiphase flow under steady-state condition and also some knowledge in transient multiphase flow. So far, UBD personnel has been learning from field experiences. No systematic training has been given to the personnel involved. Furthermore, there is no systematic training on offer. In this paper, we have demonstrated that a dynamic underbalanced drilling simulator can be an excellent tool for such purposes.

As UBD applications are predicted to increase steadily over the next decade and will be extended to high pressure reservoirs and offshore environments, training will become a more critical element in the safety and success of any UBD operation.

5.2 - Operational Procedures

In a UBD job, the operational requirements often introduce interruptions to the non-linear multiphase flow system. These operations are drilling, tripping, making connections, changing fluid rate and gas injection rate, and making survey and other measurements. A properly designed non-linear system will operate in a stable window with minimum oscillations about the average. The majority of the disturbances will be damped out quickly. Detailed discussions of specific operational procedure is out of the scope of this paper. Reference [3] has presented a detailed engineering considerations for jointed pipe UBD operation. Two most critical operations are drillstring connection and tripping. A dynamic underbalanced drilling simulator can be used to assist in developing the procedures for the drilling and tripping operations.

Making connection. During connection, two factors cause pressure spikes, i.e., loss of frictional pressure and hence increased production, and fluid separation in the system. If the BMP can be measured during connection, the loss of frictional pressure can be compensated for by increasing wellhead pressure. Fluid separation in the system is a function of time. To minimise the fluid separation, one needs to reduce the time required for connection. Float valves can been placed inside the drillstring, for safety reasons as well as to reduce the fluid separation during the stoppage period. But, the placement strategy of the float valves has not been studied systematically.

Use of a top drive rig will reduce the need for frequent pipe connection. Therefore, if possible, a top drive rig should be used. Tripping. If the well has to be killed by hydrostatic pressure, the native fluid in the reservoir section is preferred since it is the least damaging to the formation. During tripping, cautions should be exercised to minimise the dynamic pressures.

6 - CONCLUSIONS

An analysis of the factors affecting the dynamic wellbore pressure during an underbalanced drilling job has been discussed in this paper. The dynamic pressure is caused by:

• the nature of the non-linear multiphase flow system. • interactions between flow in gas injection line, wellbore multiphase flow, and the reservoir production. • interruptions due to operational requirements and unforeseen situations.

To maintain the well underbalanced at all times, localised reservoir pressure depletion will need to be taken into account. This implies that the BMP may have to be decreasing with time as reservoir pressure declines in the vicinity of the well.

Better training of UBD personnel is the key to meet the increasing demand for UBD drilling. A dynamic simulator for underbalanced drilling can be useful to enhance the understanding of the physical process involved in a UBD operation, to assist in developing procedures for specific operations, and can serve as a good training tool.

ACKNOWLEDGMENTS

The authors are grateful to Norske Shell, Norsk Agip, and Elf Aquitaine for supporting the underbalanced drilling project at RF-Rogaland Research.

REFERENCES 1. Leising, L.J. and Rike, E.A.: "Underbalanced Drilling With Coiled Tubing and Well Productivity", paper SPE 28870 presented at the 1994 SPE European Petroleum Conference, London, Oct. 25-27 2. Vennion, D. B., Thomas, F. B.: “Underbalanced Drilling of Horizontal Wells: Does it Really Eliminate Formation Damage?", paper SPE 27352 presented at the SPE Inti. Symposium on Formation Damage Control, Lafayette, La, Feb. 7-10,1994. 3. Saponja, J.: "Engineering Considerations for Jointed Pipe Underbalanced Drilling", paper presented at the 1st International Underbalanced Drilling Conf & Exhibition, The Hague, Netherlands, 2-4 Oct. 1995 4. Lage, A.C.V.M., Nakagawa, E.Y., de Souza, M.M. and Santos, F..: "Recent Case Histories of Foam Drilling in Brazil", paper SPE 36098 presented at the 4th Latin American and Caribbean Petroleum Engineering Conference, Port-of-Spain, Trinidad & Tobago, 23-26 April 1996 5. Emeh, V. and Bieseman, T.: “An Introduction to Underbalanced Drilling, RKER.95.071, Report published by Koninklijke/Shell E & P Laboratorium, Rijswijk, The Netherlands, 1995 6. Misselbrook, J., Wilde, G. and Falk K.: "The Development and Use of a Coiled-Tubing Simulation for Horizontal Applications", paper SPE 22822 presented at the 66th Annular ^"^chnicaôiânc^x^Nh^SPEâllas^l(XOct^^M9^^^^^^^^^^^^^^^^ 7. Rommetveit, R., Vefring, E.H., Wang, Z., Bieseman, T. and Faure, A. M.: “A Dynamic Model for Underbalanced Drilling With Coiled Tubing", paper SPE 29363 presented at the 1995 IADC/SPE Drilling Conference, Amsterdam, Feb. 28 - March 2, 1995 8. Wang, Z., Rommetveit, R., Vefring, E.H.., Bieseman, T. and Faure, A. M.: "A Dynamic Underbalanced Drilling Simulator", paper presented at the 1st International Underbalanced Drilling Conference & Exhibition, The Hague, 2-4 Oct. 1995 9. Wang, Z., Vefring, E.H., Rommetveit, R., Bieseman, T., Maglione, R. and Lage, A.C. : "Development and Verification of a Dynamic Underbalanced Drilling Simulator", paper presented at Energy Week ’97 Conf. & Exhibition, Houston, Tx, 28-30 Jan. 1997

Table 1 - Well geometry Table 2 - Additional data Well bore Components Length ID Mud density 1.050 s.g. Tubing 0 -1800 4.85 in Viscosity 2 cp Open hole 1800 - 2200 m 4.00 in Lift Gas Nitrogen Gas injection line Gas injection depth 985 m AH Components Length OD/ID Gas injection rate 400 scf/min Casing/tubing 0 -1004 m 6.5 in/5.0 in Mud pump rate 150 l/min BHA & CT Mud temperature at sur. 40 °C Components Length OD/ID Reservoir pressure 175 bara CT 2.5 in/2.0 in Reservoir section 2170-2200 mMD

Factors affecting the effective pressure underbalance

ch Reservoir & Near-well Wellbore V Poor knowledge of reservoir pressure • Interrupt Supply Multiple zones with different pressure • Equipment failure Q Q Local depletion effect: 0 Interrupt gas Injection o o for pipe connection Re-pressurisation Form. Pressure • Kill the well for tripping >°o Pbh • Drilling and tripping & Pbh • Full liquid column for MWD • Initial flash production Pbh 0 Inherent non-steady flow system _ Inaccurate modeling of multiphase flow

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Figure 1 Factors affecting the effective pressure underbalance 6

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- Mud+Gas+Cuttings 8.00 AM 900AM 1000 1100 1200PM 100 PM AM AM Fluid Components In the System Time •Gas{lnjected & Produced) • Drilling Fluids • DissolvedGas •Formation Oil •Formation Water E 400 - •Cuttings 300 - Formation Pi = 200 - Influx. S 100 -

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Time Fig. 2 Illustration of an Underbalanced Drilling System Figure 3 Data measured while drilling well 1-FR-1-SC, Parana, Brazil

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