Service Company Equipment Operator Workover Well Control

Curriculum, Course Delivery Requirements, and Related Learning Objectives

Form WSP-02-WS-WO-EO Revision 0 17 August 2017

All rights reserved. No part of this document may be distributed outside of the recipient’s organization unless authorized by the International Association of Drilling Contractors. WellSharp® Service Company Equipment Operator Workover Well Control Contents

1.0 Overview of Service Company Equipment Operator Workover Well Control ...... 3 2.0 Curriculum ...... 5 2.1 Risk Awareness and Management ...... 5 2.2 Well Control Principles & Calculations ...... 6 2.3 Barriers ...... 9 2.4 Influx Fundamentals...... 11 2.5 Gas Characteristics and Behavior...... 12 2.6 Completion and Workover Fluids ...... 12 2.7 General Overview of Surface and Subsurface Wellbore Equipment ...... 14 2.8 Procedures ...... 18 2.9 Well Kill in Preparation of Well Intervention ...... 20 2.10 Special Situations ...... 25 2.11 Organizing a Well Control Operation ...... 26 2.12 Testing ...... 27 2.13 Well Control Drills ...... 28 2.14 Government, Industry and Company Rules, Order and Policies ...... 28 2.15 Ancillary Considerations ...... 28

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1.0 Overview of Service Company Equipment Operator Workover Well Control This course curriculum is designed for service company equipment operators who are primarily responsible for workover operational processes of well control. This curriculum identifies a body of knowledge and a set of job skills that can be used to provide well control training for workover operations personnel.

This curriculum incorporates Core Training Modules, Sub-Modules, Learning Topics, and Learning Objectives and Assessments.

Recommended Attendees: IADC recommends that this course is attended by equipment operators who are primarily responsible for the workover operational processes of well control. Examples of these positions or job roles are listed in the table below.

Company Personnel Type Positions Operator Contractor Superintendent (Consultant)

Rig Workover Contractor Supervisor (Rig Foreman) (Workover Only Company) Crew Chiefs (Driller) Frac Supervisor Hydraulic Intervention Contractor Pumping Supervisor Hydraulic Workover Equipment Supervisor

Acceptable Delivery Methods: Instructor-led training for the initial and repeat delivery of this course is required. Demonstration and simulation are required to be incorporated into the course content delivery. See the relevant cross- reference document regarding content delivery requirements for specific learning objectives.

To the maximum extent possible, use scenarios to bring attention to specific topics. IADC also requires a “blended” approach to (multiple strategies for) content delivery and a variety of techniques that appeal to different types of learners (e.g., visual, auditory, kinesthetic). These strategies will also help engage trainees in the learning process and will help improve learning and retention.

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Minimum Course Length: Thirty-five (35) classroom hours are required for teaching the Workover curriculum. Course length excludes the knowledge assessment time (3.5 hours).

Course Curriculum Notes: The curriculum that follows includes five components: Training Modules, Sub-Modules, Learning Topics, AIM, and Learning Objectives and Assessment Guidelines. AIM: The AIM letters indicate the level of knowledge and skills required at the job level: A = Awareness of Learning Topic I = Implements Learning Topic at this job level; needs an increased level of knowledge because they may have to take action of some task related to the topic. M = Mastery of Learning Topics at this job level; needs a full knowledge because they have to take action, perhaps unsupervised, of some task related to the topic. Learning Topics: This section provides guidance for instructors on what the trainee should learn.

Learning Objectives and Assessment Guidelines: This section defines what trainees should be able to do at the conclusion of the training and provides some examples of how to meet the objectives.

Assessment Notes: Questions on the Knowledge Assessment will be graded as a cumulative score. To pass the course, the trainee must earn at least a 70% score.

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2.0 Curriculum

2.1 Risk Awareness and Management Module Name: 2.1 Risk Awareness and Management Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Describe potential risks of pore pressure prediction being incorrect and A Potential Impacts of a Risks associated with completion and well resulting in well control risk (e.g., completing a new reservoir). Well Control Event intervention operations Identify potential well control problems that could occur during I completion and well intervention operations. M Define ‘live’ well. Live/Dead Well Differences between ‘live’ and ‘dead’ well M Define ‘dead’ well. List the four principles of systematic risk management (i.e., identify, Risk Management I Systematic risk management quantify, mitigate and control risk). Explain the importance of communicating operational plan details, Pre-job Communication I Pre-job communications risks, and responsibilities. I Explain the importance of a good handover for tour and hitch change. Handover for Tour and Handover for Tour and Hitch change to Identify key components that need to be addressed during a handover Hitch Change I minimize risks for tour and hitch changes (e.g., current well status, barrier envelope, and communication of responsibilities). A Safety Margin Risks Describe the criteria used to develop a safety margin. a. Safety margins in Well Kill Operations Explain the dangers of using minimal safety margins during a well kill Safety Margin Selection A b. Dangers of using minimal safety (i.e., safety margins applied to tubular integrity, casing integrity, margins wellhead rating). Explain the purpose and importance of a well control bridging document (i.e., to assure all parties have the same information; to Purpose and Importance of Bridging Bridging Documents A resolve well control issues between different parties (which well control Documents practices will be followed); to handle specific issues in relation to a particular well/environment or legislative regime).

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Module Name: 2.1 Risk Awareness and Management Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Determine situations that require emergency procedures be activated and action(s) to secure the well (if applicable) (i.e., an uncontrolled BOP A leak; 'broaching' at surface; potential vessel collision; bad weather; Purpose and Importance of Establishing and Emergency Procedures drive-off; toxic gas; fire). Following Emergency Procedures for Rig BOP Explain when a company should initiate the emergency action plan and A assure crew members are aware of their roles and responsibilities for evacuation. I Define Maximum Allowable Working Pressure (MAWP). Pressure Control Equipment Requirements Identify the working pressure of a system based on lowest working Equipment/Barrier I pressure component (e.g., schematic or description). Envelope Considerations I Installation of rings, flanges and connections Describe characteristics and best practice for installing a ring gasket.

2.2 Well Control Principles & Calculations Module Name: 2.2 Well Control Principles & Calculations Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: M Pressure Define pressure. M Types of pressure Define hydrostatic pressure. M a. Hydrostatic pressure Calculate hydrostatic pressure. M b. Applied Pressures Explain the effects of fluid level change on hydrostatic pressure. M 1. Surface pressure Identify the different types of applied pressures. Pressure Fundamentals M a. SITP Explain shut-in pressures. M b. Annulus Pressure Explain equivalent circulating densities (ECD). 2. Pump Pressure Explain the effects of trapped pressure (e.g., above and below the M 3. ECDs (Equivalent Circulating packer or plug). M Densities) Explain the differences between swab and surge. M 4. Trapped Pressure Calculate formation pressure.

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Module Name: 2.2 Well Control Principles & Calculations Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: 5. Swab/surge Discuss situations where differential pressure exists in the wellbore M c. Formation pressure (e.g., across sliding sleeve; perforating; above/below packers; wireline d. Differential pressure plugs). M e. Fracture pressure Define fracture pressure. M f. Bottomhole pressure Define Bottomhole pressure (to include applied pressure). 1. Balanced Explain the difference between overbalanced and underbalanced M 2. Underbalanced pressure. M 3. Overbalanced Calculate equivalent fluid weight equal to formation pressure (kill fluid). M Calculate gradient for different density of liquid and gases. M Calculate well gradient from formation pressure and surface pressure. Calculate bottomhole pressure with at least one well bore with two M different densities and surface pressure. Maximum Anticipated Surface Pressure M Define MASP (reference WellSharp Definitions document). (MASP) M Calculate the effective force with a given pressure over a certain area. Forces from Applied Pressure M Calculate net force effects due to trapped pressure. M Equivalent circulating density Define equivalent fluid density. a. Definition Explain circulating frictional pressure losses and effects on pressure and M b. Frictional pressure loss effects on equivalent circulating density for forward and reverse circulation. downhole pressure M c. Surface pressure effects Calculate equivalent circulating fluid density. d. U-tube principles M Kill Mud Weight (Equivalent static fluid Define kill mud weight (equivalent static fluid density). density) a. Definition Calculate kill mud weight (equivalent static fluid density) with M b. Pressures expressed as an equivalent temperature effects. fluid weight M U-tube principles Demonstrate understanding of the U-tube concept. M Buoyancy Define buoyancy. M a. Pipe light Calculate buoyancy effects to string weight.

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Module Name: 2.2 Well Control Principles & Calculations Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: b. Pipe heavy Describe forces that must be overcome to push/pull workstring I c. Balance Point into/out of a pressured well. M Calculate tubing volumes, using given data. M Calculate strokes using given data. Calculations M Volume/Displacement calculations Calculate displacement volumes using given data. M Calculate annular volumes using given data. M Calculate usable volume of fluid in a pit/tank. Explain why applied casing pressure is needed (e.g., prevent packers from unseating, seal units from being pumped out of Polished Bore A Receptacle (PBRs), basis point for monitoring, limit differential Principles Tubing Collapse and Casing Burst pressure, prevent failures). Explain why applied casing pressure can lead to tubing collapse or A casing burst. Demonstrate how to document pre-recorded data significant to well I control situations (e.g., perforation interval, packer locations, tubing Well configuration strengths, safe working pressure). a. Top and bottom of perforations Pre-recorded Well Given a well and equipment scenario, determine pump rates to I b. Packer/Tool locations Information circulate, pump, or kill the well. c. Tubing dimensions, lengths and Demonstrate how to document the wellbore profile including depths strengths I (MD/TVD), lengths, strengths, capacities, displacements, and safe working pressures. Explain the purpose of functioning the casing valve prior to Intervention I operations. Explain the purpose of functioning the tree wing valve prior to I Wellhead/Well Control Stack/Christmas tree Secured Well Conditions Intervention operations. valves Explain the importance of a procedural lock-out on a remote actuated A tree valve. I Explain the importance of closing the tree master valve last.

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2.3 Barriers Module Name: 2.3 Barriers Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: M Define the term “barrier” (reference WellSharp Definitions document). Define the term “barrier envelope” (reference WellSharp Definitions M Barriers and barrier envelope document). List the requirements for a component to be considered a barrier (i.e., M once it is tested; when it is in contact with well fluids). Purpose of barriers during completions and Explain how barriers are used to maintain well integrity for completions M well interventions and well interventions. Philosophy and Operation Discuss the hierarchy of operations for Pressure Control Equipment of Barrier Systems M Operational Shut-in Hierarchy (PCE). Explain the action to be taken upon detection of a failed primary M barrier. Explain the action to be taken upon detection of a failed secondary M Barrier Hierarchy barrier. Explain the action to be taken upon detection of a failed emergency M closure. M Define mechanical barrier. M Mechanical barriers List examples of mechanical barriers. M Explain the validation needed to be a mechanical barrier. M Define fluid barrier. Types of Barriers Explain what is required for a fluid to be considered a barrier (i.e., M continuously observe the height and the ability to add fluid). Fluid barriers M List the types of fluid barriers. Explain the limitations of fluid barriers (e.g., it is only a barrier for a M certain period of time after circulation stops). M Explain what primary barriers are. Primary and Secondary Barriers and Levels of Barriers M Explain what secondary barriers are. Emergency Closure M Explain what emergency closures are.

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Module Name: 2.3 Barriers Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Explain why a minimum number of barriers are required for safe Minimum number of barriers required for safe M operations. (Refer to industry recommendations for minimum number operations of barriers to be in place for specific operations). Explain positive pressure and negative/inflow pressure barrier tests M (e.g., increase differential pressure across a barrier in either direction). Identify the reference sources for mechanical barrier test criteria (e.g., the well program, operations manuals, industry standards, technical I specifications from equipment manufacturers, integrity testing, and Testing mechanical barriers regulatory agency). M Explain the importance of documenting mechanical barrier testing. Explain the importance of the test pressure and time period to validate M mechanical barrier. Explain the action to take if there is a test failure of a mechanical well M barrier/element (i.e., retest, reinstall, or install additional barrier). Explain the importance of monitoring the fluid volume at surface (e.g., A open top tanks). Barrier Management M Explain how temperature affects a fluid barrier (e.g., changes density). Explain the importance of fluid density measurements as it applies to M well design. A Validating fluid barriers Identify conditions that would lead to settling of solids in the fluid. Explain how crystallization affects a fluid barrier (e.g., changes fluid M density). Explain the action to take if there is a test failure of a fluid M barrier/element (e.g., shut-in well, change out fluid, install mechanical barrier). Explain how a failed primary barrier can be detected (e.g., from the M flow from the well; through losses to the well; an increase in surface Detecting a failed barrier pressure when shut in). Explain how a failed secondary barrier can be detected (e.g., pressure M loss; detectable leaks at surface).

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Module Name: 2.3 Barriers Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Explain how a failed emergency closure can be detected (e.g., blowout, M uncontrolled flow). Identify different types of connections (e.g., NPT vs high pressure PCE Equipment I Hoses and Connections fitting, high pressure swivel joint-other operations).

2.4 Influx Fundamentals Module Name: 2.4 Influx Fundamentals Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: I Explain why reduction in hydrostatic pressures can cause an influx. I Explain why failure to keep hole full can cause an influx. Influx Causes of an influx I Explain why swabbing the well can cause an influx. I Explain why lost circulation can cause an influx. Identify possible indicators of an influx • Decrease in pump pressure/increase in pump rate • Volume displacement changes during tubular movement I • Change in surface pressures • Changes in string weight • Oil or gas shows during circulation Influx Detection Possible Indicators of an Unplanned Influx • Changes in fluid density Identify the necessity of timely response to one or more possible influx I indicators. Identify or describe potential consequences of improper or untimely response to influx indicators (e.g., extreme changes in operating M pressures, possible release of gas, pollution, potential for fire, loss of life, equipment resources).

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2.5 Gas Characteristics and Behavior Module Name: 2.5 Gas Characteristics and Behavior Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Explain the relationship between gas pressure and gas volume (e.g., the M Boyle’s Law concept to explain the pressure/volume relationship with Pressure and Volume Relationship between pressure and volume of most expansion close to surface). Relationship (Boyles Law) a gas in the wellbore Calculate new volume or pressure from original volume or pressure M change using Boyle’s Law.

2.6 Completion and Workover Fluids Module Name: 2.6 Completion and Workover Fluids Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Describe the purpose and characteristics of fluids that make them Completion and I Purpose of fluid suitable for workover and completions (e.g., compatibility with the Workover Fluids zone; pressure control). I Purpose of packer fluid Describe the purpose of packer fluid in a completion. Explain why fluid loss control is an important characteristic of I workover/completion fluid. Explain why fluid loss control is difficult to achieve when using I Fluid loss workover/completion fluids. Explain the types and methods used in fluid loss control (e.g., pills, I multiple fluids, plugs). Workover/Completion Explain why formation damage is an important consideration of A Formation damage Fluid Functions workover/completion fluid. Explain how corrosion is inhibited through the use of A Corrosion workover/completion fluids. Describe how the composition of the workover/completion fluid could A affect the environment. Environmental concerns Explain the importance of managing the returns and assessing possible A well fluids prior to discharge.

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Module Name: 2.6 Completion and Workover Fluids Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Describe properties required to enable workover/completion fluids I Rheology of Fluids carrying capacity and their effect. I Explain the effect of pump rates on fluid carrying capacity. Explain why a different brine combination may be needed based on Liquids I Brine requirements density requirements. I Density Define density. I Viscosity Define viscosity. I Define pH. pH Describe pH in relationship to density and viscosity (e.g., direct effect I on viscosity, no effect on density). Fluid Properties Define the low temperature point of brine and describe how it is I Crystallization point related to crystallization (e.g., ambient temperature to downhole temperature, density). Describe brine saturation and how it relates to crystallization and I Saturation maximum fluid weight. Discuss the effects of temperature on brine weight (e.g., surface I Temperature and pressure temperature vs downhole temperature). I Viscosity Define the relationship between viscosity and frictional pressure losses. I Flow rates Describe frictional pressure loss changes due to flow rate. I Frictional pressure losses Describe frictional pressure loss changes due to downhole restrictions. Fluid Flow Behavior Fluid flowpath geometry (wellbore/coiled I Describe frictional pressure loss changes due to well geometry. tubing) Flowpath restrictions (wellbore, downhole I Describe frictional pressure loss changes due to downhole tools. tools) A Oil based fluids Describe the applications where oil based fluids may be used. A Base oil Identify an application where base oil is used in a completion. Identify acceptable types of water based fluids that may be used in a Fluid Types workover/completion fluid (e.g., clear brines, muds, salt saturated A Water based fluids brines, gels/gel pills, stimulation fluids – acids, calcium carbonate systems, packer fluids).

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Module Name: 2.6 Completion and Workover Fluids Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Identify acceptable types of gases that may be used in a A Gases workover/completion fluid (e.g., CO2, N2). A Explain how fluid density is measured (i.e., use of mud balance). Measuring Techniques A Fluid properties Identify the conditions where a pressurized mud balance may be used. A Explain how fluid viscosity is measured (i.e., Marsh funnel).

2.7 General Overview of Surface and Subsurface Wellbore Equipment Module Name: 2.7 General Overview of Surface and Subsurface Wellbore Equipment Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: I Components Identify the key Christmas tree components. Explain the function of the Christmas Tree and how they work with particular emphasis on: Christmas Tree The purpose and function of the Christmas M • Master, swab and flow line valves Tree • The Surface Safety Valve (SSV) • Control line pressure versus tubing pressure Explain the primary function of the wellhead and casing valves and how they work with particular emphasis on: Purpose and function of the Wellhead and Wellhead M • Pressure seals between tubular casing valves • Access of annulus • Use of valve removal (VR) plugs M Identify the function of key Well Control Stack components. Describe the major components and operating principles of well control M closing and locking mechanisms. Blowout Preventer Stacks I Preventer Equipment Identify flow path(s) used in well control operations. and Components Analyze correct and incorrect make up of gaskets of specific types of M connections. M Explain and record closing time test for rams and annular.

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Module Name: 2.7 General Overview of Surface and Subsurface Wellbore Equipment Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: I Identify HCR and manual choke and kill line valves. M Explain the functionality and limitations of annular BOPs. Annular BOPs Describe the components that may be well pressure assisted to affect a M seal on closure. Identify types of rubber goods used in different applications (e.g., oil, I Rubber goods H2S, high-temp, neoprene, nitrile, aflas, chemical compatibility chart for rubber and synthetics). I OEM Replacement Parts Identify the importance of using originally manufactured components. M Explain the functionality and limitations of stripping rams (HWO). Stripping rams (HWO) Describe components that may be well pressure assisted to affect a seal M on closure. M Explain the functionality and limitations of shear rams. Shear or Cutter rams Identify non-shearables and non-sealables (e.g., production packer, M gravel pack screen-in liners, cast iron retainers, bridge plugs). Explain the functionality and limitations of blind rams and blind/shear M rams. Blind/Shear rams Identify non-shearables and non-sealables (e.g., production packer, M gravel pack screen-in liners, cast iron retainers, bridge plugs). I Multiple completions Identify proper ram selection for multiple completions. Kelly valves I a. Top drive valves Describe the function and use of Kelly valve. Auxiliary Well Control b. Power swivel valve Equipment I Full open safety valve (FOSV) Describe the function and use of the full open safety valve. a. Floor stabbing valves I b. Tubing safety valve Identify the location of the FOSV when not in use. M Identify reasons and procedures for an accumulator drawdown test. M Identify accumulator drawdown test frequency as per API STD 53. Accumulators Accumulator Drawdown test Calculate the usable fluid volume for a given BOP stack applying a M safety factor. M Describe the accumulator system function.

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Module Name: 2.7 General Overview of Surface and Subsurface Wellbore Equipment Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: M Define pre-charge pressure relative to usable fluid volume test. Define minimum system pressure relative to accumulator drawdown M test. Define normal regulated operating pressure relative to accumulator M drawdown test. Define maximum system pressure relative to accumulator drawdown M test. List conditions which would cause an adjustment to the regulated I annular operating pressure (e.g., change in OD, change in well pressure, and worn elements). Identify the reasons and procedures for a closing time test, per API STD M Closing time test 53. Explain the function of the manifold pressure regulator and bypass I valve. I Adjustment of operating pressure Explain the function of the annular pressure regulator. a. Manifold pressure regulator Describe the accumulator system functions, including an explanation of I b. Annular pressure regulator the consequences of losing nitrogen pre-charge pressure. I List the reasons for adjusting regulated annular operating pressure. Operating purpose of main and remote M Describe the purpose of main and remote control panels. control panels M Describe how to operate the BOP from the remote control panels. Operating functions of the remote BOP control Describe the consequences of lost rig air used for functioning the M panel remote BOP control panel. I Manual adjustable chokes Define the function of manual adjustable choke. Chokes and Choke I Define the function of remote adjustable choke. Remote adjustable chokes Manifolds I Explain how back-up system(s) to remotely operate chokes work. I Choke manifolds Define the function of choke manifold. Define the function of pump stroke counter in relation to calculating I Pump stroke counter Fluid Measuring volumetric rate. I Flow Rate Indicator Define the function of flow rate indicator device.

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Module Name: 2.7 General Overview of Surface and Subsurface Wellbore Equipment Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Identify tubing ratings (e.g., burst, collapse, torsion, tensile, buckling, I Tubular Integrity connection type).

I Operational Hazards Identify possible tubing failure (e.g., washouts, corrosion, H2S). I Identify IBOP options and safety considerations for each. A Inside BOPs (IBOPs) Describe the function and use of IBOP. I Identify the location and position of the IBOP when not in use. List three causes that can effect tubing ratings and result in failures Workstring and A (e.g., erosion, corrosion, thread galling). Production Tubing Explain how tubing movement during production, testing and I stimulation could result in tubing failures. Tubing Failures Identify ways to reduce tubing movement (i.e., I compression/elongation) during testing and stimulation. Identify potential problems with changes in ID (e.g., internal clearance I issues/decrease wall thickness). I Polished Bore Receptacle (PBR) Explain the function of the PBR and seal unit. Identify potential well control complications and solutions when I General running completion equipment. Describe the function of tubing hangers: • Seal off annulus I Tubing Hangers • Support tubing weight • Provide locking or threaded profile for Tubing Hanger Profile (TBH) Completion Equipment Explain the functionality and how a failure of a Surface controlled sub- I surface safety valve (SCSSV) can contribute to a well control incident. Surface Controlled Sub-Surface Safety Valve Recognize and describe the advantages/disadvantages of retrieving I (SCSSV) methods for surface controlled subsurface safety valves (SCSSVs). Explain how a failure of the lock-out device in a surface controlled Sub- I Surface Safety Valve (SCSSV) can result in a well control incident. Describe the difference between the sub-surface safety valves (SSSV) I Sub-surface safety valves (SSSVs) and the surface controlled sub-surface safety valves (SCSSV).

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Module Name: 2.7 General Overview of Surface and Subsurface Wellbore Equipment Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Describe the primary function, types, restrictions, applications and I Packers positioning of packers. Describe the primary function, types, restrictions, applications and I Landing nipples and tubing plugs positioning of landing nipples and tubing plugs. Describe the primary function and design of the sliding sleeves as I communication devices (e.g., production, circulation). Sliding sleeves and ported nipples Describe the primary function and design of the ported nipples as I communication devices (e.g., production, circulation). Describe the primary function of side pocket mandrels, either with a I Gas Lift Valve working valve (gas lift, circulation and chemical injection) or with a dummy valve installed.

2.8 Procedures Module Name: 2.8 Procedures Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Describe the relationship of pit/trip tank level indicator to a possible M High and low pit level kick situation. M Explain the purpose for setting flow sensor levels. Set/Check Alarm Limits Return flow sensor Describe the relationship of relative flow sensor to a possible influx M situation.

A Describe the purpose of H2S and explosive mixture gas sensors. H2S and flammable/explosive gas sensors A Identify the locations of H2S and explosive mixture gas sensors. Explain the well shut-in complications when non-shearable or non- Non-shearable or Non-sealable equipment sealable equipment is across the Well Control Stack (e.g., sand screens, Shut-in M across the Well Control Stack cables, control lines, Bottom Hole Assembly (BHA), packers, gas lift mandrels, and tubing hangers).

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Module Name: 2.8 Procedures Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Explain the importance of having an emergency procedure to address non-shearable and non-sealable elements across the Well Control Stack M (i.e., tapered strings, gravel pack screens, gas lift mandrels, slotted liners, packers). Explain the importance of the crew knowing their specific well control M Roles and Responsibilities responsibilities related to detection, well shut-in, and control. M Shut-in Sequence Identify the shut in sequence while tripping tubulars. Identify the valves/BOP equipment to be closed to establish a shut-in at M Annular the BOP with the use of flow line and trip tank (if applicable) to monitor. Identify the valves/BOP equipment to be closed to establish a shut-in Verification of Shut-in I Wellhead/BOP/Xmas tree (e.g. Casing valve, Crown, wing, master valves). Identify the valves/BOP equipment to be closed to establish a shut-in I Manifold (Manifold valves (standpipe/rig floor), Choke(s) (manual and/or remote). Recordkeeping M Explain procedures to use for well monitoring during well shut-in. a. Time of shut-in b. All tubing and casing pressures 1. At initial shut-in I Read, record and report well shut-in information. 2. At regular intervals Monitoring and Recording c. Pit gain During Shut-in BOP Stack/Wellhead Choke and Kill Lines, I Manifolds, Riser Spool, Accumulator Hoses Explain the importance of regular intervals of visual checks for leaks. and Connections Identify what needs to be monitored for integrity (e.g., check M Accumulator accumulator and manifold pressure, valve line up, and check status of power sources). I Explain the importance of a strip/trip tank. Stripping operations Importance of strip/trip tank and line up I Demonstrate valve line up to trip tank.

WSP-02-WS-WO-EO Page 19 of 29 Revision 0 © Copyright IADC 2017 Created: 17 August 2017 WellSharp® Service Company Equipment Operator Workover Well Control

Module Name: 2.8 Procedures Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Describe the purpose and procedure for stripping operations (with and I Stripping procedure for BOP without volumetric control). Explain the purpose and importance of using a bleed chart, with or I Measurement of volumes bled from the well without gas. Calculations relating volumes and pressure to Perform calculations for bleed volumes or pressures as method M be bled for a given number of tubing or requires. workstring stands run in the hole Describe possible situations where stripping with or without volumetric A Stripping with or without volumetric control control is important. List three well control considerations when removing a VR plug (i.e., Preparing for Well Entry M Use of valve removal plug (VR plug) excess of back pressure behind plug, assure any valve downstream of VR plug has been tested, use of lubricator). Calculate the pressure applied to the tubing needed to balance the M wellbore at a gas lift mandrel before pulling a gas lift valve. Calculations Pulling a gas lift valve or Opening sliding sleeve Calculate the pressure applied to the tubing needed to balance the M wellbore before opening the sliding sleeve.

2.9 Well Kill in Preparation of Well Intervention Module Name: 2.9 Well Kill in Preparation of Well Intervention Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Live Well intervention (without killing the Identify the objectives of well intervention well control techniques in a I well): live well where well is allowed to flow. a. Relies on pressure containment Objective of Well Control Identify the objectives of well intervention well control techniques in a I through surface well control Techniques live well where well is not allowed to flow. equipment Dead Well intervention (killing the well): Identify the objectives of circulating formation fluid out of the well as a I a. Circulate formation fluid out of well control/well intervention technique.

Module Name: 2.9 Well Kill in Preparation of Well Intervention Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: wellbore or bullhead fluid back into Identify the objectives of displacing formation fluid back into formation I formation as a well control/well intervention technique. I b. Establish hydrostatic well control Identify the objectives of reestablishing hydrostatic control. c. Avoid excessive surface and downhole pressures so as not to induce an Identify well intervention techniques which may induce downhole I underground blowout or lose kill fluids fracturing and fluid loss. to formation Describe the basic principles of Bullheading (i.e., push the formation I fluid back into the formation, possible flow paths). Discuss when Bullheading is used in preparation for remedial A operations. I Describe the advantages and disadvantages of bullheading. Discuss the well types and identify conditions when bullheading may be preferred to circulation (i.e., toxic gas present; unable to handle influx I at surface; potential to exceed equipment limitations if circulated to surface or if debris exists). Identify the importance of porosity and permeability on formation I injectivity. Bullheading I Definition, Application, and Calculation Describe how a bullheading operation can fracture the formation. Identify the importance of a pumping schedule for bullheading a given I well scenario. I Prepare a kill sheet for a Bullheading operation. M Calculate minimum pump rate to overcome gas migration. M Calculate kill weight fluid. Describe frictional losses in different well sections (slimhole, tight I tubing/casing clearances, small id tubing, restrictions). I Explain how downhole tools/equipment affects friction and fluid flow. I Determine the effect on BHP when bullheading. Determine the frictional pressure loss of pumped fluids vs. rate using a I flow chart or computer model.

Module Name: 2.9 Well Kill in Preparation of Well Intervention Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: M Identify the maximum burst pressure of tubulars. Calculate the minimal theoretical volume to be pumped to reach kill I point (without over-displacement). M Identify maximum surface pressure vs. volume pumped. I Discuss the risks associated with over-displacement. I Explain the difference between rising surface pressure and injection. Explain pressure post Bullhead in a well in which hydrostatic was not I sufficient to kill the well. Summarize how to mitigate a mechanical issue (i.e., place pressure on I the annulus to mitigate burst, placing pressure on the coil to mitigate collapse). I Determine the weakest mechanical link in a bullheading operation. M Demonstrate a detailed bullheading example on a simulator. Interpret data on a kill log and select possible kill problems (e.g., not I maintaining pressure; abnormal changes to casing pressure, choke opening size, and pit levels; SPM variations). I Explain how to verify if well has been successfully killed. List reasons why record keeping during a Bullhead operation is I important. I Define the lube and bleed method. I Describe the advantages and disadvantages of lube and bleed. Describe the well situations where lube and bleed would be applied as I opposed to other intervention methods or wellbore conditions (i.e., snubbing, coiled tubing, wireline). Lube and Bleed I Definition, Application, and Calculation Calculate pressure per unit of volume in lube and bleed operations. Identify the importance of a pumping schedule for lube and bleed I operations. I Develop a pump schedule for lube and bleed operations. I Describe the difference between safety and working margins. I Explain how to verify if well has been successfully managed.

Module Name: 2.9 Well Kill in Preparation of Well Intervention Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: I Define forward circulation (driller’s) method. Describe the well situations and conditions where forward circulation I (driller’s) method would be applied. Describe the advantages and disadvantages of forward circulation I (driller’s) method. M Calculate maximum pump pressure, as it relates to fracture pressure. Describe frictional losses in different well sections (slimhole, tight I tubing/casing clearances, extended reach, high angle). I Explain how downhole tools/equipment affects friction and fluid flow. Forward Circulation Definition, Application, and Calculation Determine the effect on BHP when circulating with tools and (Driller’s) Method I equipment. Demonstrate a detailed forward circulating (driller’s) method example M on a simulator. Interpret data on a kill log and select possible kill problems (e.g., not I maintaining pressure; abnormal changes to casing pressure, choke opening size, and pit levels; SPM variations). Explain how kill procedures can impact BHP (i.e., changing SPM; I changing mud weight; not following pressure chart; incorrect startup or shutdown procedure). I Define reverse circulation. Describe frictional losses in different well sections (slimhole, tight I tubing/casing clearances). I Explain how downhole tools/equipment affects friction and fluid flow. Reverse Circulation Applying Reverse Circulation method Describe the friction losses in the circulating system and the resulting I well pressures when reverse circulating. Determine the effect on BHP when circulating with tools and I equipment.

Module Name: 2.9 Well Kill in Preparation of Well Intervention Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Explain the main differences between a normal forward circulation kill technique and a reverse circulating technique (i.e., position of choke in I the circulating path, start-up procedure, tubing string friction, different fluids in the well, integrity of circulating path). Describe the advantages and disadvantages of reverse circulation I method (i.e., high frictional pressures downhole). Explain the importance of using startup and shutdown procedure in a M well kill (e.g., to maintain BHP). Startup/Shutdown procedures Demonstrate a startup and shutdown procedure including M communication with pump operator on a simulator. Explain the action to take to determine the ICP if an SCR has not been I recorded. Action(s) to take if an SCR has not been Determine the action to take if the shut-in pressures are not the same I recorded following the first circulation. Demonstrate how to maintain constant BHP when an influx is being M circulated through the choke lines and choke on a simulator. Explain why pump startup procedure does not give calculated ICP and Pump Startup and decide on the action to take (e.g., shut down and discuss the situation; Shutdown Procedure I Why startup pump pressure may not equal ICP continue with updated ICP and monitor pressures as gels are broken down). Explain why pump startup procedure in relation to MASP (breakover) Why pump pressure at shutdown may not I and what action(s) to take after establishing a circulation rate (i.e., equal expected pressure discuss the situation; monitor pressures as gels are broken down). Explain or demonstrate how to compensate for lag time between a M Lag time choke adjustment and pump pressure change. Determine the action(s) required to verify a well is dead before opening Verifying the well is dead following kill up the BOP (e.g., use the shutdown procedure; check for trapped I procedure pressure; monitor through choke; and use circulating practice once the well is open).

2.10 Special Situations Module Name: 2.10 Special Situations Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Blockages and Trapped I Identify types of blockages (i.e., sand bridges, paraffin, tubing plugs). Effect of blockages in retaining trapped Pressure in Identify potential well control complications with trapping pressure I pressure Tubing/Wellbore below blockages. Describe where paraffin / asphaltenes / scaling is encountered and Blockages and Restricted Effect of blockages in impeding the ability to problems caused (i.e., commonly found in older oil producing wells; Access in A run tool string in or out of the wellbore prevent tools from being run in to and out of the hole; plug up valves Tubing/Wellbore and surface equipment). I Define hydrates. Hydrates I Effect of Hydrates while Circulating Explain how hydrates can complicate well control. I Identify preventive measures to inhibit hydrate formation. Define H S and equipment limitations based on H S concentration (e.g., I 2 2 0.00011-0.00033 ppm is typical background concentration). Describe additional procedures, precaution and supplemental safety I equipment necessary, fluid scavengers, inhibitors while operating in an

H2S considerations Effect of H2S on Well Control Methodology H2S environment. Describe equipment addition, limitations, modification or replacement I necessary to work in an H2S environment (i.e., tubular or wireline embrittlement and seals).

I Explain safety considerations on safely bringing H2S to the surface. Explain how to react to problems that can happen during the well kill How to respond to problems that can happen M (i.e., shut down, realign the manifold line-up, change the choke, change during the well kill the pump, and correct any mud pit/weight management issues). Explain the importance of key components of handover procedures Managing Change During during a well kill operation and the complications created with poor a Well Kill Handover/ changes to personnel during a well handover (i.e., there must be clear communications between A kill operation Supervisors and other crew members to ascertain the good and the bad; how handovers between crewmembers must be managed during meal breaks and shift changes; written instructions, and questions).

Module Name: 2.10 Special Situations Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Kill log as a tool for troubleshooting unplanned Identify and communicate trends on a kill log (e.g., pressures; volumes; I events mud weights; the choke position; shutdowns/startups). Assess well data and determine corrective action to take for problems I Problems with the kill (i.e., incorrect mud pumped; run out of weighting material; weather problems; ram or annular failure; plugged string; rig power failure). Identify when the kill plan is not successful and decide on the “Stopping points” that indicate the kill plan corrective action to take at that point (e.g., a problem maintaining I was not working surface pressure; casing pressure and pit volume changes not going according to plan; possible points to stop the kill to check pressures). Identify the importance of reassessment of the current plan and I Management of Change techniques used (i.e., MOC). Identify problems that can happen during a well control operation (i.e., I Common well kill problems plugging; washouts; losses; equipment failure). Handling Kill Problems Identify the well control problems associated with communication I Communication between casing strings between casing strings. Operations with Specific Describe and discuss conditions where pressure calculations exceed M Pressure Calculation Exceeding MASP Well Control Concerns MASP (e.g., perforating, fracturing, energized fluids). Complication with Describe or discuss how MASP can be exceeded during well Pressure Limits Created by Hydraulic Hydraulic Fracturing M intervention operations being influenced by nearby hydraulic fracturing Fracturing Operations Operations operations (e.g., SIMOPS).

2.11 Organizing a Well Control Operation Module Name: 2.11 Organizing a Well Control Operation Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Describe required personnel assignments during a well control Personnel Assignments M Roles and Responsibilities operation. Describe locations of pre-recorded information, collection process, and Pre-Recorded Information I Pre-recorded information where supervisor will keep well documentation.

Module Name: 2.11 Organizing a Well Control Operation Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Plan Responses to Explain the importance of the emergency response plan for all well Anticipated Well Control I Emergency Response Plan operations. Scenarios Describe the lines of communication and the roles of personnel, I including the importance of pre-job on site planning meetings and tour Communications Planning and outlining routine well control safety meetings. Responsibilities responsibilities Describe how equipment and personnel would be organized to recover I a situation, once the well is safely shut in.

2.12 Testing Module Name: 2.12 Testing Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Explain the reason for pressure testing equipment for integrity upon I Purpose rig-up or when a system component is replaced, repaired, or decoupled. Identify the maximum safe working pressure for a given set of well Pressure and Function M Maximum safe working pressures of well control equipment. Tests control equipment List reasons for de-rating the maximum safe working pressure of well I control equipment (e.g., temperature, erosion, corrosion). Discuss the importance of low pressure testing in advance of high I Low Pressure and High Pressure Testing pressure testing (e.g., API 53ST and 30 CFR 250.617). Given details of specific equipment and operation, describe pressure I Requirements for pressure testing BOP Testing testing procedures. I Performing pressure tests Demonstrate procedures to pressure test a valve or BOP function. Testing of Completion I Packers Discuss the negative pressure test of a packer. Equipment I Deep-set Plug Discuss the pressure test of a deep-set plug.

2.13 Well Control Drills Module Name: 2.13 Well Control Drills Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: M Purpose Explain why pit drills are used. Pit Drills M Drill procedures Explain the standard procedure for a pit drill. M Purpose Explain why trip drills are used. Trip Drills M Drill procedures Explain the standard procedure for a trip drill. M Purpose Explain why choke drills are used. Choke Drills M Drill procedures Explain the standard procedure for a choke drill.

2.14 Government, Industry and Company Rules, Order and Policies Module Name: 2.14 Government, Industry and Company Rules, Order and Policies Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: API and ISO recommended practices, Describe or identify appropriate industry standard or recommended A standards and bulletins pertaining to well practice pertaining to job being completed. control Incorporate by Reference Regional and/or local regulations where Describe or identify appropriate regional government regulations A required pertaining to job being completed. Company/operator specific requirements Describe or identify appropriate company or operator specific A where required requirements pertaining to job being completed.

2.15 Ancillary Considerations Module Name: 2.15 Ancillary Considerations Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Describe the functions of gas detectors. Gas Detection A Purpose and location Identify the location of gas detectors. Fluid-Gas separators A Purpose and location Describe the functions of fluid-gas separators.

Module Name: 2.15 Ancillary Considerations Learning Topics Learning Objectives and Assessment Guidelines Sub-Modules AIM The instructor will impart knowledge on: The attendee will be able to: Explain the operating parameters (e.g., maximum operating pressure, Operating parameters A vent line diameter, u-tube height; and potential dangers and action to

take if overloaded). Describe the function of the emergency shutdown (ESD) on the control Wellhead Control Panel I Operation of Control Panel panel and accumulator requirements.