Cross-Reference Tool WORKOVER and INTERVENTION WELL CONTROL Course for Oil and Gas Operator Representative

INSTRUCTIONS: This Cross-Reference Tool is to be used to describe in detail the course for which IADC WellSharp® accreditation is requested. To expedite course review during the application review process, each applicant should provide as much detail as feasible when completing the Cross-Reference Tool for each course for which accreditation is requested. Use the following guidance for the information required. • • Manual – In this column, report the page number(s) of the Instructor Resources – Record the name(s) of any video, course manual that includes text pertaining to the Learning eLearning or Self-Study product, or other resources available to Topic. Include as many citations as needed to show all content the Instructor that will be used for delivering content for this pertaining to this topic. Training Module. • Delivery Method – Record all delivery methods to be used to • Materials available to Trainees – List handouts, reference deliver content for this Learning Objective. List all that apply. books, and other materials that will be given to trainees during Use the following abbreviations to document the most delivery of this Training Module. common options a training provider might utilize: • Total Time Range of Training – After entering information on all D – Demonstration (Teaching through the use of a simulator, the required Training Modules, scroll to the bottom of the last virtual simulation, or visual demonstration through video page to enter the total time range (in hours and minutes) for animation. Can also be a hands-on demonstration with delivery of all Training Modules. Include a minimum and equipment.) maximum amount of time anticipated. *Note: When using the E – Any of the eLearning (electronic) methods of delivery time ranges provided, be aware that your actual course length H – Homework shall not fall below the minimum time requirement for the L – Lecture course (as stated in accreditation requirements). O – Other methods (for example, video) • Course Outline – Attach course outline that gives time PE – Practical Exercise(s) allocations for each Learning Topic. (Record where and how S – Simulator each Learning Topic is to be addressed, i.e., classroom, simulator, live well.)

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2.1 Risk Awareness and Management

DELIVERY METHODS LEARNING OBJECTIVE AND MANUAL CHAPTER & PAGE # SUB-MODULES LEARNING TOPICS Options: D, E, H, L, O, PE, S (See ASSESSMENT GUIDELINES (Multi-line text field) instructions above; select all that apply.) Identify potential well control problems that could occur during completion and well intervention operations (e.g., stimulating a Risks associated with completion in a producing Potential Impacts of a completion and well D E H L O reservoir; reworking a producing Well Control Event intervention PE S reservoir to control water and/or operations gas production; rework to reduce or eliminate water coning; repair mechanical failure; cement repair). Define well integrity (using definition in ISO 16530-1) and explain the importance of D E H L O maintaining well integrity to PE S prevent well control incidents through the use of well barriers. Assess current status of the well Well integrity Well Integrity (e.g., review well records and management program diagnostic tests to evaluate: well construction, gauge failure, D E H L O surface failures, hydrate PE S formation, bottomhole pressure, blockage in the well, nearby fracturing operations, perforation depth, type of production).

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Explain the importance of assessing and recognizing D E H L O communication between casing PE S annuli. Explain the importance of Pre-job Pre-job D E H L O communicating operational plan Communication communications PE S details, risks, and responsibilities.

Describe the criteria used to D E H L O develop a safety margin. PE S Safety Margin Risks Explain the dangers of using a. Safety margins excess safety margins during a well kill (e.g., if the margin is too in Well Kill D E H L O high that may cause losses; adding Operations PE S b. Dangers of using a choke safety margin and a fluid Safety Margin excess safety weight safety margin adds extra Selection margins pressure). Identify an acceptable safety c. Acceptable D E H L O margin from a set of given well safety margins PE S d. Dangers of using and kill data. minimal safety Explain the dangers of using minimal safety margins during a margins D E H L O well kill (i.e., safety margins PE S applied to tubular integrity, casing integrity, wellhead rating). Explain the purpose and importance of a well control bridging document (i.e., to assure all parties have the same information; to resolve well Purpose and control issues between different D E H L O Bridging Documents Importance of parties; to handle specific issues in PE S Bridging Documents relation to a particular well/environment or legislative regime, how equipment and personnel would be organized, post shut-in, to recover or restart operations).

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Define Maximum Allowable D E H L O Working Pressure (MAWP). PE S Identify the working pressure of a system based on lowest working pressure component Rated D E H L O Equipment Working Pressure, and Maximum PE S Requirements Allowable Working Pressure (e.g., schematic or description). Discuss difference between Rated Working Pressure and Maximum D E H L O Allowable Working Pressure and PE S any surface pressure limitations for kill operations. Identify wireline equipment that requires anchoring to withstand D E H L O Pressure Control maximum expected forces during PE S Equipment/Barrier operations (e.g., wireline units, Envelope sheaves). Considerations Identify considerations when determining if a wellhead or tree bending stress analysis is required. D E H L O (e.g., weight of stack, length of PE S PCE rig-up, center of gravity of the Load Bearing stack and lubricator, age of well, Considerations and condition of well). Identify the size, type, and condition of the wellhead, tree, D E H L O and connectors, such as studs, and PE S nuts. Identify considerations when running unsupported length and D E H L O size of lubricator or riser, and PE S position of wireline valves in the PCE rig up.

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Identify environmental factors that can influence well control D E H L O

operations/rig-up (e.g., sea state, PE S wind speed, air temperature).

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2.2 Organizing a Well Control Operation

DELIVERY METHODS LEARNING OBJECTIVE AND MANUAL CHAPTER & PAGE # SUB-MODULES LEARNING TOPICS Options: D, E, H, L, O, PE, S (See ASSESSMENT GUIDELINES (Multi-line text field) instructions above; select all that apply.) Describe required personnel assignments during a well control operation (i.e., crew knowing their Personnel Roles and D E H L O specific well control Assignments Responsibilities PE S responsibilities related to detection, well shut-in, and control). Describe what type of pre- recorded information is required Pre-Recorded Pre-recorded to allow planning for a well D E H L O Information information control event and where the PE S supervisor should post and keep the information. Plan Responses to Explain the importance of the Emergency Response D E H L O Anticipated Well emergency response plan for all Plan PE S Control Scenarios well operations.

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2.3 Well Control Principles & Calculations

DELIVERY METHODS LEARNING OBJECTIVE AND MANUAL CHAPTER & PAGE # SUB-MODULES LEARNING TOPICS Options: D, E, H, L, O, PE, S (See ASSESSMENT GUIDELINES (Multi-line text field) instructions above; select all that apply.) D E H L O Types of pressure Define and calculate hydrostatic a. Hydrostatic pressure. PE S pressure Explain and calculate the effects D E H L O b. Applied Pressures of fluid level change on PE S 1. Surface pressure hydrostatic pressure. 2. Pump Pressure 3. ECDs (Equivalent Identify the different types of D E H L O Circulating applied pressures. PE S Densities) D E H L O 4. Trapped Explain shut-in pressures. PE S Pressure Pressure Fundamentals 5. Swab/surge Explain equivalent circulating D E H L O c. Formation densities (ECD). PE S pressure Explain the effects of trapped d. Differential D E H L O pressure (e.g., above and below pressure PE S the packer or plug). e. Fracture pressure f. Bottomhole Explain the differences between D E H L O pressure swab and surge. PE S 1. Balanced Calculate formation pressure (i.e., D E H L O 2. Underbalanced shut-in tubing pressure and fluid PE S 3. Overbalanced density in well).

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Explain areas of differential D E H L O pressure in the wellbore. PE S Explain fracture pressure (for both D E H L O the casing shoe and the reservoir PE S in completed interval).

Explain Bottomhole pressure (to D E H L O include applied pressure). PE S Explain the difference between D E H L O overbalanced and underbalanced PE S pressure. Explain and calculate equivalent D E H L O fluid weight equal to formation PE S pressure.

Calculate gradient for different D E H L O density of liquid and gases. PE S Calculate well gradient from D E H L O formation pressure and surface PE S pressure. Calculate bottomhole pressure with at least one well bore with two different densities and surface pressure (e.g. different D E H L O brine weights in the wellbore, PE S fluid of a different density or gas allowed to flow into the wellbore from underbalanced perforating of after pulling barrier plug). Maximum Anticipated D E H L O Surface Pressure Define and calculate MASP. PE S (MASP)

Calculate the effective force with a D E H L O Forces from Applied given pressure over a certain area. PE S Pressure Calculate net force effects due to D E H L O trapped pressure. PE S

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Equivalent circulating density Explain circulating frictional a. Frictional pressure pressure losses and effects on loss effects on D E H L O pressure and equivalent downhole PE S circulating density for forward and pressure reverse circulation. b. Surface pressure effects Kill Mud Weight Explain kill mud weight D E H L O (Equivalent static fluid (equivalent static fluid density). PE S density) a. Pressures Calculate kill mud weight D E H L O expressed as an (equivalent static fluid density) PE S equivalent fluid with temperature effects. weight D Explain the U-tube concept with U-tube principles (Must be taught through examples. Demonstration)

Explain and calculate buoyancy D E H L O effects to string weight. PE S Calculate the balance point to transition from snubbing to D E H L O stripping operations while going in PE S hole. Describe forces that must be Buoyancy D E H L O overcome to push/pull workstring a. Pipe light PE S b. Pipe heavy into/out of a pressured well. c. Balance Point D E H L O Calculate strokes using given data. PE S Calculate displacement volumes D E H L O using given data for both open- PE S ended and close-ended pipe.

Calculate annular volumes using D E H L O given data. PE S

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Calculate usable volume of fluid in D E H L O a pit/tank. PE S Calculate the compressibility and flow-back volume. D E H L O [Compressibility factor (psi-1) x PE S Volume x Pressure (psi)] Calculate the snub force (tubing D E H L O Pre-job calculations body and tubing collar/pipe PE S upset). Describe and discuss conditions Pressure Calculation where pressure calculations D E H L O Exceeding MASP exceed MASP (e.g., perforating, PE S fracturing, energized fluids). Explain why applied casing pressure is needed (e.g., prevent packers from unseating, seal units from being pumped out of D E H L O Polished Bore Receptacle (PBRs), PE S Tubing Collapse and Principles basis point for monitoring, limit Casing Burst differential pressure, prevent failures). Explain why applied casing D E H L O pressure can lead to tubing PE S collapse or casing burst. Explain the consequences of exceeding the tubing integrity due D E H L O to frictional forces (i.e., buckling PE S pipe, parting pipe, Overcoming frictional necking/ballooning). Snubbing/Buckling forces Identify factors that contribute to upward and downward forces D E H L O (e.g., pumping into a closed PE S system, pumping down a workstring).

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Recognize how tensile strength of the tubular is reduced when D E H L O subjected to differential pressure PE S (greater pressure outside the tubing than inside). Reduction of Tensile Conditions causing Identify how to mitigate reduction D E H L O under Collapse collapse or parting of in max pull due to collapse loading PE S Loading pipe Given various pressure conditions D E H L O and pipe dimensions, identify PE S which could lead to parting.

Describe how well pressure affects D E H L O the pulling limit on the pipe. PE S Describe how well pressure and Reduction of Pipe Conditions causing D E H L O string weight affects the torque Strength twist-off of pipe PE S limit on the pipe. Demonstrate how to document pre-recorded data significant to well control situations (e.g., perforation interval, packer locations, tubing strengths, safe D E H L O Well configuration working pressures, number of PE S a. Top and bottom of Electrical Submersible Pump (ESP), perforations downhole pressure gauge cables, b. Packer/Tool control lines, integrity issues with locations wellbore or tree). Pre-recorded Well c. Tubing Given a well and equipment Information dimensions, D E H L O scenario, determine pump rates to lengths and PE S circulate or kill the well. strengths Demonstrate how to document the wellbore profile including D E H L O depths, lengths, strengths, PE S capacities, displacements, and safe working pressures. Maximum safe D E H L O Identify wellhead pressure rating. pressures PE S

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a. Wellhead rating Describe safe working pressures b. Coiled Tubing and pressure-fatigue cycles (e.g., String Properties tubing grade, external damage, D E H L O c. Pumping system internal pressure; provide data in PE S a case study to determine if string is acceptable for use). Describe safe working pressure of D E H L O the pumping system (i.e. pumps, PE S lines, valves, hoses). Instructor Resources:

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2.4 Barriers

Define the term “barrier” and D E H L O

“barrier envelope” (reference PE S WellSharp Definitions document). List the requirements for a component to be considered a barrier (e.g., designed to withstand the maximum potential D E H L O Philosophy and Barriers and barrier differential pressure, it is tested, PE S Operation of Barrier envelope verified, and maintained to Systems prevent uncontrolled flow from the well). Describe how the pressure control equipment is part of the primary D E H L O well barrier envelope (e.g., PE S stuffing box, lubricator, wireline valve, pump-in sub).

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Explain how barriers are used to Purpose of barriers maintain well integrity for D E H L O during completions completions and well PE S and well interventions interventions. Explain action to take upon detection of a failed primary D E H L O barrier element(s) and how it PE S affects the failure of the primary Barrier Hierarchy envelope. Explain action to take upon detection of a failed secondary D E H L O barrier element(s) (i.e., reference PE S Emergency Response Plan). Explain what primary and secondary barriers are: a. For completion / workovers, the fluid is the “Primary well control barrier” and the BOP is the “secondary well Primary and control barrier”. Secondary Barriers b. For well servicing the D E H L O Levels of Barriers a. Completions / primary well barrier PE S Workover envelope consists of the b. Well Servicing pressure control equipment (PCE) such as the wireline valve, lubricator, stuffing box. The secondary “well control barrier” consist of the Well Control Stack or wireline valve closure.

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Explain why a minimum number of barriers are required for safe Minimum number of operations. (Refer to industry D E H L O barriers required for recommendations for minimum PE S safe operations number of barriers to be in place for specific operations) (e.g., reference ISO 16530-1).

Define and provide examples of D E H L O mechanical barrier. PE S Mechanical barriers Explain the validation needed to D E H L O be a mechanical barrier. PE S Explain what is required for a fluid Types of Barriers to be considered a barrier (i.e., D E H L O continuously observe the height PE S and the ability to add fluid). Fluid barriers Explain the limitations of fluid barriers (e.g., it is only a barrier for D E H L O a certain period of time after PE S circulation stops). Explain positive pressure and negative/inflow pressure barrier D E H L O tests (e.g., increase differential PE S pressure across a barrier in either direction). Testing mechanical Barrier Management Explain the risks associated with barriers negative pressure tests and trapped pressures when testing D E H L O small volumes (e.g., wellhead PE S voids, lockdown screws, potential for ejection).

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Identify the reference sources for mechanical barrier test criteria (e.g., the well program, operations manuals, industry standards, D E H L O technical specifications from PE S equipment manufacturers, integrity testing, and regulatory agency). Explain the importance of D E H L O documenting mechanical barrier PE S testing.

Explain the importance of the test pressure and time period to validate mechanical barrier (e.g., D E H L O to ensure compressibility and PE S temperature effects are taken into account). Explain the action to take if there is a test failure of a mechanical D E H L O well barrier/element (i.e., retest, PE S reinstall, or install additional barrier). Explain the importance of D E H L O monitoring the fluid volume at PE S surface (e.g., open top tanks). Identify the reference sources for fluid barrier test criteria (e.g., the D E H L O well program, industry standards, PE S Validating fluid and technical specifications from barriers company manufacturers). Explain the importance of fluid D E H L O density measurements as it PE S applies to well control. Identify conditions that would D E H L O lead to settling of solids in the PE S fluid.

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Explain the action to take if there is a failure of a fluid barrier or a failure of the fluid meeting the D E H L O acceptance criteria to be PE S considered a barrier. (e.g., shut-in well, change out fluid, install mechanical barrier). Explain how a failed barrier can be detected (e.g., from the flow from Detecting a failed D E H L O the well; through losses to the barrier PE S well; an increase in surface pressure when shut in). Instructor Resources:

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2.5 Coiled Tubing Pressure Control Equipment

Describe the advantage and use of D E H L O Primary PCE Stripper rigging-up two strippers. PE S Describe the factors that impact wear rate of the stripper element D E H L O and how to shut-in the well when PE S it fails.

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Identify and describe fluid compatibility and temperature D E H L O

limitations with the common PE S elastomer used in strippers. Explain the purpose of the flow D E H L O check assembly in BHA as an PE S internal primary PCE. Explain when a flow check assembly may not be used (e.g., D E H L O during reverse circulating or PE S Flow Check Assembly concentric coiled tubing). in Bottom Hole Identify and describe the function Assembly (BHA) of different types of flow check D E H L O assemblies in the BHA (e.g., PE S flapper valve, dart valve). Explain the limitations of testing D E H L O the flow check assembly in the PE S BHA (e.g., only test one flapper). Describe the function and potential risks of lubricator/spool in the barrier envelope (e.g. use of D E H L O quick unions instead of flanged PE S Lubricator/Spool connection; damage to quick (between the Well union seals and potential to Control Stack and loosen during movement). Stripper) Explain the need for sufficient length between stripper and the D E H L O lower most barrier(s) to PE S accommodate the maximum length of BHA. Explain how the Quad Well Quad Well Control D E H L O Secondary PCE Control Stack acts as a secondary Stack PE S PCE.

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Explain the use and limitations of coiled tubing Well Control Stack D E H L O when used as a PCE. (i.e., quad PE S type; dual combi-type, shear/seal, triple combi rams). Identify and describe the function and location of the flow tee/flow D E H L O cross in a typical Well Control PE S Fluid inlet/outlet Stack. a. Flow tee with Describe valve configuration on isolation valves flow tee or flow cross needed to D E H L O b. Flow cross with meet API standards (i.e., RP16ST; PE S isolation valves API 53ST 6.2). c. Kill line with Identify the location of kill line isolation and inlet and valve configuration on a check valves D E H L O Coiled Tubing Well Control Stack PE S as recommended in API standards (i.e., RP16ST; API 53ST 6.2).

Explain when to use the additional D E H L O blind shear ram. PE S Explain the implication of using an Additional Blind Shear additional blind shear ram (e.g., Ram additional closing volume, D E H L O additional pressure remaining to PE S shear, proof testing of shear ram, test frequency). Explain the use and limitations of the tree when coiled tubing is not D E H L O Christmas tree in the well and a release occurs PE S (i.e. personnel approaching gas cloud is not recommended). Instructor Resources:

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2.6 Wireline Pressure Control Equipment

DELIVERY METHODS LEARNING OBJECTIVE AND MANUAL CHAPTER & PAGE # SUB-MODULES LEARNING TOPICS Options: D, E, H, L, O, PE, S (See ASSESSMENT GUIDELINES (Multi-line text field) instructions above; select all that apply.) Identify and describe general D E H L O Line Wiper functions of line wiper and its use. PE S Identify and describe general D E H L O functions of stuffing boxes and PE S their use. Determine if a stuffing box would D E H L O seal if the wire were not present PE S (ball check present, yes/no).

Describe how to regain a seal on D E H L O Stuffing Box/Pack off the wire following a leak. PE S a. Manual Discuss applied forces associated D E H L O b. Hydraulic with the use of stuffing boxes. PE S Control Heads Describe operational limits of (Primary PCE) stuffing box/pack-off (i.e., line D E H L O speed, cable size, and pressure PE S rating).

Identify potential well control risks D E H L O when using stuffing boxes. PE S Identify and describe general D E H L O functions of grease injection and PE S its use. Describe how to regain the seal on D E H L O Grease Injection the wire once the seal has been PE S lost. Describe operational limits of D E H L O grease injection in relation to the PE S assembly.

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Identify potential well control risks D E H L O when using grease injection. PE S Discuss the relationship of flow tubes as it relates to fluid and D E H L O pressure requirements (e.g., need PE S to season braided line). Describe the effects of hose D E H L O length, grease viscosity, hose ID PE S and ambient temperature. Identify potential well control risks when using lubricator (e.g., use of D E H L O Lubricator quick unions, seal damage, and PE S potential to back-off during Lubricator operations). Identify and describe general (Primary PCE) D E H L O functions of quick test sub and its PE S Quick test sub use. Identify potential well control risks D E H L O when using quick test sub. PE S Identify and describe the function D E H L O of conductor/braided line rams in PE S wireline valves. Identify and describe the function of shear seal rams in wireline D E H L O valves when using PE S Wireline Valves conductor/braided line rams. (Conductor/Braided Describe the configuration of the Wireline Valves line rams) wireline valves when using D E H L O (Secondary PCE) a. Line rams conductor/braided line rams, PE S b. Shear seal rams including inverted rams. Describe operational limits such as D E H L O maximum shear capacity and PE S ability to seal the wellbore. Identify potential well control risks D E H L O when using conductor/braided PE S line rams in wireline valves.

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Identify and describe the function D E H L O of slick line rams in wireline PE S valves. Identify and describe the function D E H L O of shear seal rams in wireline PE S valves when using slick line. Wireline Valves (Slick Describe the configuration of the line) wireline valves when using slick D E H L O a. Line rams line (e.g., stripping wire through PE S b. Shear seal rams wireline valves).

Describe operational limits such as D E H L O maximum shear capacity. PE S Identify potential well control risks D E H L O when using slick line in wireline PE S valves. Describe the configuration of the wireline valves when using pump- D E H L O Pump-in Sub in sub and when it can be PE S eliminated from the rig up. Identify potential well control risks Lubricator Extension D E H L O when using lubricator extension (Riser) PE S (riser).

Additional PCE Describe the purpose and D E H L O placement of a wireline shear seal. PE S Discuss using a tree valve to cut wireline and the qualifications D E H L O Wireline Shear Seal required to maintain valve as PE S barrier.

Identify potential well control risks D E H L O when using a wireline shear seal. PE S Instructor Resources:

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2.7 Snubbing Pressure Control Equipment

tubulars) barriers (i.e., back PE S pressure valve).

Identify external (annulus) barriers D E H L O Snubbing Barriers Barriers (i.e., stripping rams, annular). PE S Explain how to maintain barrier(s) when changing a sealing element D E H L O during intervention and give PE S examples of barriers used. Identify different types of sealing D E H L O elements (e.g., stripping annular, PE S ram type). Stripper Assemblies Sealing elements Identify critical seals that have the potential to fail through wear and D E H L O explain why they need to be PE S replaced. Describe major components and D E H L O operating principles of PCE closing PE S and locking mechanisms. D E H L O Describe equipment limitations. PE S Additional Rams Snubbing Pressure Identify flow path(s) used in well D E H L O Control Equipment control operations. PE S

Identify locations for choke and D E H L O kill line valves. PE S

Describe operating principles and D E H L O Stripping rams limitations of stripping rams. PE S

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Describe closing and operating D sequences to strip and/or snub (Must be taught through pipe into the well. Demonstration) Describe components that may be D E H L O well pressure assisted to affect a PE S seal on closure.

Explain what equalizing loops and D E H L O bleed-off lines are. PE S

Equalizing Loop and Explain the purpose of using the D E H L O Bleed-off Line equalizing loop and bleed-off line. PE S Explain the flow path for bleeding D E H L O off well fluids and gasses, PE S considering area classifications. Instructor Resources:

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2.8 Influx Fundamentals

DELIVERY METHODS LEARNING OBJECTIVE AND MANUAL CHAPTER & PAGE # SUB-MODULES LEARNING TOPICS Options: D, E, H, L, O, PE, S (See ASSESSMENT GUIDELINES (Multi-line text field) instructions above; select all that apply.) Identify possible indicators of an influx • Decrease in pump pressure/increase in pump rate • Volume displacement changes during pipe D E H L O

movement PE S • Change in surface pressures • Changes in string weight • Oil or gas shows during circulation Possible/Positive • Changes in fluid density Influx Detection Indicators of an Identify positive indicators of an D E H L O Unplanned Influx influx (e.g. pit gain, increase PE S return flow, flow with pumps off). Identify how to respond to a possible/positive influx indicator D E H L O (e.g., flow check/shut-in PE S procedure). Identify or describe potential consequences of improper or untimely response to influx indicators (e.g., extreme changes D E H L O in operating pressures, possible PE S release of gas, pollution, potential for fire, loss of life, equipment resources).

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Instructor Resources:

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2.9 Gas Characteristics and Behavior

DELIVERY METHODS LEARNING OBJECTIVE AND MANUAL CHAPTER & PAGE # SUB-MODULES LEARNING TOPICS Options: D, E, H, L, O, PE, S (See ASSESSMENT GUIDELINES (Multi-line text field) instructions above; select all that apply.) Explain the relationship between gas pressure and gas volume (e.g., the Boyle’s Law concept to explain D E H L O Relationship between Pressure and Volume the pressure/volume relationship PE S pressure and volume Relationship (Boyles with most expansion close to of a gas in the Law) surface). wellbore Calculate new volume or pressure D E H L O

from original volume or pressure PE S change using Boyle’s Law. Instructor Resources:

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2.10 Completion and Workover Fluids

DELIVERY METHODS LEARNING OBJECTIVE AND MANUAL CHAPTER & PAGE # SUB-MODULES LEARNING TOPICS Options: D, E, H, L, O, PE, S (See ASSESSMENT GUIDELINES (Multi-line text field) instructions above; select all that apply.) Explain why fluid loss control is D E H L O difficult to achieve when using Workover / PE S workover/completion fluids. Completion Fluid Fluid loss Explain the types and methods Functions D E H L O used in fluid loss control (e.g., PE S pills, multiple fluids, plugs). Explain why a different brine D E H L O Brine requirements combination may be needed PE S based on density requirements. Describe how stimulation and Liquids treatment fluids affect the Applied stimulation D E H L O dynamics of the well operations and treatment fluids PE S (e.g., acids, gel pills, CO2, Steam, and Nitrogen). Explain compressibility of various D E H L O fluids (e.g., water based, non- PE S aqueous based). Explain the importance of D E H L O compressibility and the effects on PE S pressure and volume calculations. Define the freezing point of brine D E H L O and describe how it is related to Fluid Properties Fluid Properties PE S crystallization. Describe brine saturation and how it relates to crystallization, D E H L O maximum fluid weight, and the PE S freezing point.

Explain the temperature effect on D E H L O the density of the brine. PE S

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Explain the importance of fluid D E H L O density measurements as it PE S applies to well design. Identify conditions that would D E H L O lead to settling of solids in the PE S fluid. Describe frictional pressure loss changes due to downhole restrictions and other fluid Frictional pressure D E H L O properties, fluid type, flow rate, losses PE S downhole tools, and viscosity (e.g., crude oil, base oil, diesel, water, brine, gelled fluids). Fluid flowpath Describe frictional pressure loss geometry D E H L O Fluid Flow Behavior changes due to well geometry and (wellbore/coiled PE S restrictions. tubing or workstring) Instructor Resources:

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2.11 General Overview of Surface and Subsurface Wellbore Equipment

Explain the importance of D E H L O Preventer Equipment recording closing time test for Blowout Preventer PE S rams and annular. Stacks and Explain the importance of using Components OEM Replacement D E H L O originally manufactured Parts PE S components.

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Explain the functionality and D E H L O limitations of shear rams. PE S Identify non-shearables and non- Shear or Cutter rams sealables (e.g., production packer, D E H L O gravel pack screen-in liners, cast PE S iron retainers, bridge plugs, control lines, cables).

Explain the functionality and D E H L O limitations of blind rams. PE S Blind/Shear rams Identify non-shearables and non- sealables (e.g., production packer, D E H L O gravel pack screen-in liners, cast PE S iron retainers, bridge plugs). Barrier Elements List barrier elements of the Well D E H L O a. Annular Type Control Stack used in snubbing PE S Blowout Preventer operations. (BOP) Explain advantages and b. Ram Type BOP disadvantages of each type of D E H L O 1) Strippers (see equipment used in snubbing PE S sub-module operations as a barrier element. lubricator / Identify criteria used in the stripper selection of the barrier element assemblies for for different operating D E H L O more learning environments (e.g., pressure, PE S objectives) safety margins, operational 2) Pipe/Multiple objectives of the job, operating string limits of the elements). 3) Blind Explain what must be done in 4) Blind/Shear order for a barrier element to 5) Shear D E H L O become part of the barrier 6) Slip PE S envelope (e.g., tested, configured, 7) Variable bore and applied as designed). c. Valves Describe the major components Operating D E H L O and operating principles of BOP Environment PE S closing and locking mechanisms

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Verify operating limits of BOP D E H L O equipment (e.g., pressure and PE S space out limits).

Identify reasons and procedures D E H L O for a drawdown test. PE S Identify drawdown test frequency D E H L O as per API standards (i.e., API 53 PE S and 16ST (Coiled Tubing)).

Calculate the usable fluid volume D E H L O for a given BOP stack. PE S

Describe the accumulator system D E H L O functions. PE S

Explain pre-charge pressure D E H L O relative to usable fluid volume. PE S

Usable fluid Explain minimum system pressure D E H L O Accumulators volume/Drawdown relative to usable fluid volume. PE S test Explain normal regulated D E H L O operating pressure relative to PE S usable fluid volume. Explain maximum system pressure D E H L O relative to usable fluid PE S volume/drawdown test. Explain closing time requirements for various Well Control equipment (e.g., surface workover stack rams, coiled tubing stack D E H L O rams, wireline valves, subbing PE S stripping rams, choke and kill line valves, hose length, hose ID, control fluid viscosity, and ambient temperature).

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List conditions which would cause an adjustment to the regulated D E H L O annular operating pressure (e.g., PE S change in OD, change in well pressure, and worn elements). Explain the importance for adjusting the operating pressure D E H L O on a manifold and annular PE S pressure regulator. Describe the accumulator system functions, including an D E H L O explanation of the consequences Adjustment of PE S operating pressure of losing nitrogen pre-charge a. Manifold pressure pressure. regulator Explain the factors that affect the b. Annular pressure following: (surface and coiled regulator tubing) • Pre-charge pressure D E H L O • Minimum system pressure PE S • Normal regulated operating pressure • Maximum system pressure

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Explain the functions of main and remote well control panels and the consequences of losing air or power to the remote BOP control panel (e.g., well control panels used to hold open tree actuated valves and subsurface safety Operating functions of valves; Alternatives to Well D E H L O main and remote well Control panel – a) Fusible caps for PE S control panels tree actuated valve, b) trapping

pressure on the downhole safety valve hydraulic control line to hold open; when to consider using one method over the other; design considerations including hose size, accumulator size, power fluid viscosity for cold environments). Power packs Identify and describe pressure D E H L O a. Pressure control control unit power pack functions PE S unit and configuration. List three causes that can effect tubing ratings and result in failures D E H L O (e.g., erosion, corrosion, thread PE S galling). Explain how tubing movement Tubing Failures D E H L O during testing and stimulation PE S could result in tubing failures. Identify ways to reduce tubing Workstring and D E H L O movement during testing and Production Tubing PE S stimulation.

Polished Bore Explain the function of the PBR D E H L O Receptacle (PBR) and seal unit. PE S Explain how a failure of a Surface Surface Controlled controlled sub-surface safety valve D E H L O Sub-Surface Safety (SCSSV) can result in a well control PE S Valve (SCSSV) incident.

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Explain how a failure of the lock- out device in a surface controlled Sub-Surface Safety Valve (SCSSV) D E H L O can result in a well control PE S incident. (i.e., address open flow path through the control line) Explain the use of sliding sleeves D E H L O Sliding Sleeve during well control or circulation PE S operations. Describe the primary function of side pocket mandrels, either with a working valve (e.g., gas lift, Gas lift mandrels and D E H L O circulation, and chemical valves PE S injection) or with a dummy valve installed, as it relates to well control. Explain the necessity of redundancy regarding internal application of floats/downhole Auxiliary Well Control Floats/downhole D E H L O check valves to prevent flow up Equipment check valves PE S the string (i.e., when or why redundant valves are necessary in coiled tubing and snubbing). Explain the importance of different types of plugs and the D E H L O Type of Plug direction they hold pressure PE S (reference API Spec 11D1 and API Spec 14L). Explain the effect of sweet or sour wellbore conditions on D E H L O Plugs performance of plug and PE S elastomers. Service Ratings Explain where to locate the pressure differential rating of the D E H L O plug to ensure proper plug PE S selection (e.g., manufactures specifications, well program).

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Calculate potential pressure differentials across plugs, packers, D E H L O Differential Pressure sand bridges, cement, sliding PE S sleeve, gas lift valve. Explain the importance of an D E H L O Equalizing Sub equalizing sub on flow control PE S devices and plugs. Identify well control risk, common and unique, to both permanent D E H L O Packers Types of Packers and retrievable packers (e.g., PE S swabbing and trapped pressure). Instructor Resources:

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2.12 Procedures

DELIVERY METHODS LEARNING OBJECTIVE AND MANUAL CHAPTER & PAGE # SUB-MODULES LEARNING TOPICS Options: D, E, H, L, O, PE, S (See ASSESSMENT GUIDELINES (Multi-line text field) instructions above; select all that apply.) Discuss the general procedures to D E H L O shut-in and secure the well in Procedures for shut-in coiled tubing operations including PE S and securing the well use of slip rams. a. Coiled Tubing Discuss the general procedures to Shut-in D E H L O b. Wireline shut-in and secure the well in PE S c. Snubbing wireline operations. d. Workover Discuss the general procedures to D E H L O shut-in and secure the well in PE S snubbing operations.

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Discuss the general procedures to shut-in and secure the well in D E H L O

workover operations (i.e., while PE S tripping pipe). Explain the well shut-in complications and importance of emergency procedures when non- Non-shearable or shearable or non-sealable Non-sealable D E H L O equipment is across the BOP (e.g., equipment across the PE S sand screens, cables, control lines, BOP Bottom Hole Assembly (BHA), packers, gas lift mandrels, and tubing hangers). Verification of Shut-in Explain how to verify that the well a. Coiled Tubing is shut-in (i.e., check for leaks and Verification of Shut- D E H L O b. Snubbing pressure, check annulus and in PE S c. Wireline tubing, BOP equipment, Christmas d. Workover tree, and manifold line-up). Recordkeeping Explain procedures to use for well D E H L O a. Time of shut-in monitoring during well shut-in. PE S b. All tubing and casing pressures Describe the purpose of reading, 1. At initial shut-in D E H L O recording, and reporting well shut- 2. At regular PE S intervals in information, including pit gain. c. Pit gain Monitoring and BOP Stack/Wellhead Recording During Choke and Kill Lines, Shut-in Manifolds, Riser Explain the importance of regular D E H L O Spool, Accumulator intervals of visual checks for leaks. PE S Hoses and Connections Identify what needs to be monitored for integrity (e.g., D E H L O Accumulator check accumulator and manifold PE S pressure, valve line up, and check status of power sources).

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Importance of Explain the importance of a D E H L O trip/stripping tank trip/stripping tank. PE S Describe purpose and procedure Stripping procedure for stripping operations (with and D E H L O for BOP without volumetric control PE S Stripping operations including a bleed chart). Calculations relating volumes and pressure Perform calculations for bleed to be bled for a given D E H L O volumes or pressures as method number of tubing or PE S requires. workstring stands run in the hole Identify well conditions and equipment that need to be verified prior to well entry (e.g., Verification prior to D E H L O equipment in the well, equipment well entry PE S ratings, type of fluid and fluid level, restrictions, and maximum anticipated well head pressure). List three well control considerations when removing a VR plug (i.e., excess of back pressure behind plug, assure any Use of valve removal D E H L O Preparing for Well valve downstream of VR plug has plug (VR plug) PE S Entry been tested, use of lubricator, include potential risks of the Valve Removal Lubricator, and using dry rods).

Describe reasons for and use of D E H L O back pressure valves. PE S Describe the potential risks from Removal of tree trapped pressure when using a D E H L O solid rod to recover a plug and the PE S risks of getting a plug stick across the Xmas tree valves.

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Describe procedures for installing D E H L O and testing of BOP and wellhead PE S prior to barrier removal.

Discuss maximum potential force D E H L O below back pressure valves. PE S

Explain the purpose for using a D E H L O two-way check valve. PE S Describe the importance of bottom-up circulation prior to conducting open-hole operations Wireline Open Hole Conditioning the D E H L O (e.g., primary logging run, Operations Wellbore PE S subsequent operations, dipmeter, formation sampling tool (FST), and sidewall coring). Describe the importance of Pre-operating drift/gauge runs before other D E H L O Drift/Gauge Runs Procedures cased hole/completion PE S operations. Identify potential problems with space-out and configuration when Rigging Up and Pressure Control positioning wireline valves (e.g., D E H L O Deployment Into Equipment slick line set on onshore jobs, back PE S Well pressure valve, tool string across tree). Describe the procedure for securing the well after shearing D E H L O wireline with and without the tree PE S Procedure for Well installed. Contingency Control Drills Describe scenarios where wireline Procedure for D E H L O valves vs. shear rams would be Wireline PE S used. List potential well control D E H L O Open hole logging problems that could occur during PE S open hole operations.

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List potential well control Cased hole problems that could occur during D E H L O logging/perforating cased hole logging/perforating PE S operations. List potential well control Slick line/production problems that could occur during D E H L O logging slick line/production logging PE S operations. Discuss contingency procedure, as per API Coiled Tubing Standard D E H L O (API 16ST), for stipper assembly PE S failure. Discuss contingency procedure, as per API Coiled Tubing Standard D E H L O (API 16ST), for leaking Coiled PE S Tubing between gooseneck and the reel. Discuss contingency procedure, as per API Coiled Tubing Standard D E H L O (API 16ST), for leaking Coiled PE S Tubing between the gooseneck Contingency Contingency and the stripper assembly. Procedures (API Procedures for Coiled Discuss contingency procedure, as Coiled Tubing Tubing per API Coiled Tubing Standard Standard (API 16ST)) D E H L O (API 16ST), for parted Coiled PE S Tubing between the gooseneck and the reel. Discuss contingency procedure, as per API Coiled Tubing Standard D E H L O (API 16ST), for parted Coiled PE S Tubing between the stripper assembly and the injector. Discuss contingency procedure, as per API Coiled Tubing Standard D E H L O (API 16ST), for buckled Coiled PE S Tubing between injector and stripper assembly.

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Discuss contingency procedure, as per API Coiled Tubing Standard D E H L O (API 16ST), for leak between tree PE S and Well Control Stack pressure- sealing rams. Discuss contingency procedure, as per API Coiled Tubing Standard D E H L O (API 16ST), for leak between the PE S stripper and Well Control Stack rams. Discuss additional contingency procedures and verification of securing the well (e.g., coiled tubing surface equipment failure, circulation equipment failure, Additional external leak in the riser or Well D E H L O Contingency Control Stack, general muster PE S Procedures alarm while coiled tubing in the well, leak at the swivel joint (rotating), simultaneous power pack and coiled tubing failure, and power pack failure). Identify problems that can happen Common well kill during a well control operation D E H L O problems (i.e., plugging; washouts; losses; PE S equipment failure, surface leak). Assess the options available if surface casing pressure is likely to Handling Kill exceed MAASP and decide on the Problems Action(s) to take if action to take (i.e., continue and D E H L O casing pressure accept losses; reduce the PE S exceeds MAASP circulating friction in the annulus and choke lines yet maintain BHP, use the Volumetric method to manage the pressure).

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Identify the well control problems associated when communication exists between casing strings (e.g., Communication leaks, different fluid densities, D E H L O between casing burst/collapse outer strings, PE S strings casing annulus gauges, consider using case history for wireline, snubbing, and workover/completions). Instructor Resources:

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2.13 Coiled Tubing Operational Considerations

DELIVERY METHODS LEARNING OBJECTIVE AND MANUAL CHAPTER & PAGE # SUB-MODULES LEARNING TOPICS Options: D, E, H, L, O, PE, S (See ASSESSMENT GUIDELINES (Multi-line text field) instructions above; select all that apply.) D E H L O Identify the maximum allowable burst and collapse pressures. PE S Pressures Identify conditions that can cause D E H L O burst and collapse of the coiled tubing string (i.e., mechanical PE S Coiled Tubing damage to coiled tubing). Operational Identify maximum and minimum Limitations run-in hole and pull-out hole D E H L O Forces forces to prevent pipe buckling or PE S parting the pipe. Identify surface force on the D E H L O Surface Force Gooseneck and injector forces PE S above the stripper.

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Discuss limitations of material strength selection when working Coiled tubing material D E H L O in sour and/or corrosive strengths PE S environments (NACE MR0175/ISO 15156). Identify and describe physical conditions leading to pressure Coiled tubing pressure bend cycle fatigue damage and D E H L O bend-cycle fatigue subsequent failure of coiled tubing PE S a. Pressure (bending radii over tubing guide b. Surface damage arch and reel, coupled with c. Corrosion internal pressure). Coiled Tubing d. Mechanical Explain the importance of avoiding Limitations defects and ovality excessive cycling on the coiled D E H L O e. Erosion tubing string (e.g., trip and cut PE S coiled tubing rather than retire string for fatigue limit). Explain the need to fill coiled tubing with kill fluid prior to conducting simultaneous D E H L O bullheading pumping operations PE S Collapsed Coiled (through coiled tubing and annular Tubing space). Identify conditions under which D E H L O mechanically collapse may exist PE S (e.g., ovality; obstructions). Instructor Resources:

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2.14 Well Kill in Preparation of Well Intervention

DELIVERY METHODS LEARNING OBJECTIVE AND MANUAL CHAPTER & PAGE # SUB-MODULES LEARNING TOPICS Options: D, E, H, L, O, PE, S (See ASSESSMENT GUIDELINES (Multi-line text field) instructions above; select all that apply.) Live Well intervention (without killing the well): Identify the objectives of well a. Relies on pressure D E H L O intervention well control containment PE S techniques in a live well. through surface well control equipment Dead Well Identify the objectives of intervention (killing circulating formation fluid out of D E H L O the well): the well as a well control/well PE S a. Circulate intervention technique. formation fluid Identify the objectives of Objective of Well out of wellbore or displacing formation fluid back D E H L O Control Techniques bullhead fluid back into formation as a well PE S into formation control/well intervention b. Establish technique. hydrostatic well Identify the objectives of D E H L O control reestablishing hydrostatic control. PE S c. Avoid excessive surface and downhole pressures so as Identify well intervention D E H L O not to induce an techniques which may induce PE S underground downhole fracturing and fluid loss. blowout or lose kill fluids to formation

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Describe the basic principles of Bullheading (i.e., push the D E H L O formation fluid back into the PE S formation, possible flow paths). Discuss when Bullheading is used D E H L O in preparation for remedial PE S operations.

Describe the advantages and D E H L O disadvantages of bullheading. PE S Discuss the well types and identify conditions when bullheading may be preferred to circulation (i.e., toxic gas present; unable to D E H L O handle influx at surface; potential PE S to exceed equipment limitations if circulated to surface or if debris Definition, exists). Identify the importance of Bullheading Application, and D E H L O porosity and permeability on Calculation PE S formation injectivity. Identify the importance of a D E H L O pumping schedule for bullheading PE S a given well scenario.

Prepare a kill sheet for a D E H L O Bullheading operation. PE S

Calculate minimum pump rate to D E H L O overcome gas migration. PE S

D E H L O Calculate kill weight fluid. PE S Describe frictional losses in different well sections (slimhole, D E H L O tight tubing/casing clearances, PE S small id tubing, restrictions, pump rates, fluid types).

Determine the effect on BHP D E H L O when bullheading (i.e. fracturing PE S formation). Calculate minimal theoretical volume to be pumped to reach kill D E H L O point (without over-displacement PE S for horizontal well or deviated wells with long intervals).

Identify maximum surface D E H L O pressure vs. volume pumped. PE S

Identify the risks associated with D E H L O over-displacement. PE S Explain the difference between D E H L O rising surface pressure and PE S injection. Explain pressure, post-Bullhead in D E H L O a well in which hydrostatic was PE S not sufficient to kill the well. Summarize how to mitigate a mechanical issue (i.e., place D E H L O pressure on the annulus to PE S mitigate burst, placing pressure on the coil to mitigate collapse).

Discuss the weakest mechanical D E H L O link in a bullheading operation. PE S Identify whether it is mechanical or formation limitations that D E H L O determine the maximum surface PE S pressure that can be applied. Interpret data on a kill log and select possible kill problems (e.g., D E H L O not maintaining pressure; PE S abnormal changes to casing annulus pressure; SPM variations).

Explain how to verify if well has D E H L O been successfully killed. PE S List reasons why record keeping D E H L O during a Bullhead operation is PE S important. Explain when to use the Volumetric Method (e.g., when When to use the you are unable to circulate; when D E H L O Volumetric Method there is no SITP to monitor; when PE S you are off-bottom; when you are out of the hole). Explain the basic principles of the Volumetric Method Volumetric Method (e.g., pressure D E H L O Basic principles increase and controlled bleed off PE S cycles). Summarize actions to take once Action(s) to take once the influx reaches the surface D E H L O an influx reaches the (e.g., wait for equipment; PE S BOP snubbing options; lube and bleed).

Explain the lube and bleed D E H L O method. PE S

Describe the advantages and D E H L O disadvantages of lube and bleed. PE S Describe the well types where lube and bleed would be applied Definition, as opposed to other intervention D E H L O Lube and Bleed Application, and methods or wellbore conditions PE S Calculation (i.e., snubbing, coiled tubing, wireline, annulus kill). Calculate pressure per unit of D E H L O volume in lube and bleed PE S operations. Explain the importance of a D E H L O pumping schedule for lube and PE S bleed operations.

Develop a pump schedule for lube D E H L O and bleed operations. PE S

Describe the difference between D E H L O safety and working margins. PE S

Explain forward circulation D E H L O (driller’s) method. PE S Describe the well types and conditions where forward D E H L O circulation (driller’s) method PE S would be applied. Describe the advantages and D E H L O disadvantages of forward PE S circulation (driller’s) method.

Calculate maximum pump D E H L O pressure. PE S Determine the effect on BHP D E H L O when circulating with tools and PE S Definition, equipment. Forward Circulation Application, and (Driller’s) Method Explain frictional pressure loss of D E H L O Calculation pumped fluids vs. rate. PE S Demonstrate a detailed forward S circulating (driller’s) method (Must be taught through example on a simulator. Simulation) Interpret data on a kill log and select possible kill problems (e.g., not maintaining pressure; D E H L O abnormal changes to casing PE S pressure; choke opening size; pit levels; SPM variations). Explain how kill procedures can impact BHP (i.e., changing SPM; D E H L O changing fluid weight; not PE S following pressure chart; incorrect startup or shutdown procedure).

D E H L O Explain reverse circulation. PE S Describe frictional losses in D E H L O different well sections (slimhole, PE S tight tubing/casing clearances). Determine the effect on BHP D E H L O when circulating with tools and PE S Applying Reverse equipment. Reverse Circulation Circulation method Explain the main differences between a normal forward circulation kill technique and a reverse circulating technique (i.e., D E H L O position of choke in the circulating PE S path, start-up procedure, tubing string friction, different fluids in the well, integrity of circulating path, high frictional pressures). Explain the importance of using startup and shutdown procedure D E H L O in a well kill (e.g., to maintain PE S Startup/Shutdown BHP). procedures Demonstrate a startup and S shutdown procedure including (Must be taught through communication with pump Simulation) operator on a simulator. Explain the action to take to Pump Startup and determine the Initial Circulating D E H L O Shutdown Procedure Pressure (ICP) if a Slow Circulating PE S Rate (SCR) has not been recorded. Action(s) to take if a Determine the action to take if the D E H L O Slow Circulating Rate shut-in pressures are not the same PE S (SCR) has not been following the first circulation. recorded Demonstrate how to maintain constant BHP when an influx is S being circulated through the (Must be taught through choke lines and choke on a Simulation) simulator.

Explain why pump startup Why startup pump pressure may differ from pre- pressure may not calculated ICP and what action(s) D E H L O equal Initial to take after establishing a PE S Circulating Pressure circulation rate (i.e., discuss the (ICP) situation; monitor pressures as gels are broken down). Why pump pressure Explain why a shutdown may not at shutdown may not return shut-in pressure to the D E H L O equal expected expected value (e.g., safety PE S pressure factors; trapped pressure). Explain or demonstrate how to compensate for lag time between D E H L O Lag time a choke adjustment and pump PE S pressure change. Determine the action(s) required to verify a well is dead before Verifying the well is opening up the BOP (e.g., use the D E H L O dead following kill shutdown procedure; check for PE S procedure trapped pressure; monitor through choke; and use circulating practice once the well is open). Instructor Resources:

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2.15 Special Situations

Blockages & Trapped Effect of blockages in Identify types of blockages (i.e., D E H L O

Pressure in retaining trapped sand bridges, paraffin, tubing PE S Tubing/Wellbore pressure plugs, tools across Xmas tree).

Identify potential well control D E H L O complications with trapping PE S pressure below blockages. Describe where paraffin / asphaltenes / scaling is Effect of blockages in encountered and problems caused Blockages & impeding the ability to (i.e., commonly found in older oil D E H L O Restricted Access in run tool string in or producing wells; prevent tools PE S Tubing/Wellbore out of the wellbore from being run in to and out of the hole; plug up valves and surface equipment). D E H L O Define hydrates. PE S

Explain how hydrates can D E H L O Effect of Hydrates complicate well control. PE S Hydrates while Circulating Describe typical hydrate removal D E H L O techniques. PE S

Identify preventive measures to D E H L O inhibit hydrate formation. PE S Explain H S and equipment 2 D E H L O limitations based on H S 2 PE S concentration. Describe additional procedures, precaution and supplemental D E H L O safety equipment necessary, fluid PE S Effect of H2S on Well scavengers, inhibitors while H2S considerations Control Methodology operating in an H2S environment. Describe equipment addition, limitations, modification or replacement necessary to work in D E H L O an H2S environment (i.e., tubular PE S or wireline embrittlement and seals).

Explain safety considerations on D E H L O safely bringing H2S to the surface. PE S Explain how to react to problems and, if necessary, mobilize the How to respond to crew (i.e., shut down, realign the problems that can D E H L O manifold line-up, change the happen during the PE S choke, change the pump, and well kill correct any mud pit/weight management issues). Analyze the communication modifications that may be Organizing abnormal necessary because of an abnormal D E H L O operations during well operation and describe how PE S control events communications could be handled if differing from standard personnel assignments. Explain importance of key Managing Change components of handover During a Well Kill procedures during a well kill operation and the complications created with poor handover (i.e., there must be clear Handover/ changes to communications between D E H L O personnel during a Supervisors and other crew PE S well kill operation 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). Identify and communicate trends Kill log as a tool for on a kill log (e.g., pressures; D E H L O troubleshooting volumes; fluid weights; the choke PE S unplanned events position; shutdowns/startups).

Assess well data and determine corrective action to take for problems (i.e., incorrect mud D E H L O Problems with the kill pumped; run out of weighting PE S material; weather problems; ram or annular failure; plugged string; rig power failure). Identify when the plan is not successful and decide on the corrective action to take at that “Stopping points” that point (e.g., a problem maintaining D E H L O indicate the kill plan surface pressure; casing pressure PE S was not working and pit volume changes not going according to plan; possible points to stop the kill to check pressures). Identify the importance of D E H L O reassessment of the current plan PE S Management of and techniques used. Change Discuss the importance of D E H L O communicating the revised plan. PE S Describe or discuss how MASP can be exceeded during well intervention operations being D E H L O influenced by hydraulic fracturing PE S Complication with Pressure Limits and nearby hydraulic fracturing Hydraulic Fracturing Created by Hydraulic operations (e.g., SIMOPS). Operations Fracturing Operations Discuss additional precautions to be taken to address the risk of D E H L O casing burst (e.g. placement of PE S equipment and personnel).

Describe and discuss the potential complications of wireline, coiled tubing, and snubbing operations rigged up on a drilling rig’s well control system (e.g., Use of a D E H L O Drilling Operations Rig-up Complications shooting nipple, connection from PE S PCE to rig BOP stack, free standing tubular, PCE requirements, securing riser in BOP pipe rams, and testing connections). Identify circumstances where shearing/cutting the wireline may D E H L O be required (e.g., leak at PE S connection between production Cutting Wireline with Wireline Shear Seals tree and wireline valves). Shear Seal Discuss why using shear seal ram is a method of last resort and the D E H L O consequences of using shear seal PE S ram. Identify tools and pressure control considerations necessary for successful fishing operations (e.g., size of fish, size of lubricator, D E H L O length of lubricator, redundant PE S Fishing Wireline Retrieving Wireline wireline valves, proper rams for fishing wire and wire size being fished). Describe the differences between D E H L O fishing with wireline in pressured PE S and non-pressured environment.

Describe when a guide ram is D E H L O used. PE S Special BOP Rig-Up Identify special situations that Equipment D E H L O would use guide tubes in a BOP PE S stack to prevent pipe buckling.

Identify special situations when a D E H L O telescoping tubing guide would be PE S used in the jack. Identify special situations when an D E H L O IBOP or downhole check valves PE S are run in the string. Explain or demonstrate actions to Encountering take when encountering D E H L O Unexpected Pressure unexpected pressure and what are PE S the causes.

Explain preventative measures to D E H L O take to prevent slip bowl failures. PE S Given a scenario, explain the Slip bowl failure potential impact and the action to D E H L O be taken in the event of slip bowl PE S failure on the immediate operation. Explain preventative measures to D E H L O Planned Responses take in relation to power unit or PE S to Anticipated Well Power unit or hydraulic circuit failure. Control Scenarios hydraulic circuit Given a scenario, explain the failure while in the potential impact and the action to D E H L O hole be taken in the event of power PE S unit or hydraulic circuit failure on the immediate operation. Explain preventative measures to D E H L O take in relation to stripping PE S annular element failures. Stripping annular Given a scenario, explain the element failure potential impact and the action to D E H L O be taken in the event of stripping PE S annular element failure on the immediate operation.

Explain preventative measures to take in relation to a leak below D E H L O BOP stack and/or PCE (e.g., flange PE S connections torqued properly, Leak below BOP stack stack is secured from movement). and/or PCE Given a scenario, explain the potential impact and the action to D E H L O be taken in the event of a leak PE S below BOP stack and/or PCE on the immediate operation. Explain preventative measures to D E H L O take in relation to pressure at PE S surface inside the work string. Pressure at surface Given a scenario, explain the inside the work string potential impact and the action to D E H L O be taken in the event of pressure PE S at surface inside the work string on the immediate operation. Explain preventative measures to D E H L O take in relation to a leak in the PE S stripper PCE ram. Leak in the stripper Given a scenario, explain the PCE ram potential impact and the action to D E H L O be taken in the event of a leak in PE S the stripper PCE ram on the immediate operation. D E H L O Explain tubular buckling. PE S Describe where tubular buckling D E H L O Buckling of tubulars may occur (e.g., supported and PE S unsupported).

Identify factors that may impact D E H L O tubular buckling. PE S

Explain the action to take to make the operation safe while D E H L O maintaining control of the well PE S during buckling of string. Explain preventative measures to D E H L O take in relation to buckling of PE S string in BOP stack. Explain the impact of buckling of D E H L O string in BOP stack on the PE S immediate operation. Explain the action to take to make the operation safe while D E H L O maintaining control of the well PE S during parting of string. Explain preventative measures to Parting of string D E H L O take in relation to parting of PE S string. Explain the impact of parting of D E H L O string on the immediate PE S operation. Instructor Resources:

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2.16 Testing

volume (i.e., compressibility) PE S when testing downhole Testing of Downhole equipment for integrity. Completion Packers and Plugs Monitor flow back for proper flow Equipment back volume due to D E H L O compressibility fluids, volumes PE S greater than expected could indicate a failed test. Explain that the qualification of Testing of well control equipment as a Testing of Well Connections barrier requires testing the D E H L O Control Equipment a. Rig BOP connection below the lowest PE S Connections b. Wireline Valve closing ram (e.g., rig BOP, wireline c. Well Control Stack valve, Well Control Stack, wellhead). Instructor Resources:

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2.17 Well Control Drills

Explain the importance of and D E H L O Trip Drills procedure for trip drills. PE S

Explain the importance of and D E H L O Choke Drills procedure for choke drills. PE S Well Control Drills List the various action drills applicable to wireline, coiled tubing, and snubbing operations (e.g., loss of primary well barrier D E H L O Various Action Drills for braided or conductor line, loss PE S of primary well barrier for slick line, loss of power to unit, leak above secondary barrier, leak below secondary barrier). Instructor Resources:

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2.18 Government, Industry and Company Rules, Orders and Policies

DELIVERY METHODS LEARNING OBJECTIVE AND MANUAL CHAPTER & PAGE # SUB-MODULES LEARNING TOPICS Options: D, E, H, L, O, PE, S (See ASSESSMENT GUIDELINES (Multi-line text field) instructions above; select all that apply.) API and ISO recommended Describe or identify appropriate D E H L O practices, standards industry standard or and bulletins recommended practice pertaining PE S pertaining to well to job being completed. control Incorporate by Regional and/or local Describe or identify appropriate Reference D E H L O regulations where regional government regulations PE S required pertaining to job being completed. Describe or identify appropriate Company/operator company or operator specific D E H L O specific requirements requirements pertaining to job PE S where required being completed. Instructor Resources:

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2.19 Ancillary Considerations

DELIVERY METHODS LEARNING OBJECTIVE AND MANUAL CHAPTER & PAGE # SUB-MODULES LEARNING TOPICS Options: D, E, H, L, O, PE, S (See ASSESSMENT GUIDELINES (Multi-line text field) instructions above; select all that apply.) Describe the functions of fluid-gas D E H L O Fluid-Gas separators Purpose and location separators. PE S

Explain the operating parameters (e.g., maximum operating D E H L O pressure, vent line diameter, u- PE S tube height; and potential dangers Operating parameters and action to take if overloaded). Calculate the water leg for D E H L O determining the effective PE S operating pressure.

Describe the various requirements D E H L O for zone classification. PE S Explain the importance of Electrical Hazardous Area Zone equipment classifications for designated zones (e.g., Classification Classification D E H L O hydrocarbon handling when PE S bleeding off lubricators and risers, proximity to ignition sources, routed away from work area). Instructor Resources:

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Required:

Total Time Range for Course:* hours minutes to hours minutes

*The minimum delivery time shall not fall below the minimum time requirement for the course, as stated in accreditation requirements.