Well Control Institute (WCI) Core Curriculum and Related Learning Outcomes: Supervisory Level

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1 Well Control nstitute (WC) Core Curriculum and Related Learning Outcomes: Level Revision 4B ay 14, 2014 Prepared by Black & Veatch Corp. DRAFT WORK PRODUCT FOR NDUSTRY COENT

2 Well Control nstitute (WC) Contents 4. Supervisor Level Overview Drilling, Workover, Completion Plan Technical Principles ud & Pit anagement Pre- Kick Data Pore Pressure Prediction Kick Awareness during Drilling, Workover, & Completion Operations Barriers Kick Detection & Drills Shallow Gas/Water Flows & Top Hole Drilling Shut- n Procedures & Verification Well Control/Risk anagement Well Control ethods Equipment Readiness/Assurance Extract of Subsea Elements Page 1 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT

3 Well Control nstitute (WC) 4. Supervisor Level Overview The purpose of the core curriculum is to identify a body of knowledge and a set of job skills that can be used to provide well control skills for drilling operations. This curriculum incorporates both surface and subsea topics. The majority of the topics are relevant to both surface and subsea operations. Those topics specific to subsea are in a BLUE font. To assist the user, all Subsea topics have been extracted into Section Recommended Attendees: WC recommend the following Job Positions attend the Supervisor Level course: Wellsite Supervisors, Company men and assistants PD/UBD Wellsite supervisors Office- based drilling supervisors/superintendent (not involved with well design approval) Office- based rig, drilling manager O for mobile offshore drilling units Rig anager (shore- based/superintendent (land)) Rig Superintendent offshore (most senior offshore leader for drill crew, may be the O) Toolpushers Note: Blue Text = Subsea Black Text = Common to Surface and Subsea Page 2 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT

4 4.1. Drilling, Workover, Completion Plan Well Control nstitute (WC) *A = Awareness of learning topics at this job level odule Name: Drilling, Workover, Completion Plan = mplements learning topics at this job level = astery of learning topics at this job level Learning Topics A* Learning Objectives Assessments and Learning Outcomes Well Work Objectives Fracture Gradients and Pore Pressures Casing & Cementing Program Reasons for Workover Completion Program A A A A A Key elements of the drilling, work over, completion program that are important to ensure control and containment of formation fluids at all times during rig operations. The importance of knowing the Fracture gradients and pore pressures in the well. The role of casing and cementing in the drilling of a well and for containing formation fluids. Why wells have to be worked over. ajor well control differences between drilling a well and a 'workover'. ajor well control differences between drilling a well and completing a well. dentify key elements of the well program that the Supervisor applies to kick prevention. dentify the importance of knowing Fracture Pressures and Formation Fluid Pressures (Pore Pressures) when drilling, completing and workovers. dentify the role/s of casing and cementing in a well. dentify reasons for a workover. Differentiate between well control operations normally related to drilling operations and those related to workover. Differentiate between well control operations normally related to drilling operations and those related to completions. Fluids Program A Why a well- designed drilling and completions fluid program is important to containment of dentify key functions of a fluids program formation fluids. Barrier anagement A The term Barrier anagement. Select definition of Barrier anagement Well Control Equipment Selection A Why BOP selection is essential to containment of formation fluids Select reason why a BOP has to be selected to meet the requirements of the formations drilled. Page 3 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT

5 Well Control nstitute (WC) 4.2. Technical Principles odule Name: Technical Principles Learning Topics A* Learning Topics Assessments and Learning Outcomes The principle of a U- tube. Select correct definition of a U- Tube. Calculate pressures on each side of a u- tube. State what would happen if a certain weight of fluid was pumped into the u- tube and how this might affect hydrostatic How the model of a u- tube works during a pressure and pump pressure: e.g. effect on mud level in the well kill. two legs of the u- tube; effect of surface pressures if end of u- tube is sealed by BOP or Valve. Principle of U- Tube Pump Pressure Effects & Circulating Friction Pressures The effect of the u- tube when pumping kill weight mud during a kill operations tripping. How the u- tube can assist in calculating displacement position of cement. Friction and pump pressure. How friction in the different sections of the well contribute to final pump pressure. How mud weight, viscosity, flow rate and hole geometry affects pump pressure. Calculate changes in pump pressure due to changes in pump speed and mud weight. Calculate SDPP if kill is shut down with kill mud being circulated to Bit. Calculate mud returns following displacement of a heavy weight slug into the drill string prior to tripping: e.g. how much mud should return back at surface from a given weight and volume of slug. Calculate top of cement position once displaced into position Select correct statement when defining friction in the well or pump pressure Describe how frictional losses around the circulating system result in pump pressure: e.g. sum of losses in surface lines, drill string, bit and annulus. Recognize how mud properties, hole geometry and flow rate affect the pump pressure and the effect of pumping a different weight fluid around the well (u- tube effect). Using standard industry formula calculate effect of SP and ud Weight changes on pump pressure. Page 4 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT

6 Well Control nstitute (WC) odule Name: Technical Principles Learning Topics A* Learning Topics Assessments and Learning Outcomes Kick Tolerance and how it is expressed. Define the term Kick Tolerance: e.g. general definition, explain the limitation of maximum pressure and volume of a kick to safely shut- in and circulate kick to surface The assumptions used in the kick tolerance calculation. State common assumptions used when calculating kick tolerance: e.g. increase in pore pressure, maximum kick size. Planning & Use a kick tolerance graph showing kick intensity versus kick Operational Kick volume to obtain kick tolerance: e.g. identify initial shut- in ethods to obtain Kick Tolerance Tolerance kick tolerance and circulating kick tolerance, aware of alternative ways to calculate the value. State options available if a low kick tolerance is established: Options available if Kick Tolerance is low. e.g. set casing, shut- in immediately, enhanced well monitoring for warning signs. Options if well kicks with zero kick tolerance. State options available with zero kick tolerance The term formation strength. Select the correct definition of formation strength Why we need to determine Formation State why knowledge of formation strength is important in Strength. the drilling process. Formation Stresses & Strength How formation strength can be determined on the rig using Formation ntegrity Test or Leak Off Test (FT/LOT). The key preparation tasks to ensure an accurate FT/LOT The term aximum Allowable ud Weight (AW). How to calculate Fracture Pressure and aximum Allowable ud Weight (AW). Page 5 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT Select reason why we need to know formation strength: e.g. to determine maximum pressure than can be safely applied to the open hole shoe formation List key tasks to carry out to ensure an accurate LOT/FT result: e.g. clean hole, consistent mud weight around well, calibrated pressure gauges, surface equipment tested for leaks, Select correct definition for aximum Allowable ud Weight. Calculate Formation Fracture pressure and AW from FT or LOT data.

7 Well Control nstitute (WC) odule Name: Technical Principles Learning Topics A* Learning Topics Assessments and Learning Outcomes State actions that can be taken if formation strength is lower Possible action/s to take if AW is too low than expected: e.g. carry out cement squeeze, repair casing if for expected formation fluid pressures in next damaged, adjust drilling program to accommodate lower hole section. fracture strength. The term aximum Predicted Surface Pressure. Select the correct definition of ASP aximum Predicted Surface Pressure & aximum Allowable Annular Surface Pressure (AASP) Equivalent Circulating Density (ECD) & Bottomhole Pressure (BHP) How aximum Predicted Surface Pressure is used in well design and the consequences of exceeding maximum pressure limitations. The term aximum Allowable Annular Surface Pressure (AASP). Why a knowledge of maximum allowable and maximum predicted pressures important in drilling operations. How to calculate AASP. When AASP must be recalculated. Difference between Static and Dynamic AASP The term bottom hole pressure (BHP). How BHP can be different from hydrostatic pressure. The importance of having the correct bottom hole pressure (BHP). The term ECD. Page 6 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT Describe why ASP is important to Well Control/ntegrity: e.g. consequences of exceeding maximum pressure limitations, BOP selection, casing burst selection, wellhead rating, surface manifolds pressure rating. Select the correct definition of AASP Describe the potential consequences of exceeding AASP or AW on well control/integrity: e.g. lost circulation, mud level drop, potential kick, downtime. Using Formation Strength data calculate AASP using formula or kill sheet. State when AASP needs to be re- calculated. State the difference between the terms Static AASP and Dynamic AASP Select the correct definition of bottom hole pressure Distinguish between hydrostatic pressure and bottom hole pressure: e.g. Static versus circulating bottom hole pressure, cuttings loading, shut- in pressure, pipe movement. Describe why correct bottom hole pressure is so important to well control/integrity Select the correct definition of ECD

8 Well Control nstitute (WC) odule Name: Technical Principles Learning Topics A* Learning Topics Assessments and Learning Outcomes How ECD is derived (formula not required). State how ECD is derived (formula not required): e.g. from calculated annular friction losses. How ECD affects bottomhole pressure. Describe how different operations can impact ECD and the resulting effect on bottom hole pressure: e.g. reduction when pumps are stopped at connections or flow checks, circulation across flowline versus circulating through subsea choke or kill line, pumping out of the hole, circulating cement, high viscosity pills, pumping lost circulation material Describe the process of ECD drilling state the potential well control problems that can arise from this process: e.g. The principle of ECD drilling and associated underbalance on connections, connection gas, gas issues in well control problems. long marine Risers, narrow drilling window, mud weight displacement for tripping. Gas Behavior in Fluids How the relatively low density of gas affects the hydrostatic pressure. The relationship between pressure and volume of a gas in the wellbore. Why a gas kick must expand as it is circulated up the wellbore. The term gas migration Page 7 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT Select the effects of gas on wellbore mud hydrostatic and bottom hole pressure: e.g. reduces pressure as gas expands, may cause underbalance, gas- cut mud at surface effect, re- circulating gas- cut mud. Describe the correct relationship between gas pressure and gas volume: e.g. Boyles Law concept to explain pressure/volume relationship, most expansion close to surface. Carry out basic calculation using Boyles Law State why the pressure of gas in the mud must be reduced in a controlled manner as it is brought to surface (circulated up hole): e.g. if not allowed to expand gas will increase wellbore pressures, danger of allowing it to expand uncontrolled (reduced hydrostatic, well kick, Riser unloading), circulating through choke to maintain bottom hole pressure. Select correct definition of gas migration

9 Well Control nstitute (WC) odule Name: Technical Principles Learning Topics A* Learning Topics Assessments and Learning Outcomes The consequences of gas migration. Predict the consequences of gas migration in the wellbore and on associated pressure gauges. e.g. n a shut- in well, in an open well, migration rates, effect of hole angle How gas normally behaves in a water- based mud. Describe how gas generally behaves when circulated in a water- based mud and how this impacts detection. How gas normally behaves in an oil- based mud Describe how gas generally behaves when circulated in a non- aqueous mud. Describe the difficulty of detecting kicks with soluble gases while drilling and/or tripping. Select reasons why it can be difficult to detect kicks when gas is in solution in the mud: e.g. gas in solution, smaller volume increase seen on surface, flow rate and PVT accuracy for small influxes, effect of rapid expansion at bubble point. Compressibility and Temperature Effects on Oil Based Fluids (Non Aqueous Fluids (NAF)) and Brines Describe what happens to a gas as it is circulated through the choke from a high- pressure environment to a low- pressure environment. How downhole pressure can affect fluid weight. How mud temperature can affect mud properties. How downhole pressure and temperature can impact well control. Page 8 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT Select correct statements on gas behavior as it is circulated across the choke. e.g. rapid expansion overloading mud- gas separator, cooling effect on equipment, increase velocity and potential erosion, possible hydrate formation causing plugging. State how pressure affects fluid weight State how temperature affect mud properties: e.g. weight, viscosity and gel strength, potential for hydrate formation, effect on mud in subsea choke and kill lines, heat expansion, crystallization of brines Describe how pressure and temperature effects on the mud can impact well control: e.g. actual mud weight downhole, mud weight to mix on surface to get correct value downhole, potential ECD effects, potential change in downhole condition when circulating and not circulating; monitoring for flow.

10 Well Control nstitute (WC) odule Name: Technical Principles Learning Topics A* Learning Topics Assessments and Learning Outcomes Describe how the values of wellbore pressure and string How well pressure effects whether pipe can weight and annular preventer limitations impact the decision Snubbing/Stripping be stripped or snubbed into the well. to strip or snub into the well. Forces Describe the effect of buoyancy on forces required for Effect of buoyancy on calculations. stripping or snubbing. How to interpret Shut- n Pressures for a nterpret shut- in values for high angle wells and how they directional well. impact a well kill operation. Directional Well Effects on Well Control Tapered Drill String Effects How gas expansion and migration is affected in a highly deviated well The potential problems if standard vertical well- kill calculations are applied to killing of a highly deviated well. How tapered strings affect Trip onitoring How tapered strings affect Kill procedure State the effect of hole angle on potential for gas expansion and migration: e.g. minimal effect in horizontal section, significant change as it enters the build section. Describe the effect on bottom hole pressure id vertical well- kill calculations are use on a highly deviated well. Describe how a tapered string will impact trip monitoring values Describe how a tapered string will impact well control calculations: e.g. CP to FCP values 4.3. ud & Pit anagement odule Name: ud & Pit anagement Learning Topics A* Learning Topics Assessments and Learning Outcomes Describe how mud density is measured using atmospheric or aintaining Correct Two different methods to measure fluid pressurized mud- balances: e.g. reason for difference, ud Weight density and the reason for the difference. importance of calibration Page 9 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT

11 Well Control nstitute (WC) odule Name: ud & Pit anagement Learning Topics A* Learning Topics Assessments and Learning Outcomes mportance of regular mud property measurements in kick prevention. Select reasons why key mud properties are checked at the suction pit and shakers at regular time intervals: e.g. close monitoring of mud weight in and out, early recognition of problems, time between measurements, who should be told. anaging Pits during a Kill Operation anaging Pits during Wholesale Wellbore Displacements Role and responsibilities of drill crew personnel who are working with the pit system. Possible pit line- ups that can be used during a well kill operation How to handle volume increases due to influx expansion. Dangers of circulating formation fluids into surface pit system. Actions to take to reduce risks associated with formation fluids at surface. How drill crew should responsibilities when circulating out and killing a kick. The dangers of adding/transferring fluids to a pit system during active drilling/circulating operation. Actions to take in the event of a pit volume discrepancy. Page 10 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT Give instructions to crew on mud pit monitoring when drilling and during a well kill: e.g. pit measuring devices, mud weight readings, communication with rig floor, record keeping, contamination by light fluids. Demonstrate effective management of pit line- up for a kill operation. State actions to take to manage pit gains during a well kill: e.g. pre- planning, pit size, transfers. State dangers involved in circulating formation fluids into the surface pit system Describe how formation fluids are handled at surface during a kill operation: e.g. handling gas, handling oil/condensate, handling formation water. Give instructions to crew on roles and responsibilities during a well kill. e.g. weighting up mud, monitoring pit levels, switching suction when required, monitoring shakers, manifold line- ups, recording data, pump control. Select well control problems that can occur when displacing wellbore to a different weight of fluid: e.g. correct procedure to use when adding/transferring mud and potential to miss gains or losses. Select action to take in event of a pit level discrepancy: e.g. stop drilling, flow check, analyze pit level records

12 Well Control nstitute (WC) odule Name: ud & Pit anagement Learning Topics A* Learning Topics Assessments and Learning Outcomes State importance of correct pit level sensor calibration and mportance of correct calibration of different agreement in volumes between different sensors and pit measuring systems. recording devices Pre- Kick Data odule Name: Pre- Kick Data Learning Topics A* Learning Topics Assessments and Learning Outcomes Reason for taking slow circulating rates (SCRs). Give reasons for taking a SCR: e.g. calculate CP/FCP, detect potential leaks in system, required for wait & weight method Time/s an SCR should be taken. Select times that an SCR can be taken: e.g. at selected depth interval, mud property changes, hole geometry changes, every shift, pump output changes. Typical flow rate/sp for an SCR. Choose acceptable flow rate/sp for a SCR Slow Circulating Which gauges are commonly used to read the Rates (SCR) SCR value. Select gauges to use to record a SCR Choke Line Friction (CLF) What can affect SCR readings and why SCRs may not be 100% accurate for well kill operations. Reason for taking choke line frictions (CLFs). Page 11 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT Give reasons why a SCR may not be accurate and could impact a well kill: e.g. if taken immediately after a trip or extended non- circulating time, different mud weights in hole at time of test, inaccurate result can lead to incorrect kick circulating pressure, using it only as a guide to 'actual' pressure generated by 'start- up' procedure. Give reasons for taking a CLF: e.g. used in well kill start- up procedure, potential increase in bottom hole pressure if used incorrectly or during latter stages of well kill, detect potential leaks in system.

13 Well Control nstitute (WC) odule Name: Pre- Kick Data Learning Topics A* Learning Topics Assessments and Learning Outcomes Time/s a CLF should be taken. Select times a CLF can be taken: e.g. mud property changes, pump output changes Choke & Kill Line Fluid Densities Typical flow rate/sp for a CLF. Which gauges are commonly used to read the CLF value. The effect of taking the CLF on bottom hole pressure. What effect choke and kill line fluid densities, that are different from the fluid density in the wellbore, have on preparations to kill a well. Choose acceptable flow rate/sp for a CLF Select gauges to use to record a CLF Given various techniques for recording CLF state the effect on bottom hole pressure. Describe the effect on SCP of a choke or kill line having a different fluid density than that in the well and possible action to take prior to killing the well Pore Pressure Prediction odule Name: Pore Pressure Prediction Learning Topics A* Learning Topics Assessments and Learning Outcomes PWD/LWD Data How data from downhole tools such as LWD and Resistivity can help detect changes in formation fluid pressure. Give basic description of downhole tools that can enhance detection of increasing formation pressure or reduction in overbalance margin. Page 12 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT

14 Well Control nstitute (WC) odule Name: Pore Pressure Prediction Learning Topics A* Learning Topics Assessments and Learning Outcomes nterpret observations and trends at Shakers that may help Shaker Evidence crew members identify potential well control problems: e.g. How the returns at the shale shaker can visual condition of mud, cuttings load, cuttings shape, identify potential kick conditions. sloughing shales (cavings), gas- cut mud, mud weight and viscosity. Changes in ud Properties Changes in Drilling Data/Parameters ud Weight anagement in Transition Zone Drilling Trend Analysis How mud properties that can be affected by potential kick conditions, e.g. (gas cutting, chlorides, temperature) How drilling parameters are affected by potential kick conditions (e.g., ROP, torque, drag) Transition Zones. Actions that may need to be taken during drilling of a transition zone. Reason why mud weight management is important in a transition zone. Abnormal pressure and how it affects primary control. Page 13 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT nterpret observations and trends in mud data that may help crew members identify potential well control problems: e.g. weight, viscosity, gas cutting, background gas increases, trip gas, connection gas, mud chlorides, mud temperature nterpret observations and trends in drilling parameters that may help you identify potential well control problems: e.g. ROP changes (drilling break), torque, drag, pump pressure decrease Define the term transition zone in relation to Abnormal pressure State actions that may need to be taken during transition zone drilling: e.g. regular flow checks, enhanced mud weight monitoring in pits and shakers, enhanced logging of drilling and gas parameters by Driller and ud Logger, enhanced 'fingerprinting' of flowback at connections, increased awareness of essential crew to warning signs, use of PWD/LWD. Give reason why good mud weight management is required during transition zone drilling: e.g. formation pressure are rising and mud weight must be adjusted to prevent losing overbalance margin. State how Abnormal pressure affects primary control in the wellbore

15 Well Control nstitute (WC) odule Name: Pore Pressure Prediction Learning Topics A* Learning Topics Assessments and Learning Outcomes Common trends in the warning signs that can dentify trends in mud, shaker and drilling data that indicate indicate increasing formation fluid pressure potential abnormal pressure development (transition zone) (or a reduction in Overbalance). Actions the Supervisor must take when warning signs are recognized. Role and responsibilities of various rig floor crewmembers in monitoring for warning signs. State appropriate actions a Supervisor must take when warning signs are noted: e.g. analyze, compare different trends. List responsibilities of key team members in the monitoring of trends: e.g. Driller, ud Logger, ud Engineer, Company representative, geologist, drilling engineer Kick Awareness during Drilling, Workover, & Completion Operations odule Name: Kick Awareness during Drilling, Workover, & Completion Operations Learning Topics A* Learning Topics Assessments and Learning Outcomes Use of trip sheet to determine if hole fill is Analyze a trip sheet for signs of abnormal hole fill: e.g. normal or abnormal. swabbing, surging. Tripping Operations Non- Shearables Action/s to take if hole fill readings are abnormal. Considerations for trip tank capacity in large volume operations. Running non- shearables. Well flows with a non- shearable across the BOP. Page 14 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT State action to take if trip tank readings show swabbing or surging: e.g. flow checks, returning to bottom, lost circulation remediation. State how to monitor large volume operations on a trip tank. State standard procedures to follow before running non- shearables. State action to take if well flows with a non- shearable across the BOP.

16 Well Control nstitute (WC) odule Name: Kick Awareness during Drilling, Workover, & Completion Operations Learning Topics A* Learning Topics Assessments and Learning Outcomes Classification of loss Classify loss rates: e.g. seepage, minor, major Handling Losses State first actions to take for each of the loss types: e.g. Actions to take for each of these loss types. monitor, maintain hole full, add base fluid, monitor volumes pumped, shut- in. Ballooning ssues Casing & Cementing Operations The term wellbore ballooning. Recognition of Ballooning. First action to take if a Supervisor suspects Ballooning. How Ballooning can be distinguished from a Kick at shut- in. Procedure for bleeding down ballooning. Factors that increase risk of swabbing and surging during casing running/pulling operations. Casing displacements and how often casing should be filled when running in hole. Precautions to take when running self- fill/automatic casing shoe floats. Page 15 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT Define the term ballooning Select surface data that can help the Supervisor determine if it is ballooning. Select correct action to take if ballooning is suspected. Analyze fingerprinting, shut- in and bleed back data to decide if well is ballooning or kicking: e.g. compare flow rate with flow back fingerprint, shut- in pressures versus ECD effect, pressures after bleed back, bleed back rate. Describe procedure to bleed down ballooning and dangers associated with the bleed back process: e.g. bleed back amount, circulate bottoms- up, route through choke, danger of gas bled into well, gas expansion, gas in Riser. State what can increase risk of swabbing and surging during casing operations: e.g. narrow clearance, mud condition, running or pulling speed, heave at connections, casing jewelry. Calculate casing displacements required for monitoring the hole and casing fill- up. State precautions when running self- fill/automatic floats: e.g. what can cause mechanism to fail, manually fill to check system is functioning, monitor weight of string.

17 Well Control nstitute (WC) odule Name: Kick Awareness during Drilling, Workover, & Completion Operations Learning Topics A* Learning Topics Assessments and Learning Outcomes Wellbore Fluid Displacements Well control risks if a self- fill float fails to convert. Equipment required to shut- in on a kick when running casing or during and after cementing. Effects of a cementing operation on BHP. mportance of following recommendations based on cement pilot testing before beginning follow up operations. onitoring wellbore flow rates/pit levels during the cementing and displacement. How well is monitored during cement waiting time. How final pumping pressure can be used to calculate cement height in the annulus. Common practices when displacing wellbore fluid to a lower density fluid. Select statements regarding problems of a self- filling float that does not convert: e.g. allows formation fluids to flow directly up inside the casing, allow cement to backflow up inside casing. State equipment used to shut- in on a kick while casing or cementing: e.g. circulating head State effect of cement hardening on cement hydrostatic and how that affects well control: e.g. reduction in hydrostatic Select reason/s why cement waiting time is critical to well control. State how to monitor flow rate during cement operations: e.g. expected increases while pumping cement, expected pit levels during displacement by mud, stabilized flow rate, monitoring correct pits, handling contaminated return volumes. State how to monitor the while waiting on cement: e.g. annulus flow, flow inside casing, detecting small amounts of flow over time. Calculate height of cement in annulus based on pump pressure at final displacement or final expected pump pressure at planned displacement. Select kick prevention monitoring practices to employ during displacements to lighter fluid: e.g. maintain accurate volume control at all times, monitor flow rates, expected pumping pressures. Page 16 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT

18 Well Control nstitute (WC) odule Name: Kick Awareness during Drilling, Workover, & Completion Operations Learning Topics A* Learning Topics Assessments and Learning Outcomes Wireline Operations Negative Testing Riser argin Point at which a low- density displacement causes a negative pressure across a barrier. Potential causes of a kick during wireline operations. Common kick prevention practices during wireline operations. Negative testing Common procedure for carrying out a negative test. Riser argin. Calculate Riser argin. Using data provided calculate when hydrostatic pressure above a barrier exerts a negative pressure across that barrier. Select possible causes of a kick during wireline operations: e.g. swabbing, free gas migrating and expanding, barite settling. State kick prevention practices while wirelining: e.g. monitor fluid displacement on trip tank, stable mud condition, effects of temperature changes on mud expansion/contraction. Define the term negative test. Describe common procedure for carrying out a negative test. Define the term Riser argin Using given data calculate Riser argin 4.7. Barriers odule Name: Barriers Learning Topics A* Learning Topics Assessments and Learning Outcomes Barriers and Barrier Systems. Define the terms barrier and barrier system Philosophy and For typical drilling operations state how barriers maintain well Operations How barriers are used to maintain well integrity: e.g. role of mud, cement, casing, BOP, String Valves, Requiring Barriers integrity in drilling and casing operations. Packers. Page 17 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT

19 Well Control nstitute (WC) odule Name: Barriers Learning Topics A* Learning Topics Assessments and Learning Outcomes For typical casing & cementing operations state how barriers maintain well integrity: e.g. role of mud, cement, previous casing, BOP, inside casing non return valves Effect of subsea BOP on barrier location State location of barriers at sea- floor and effect if breached: e.g. gas in Riser with only Diverter as a barrier, effect of formation breakdown around wellhead, impact of blowout at sea bed, option to unlatch or ESD The minimum number of barriers required for Number of Barriers Select the minimum number of barriers for normal operations safe operations and why. for Safe Operation Number of barriers for given well designs. dentify the number of barriers present in a given well design How common mechanical barriers are tested to ensure well integrity. Select definition of positive and negative testing for barriers Testing Barriers Describe how a failed barrier can be detected: e.g. flow from How to recognize a failed barrier. the well, losses to the well, increase in surface pressure when shut- in Kick Detection & Drills odule Name: Kick Detection & Drills Learning Topics A* Learning Topics Assessments and Learning Outcomes Define a Flow Check. Select the correct definition of a flow check Recognize the need to carry out a flow check and take Well Flow with How to carry out a flow check. required action: e.g. difference between tripping and drilling Pumps Off flow check Action to take if flow check is positive. State action if flow check is positive: e.g. difference between tripping and drilling operation. Page 18 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT

20 Well Control nstitute (WC) odule Name: Kick Detection & Drills Learning Topics A* Learning Topics Assessments and Learning Outcomes How the trip tank can be used for a flow check. State how to carry out a flow check using the Trip Tank: e.g. line up on trip tank and monitor flow Surface and subsurface conditions that can make it difficult to decide if well is flowing Select surface and subsurface conditions that may make it difficult to identify if the well is flowing: e.g. inoperable flow meter, rig movement, dumping trip tank, low permeability formation, small underbalance, ECD effects, gas solubility. How to react to flow if ballooning is suspected. Select correct reaction to well flow that may be due to ballooning: e.g. initially assume an influx and shut- in, make assessment for ballooning criteria. Pit Gain Why pit levels are closely monitored at all times. Acceptable alarm limits for pit levels. What operations can increase or decrease pit level that are not related to flow or losses in the well. Conditions on surface that can make it difficult to get accurate pit level readings. State action to take in event of abnormal pit level Select reasons why it is important to monitor pit levels at all times the rig is connected to the well: e.g. open hole always has a potential to flow, tested barriers may fail. Choose acceptable values for high and low level alarms set on PVT. Select surface operations that can give false pit level indications of a kick or losses: e.g. surface additions of fluid, fluid transfers, ballooning, gas solubility, losses through mud cleaning equipment, leaks Select surface conditions that may make it difficult to accurately measure pit level: e.g. inoperable pit level sensors, rig movement, incorrect line up of circulation system, mixing mud, dumping or transferring fluid/by- pass shakers, tides, riser not connected, use of riser boost line Select correct action to take for a pit level increase/decrease: e.g. flow check, shut- in, investigate other options such as pit line- up only after shut- in. Abnormal Trip Tank returns when tripping dentify abnormal trip tank readings from a trip sheet: pipe or wirelining. e.g. identify abnormal readings on a trip sheet. Page 19 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT

21 Flow Returns Rate ncrease Well Control nstitute (WC) odule Name: Kick Detection & Drills Learning Topics A* Learning Topics Assessments and Learning Outcomes Select reasons why it is important to monitor flow rates at all Why flow rates are closely monitored at all times the rig is connected to the well: e.g. open hole always times. has a potential to flow, tested barriers may fail. Acceptable alarm limits for flow rates. Choose acceptable values for high and low level alarms for Flow Rate. Pit Drills Trip Drills Stripping Drills Choke Drills State what operations can increase or decrease flow rate that are not related to increased flow or losses in the well. Conditions on surface that can make it difficult to get accurate flow rate readings. Action to take in event of an abnormal flow reading Reason for regular Pit Drills. Roles and responsibilities of rig crew personnel for a Pit Drill. Reason for regular Trip Drills. Roles and responsibilities of rig crew personnel for a Trip Drill. State reason for Stripping Drills. Roles and responsibilities of rig crew personnel for a Stripping Drill. State reason for Choke Drills. Roles and responsibilities of rig crew personnel for a Choke Drill. Select surface operations that can give false flow rate indications of a kick or losses: e.g. increased SP, dumping trip tank, leaks in surface system. Select surface conditions that may make it difficult to accurately measure flow rate: e.g. inoperable flow sensor, rig movement, tides, riser not connected, use of riser boost line Select correct action to take for a flow rate increase/decrease: e.g. flow checks, shut- in, investigate other options only after shut- in. Select reason for carrying out Pit Drills. Select common crew roles for a Pit Drill: e.g. what crew members normally do during this drill. Select reason for carrying out Trip Drills. Select common crew roles for a Trip Drill: e.g. what crew members normally do during this drill. Select reason for carrying out Stripping Drills. Select common crew roles for a Stripping Drill: e.g. what crew members normally do during this drill. Select reason for carrying out Choke Drills. Select common crew roles for a Choke Drill: e.g. what crew members normally do during this drill. Page 20 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT

22 Well Control nstitute (WC) odule Name: Kick Detection & Drills Learning Topics A* Learning Topics Assessments and Learning Outcomes State reason for regular Emergency Evacuation Select reason for carrying out Emergency Evacuation & Emergency & Abandonment Drills. Abandonment Drills. Evacuation and Roles and responsibilities of rig crew Select common crew roles for an Emergency Evacuation & Abandonment personnel for an Emergency Evacuation & Abandonment Drill: e.g. what crew members normally do Drills Abandonment Drill. during this drill. State reason for Diverter Drills. Select reason for carrying out Trip Drills. Diverter Drills Roles and responsibilities of rig crew personnel for a Diverter Drill. Select common crew roles for a Trip Drill: e.g. what crew members normally do during this drill. mportance of Early Response, Stop Work Authority & Empowerment to Act mportance of early detection and the consequences of not responding to a kick in a timely manner. Why each crewmember has the authority to stop work and communicate any possible early indications of well control problems. Explain why early detection of a kick is important: e.g. minimize kick size and surface annular pressure, minimize chance of formation breakdown, blowout, personnel safety, broaching around casing, gas releases, fire, pollution, loss. Give reasons why all crewmembers must inform their supervisor if they see any potential well control issues: e.g. minimizing chance of a kick and associated consequences, increased communication, the more eyes on the problem the better, consequence of stopping work is insignificant compared to a kick or blowout Shallow Gas/Water Flows & Top Hole Drilling odule Name: Shallow Gas/Water Flows & Top Hole Drilling Learning Topics A* Learning Topics Assessments and Learning Outcomes Top Hole Drilling Causes of abnormal pressure in top- hole State causes of abnormal pressure in top- hole sediments: e.g. Practices and formations. trapped fluids, weight of overburden, charged formation. Page 21 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT

23 Well Control nstitute (WC) odule Name: Shallow Gas/Water Flows & Top Hole Drilling Learning Topics A* Learning Topics Assessments and Learning Outcomes Causes of Kicks in Top Hole Kill Options in Top Hole Shallow Subsea Fracture Gradients ain causes of underbalance in top hole drilling Top hole drilling practices that can reduce risk of a well flow Well control procedural options available (i.e., Divert, ncrease SP, Pump Kill ud). How water depth affects formation fracture pressures in shallow formations. Select common causes of going underbalance in top hole: e.g. mud weight too low, gas cutting, swabbing, overloaded annulus, lost circulation, abnormal pressure, artesian flow, reduced hydrostatic while waiting on cement to set. Select common good drilling and tripping practice in top hole to prevent kicks: e.g. control of mud weight, logging tool data, regular hole sweeps, drill pilot hole, controlled ROP, pump out of hole, seismic data. State possible options available with a shallow flow: e.g. Divert and desert, pump kill mud, pump at fast rate for ECD- dynamic kill. State how water depth affects the formation fracture pressure: e.g. distance from sea floor to rig floor (water depth and Air Gap), less compaction, narrower drilling window Shut- n Procedures & Verification odule Name: Shut- n Procedures & Verification Learning Topics A* Learning Topics Assessments and Learning Outcomes State advantage of shutting in early: e.g. minimize influx size, minimize SCP, reduce pressures on wellbore, importance of Why an immediate shut- in is an advantage. crew shut- in training, ensure crew know that if in doubt, shut Drilling & Tripping it in. Steps to take to verify the well is secure and potential problem/s if not secure. Carry out checks following shut- in to ensure well is secure: e.g. no leaks at BOP, string, pumps, manifolds. Page 22 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT

24 Well Control nstitute (WC) odule Name: Shut- n Procedures & Verification Learning Topics A* Learning Topics Assessments and Learning Outcomes Reasons for use of Blind/Shear Rams Choose reasons for using blind and blind/shear rams: e.g. no pipe in hole, blowout through drill string, emergency disconnect. State why knowledge of shear ram capability versus tubular mportance of knowing what the Shear Rams shear strengths is critical to development of shut- in can shear. procedures and the management of risk. Out of Hole Procedure for shut- in with all tubulars out of the hole. State shut- in procedure when out of hole. Select actions that can be taken if well kicks with non- Running Casing Action to take if non- shearables are across shearable tubulars across the BOP: e.g. use of Annular, casing and Cementing BOPs. rams, drop pipe, emergency disconnect issues. Wireline Procedure for shut- in with wireline in the hole. Select correct shut- in procedure: e.g. including cutting wire Reason for recording data following a kick. Select reason/s for recording shut- in data; e.g. show buildup of pressures over time, calculating kill data. ain data to record following a kick and how Record data following shut- in e.g. pressures, volumes, time. Recording of Shut- n Pressures, Differences, and Float in String onitoring for Gas igration, Handling Technique, and often. Which gauges should be used to record Drillpipe and Casing pressures. The procedure to open the float to obtain shut- in drill pipe pressure. Complications to reading accurate shut- in pressures in deepwater wells. Describe the procedure for identifying gas migration based on shut- in pressures. Action the Supervisor must initiate if gas is migrating. Page 23 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT Record data on correct gauges: e.g. normally on Choke control panel, need for calibration checks. Demonstrate how to measure SDPP with a float in the string. State how shut- in pressure accuracy may be affected by water depth: e.g. cool mud in choke and kill lines, potentially high gel strengths that can mask real pressure. State how gas migration in a shut- in well can be recognized: e.g. increasing shut- in pressures after initial stabilization. Demonstrate how to manage migrating gas in a shut- in well: e.g. in a well without a float.

25 Well Control nstitute (WC) odule Name: Shut- n Procedures & Verification Learning Topics A* Learning Topics Assessments and Learning Outcomes Problems with State how to manage gas migration in a well where there is Excessive float in the drillstring: e.g. volumetric technique. Pressures Analysis of Shut- n Conditions Trapped Pressure and How to Handle Riser Flow after Shut- n Relationship between Formation Fluid pressure, ud Hydrostatic pressure and Shut- n Pressure (SDPP and SCP). Effect of formation fluids on shut- in pressures values. How incorrect reading of shut- in pressures can affect the kill operation. Shut- in pressures readings at any time during a kill operation to determine if kill is going according to plan. How to identify trapped pressure from true shut- in pressure. Procedure to reduce trapped pressure. Reasons for mud flow from the Riser following well shut- in. Define SDPP and SCP. Given data, calculate either formation fluid pressure or shut- in pressure. Give reason why SDPP and SCP are different: e.g. fluid hydrostatics in the u- tube Select well conditions than cause SDPP to exceed SCP: e.g. formation fluids in string, cuttings effect on annulus hydrostatic, lighter mud in string. State consequences of trapped pressure on kill calculations and how incorrect pressure can affect success of kill process: e.g. higher shut- in pressures, incorrect kill mud weight, higher pressure for start- up, potential losses. Analyze shut- in pressure at selected points in a kill and determine if correct bottom hole pressure is being maintained e.g. analysis of shut- in pressure with kill mud at different points in the string, kill mud at certain positions in the annulus, reaction on gauges following a shut down. Demonstrate how to identify if the current surface pressure reflect trapped pressure. Demonstrate how to reduce trapped pressure in a controlled manner. State what can cause Riser flow following well shut- in: e.g. leaking BOP, gas migration in Riser. Page 24 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT

26 Well Control nstitute (WC) odule Name: Shut- n Procedures & Verification Learning Topics A* Learning Topics Assessments and Learning Outcomes State the action to take if Riser is flowing following shut- in: Action to be taken if the Riser is flowing e.g. Check for BOP operation, close another preventer, Divert following shut- in. overboard Well Control/Risk anagement odule Name: Well Control/Risk anagement Learning Topics A* Learning Topics Assessments and Learning Outcomes Reason for developing a kill plan Give reason for supervisors and crew to develop and communicate a well kill plan: e.g. to have a procedure to follow, to communicate that procedure to relevant personnel, to get feedback from the team to ensure they understand and can carry out their role, action to take if plan goes wrong. State role that the supervisor plays in planning: e.g. key role Assessing Risks and in development of technical aspects of plan, consults with Key role of Supervisor in well kill planning. Planning the Kill wide range of subject matter experts, communicates the plan, Operations motivates personnel to do the right thing. Develop a kill plan including pit management for a well kill. Using a set of data identify key elements that would be needed in a kill plan. dentify main risk areas during a kill plan and actions to take to mitigate the risk. For a set of pre- determined risks within a kill plan select actions that could be taken to mitigate those risks. How to carry out a handover during a well kill exercise. Demonstrate a handover to another supervisor during a well kill exercise. Page 25 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT

27 Well Control nstitute (WC) odule Name: Well Control/Risk anagement Learning Topics A* Learning Topics Assessments and Learning Outcomes nterpret data on a kill log and select possible kill problems/s: What to record on a kill log and how to not maintaining correct pressure, abnormal changes to casing analyze kill log during well kill to identify pressure and/or choke opening size and pit levels, SP possible problems. variations State reason for having a safety margin during a kill Reason for using safety margins. operation: e.g. to reduce risk of going underbalance during a Safety argin Selection anaging Change during a Well Kill Handling Kill Problems Dangers of using safety margins. What is an acceptable safety margin. Action that should be taken due to a problem with the kill. dentify 'stopping points' that would indicate the kill plan was not working. Typical well kill problems. Responses to kill problems. Page 26 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT well kill. State dangers of using safety margins during a well kill: e.g. margin too high that may cause losses, adding a choke safety margin and a mud weight safety margin adds extra pressure. Select an acceptable safety margin from a set of kill data. Using specific well data determine an action to take: e.g. incorrect mud pumped, run out of weighting material; weather problem (onshore and offshore), Ram or Annular failure, plugged string, rig power failure. For a specific kill plan identify key feedback from the well that would indicate the plan is not successful and state action to take at that point: e.g. problem maintaining correct surface pressure, casing pressure and pit volume changes not according to plan, possible points to stop the kill to check pressures. Recognize selected well control problems that can occur during a well control operation: e.g. plugging, washouts, equipment issues. Demonstrate correct action to a specific problem that maintains well integrity, minimizes further influx and restores bottom hole pressure in a timely manner.

28 Well Control nstitute (WC) odule Name: Well Control/Risk anagement Learning Topics A* Learning Topics Assessments and Learning Outcomes Action/s to take if Casing Pressure may exceed AASP. State options available if surface casing pressure is likely to exceed AASP: e.g. continue and accept losses, reduce circulating friction in annulus and choke lines yet maintain correct bottom hole pressure Reason for calculating Bit to Shoe Strokes. State why Bit to Shoe strokes are calculated as part of the kill plan: e.g. establish when influx is at the shoe, realize that shoe pressure will not increase once influx is above shoe even though surface pressure continues to rise (assuming constant bottom hole pressure procedure is maintained). Bridging Documents Decision to mplement Emergency Procedures (e.g., during a Well Kill) Purpose of a Well Control bridging document. Circumstances during a well kill operation that would require emergency procedures to be initiated and possible actions to take to secure the well. State the purpose of a well control bridging document: e.g. assure all parties have the same information, well control issues between different parties have been resolved, handle specific issues in relation to a particular well/environment or legislative regime. State potential situations during a well kill that would require rig emergency procedures to be activated and the actions to take to secure the well (if applicable): e.g. uncontrolled BOP leak, 'broaching' at surface, potential vessel collision, bad weather, drive- off, toxic gas, fire Well Control ethods odule Name: Well Control ethods Learning Topics A* Learning Topics Assessments and Learning Outcomes Drillers ethod Basic principles of the Driller's method. Explain basic principles and steps involved in the Drillers ethod. Page 27 of 43 DRAFT WORK PRODUCT FOR NDUSTRY COENT

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