well!control!institute!(wci)! corecurriculum!and!related ... ·...

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

Supervisory Level

Revision 4B May 14, 2014

Prepared by Black & Veatch Corp.

DRAFT WORK PRODUCT – FOR INDUSTRY COMMENT

Well Control Institute (WCI) Core Curriculum and Related Learning Outcomes for Drilling Operations:

Supervisory

Page 1 of 43 Prepared by Black & Veatch Corp. Revision 4B: May 14, 2014 DRAFT WORK PRODUCT – FOR INDUSTRY COMMENT

Contents 4. Supervisor Level Overview .................................................................................................................................................................................... 2

4.1. Drilling, Workover, Completion Plan ............................................................................................................................................................ 3

4.2. Technical Principles ....................................................................................................................................................................................... 4

4.3. Mud & Pit Management ............................................................................................................................................................................... 9

4.4. Pre-‐Kick Data ............................................................................................................................................................................................... 11

4.5. Pore Pressure Prediction ............................................................................................................................................................................ 12

4.6. Kick Awareness during Drilling, Workover, & Completion Operations ....................................................................................................... 14

4.7. Barriers ....................................................................................................................................................................................................... 17

4.8. Kick Detection & Drills ................................................................................................................................................................................ 18

4.9. Shallow Gas/Water Flows & Top Hole Drilling ............................................................................................................................................ 21

4.10. Shut-‐In Procedures & Verification .......................................................................................................................................................... 22

4.11. Well Control/Risk Management ............................................................................................................................................................. 25

4.12. Well Control Methods ............................................................................................................................................................................. 27

4.13. Equipment Readiness/Assurance ........................................................................................................................................................... 31

4.14. Extract of Subsea Elements ..................................................................................................................................................................... 35


Supervisory


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 4.14.

Recommended Attendees:

WCI recommend the following Job Positions attend the Supervisor Level course:

• Wellsite Supervisors, Company men and assistants

• MPD/UBD Wellsite supervisors

• Office-‐based drilling supervisors/superintendent (not involved with well design approval)

• Office-‐based rig, drilling manager

• OIM for mobile offshore drilling units

• Rig Manager (shore-‐based/superintendent (land))

• Rig Superintendent offshore (most senior offshore leader for drill crew, may be the OIM)

• Toolpushers

Note:

• Blue Text = Subsea • Black Text = Common to Surface and Subsea


Supervisory


4.1. Drilling, Workover, Completion Plan

Module Name: Drilling, Workover, Completion Plan *A = Awareness of learning topics at this job level I = Implements learning topics at this job level M = Mastery of learning topics at this job level

Learning Topics AIM* Learning Objectives Assessments and Learning Outcomes The attendee will gain an understanding of: The attendee will be able to:

Well Work Objectives 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.

Identify key elements of the well program that the Supervisor applies to kick prevention.

Fracture Gradients and Pore Pressures A The importance of knowing the Fracture

gradients and pore pressures in the well.

Identify the importance of knowing Fracture Pressures and Formation Fluid Pressures (Pore Pressures) when drilling, completing and workovers.

Casing & Cementing Program A

The role of casing and cementing in the drilling of a well and for containing formation fluids.

Identify the role/s of casing and cementing in a well.

Reasons for Workover A

Why wells have to be worked over. Identify reasons for a workover. Major well control differences between drilling a well and a 'workover'.

Differentiate between well control operations normally related to drilling operations and those related to workover.

Completion Program A Major well control differences between drilling a well and completing a well.

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 formation fluids.

Identify key functions of a fluids program

Barrier Management A The term Barrier Management. Select definition of Barrier Management 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.


Supervisory


4.2. Technical Principles

Module Name: Technical Principles Learning Topics AIM* Learning Topics Assessments and Learning Outcomes

The attendee will gain an understanding of: The attendee will be able to:

Principle of U-‐Tube M

The principle of a U-‐tube. Select correct definition of a U-‐Tube. Calculate pressures on each side of a u-‐tube.

How the model of a u-‐tube works during a well kill.

State what would happen if a certain weight of fluid was pumped into the u-‐tube and how this might affect hydrostatic pressure and pump pressure: e.g. effect on mud level in the two legs of the u-‐tube; effect of surface pressures if end of u-‐tube is sealed by BOP or Valve.

The effect of the u-‐tube when pumping kill weight mud during a kill operations tripping.

Calculate SIDPP 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.

How the u-‐tube can assist in calculating displacement position of cement. Calculate top of cement position once displaced into position

Pump Pressure Effects & Circulating Friction Pressures

M

Friction and pump pressure. Select correct statement when defining friction in the well or pump pressure

How friction in the different sections of the well contribute to final 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.

How mud weight, viscosity, flow rate and hole geometry affects pump pressure.

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).

Calculate changes in pump pressure due to changes in pump speed and mud weight.

Using standard industry formula calculate effect of SPM and Mud Weight changes on pump pressure.


Supervisory




Planning & Operational Kick Tolerance

I

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.

Methods to obtain Kick Tolerance

Use a kick tolerance graph showing kick intensity versus kick volume to obtain kick tolerance: e.g. identify initial shut-‐in kick tolerance and circulating kick tolerance, aware of alternative ways to calculate the value.

Options available if Kick Tolerance is low. State options available if a low kick tolerance is established: 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

Formation Stresses & Strength I

The term formation strength. Select the correct definition of formation strength Why we need to determine Formation Strength.

State why knowledge of formation strength is important in the drilling process.

How formation strength can be determined on the rig using Formation Integrity Test or Leak Off Test (FIT/LOT).

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

The key preparation tasks to ensure an accurate FIT/LOT

List key tasks to carry out to ensure an accurate LOT/FIT result: e.g. clean hole, consistent mud weight around well, calibrated pressure gauges, surface equipment tested for leaks,

The term Maximum Allowable Mud Weight (MAMW).

Select correct definition for Maximum Allowable Mud Weight.

How to calculate Fracture Pressure and Maximum Allowable Mud Weight (MAMW).

Calculate Formation Fracture pressure and MAMW from FIT or LOT data.


Supervisory




Possible action/s to take if MAMW is too low for expected formation fluid pressures in next hole section.

State actions that can be taken if formation strength is lower than expected: e.g. carry out cement squeeze, repair casing if damaged, adjust drilling program to accommodate lower fracture strength.

Maximum Predicted Surface Pressure & Maximum Allowable Annular Surface Pressure (MAASP)

I

The term Maximum Predicted Surface Pressure. Select the correct definition of MASP

How Maximum Predicted Surface Pressure is used in well design and the consequences of exceeding maximum pressure limitations.

Describe why MASP is important to Well Control/Integrity: e.g. consequences of exceeding maximum pressure limitations, BOP selection, casing burst selection, wellhead rating, surface manifolds pressure rating.

The term Maximum Allowable Annular Surface Pressure (MAASP). Select the correct definition of MAASP

Why a knowledge of maximum allowable and maximum predicted pressures important in drilling operations.

Describe the potential consequences of exceeding MAASP or MAMW on well control/integrity: e.g. lost circulation, mud level drop, potential kick, downtime.

How to calculate MAASP. Using Formation Strength data calculate MAASP using formula or kill sheet.

When MAASP must be recalculated. State when MAASP needs to be re-‐calculated. Difference between Static and Dynamic MAASP

State the difference between the terms Static MAASP and Dynamic MAASP

Equivalent Circulating Density (ECD) & Bottomhole Pressure (BHP)

I

The term bottom hole pressure (BHP). Select the correct definition of bottom hole pressure

How BHP can be different from hydrostatic pressure.

Distinguish between hydrostatic pressure and bottom hole pressure: e.g. Static versus circulating bottom hole pressure, cuttings loading, shut-‐in pressure, pipe movement.

The importance of having the correct bottom hole pressure (BHP).

Describe why correct bottom hole pressure is so important to well control/integrity

The term ECD. Select the correct definition of ECD


Supervisory




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

The principle of ECD drilling and associated well control problems.

Describe the process of ECD drilling state the potential well control problems that can arise from this process: e.g. underbalance on connections, connection gas, gas issues in long marine Risers, narrow drilling window, mud weight displacement for tripping.

Gas Behavior in Fluids I

How the relatively low density of gas affects the hydrostatic pressure.

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.

The relationship between pressure and volume of a gas in the wellbore.

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

Why a gas kick must expand as it is circulated up the wellbore.

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.

The term gas migration Select correct definition of gas migration


Supervisory




The consequences of gas migration. Predict the consequences of gas migration in the wellbore and on associated pressure gauges. e.g. In 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.

Describe what happens to a gas as it is circulated through the choke from a high-‐pressure environment to a low-‐pressure environment.

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.

Compressibility and Temperature Effects on Oil Based Fluids (Non Aqueous Fluids (NAF)) and Brines

I

How downhole pressure can affect fluid weight. State how pressure affects fluid weight

How mud temperature can affect mud properties.

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

How downhole pressure and temperature can impact well control.

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.


Supervisory




Snubbing/Stripping Forces I

How well pressure effects whether pipe can be stripped or snubbed into the well.

Describe how the values of wellbore pressure and string weight and annular preventer limitations impact the decision to strip or snub into the well.

Effect of buoyancy on calculations. Describe the effect of buoyancy on forces required for stripping or snubbing.

Directional Well Effects on Well Control

I

How to interpret Shut-‐In Pressures for a directional well.

Interpret shut-‐in values for high angle wells and how they impact a well kill operation.

How gas expansion and migration is affected in a highly deviated well

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.

The potential problems if standard vertical well-‐kill calculations are applied to killing of a highly deviated well.

Describe the effect on bottom hole pressure id vertical well-‐kill calculations are use on a highly deviated well.

Tapered Drill String Effects I

How tapered strings affect Trip Monitoring Describe how a tapered string will impact trip monitoring values

How tapered strings affect Kill procedure Describe how a tapered string will impact well control calculations: e.g. ICP to FCP values

4.3. Mud & Pit Management

Module Name: Mud & Pit Management Learning Topics AIM* Learning Topics Assessments and Learning Outcomes


Maintaining Correct Mud Weight I Two different methods to measure fluid

density and the reason for the difference.

Describe how mud density is measured using atmospheric or pressurized mud-‐balances: e.g. reason for difference, importance of calibration


Supervisory




Importance 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.

Role and responsibilities of drill crew personnel who are working with the pit system.

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.

Managing Pits during a Kill Operation I

Possible pit line-‐ups that can be used during a well kill operation

Demonstrate effective management of pit line-‐up for a kill operation.

How to handle volume increases due to influx expansion.

State actions to take to manage pit gains during a well kill: e.g. pre-‐planning, pit size, transfers.

Dangers of circulating formation fluids into surface pit system.

State dangers involved in circulating formation fluids into the surface pit system

Actions to take to reduce risks associated with formation fluids at surface.

Describe how formation fluids are handled at surface during a kill operation: e.g. handling gas, handling oil/condensate, handling formation water.

How drill crew should responsibilities when circulating out and killing a kick.

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.

Managing Pits during Wholesale Wellbore Displacements

I

The dangers of adding/transferring fluids to a pit system during active drilling/circulating operation.

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.

Actions to take in the event of a pit volume discrepancy.

Select action to take in event of a pit level discrepancy: e.g. stop drilling, flow check, analyze pit level records


Supervisory




Importance of correct calibration of different pit measuring systems.

State importance of correct pit level sensor calibration and agreement in volumes between different sensors and recording devices.

4.4. Pre-‐Kick Data

Module Name: Pre-‐Kick Data Learning Topics AIM* Learning Topics Assessments and Learning Outcomes


Slow Circulating Rates (SCR) I

Reason for taking slow circulating rates (SCRs). Give reasons for taking a SCR: e.g. calculate ICP/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/SPM for an SCR. Choose acceptable flow rate/SPM for a SCR Which gauges are commonly used to read the SCR value. Select gauges to use to record a SCR

What can affect SCR readings and why SCRs may not be 100% accurate for well kill operations.

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.

Choke Line Friction (CLF)

I Reason for taking choke line frictions (CLFs).

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.


Supervisory


Module Name: Pre-‐Kick Data Learning Topics AIM* 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

Typical flow rate/SPM for a CLF. Choose acceptable flow rate/SPM for a CLF Which gauges are commonly used to read the CLF value.

Select gauges to use to record a CLF

The effect of taking the CLF on bottom hole pressure.

Given various techniques for recording CLF state the effect on bottom hole pressure.

Choke & Kill Line Fluid Densities

I 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.

Describe the effect on SICP 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.

4.5. Pore Pressure Prediction

Module Name: Pore Pressure Prediction Learning Topics AIM* Learning Topics Assessments and Learning Outcomes


PWD/LWD Data I 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.


Supervisory




Shaker Evidence I How the returns at the shale shaker can identify potential kick conditions.

Interpret observations and trends at Shakers that may help crew members identify potential well control problems: e.g. visual condition of mud, cuttings load, cuttings shape, sloughing shales (cavings), gas-‐cut mud, mud weight and viscosity.

Changes in Mud Properties I

How mud properties that can be affected by potential kick conditions, e.g. (gas cutting, chlorides, temperature)

Interpret 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

Changes in Drilling Data/Parameters I

How drilling parameters are affected by potential kick conditions (e.g., ROP, torque, drag)

Interpret 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

Mud Weight Management in Transition Zone Drilling

I

Transition Zones. Define the term transition zone in relation to Abnormal pressure

Actions that may need to be taken during drilling of a transition zone.

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 Mud Logger, enhanced 'fingerprinting' of flowback at connections, increased awareness of essential crew to warning signs, use of PWD/LWD.

Reason why mud weight management is important in a transition zone.

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.

Trend Analysis I Abnormal pressure and how it affects primary control.

State how Abnormal pressure affects primary control in the wellbore


Supervisory



The attendee will gain an understanding of: The attendee will be able to: Common trends in the warning signs that can indicate increasing formation fluid pressure (or a reduction in Overbalance).

Identify trends in mud, shaker and drilling data that indicate potential abnormal pressure development (transition zone)

Actions the Supervisor must take when warning signs are recognized.

State appropriate actions a Supervisor must take when warning signs are noted: e.g. analyze, compare different trends.

Role and responsibilities of various rig floor crewmembers in monitoring for warning signs.

List responsibilities of key team members in the monitoring of trends: e.g. Driller, Mud Logger, Mud Engineer, Company representative, geologist, drilling engineer.

4.6. Kick Awareness during Drilling, Workover, & Completion Operations

Module Name: Kick Awareness during Drilling, Workover, & Completion Operations

Learning Topics AIM* Learning Topics Assessments and Learning Outcomes The attendee will gain an understanding of: The attendee will be able to:

Tripping Operations M

Use of trip sheet to determine if hole fill is normal or abnormal.

Analyze a trip sheet for signs of abnormal hole fill: e.g. swabbing, surging.

Action/s to take if hole fill readings are abnormal.

State action to take if trip tank readings show swabbing or surging: e.g. flow checks, returning to bottom, lost circulation remediation.

Considerations for trip tank capacity in large volume operations.

State how to monitor large volume operations on a trip tank.

Non-‐Shearables I Running non-‐shearables. State standard procedures to follow before running non-‐

shearables. Well flows with a non-‐shearable across the BOP.

State action to take if well flows with a non-‐shearable across the BOP.


Supervisory




Handling Losses M

Classification of loss Classify loss rates: e.g. seepage, minor, major

Actions to take for each of these loss types. State first actions to take for each of the loss types: e.g. monitor, maintain hole full, add base fluid, monitor volumes pumped, shut-‐in.

Ballooning Issues M

The term wellbore ballooning. Define the term ballooning

Recognition of Ballooning. Select surface data that can help the Supervisor determine if it is ballooning.

First action to take if a Supervisor suspects Ballooning. Select correct action to take if ballooning is suspected.

How Ballooning can be distinguished from a Kick at shut-‐in.

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.

Procedure for bleeding down ballooning.

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.

Casing & Cementing Operations M

Factors that increase risk of swabbing and surging during casing running/pulling operations.

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.

Casing displacements and how often casing should be filled when running in hole .

Calculate casing displacements required for monitoring the hole and casing fill-‐up.

Precautions to take when running self-‐fill/automatic casing shoe floats.

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.


Supervisory




Well control risks if a self-‐fill float fails to convert.

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.

Equipment required to shut-‐in on a kick when running casing or during and after cementing.

State equipment used to shut-‐in on a kick while casing or cementing: e.g. circulating head

Effects of a cementing operation on BHP. State effect of cement hardening on cement hydrostatic and how that affects well control: e.g. reduction in hydrostatic

Importance of following recommendations based on cement pilot testing before beginning follow up operations.

Select reason/s why cement waiting time is critical to well control.

Monitoring wellbore flow rates/pit levels during the cementing and displacement.

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.

How well is monitored during cement waiting time.

State how to monitor the while waiting on cement: e.g. annulus flow, flow inside casing, detecting small amounts of flow over time.

How final pumping pressure can be used to calculate cement height in the annulus.

Calculate height of cement in annulus based on pump pressure at final displacement or final expected pump pressure at planned displacement.

Wellbore Fluid Displacements M Common practices when displacing wellbore

fluid to a lower density fluid.

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.


Supervisory




Point at which a low-‐density displacement causes a negative pressure across a barrier.

Using data provided calculate when hydrostatic pressure above a barrier exerts a negative pressure across that barrier.

Wireline Operations M

Potential causes of a kick during wireline operations.

Select possible causes of a kick during wireline operations: e.g. swabbing, free gas migrating and expanding, barite settling.

Common kick prevention practices during wireline operations.

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.

Negative Testing M Negative testing Define the term negative test. Common procedure for carrying out a negative test.

Describe common procedure for carrying out a negative test.

Riser Margin M Riser Margin. Define the term Riser Margin Calculate Riser Margin. Using given data calculate Riser Margin

4.7. Barriers

Module Name: Barriers Learning Topics AIM* Learning Topics Assessments and Learning Outcomes


Philosophy and Operations Requiring Barriers

M

Barriers and Barrier Systems. Define the terms barrier and barrier system

How barriers are used to maintain well integrity in drilling and casing operations.

For typical drilling operations state how barriers maintain well integrity: e.g. role of mud, cement, casing, BOP, String Valves, Packers.


Supervisory


Module Name: Barriers Learning Topics AIM* Learning Topics Assessments and Learning Outcomes

The attendee will gain an understanding of: The attendee will be able to: 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

Number of Barriers for Safe Operation M

The minimum number of barriers required for safe operations and why. Select the minimum number of barriers for normal operations

Number of barriers for given well designs. Identify the number of barriers present in a given well design

Testing Barriers M

How common mechanical barriers are tested to ensure well integrity. Select definition of positive and negative testing for barriers

How to recognize a failed barrier. Describe how a failed barrier can be detected: e.g. flow from the well, losses to the well, increase in surface pressure when shut-‐in.

4.8. Kick Detection & Drills

Module Name: Kick Detection & Drills Learning Topics AIM* Learning Topics Assessments and Learning Outcomes


Well Flow with Pumps Off M

Define a Flow Check. Select the correct definition of a flow check

How to carry out a flow check. Recognize the need to carry out a flow check and take required action: e.g. difference between tripping and drilling 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.


Supervisory



The attendee will gain an understanding of: The attendee will be able to: 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 M

Why pit levels are closely monitored at all times.

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.

Acceptable alarm limits for pit levels. Choose acceptable values for high and low level alarms set on PVT.

What operations can increase or decrease pit level that are not related to flow or losses in the well.

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

Conditions on surface that can make it difficult to get accurate pit level readings.

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

State action to take in event of abnormal pit level

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 pipe or wirelining.

Identify abnormal trip tank readings from a trip sheet: e.g. identify abnormal readings on a trip sheet.


Supervisory




Flow Returns Rate Increase M

Why flow rates are closely monitored at all times.

Select reasons why it is important to monitor flow rates at all times the rig is connected to the well: e.g. open hole always 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.

State what operations can increase or decrease flow rate that are not related to increased flow or losses in the well.

Select surface operations that can give false flow rate indications of a kick or losses: e.g. increased SPM, dumping trip tank, leaks in surface system.

Conditions on surface that can make it difficult to get accurate flow rate readings.

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

Action to take in event of an abnormal flow reading

Select correct action to take for a flow rate increase/decrease: e.g. flow checks, shut-‐in, investigate other options only after shut-‐in.

Pit Drills M Reason for regular Pit Drills. Select reason for carrying out Pit Drills. Roles and responsibilities of rig crew personnel for a Pit Drill.

Select common crew roles for a Pit Drill: e.g. what crew members normally do during this drill.

Trip Drills M Reason for regular Trip Drills. Select reason for carrying out Trip Drills. Roles and responsibilities of rig crew personnel for a Trip Drill.

Select common crew roles for a Trip Drill: e.g. what crew members normally do during this drill.

Stripping Drills M State reason for Stripping Drills. Select reason for carrying out Stripping Drills. Roles and responsibilities of rig crew personnel for a Stripping Drill.

Select common crew roles for a Stripping Drill: e.g. what crew members normally do during this drill.

Choke Drills M State reason for Choke Drills. Select reason for carrying out Choke Drills. Roles and responsibilities of rig crew personnel for a Choke Drill.

Select common crew roles for a Choke Drill: e.g. what crew members normally do during this drill.


Supervisory




Emergency Evacuation and Abandonment Drills

M

State reason for regular Emergency Evacuation & Abandonment Drills.

Select reason for carrying out Emergency Evacuation & Abandonment Drills.

Roles and responsibilities of rig crew personnel for an Emergency Evacuation & Abandonment Drill.

Select common crew roles for an Emergency Evacuation & Abandonment Drill: e.g. what crew members normally do during this drill.

Diverter Drills M State reason for Diverter Drills. Select reason for carrying out Trip 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.

Importance of Early Response, Stop Work Authority & Empowerment to Act

M

Importance of early detection and the consequences of not responding to a kick in a timely manner.

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.

Why each crewmember has the authority to stop work and communicate any possible early indications of well control problems.

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.

4.9. Shallow Gas/Water Flows & Top Hole Drilling

Module Name: Shallow Gas/Water Flows & Top Hole Drilling Learning Topics AIM* Learning Topics Assessments and Learning Outcomes

The attendee will gain an understanding of: The attendee will be able to: Top Hole Drilling Practices and I Causes of abnormal pressure in top-‐hole

formations. State causes of abnormal pressure in top-‐hole sediments: e.g. trapped fluids, weight of overburden, charged formation.


Supervisory


Module Name: Shallow Gas/Water Flows & Top Hole Drilling Learning Topics AIM* Learning Topics Assessments and Learning Outcomes

The attendee will gain an understanding of: The attendee will be able to: Causes of Kicks in Top Hole Main causes of underbalance in top hole

drilling

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.

Top hole drilling practices that can reduce risk of a well flow

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.

Kill Options in Top Hole I Well control procedural options available (i.e.,

Divert, Increase SPM, Pump Kill Mud).

State possible options available with a shallow flow: e.g. Divert and desert, pump kill mud, pump at fast rate for ECD-‐dynamic kill.

Shallow Subsea Fracture Gradients

I How water depth affects formation fracture pressures in shallow formations.

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.

4.10. Shut-‐In Procedures & Verification

Module Name: Shut-‐In Procedures & Verification Learning Topics AIM* Learning Topics Assessments and Learning Outcomes


Drilling & Tripping M Why an immediate shut-‐in is an advantage.

State advantage of shutting in early: e.g. minimize influx size, minimize SICP, reduce pressures on wellbore, importance of crew shut-‐in training, ensure crew know that if in doubt, shut 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.


Supervisory




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.

Importance of knowing what the Shear Rams can shear.

State why knowledge of shear ram capability versus tubular shear strengths is critical to development of shut-‐in procedures and the management of risk.

Out of Hole M Procedure for shut-‐in with all tubulars out of the hole. State shut-‐in procedure when out of hole.

Running Casing and Cementing M Action to take if non-‐shearables are across

BOPs.

Select actions that can be taken if well kicks with non-‐shearable tubulars across the BOP: e.g. use of Annular, casing rams, drop pipe, emergency disconnect issues.

Wireline M Procedure for shut-‐in with wireline in the hole. Select correct shut-‐in procedure: e.g. including cutting wire

Recording of Shut-‐In Pressures, Differences, and Float in String

M

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.

Main data to record following a kick and how often. Record data following shut-‐in e.g. pressures, volumes, time.

Which gauges should be used to record Drillpipe and Casing pressures.

Record data on correct gauges: e.g. normally on Choke control panel, need for calibration checks.

The procedure to open the float to obtain shut-‐in drill pipe pressure. Demonstrate how to measure SIDPP with a float in the string.

Complications to reading accurate shut-‐in pressures in deepwater wells.

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.

Monitoring for Gas Migration, Handling Technique, and

M

Describe the procedure for identifying gas migration based on shut-‐in pressures.

State how gas migration in a shut-‐in well can be recognized: e.g. increasing shut-‐in pressures after initial stabilization.

Action the Supervisor must initiate if gas is migrating.

Demonstrate how to manage migrating gas in a shut-‐in well: e.g. in a well without a float.


Supervisory



The attendee will gain an understanding of: The attendee will be able to: Problems with Excessive Pressures

State how to manage gas migration in a well where there is float in the drillstring: e.g. volumetric technique.

Analysis of Shut-‐In Conditions M

Relationship between Formation Fluid pressure, Mud Hydrostatic pressure and Shut-‐In Pressure (SIDPP and SICP).

Define SIDPP and SICP. Given data, calculate either formation fluid pressure or shut-‐in pressure.

Effect of formation fluids on shut-‐in pressures values.

Give reason why SIDPP and SICP are different: e.g. fluid hydrostatics in the u-‐tube Select well conditions than cause SIDPP to exceed SICP: e.g. formation fluids in string, cuttings effect on annulus hydrostatic, lighter mud in string.

How incorrect reading of shut-‐in pressures can affect the kill operation.

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.

Shut-‐in pressures readings at any time during a kill operation to determine if kill is going according to plan.

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.

Trapped Pressure and How to Handle

M

How to identify trapped pressure from true shut-‐in pressure.

Demonstrate how to identify if the current surface pressure reflect trapped pressure.

Procedure to reduce trapped pressure. Demonstrate how to reduce trapped pressure in a controlled manner.

Riser Flow after Shut-‐In

M Reasons for mud flow from the Riser following well shut-‐in.

State what can cause Riser flow following well shut-‐in: e.g. leaking BOP, gas migration in Riser.


Supervisory




Action to be taken if the Riser is flowing following shut-‐in.

State the action to take if Riser is flowing following shut-‐in: e.g. Check for BOP operation, close another preventer, Divert overboard.

4.11. Well Control/Risk Management

Module Name: Well Control/Risk Management Learning Topics AIM* Learning Topics Assessments and Learning Outcomes


Assessing Risks and Planning the Kill Operations

I

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.

Key role of Supervisor in well kill planning.

State role that the supervisor plays in planning: e.g. key role in development of technical aspects of plan, consults with wide range of subject matter experts, communicates the plan, 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.

Identify 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.


Supervisory




What to record on a kill log and how to analyze kill log during well kill to identify possible problems.

Interpret data on a kill log and select possible kill problems/s: not maintaining correct pressure, abnormal changes to casing pressure and/or choke opening size and pit levels, SPM variations

Safety Margin Selection M

Reason for using safety margins. State reason for having a safety margin during a kill operation: e.g. to reduce risk of going underbalance during a well kill.

Dangers of using safety margins. 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.

What is an acceptable safety margin. Select an acceptable safety margin from a set of kill data.

Managing Change during a Well Kill I

Action that should be taken due to a problem with the kill.

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.

Identify 'stopping points' that would indicate the kill plan was not working.

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.

Handling Kill Problems M

Typical well kill problems. Recognize selected well control problems that can occur during a well control operation: e.g. plugging, washouts, equipment issues.

Responses to kill problems. Demonstrate correct action to a specific problem that maintains well integrity, minimizes further influx and restores bottom hole pressure in a timely manner.


Supervisory




Action/s to take if Casing Pressure may exceed MAASP.

State options available if surface casing pressure is likely to exceed MAASP: 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 I Purpose of a Well Control bridging document.

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.

Decision to Implement Emergency Procedures (e.g., during a Well Kill)

M

Circumstances during a well kill operation that would require emergency procedures to be initiated and possible actions to take to secure the well.

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.

4.12. Well Control Methods

Module Name: Well Control Methods Learning Topics AIM* Learning Topics Assessments and Learning Outcomes


Drillers Method M Basic principles of the Driller's method. Explain basic principles and steps involved in the Drillers Method.


Supervisory



The attendee will gain an understanding of: The attendee will be able to: How to kill a well using the Driller's Method. Demonstrate how to kill a well with the Drillers method. Action/s to take if shut-‐in pressures are not the same following the first circulation.

Select possible courses of action if the shut-‐in pressures are not the same following the first circulation.

How to maintain constant BHP when influx is being circulated through the choke/choke lines.

Demonstrate how to maintain constant BHP when influx is being circulated through the choke lines and choke.

How to handle choke line friction effects during the well kill.

Demonstrate how to start up and shut down a well while compensating for Choke Line friction. State effect of choke line friction on surface pressures during the later stages of the kill process.

State key differences with W&W method Select key differences with Wait & Weight Method Method.

Wait & Weight Method M

Basic principles of the Wait & Weight method. Explain basic principles and steps involved in the Wait & Weight Method.

How to kill a well using the Wait & Weight Method.

Demonstrate how to kill a well with the Wait & Weight method.

Shut-‐in pressure if well is shut-‐in with kill mud at bit.

Select possible courses of action if the shut-‐in drill pipe pressure is not zero following shut-‐in once kill mud is pumped to the Bit.

How to maintain constant BHP when influx is being circulated through the choke/choke lines.

Demonstrate how to maintain constant BHP when influx is being circulated through the choke lines and choke.

How to handle choke line friction effects during the well kill.


Key differences with Drillers method Select key differences with Drillers Method Kill Sheets M Kill sheets Complete a kill sheet using given data (surface or subsea)


Supervisory




Pump Startup and Shut Down Procedure

M

The importance of the start-‐up/shut down procedures in maintaining constant bottomhole pressure.

Explain the importance of using the correct start up and shut down procedure in a well kill: e.g. maintain BHP

The Supervisor's role in the start-‐up/shut down procedures. Demonstrate a start up and shut down procedure

Reasons why start-‐up pump pressure may not equal ICP.

State action to take if start up procedure does not give ICP on the drillpipe gauge: e.g. shut down and discuss, continue with updated ICP, monitor pressures as gels are broken down.

Reasons why pump pressure at shut down may not equal expected pressure.

State reasons why a shutdown may not return shut-‐in pressure to expected value: e.g. safety factors, trapped pressure.

Lag time Demonstrate how to compensate for lag time between a choke adjustment and pump pressure change.

How a Choke Line Friction greater than Shut-‐In Casing Pressure affects start-‐up.

State how a CLF greater than SICP affects start-‐up: e.g. increased ICP, zero casing pressure.

Method used at the end of a kill to verify well is dead

State appropriate actions to take to ensure well is dead before opening up the BOP: e.g. shut down procedure, check for trapped pressure, monitor through choke, circulating practice once well is open.

Method used to shut down at the end of a kill and verify well is dead

State appropriate actions to minimize CLF effect on well when shutting down: e.g. shut down procedure, check for trapped pressure, monitor through choke, circulating practice once well is open.

Volumetric Method I Situations when the Volumetric method is

used.

Select situations when the volumetric method would be used: e.g. unable to circulate, no SIDPP to monitor, off bottom, out of hole.


Supervisory



The attendee will gain an understanding of: The attendee will be able to: Explain the basic principles of the Volumetric method.

Describe basic principles of volumetric method e.g. pressure increase and controlled bleed off cycles.

Action/s to take once influx reaches the BOP. Describe principle of lube and bleed method.

Stripping Technique I

Situations when Stripping is used. Select situations when the stripping would be used: e.g. bit off bottom

Outline key steps in Stripping and Stripping with Gas Migration.

State key steps in stripping process whether compensating for gas migration or not: e.g. strip in pipe, bleed off closed end displacement (barrel in barrel out), incorporating volumetric method to handle potential gas migration, reasons for these two techniques, action to take when Bit is stripped back into the influx

State key considerations to ensure well integrity during stripping operations.

State how to ensure well integrity during stripping operations: e.g. monitor surface pressures, do not exceed formation breakdown, ensure minimum leakage through stripping BOP, maintain overbalance, bleed off correct volumes.

Trapped Gas at BOP

I

Trapped gas at the BOP. Define trapped gas at the BOP

Problems associated with trapped gas at the subsea BOP

Explain how trapped gas can be a problem: e.g. gas trapped beneath BOP can migrate when BOP opened, large-‐scale gas expansion; water depth, divert, danger of gas at rig floor.

Procedure for safely removing trapped gas. List basic steps to remove trapped gas: e.g. secure well below choke line, flush choke line to light fluid, u-‐tube riser back up choke line, fill riser and monitor for residual flow.

Displacing Riser Post-‐Kill

I Reason for displacing Riser following a kill. Give reason for displacing Riser to kill mud.


Supervisory




Bullheading I

Circumstances when Bullheading may be used.

Select reasons why bullheading may be preferred to circulation: e.g. toxic gas, unable to handle influx at surface, potential to exceed equipment limitations if circulated to surface.

Explain the basic principles of Bullheading. Describe key elements of bullheading. Explain how gas migration affects bullhead rate.

State effect gas migration would have on chosen bullhead rate.

Reverse Circulation I Circumstances when Reverse Circulation may be used.

Select reasons why reverse circulation may be preferred to normal circulation: e.g. better containment of formation fluids, less circulation to remove formation fluids, reduced casing pressure.

Basic principles of Reverse Circulation. Describe key elements of reverse circulation

Handling Gas in the Riser

I

Dangers of Riser Gas. State dangers of uncontrolled gas expansion in the Riser: e.g. danger of unloading riser, danger to personnel, danger of fire, reduction in BHP.

Procedures for preventing and handling Riser Gas

State basic principles for preventing riser gas and handling technique: e.g. circulate proportion of bottoms up through choke line, effect of mud type of gas expansion, water depth effect, monitor riser on trip tank to see small gains due to expansion, employ diverter to protect rig floor, possible use of flowline mud gas separators (include dangers associated with their use).

4.13. Equipment Readiness/Assurance

Module Name: Equipment Readiness/Assurance Learning Topics AIM* Learning Topics Assessments and Learning Outcomes


Supervisory



Diverters I

Purpose of Diverter State the purpose of the Diverter in well control operations.

How it functions Describe how the Diverter functions: e.g. valve/s open when Diverter is closed.

General operating parameters Select general operating parameters e.g. pressure to operate, maximum wellbore pressures.

Potential failure and remedial actions during shut-‐in and ongoing kill operation.

State areas where failure may occur during a well control operation: e.g. packer element, flowline seals, valves, action if packer fails.

Well Control Equipment Alignment and Stack Configuration

I How to line up equipment for chosen operation.

Inspect and approve line-‐up BOP stack and manifolds for certain operations: e.g. drilling ahead for chosen shut-‐in procedure and well kill operations.

BOP Stack, Stack Valves, and Wellhead Components

I

Purpose of key equipment.

State the purpose of key items of equipment on the BOP Stack: e.g. Annular, Pipe Rams, VBR's Blind/Shear Rams, Casing Rams, Test Rams, Rubber goods, Locking devices, Failsafe or HCR valves, drilling spool, Choke and kill line connections, wellhead connector/casing head and riser connector, booster line and bleed line.

How each item functions. Describe how each of the key items of equipment function.

General operating parameters. Select general operating parameters: e.g. pressures to operate, temperature rating, maximum wellbore pressures, flow measurement devices, lights.


State areas where failure may occur during a well control operation and how to recognize them: e.g. stuck in open position, primary packers and seals, secondary seals, locking devices, flange seal rings.

Manifolds, Piping, and Valves I Function of this equipment. Describe the function of this equipment in the well control

process.


Supervisory




Typical operating pressure

State how pressure rating can impact line ups during the well kill process: e.g. standpipe manifold, choke manifold, cement manifold, various pressure ratings, temperature rating, valves upstream and downstream of Chokes, flexible hoses, mud pump valves and pressure-‐relief valve, targeted ‘tees’.

Drillstring Valves I

Purpose of key equipment

State the purpose of key items of this equipment: e.g. Inside BOPs, full opening safety valves (including Top-‐Drive/Kelly valves), non-‐return valves, 'dart' valves, float valves in drill string and casing, crossovers

How each item functions Describe how each of the key items of equipment function.

General operating parameters Select general operating parameters: e.g. maximum wellbore pressures, temperature rating,


State areas where failure may occur during a well control operation and how to recognize them: e.g. stuck in the open position, seals and sealing faces, operator seals, leak paths to surface.

Well Control Related Instrumentation and Auxiliary Well Control Equipment

I Purpose of key equipment

Explain purpose and location of key well control instrumentation equipment: e.g. Pit Level indicators, flowline indicators, pressure measuring devices, mud pump stroke counter, pressure gauges, ROP indicator/recorder, maintain calibration, daily maintenance.

Gas Detection Equipment A Purpose of this equipment

Explain purpose and location of gas detection equipment in the circulating system; e.g. measure gas levels in mud and air, flowline, pits, cellar, shakers.

BOP Closing Unit & Control Panels I Purpose of this equipment

Explain the purpose of this equipment in the well control process: e.g. to operate the BOP, give feedback on whether BOP closed, feedback on operating pressure on BOP, secondary stations to operate the BOP.


Supervisory




How the unit and control panel function

Describe how key equipment in this system functions: e.g. Surface v Subsea, fluid storage and accumulators, pressure systems, valving and piping to the BOP, regulators, feedback instrumentation such as gauges, flow meter and lights, Block position

General operating parameters Select general operating parameters: e.g. pressures to operate, maximum wellbore pressures


Interpret (at the level of a Supervisor) operation of gauges, flow meter and lights to check status of BOP during and after closing and opening operations: e.g. demonstrate understanding panel lights, gauges and flow to decide if BOP has functioned correctly.

Function Tests and Pressure Tests I

Difference between Function and Pressure tests

Describe the difference between a function test and a pressure test.

Difference between high and low pressure tests

Describe the difference between a high-‐pressure test and a low-‐pressure test: e.g. typical test values, holding time, period between tests, test fluid type.

How often tests are to be carried out State how often these test are to be carried out, what equipment is tested and direction to test equipment

Monitoring Equipment Failures/ Erroneous Sensor Reading

I Common failures and how they can impact well control operations.

Recognize an error in gauge readings based on discrepancy between gauges: e.g. drill pipe and casing gauges on standpipe, choke manifold and choke panel, analog versus digital.

Deadman, Autoshear and Emergency

I Purpose of this equipment State the purpose of this equipment in the well control process and its basic functionality: e.g. reasons why, basic sequence of events.


Supervisory



The attendee will gain an understanding of: The attendee will be able to: Disconnect System Action to take in case of emergency

disconnect State what action the Supervisor should take if an emergency-‐disconnect is required.

Mud-‐Gas Separator I

Purpose of this equipment Explain purpose and location of the mud gas separator in the circulating system.

General operating parameters

Select general operating parameters: e.g. pressure to operate, calculate maximum operating pressure, vent line diameter, u-‐tube height, potential dangers if overloaded and immediate action to take if overloaded.

Control Chokes (Manual and/or Hydraulic)

I

Purpose of this equipment Explain purpose and location of the control choke/s in the well control system: e.g. manual, hydraulic, fixed.

General operating parameters Select general operating parameters: e.g. how they operate, maximum operating pressure, positive seal or leak potential, control of operating speed.

ROV Hotstab Capability

A Purpose of this equipment e.g. how they operate, maximum operating pressure, positive seal or leak potential, control of operating speed.

Riser Gas Handling Equipment

I Purpose of this equipment State the purpose of this equipment in the well control process and potential dangers with its use.

Stripping and Tripping Tanks I Purpose of this equipment State the purpose of this equipment in the well control

process: e.g. monitoring for leaks, for stripping process Role of Rules and Regulations A Common industry regulation bodies for well

control State major regulating bodies for the student’s area of operation.

4.14. Extract of Subsea Elements

Module Name: Extract of Subsea Elements Learning Topics AIM* Learning Topics Assessments and Learning Outcomes



Supervisory



The attendee will gain an understanding of: The attendee will be able to: Technical Principles

Compressibility and Temperature Effects on Oil Based Fluids (Non Aqueous Fluids (NAF)) and Brines.

I How mud temperature can affect fluid properties.

State how temperature affect fluid 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.

Equivalent Circulating Density (ECD) & Bottom hole Pressure (BHP)

I

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.

The principle of ECD drilling and associated well control problems.

Describe the process of ECD drilling state the potential well control problems that can arise from this process: e.g. underbalance on connections, connection gas, gas issues in long marine Risers, narrow drilling window, mud weight displacement for tripping.

Gas Behavior I Why a gas kick must expand as it is circulated up the wellbore.

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.

Pre-‐Recorded Information


Supervisory




Choke Line Friction (CLF)

I

Reason for taking choke line frictions (CLFs).

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.

Time/s a CLF should be taken. Select times a CLF can be taken: e.g. mud property changes, pump output changes.

Typical flow rate/SPM for a CLF. Choose acceptable flow rate/SPM for a CLF. Which gauges are commonly used to read the CLF value. Select gauges to use to record a CLF.

The effect of taking the CLF on bottom hole pressure.

Given various techniques for recording CLF state the effect on bottom hole pressure.

Choke & Kill Line Fluid Densities

I 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.

Describe the effect on SICP 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.

Kick Awareness during Drilling, Workover, & Completion Operations

Ballooning Issues M Procedure for bleeding down ballooning.

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.

Casing & Cementing Operations

M Factors that increase risk of swabbing and surging during casing running/pulling operations.

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.

Riser Margin M Riser Margin. Define the term Riser Margin. Calculate Riser Margin. Using given data calculate Riser Margin.


Supervisory



The attendee will gain an understanding of: The attendee will be able to: Barriers

Philosophy and Operations Requiring Barriers

M 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

Kick Detection & Drills

Well Flow with Pumps Off

M Conditions on surface that can make it difficult to get accurate pit level readings.


Pit Gain M Conditions on surface that can make it difficult to get accurate pit level readings.


Flow Returns Rate Increase

M Conditions on surface that can make it difficult to get accurate flow rate readings.

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

Shallow Gas/Water Flows & Top Hole Drilling Shallow Subsea Fracture Gradients

I How water depth affects formation fracture pressures in shallow formations.

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.

Drilling & Tripping M 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


Supervisory



The attendee will gain an understanding of: The attendee will be able to: Shut-‐In Procedures & Verification

Running Casing and Cementing

M Action to take if non-‐shearables are across BOPs.

Select actions that can be taken if well kicks with non-‐shearable tubulars across the BOP: e.g. use of Annular, casing rams, drop pipe, emergency disconnect issues

Recording of Shut-‐In Pressures, Differences, and Float in String

M Complications to reading accurate shut-‐in pressures in deepwater wells.

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.

Riser Flow after Shut-‐In

M

Reasons for mud flow from the Riser following well shut-‐in.

State what can cause Riser flow following well shut-‐in: e.g. leaking BOP, gas migration in Riser.

Action to be taken if the Riser is flowing following shut-‐in.

State the action to take if Riser is flowing following shut-‐in: e.g. Check for BOP operation, close another preventer, Divert overboard.

Well Control/Risk Management Decision to Implement Emergency Procedures (e.g., during a Well Kill)

M

Circumstances during a well kill operation that would require emergency procedures to be initiated and possible actions to take to secure the well.

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 Kill Methods

Drillers Method M How to handle choke line friction effects during the well kill.


Wait & Weight Method

M How to handle choke line friction effects during the well kill.

Demonstrate how to start up and shut down a well while compensating for Choke Line friction.


Supervisory



The attendee will gain an understanding of: The attendee will be able to: State effect of choke line friction on surface pressures during the later stages of the kill process.

Kill Sheets M Kill sheets. Complete a kill sheet using given data (surface or subsea)

Pump Start Up and Shut Down Procedure

M

How a Choke Line Friction greater than Shut-‐In Casing Pressure affects start-‐up.

State how a CLF greater than SICP affects start-‐up: e.g. increased ICP, zero casing pressure.

Method used to shut down at the end of a kill and verify well is dead

State appropriate actions to minimize CLF effect on well when shutting down: e.g. shut down procedure, check for trapped pressure, monitor through choke, circulating practice once well is open.

Trapped Gas at BOP

I

Trapped gas at the BOP. Define trapped gas at the BOP

Problems associated with trapped gas at the subsea BOP

Explain how trapped gas can be a problem: e.g. gas trapped beneath BOP can migrate when BOP opened, large-‐scale gas expansion; water depth, divert, danger of gas at rig floor.

Procedure for safely removing trapped gas. List basic steps to remove trapped gas: e.g. secure well below choke line, flush choke line to light fluid, u-‐tube riser back up choke line, fill riser and monitor for residual flow.

Displacing Riser Post-‐Kill

I Reason for displacing Riser following a kill. Give reason for displacing Riser to kill mud.

Handling Gas in the Riser

I Dangers of Riser Gas. State dangers of uncontrolled gas expansion in the Riser: e.g. danger of unloading riser, danger to personnel, danger of fire, reduction in BHP.


Supervisory




Procedures for preventing and handling Riser Gas

State basic principles for preventing riser gas and handling technique: e.g. circulate proportion of bottoms up through choke line, effect of mud type of gas expansion, water depth effect, monitor riser on trip tank to see small gains due to expansion, employ diverter to protect rig floor, possible use of flowline mud gas separators (include dangers associated with their use)

Equipment Readiness/Assurance

Diverter I Purpose of Diverter State the purpose of the Diverter in well control operations: e.g. for protection against gas in the Riser

BOP Stack, Stack Valves, and Wellhead Components

I

Riser Equipment State the purpose of key items of equipment: e.g. LMRP, Riser Connector, Slip Joint, Ball Joint, Flex Joint, Choke & Kill lines, Riser Dump valve, Booster Line, Bleed line

Purpose of key equipment

State the purpose of key items of equipment on the subsea BOP Stack: e.g. Annular, Pipe Rams, VBR's Blind/Shear Rams, Casing Rams, Test Rams, Locking devices, Failsafe valves, wellhead connector

BOP Closing Unit & Control Panels

I Purpose of this equipment

Explain the purpose of this equipment in the well control process: e.g. to operate the BOP, give feedback on whether BOP closed, feedback on operating pressure on BOP, secondary stations to operate the BOP. control valves in correct position, pump start-‐up facility set correctly.


Supervisory




How the unit and control panel function

Describe how key equipment in this system functions: e.g. Pods, fluid storage and accumulators, importance of pre-‐charge, pressure systems (main/pilot), valves and piping/signals to the BOP, regulators, feedback instrumentation such as gauges, flow meter and lights, Block position.

General operating parameters Select general operating parameters e.g. pressures to operate, maximum wellbore pressures.

Potential failure and remedial actions during shut-‐in and on-‐going kill operation.

Interpret (at the level of a Supervisor) operation of gauges, flow meter and lights to check status of BOP during and after closing and opening operations: e.g. did BOP close, demonstrate understanding panel lights, gauges and flow count to decide if BOP has functioned correctly.

Deadman, Autoshear and Emergency Disconnect System

I Purpose of this equipment

State the purpose of this equipment in the well control process and its basic functionality: e.g. basic difference between the systems, reasons why, basic sequence of events.

Action to take in case of emergency disconnect

State what action the Supervisor should take if an emergency-‐disconnect is required.

ROV Hot stab Capability

A Purpose of this equipment State the purpose of this equipment in the well control process.

Riser Gas Handling Equipment

I Purpose of this equipment State the purpose of this equipment in the well control process.