IWCF Well Control Homework [PDF]

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Instructor Copy IWCF Combined Surface & Subsea Student Book Students Manual

I'll MAERSK W TRAINING

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IWCF L3 & L4 Well Control Student Exercise Manual Combined Subsea MT DUB Rev.03-2018/AMT

Maersk Training IWCF L3 & L4 Daily Homework/Exercises

Day One

Student Book Index Combined Surface & Subsea

1 Introduction & Definitions 2 Hydrostatic & Circulating Pressures 3 Formation Strength 4 Causes Of Kicks 5 Warning Signs & Indicators 6 Shut In Methods & Data To Collect Kill Sheet Exercise 1 – Surface or Subsea Day Two 7 Kill Methods 8 Kill Problems 9 Gas Behaviour & Volumetric 10 Tripping & Stripping Kill Sheet Exercise 2 – Surface or Subsea Drillers Method Gauge Questions for L4 candidates – Surface or Subsea Day Three 11 Top Hole, Shallow Gas & Horizontal 12 Casing, Cementing & Wireline 13 Barriers & Inflow Testing 14 Equipment 15 Subsea Equipment – Subsea Candidates Only Kill Sheet Exercise 3 – Surface or Subsea W&W Method Gauge Questions for L4 candidates – Surface or Subsea Day Four Classroom Exercises 16 Ad Hoc Topics 17 IWCF New subsea equipment test Deviated Kill Sheet Gauge Questions for L4 candidates same for all IWCF P&P Practice Exam

MT DUB Rev.07-2017/ AMT

Maersk Training Centre IWCF Well Control Pre-test

Time allowed - 30 minutes

NAME : _________________ DATE : ______________

1 of 6

Q1) Calculate the hydrostatic pressure in the well below: MD

= 13,460 ft

Answer:

7,325

Mud Weight = 12.6 ppg

TVD = 11,180 ft

psi

Q2) Calculate mud weight from the following gradients: a) 0.5096 psi/ft

=

9.8 ppg

b) 0.7748 psi/ft

=

14.9 ppg

Q3) Calculate mud gradients from following mud weights: a) 10.7 ppg

=

0.5564 psi/ft

b) 13.5 ppg

=

0.702 psi/ft

Q4) Use the data below to calculate ECD TVD Current Mud Weight APL = 110 psi

9165 ft 11.1 ppg

11.33 Q5)

ppg

If bottom hole pressure is greater than formation pressure then you have primary well control. TRUE ___

/

FALSE

2 of 6

Q6)

Which of the following are likely to increase the chance of swabbing? (THREE ANSWERS) a) b) c) d) e) f)

Q7)

Pulling through tight hole with the pump off Pulling pipe too quickly Pulling pipe too slowly High mud viscosity Pumping out of the hole Pulling through tight hole with the pump on

Which of the following is the FIRST POSITIVE INDICATOR that you have taken a kick while drilling? a) b) c) d)

Increase in torque Gas cut mud Decrease in pump pressure Increase in return flow

Q8) What is the first action a driller should take after getting a drilling break? a) b) c) d)

Circulate bottoms up Flow check Shut the well in Check with the mud loggers

Q9) Why are the pumps usually kept running when picking up to check for flow? a) It is a throw back to kelly rigs - there is no need with a top drive. b) To check the pressure losses in the Annulus. c) To clean the bottom of the hole of cuttings. d) To maximise the pressure on the bottom of the hole.

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Q10) While killing the well with a surface stack BOP, as the pump speed is increased, what should happen to the casing pressure in order to keep BHP constant? a) Casing pressure should be held steady during a SPM change b) Casing pressure should be allowed to rise during a SPM change c) Casing pressure should be allowed to fall during a SPM change

Q11) Well data: MD TVD Mud weight SCR @ 30 spm SIDPP SICP

9,960 ft 8,780 ft 9.7 ppg 375 psi 425 psi 580 psi

Calculate: a) Kill mud weight

10.7

ppg

b) ICP

800

psi

c) FCP

413

psi

Q12) Use the following data to calculate the maximum allowable mud weight: Shoe TVD = 3,570 feet Test Mud Weight = 10.6 ppg Surface Leak-off Test Pressure = 850 psi

15.1

4 of 6

ppg

Q13) The "unit/remote" switch on the accumulator allows you to do what when "unit" is selected. a) b) c) d)

Adjust Adjust Adjust Adjust

the the the the

annular regulator from the remote panel. manifold regulator from the accumulator. manifold regulators from the remote panel. annular regulator from the accumulator.

Q14) Which of the following correctly describes the operation of the master valve on the BOP remote panel? a)

The master valve when operated moves the 3 position valve to the close position. The master valve when operated will do a panel light test. The master valve must be continually operated whilst functions on the panel are made. Holding the master air valve for 5 seconds then releasing it will allow functions to take place.

b) c) d)

Q15) Once the diverter has been activated, what is the correct sequence for the operation of a surface diverter system. Wind direction is starboard to port. a) b) c) d)

Open starboard vent, close shaker valve, close diverter. Close diverter, close shaker valve, open starboard vent. Close diverter, open port vent, close shaker valve. Open port vent, close shaker valve, close diverter.

Q16) Why is a 20 bbl kick in a small annulus more significant than a 20 bbl kick in a large annulus? a) b) c) d)

The KWM cannot be easily calculated It results in higher annular pressures The kicks are usually gas The pipe is more prone to getting stuck

5 of 6

Q17) Company policy states: “…while killing a well you will always attempt to kill the well using a method that minimizes the pressure on the stack and upper casing.” Which method would you choose? a) b) c) d)

Wait and Weight Driller’s Lubricate and Bleed Volumetric

Q18) On the second circulation of the Driller’s method if the casing pressure was held constant until KWM reached the surface what would happen to BHP? a) Increase b) Decrease c) Stay the same

Q19) Below is a list of possible problems that may occur during a kill. Match the cause to the problem. PROBLEM a. b. c. d.

CAUSE

Both gauges falling Both gauges rising D.P. gauge rising D.P. gauge falling

1. 2. 3. 4.

Choke plugging Bit plugging Choke washout Nozzle/pipe washout

3 a. matches ___________ 1 b. matches ____________ 2 c. matches ____________ 4 d. matches ____________

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0. Index, well barriers material & Pre-Test 1. Day 1: Homework

2.

Day 2: Homework

3. Day 3: Homework

4. Day 4: Classroom Exercises

5. IWCF Practice Exam(s)

6.

7.

International Well Control Forum

Well Barriers © IWCF 2014

IWCF Accredited Centres are free to use and adapt this material as they see fit, for use in training. Please be aware that this presentation is provided for general information only and it is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of the presentation.

© IWCF 2014

WELL BARRIERS

This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or upto-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

WELL BARRIERS Aim: • To fully understand Well Barrier philosophy in Drilling, Coring & Tripping operations. Objectives: • State the Primary Barrier in normal Drilling operations. • Identify Secondary Barrier elements. • Describe a Barrier envelope. • List what Barrier test documentation should contain.

This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

Well Barriers Primary well barrier: • This is the first object that prevents flow from a source. Secondary well barrier: • This is the second object that prevents flow from a source. This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

What are Well Barriers • Well barriers are envelopes (something that surrounds or encloses something else) of one or more dependent WBE’s (well barrier elements) to prevent fluids or gases from flowing unintentionally from a formation, into another formation or back to surface. • Well barrier(s) shall be defined prior to commencement of an activity or operation by description of the required WBE’s to be in place and the specific acceptance criteria. This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

Well Barrier Element Examples 1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

Fluid Barriers Casing and Cement Drill string Drilling, Wireline, Coil Tubing, Workover BOP’s Wellhead Deep set tubing plug Production Packer Stab-in Safety Valves Completion String Tubing Hanger * Barrier elements in red denote other operations in a well

This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

Well Barriers Drilling, Coring, Tripping Primary well barrier: This is the first object that prevents flow from a source.

AP SSR

UPR MPR LPR

Drilling Fluid

Drilling BOP

Formation Pressure

(Fluid) Barrier: The hydrostatic head of the wellbore fluid is greater than the formation pressure. This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

Well Barriers Drilling, Coring, Tripping Primary well barrier: This is the first object that prevents flow from a source.

Secondary well barrier: This is the second object that prevents flow from a source.

This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

SOME OF THE (ELEMENTS) THAT FORM THE BARRIER ENVELOPE BOP

Tubulars Rams

Wellhead Casing Formation Pressure

Cement

Safety Valves

Choke/Kill line valves

This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

SOME OF THE (ELEMENTS) THAT FORM THE BARRIER ENVELOPE

Safety Valves Rams

Wellhead

BOP

Cement Tubulars Casing Choke/Kill line valves

This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

Well Barrier Acceptance Criteria.

•

Well barrier acceptance criteria are technical and operational requirements that need to be fulfilled in order to qualify the well barrier or WBE for its intended use.

This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

Acceptance Criteria Function and number of well barriers The function of the well barrier and WBE shall be clearly defined. • One well barrier in place during all well activities and operations, including suspended or abandoned wells, where a pressure differential exists that may cause uncontrolled cross flow in the wellbore between formation zones.

• Two well barriers available during all well activities and operations, including suspended or abandoned wells, where a pressure differential exists that may cause uncontrolled outflow from the borehole/well to the external environment.

This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

Well Barrier Acceptance Criteria Example Drilling BOP Features

Acceptance Criteria

A.Description

The element consists of the wellhead connector and drilling BOP with kill/choke line valves.

B. Function

The function of wellhead connector is to prevent flow from the bore to the environment and to provide a mechanical connection between drilling BOP and the wellhead. The function of the BOP is to provide capabilities to close in and seal the well bore with or without tools/equipment through the BOP.

C. Design construction selection

1. The drilling BOP shall be constructed in accordance with !!!!! standards. 2. The BOP WP shall exceed the MWDP (maximum well design pressure) including a margin for kill operations. 3. It shall be documented that the shear/seal ram can shear the drill pipe, tubing, wireline, CT or other specified tools, and seal the well bore thereafter. If this can not be documented by the manufacturer, a qualification test shall be performed and documented. 4. When running non shearable items, there shall be minimum one pipe ram or annular preventer able to seal the actual size of the non shearable item. 5. For floaters the wellhead connector shall be equipped with a secondary release feature allowing release with ROV. 6. When using tapered drill pipe string there should be pipe rams to fit each pipe size. Variable bore rams should have sufficient hang off load capacity. 7. There shall be an outlet below the LPR. This outlet shall be used as the last resort to regain well control in a well control situation. 8. HTHP: The BOP shall be furnished with surface readout pressure and temperature. 9. Deep water: 9.1. The BOP should be furnished with surface readout pressure and temperature. 9.2. The drilling BOP shall have two annular preventers. One or both of the annular preventers shall be part of the LMRP. It should be possible to bleed off gas trapped between the preventers in a controlled way. 9.3. Bending loads on the BOP flanges and connector shall be verified to withstand maximum bending loads (e.g. Highest allowable riser angle and highest expected drilling fluid density.) 9.4 From a DP vessel it shall be possible to shear full casing strings and seal thereafter. If this is not possible the casings should be run as liners.

D. Initial test and verification

See Example, Table A

E. Use

The drilling BOP elements shall be activated as described in the well control action procedures.

F. Monitoring

See Example, Table A

G. Failure modes

Non-fulfillment of the above mentioned requirements. See Example, Table B

See

API RP53

This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

Table A. Routine leak testing of drilling BOP and well control equipment Before Drilling out Casing

Frequency Stump

Surface Element

BOP

Choke/Kill line and Manifold

Other Equipment

Deeper Casing & Liners

Periodic Before Well Testing

Annulars Pipe Rams Shear Rams Failsafe Valves Wellhead Connector Wedge Locks

MWDP 1) MWDP MWDP MWDP MWDP Function

Function Function Function Function MSDP

MSDP 1) MSDP MSDP MSDP 3)

TSTP 1) TSTP TSTP TSTP TSTP

Choke/Kill Lines Manifold Valves Remote Chokes

MWDP MWDP Function

MSDP MSDP Function

MSDP MSDP Function

TSTP TSTP Function

Kill Pump Inside BOP Stabbing Valves Upper Kelly Valve Lower Kelly Valve

WP 2) MWDP 2) MWDP 2) MWDP 2) MWDP 2)

Legend WP

Working Pressure

MWDP

Maximum Well Design Pressure

MSDP

Maximum Section Design Pressure

Function

Function Testing shall be done from alternating panels/pods

TSTP

Tubing String Test Pressure

1)

Or Maximum 70% of WP

2)

Or at initial installation

3)

From above if restricted by BOP arrangement

MSDP MSDP MSDP MSDP MSDP

TSTP TSTP

Weekly Function Function Function Function

Each 14 Days MSDP 1) MSDP MSDP 3) MSDP

Each 6 Months WP x 0.7 WP WP WP WP

MSDP MSDP Function

WP WP

MSDP MSDP MSDP MSDP MSDP

WP WP WP WP WP

NOTE 1 All tests shall be 1,5 MPa (200 psi) to 2 MPa (300 psi) for 5 min and high pressure for 10 min. NOTE 2 If the drilling BOP is disconnected/re-connected or moved between wells without having been disconnected from its control system, the initial leak test of the BOP components can be omitted. The wellhead connector shall be leak tested. NOTE 3 The BOP with associated valves and other pressure control equipment on the facility shall be subjected to a complete overhaul and shall be recertified every five years. The complete overhaul shall be documented.

© IWCF 2014

Table B - Failure of drilling BOP and control systems

Barrier element/equipment Annular

Shear ram

Actions to be taken when failure to test

Repair immediately.

If WBE, repair immediately.

Pipe ram (upper, middle, lower)

If WBE, repair immediately if no other pipe rams is available for that pipe size. Rams that failed to test to be repaired at a convenient time.

Choke valves, inner/outer Kill valves, inner/outer

If both valves in series have failed, repair immediately. If one valve in series has failed, repair after having set casing.

Marine riser choke and kill line *

If one has failed, repair immediately.

Yellow and blue pod *

If both have failed, repair immediately. If one has failed, repair at a convenient time.

Acoustic – shear ram *

Same as for shear ram.

Acoustic – pipe rams *

If one or more have failed, repair after having set casing if size is covered by another ram. If not, repair immediately.

Floating Installations Nomenclature :

Immediately: Stop operation and temporary abandon well. After having set casing: Carry on with the operation and repair after having set the next casing. Convenient time: Applicable for WBE’s that are not required.

This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

Pressure direction • The pressure should be applied in the flow direction. If this is impractical, the pressure can be applied against the flow direction, providing that the WBE is constructed to seal in both flow directions or by reducing the pressure on the downstream side of the well barrier to the lowest practical pressure (inflow test).

This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

Documentation of leak and function testing of well barriers

All well integrity tests shall be documented and accepted by an authorized person. This authorized person can be the driller, tool-pusher, drilling and well intervention supervisor or the equipment and service provider's representative. The chart and the test documentation should contain • Type of test, • Test pressure, • Test fluid, • System or components tested, • Estimated volume of system pressurized, • Volume pumped

This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

‘Swiss Cheese Model’

•

What Is Human Error? Human error is an imbalance between what the situation requires, what the person intends, and what he/she actually does.

•

Human error happens when people: Plan to do the right thing but with the wrong outcome (e.g., misdial a correct telephone number; give the correct instruction but to the wrong person) Do the wrong thing for the situation (e.g. turn an alarm off) Fail to do anything when action is required (e.g. fail to report faulty equipment)

This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

‘Swiss Cheese Model’

•

Why do Errors Happen? As imperfect humans, we have inherent limitations in our abilities. We will make mistakes. To answer the question of “why do errors happen?” or “why did the error happen?” it is necessary to look beyond the person who made the error. Simply put, errors happen when multiple factors come together to allow them to happen. What we usually call “human error” is really “system error”. People are one part of a system that includes all of the other parts of the organization or work environment – equipment, technology, environment, organization, training, policies, and procedures. Human error is rooted in failure of the system or the organization to prevent the error from happening, and if an error happens, failure to prevent the error from becoming a problem.

This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

‘Swiss Cheese Model’

© IWCF 2014

The concept of ‘defenses’ against human error Examples of defenses: • Checking drilling mud weights. • Challenging response procedures (being told to do something you know is wrong). • Setting alarms correctly. • Following correct testing procedures. • It is when these defenses are weakened and breached that human errors can result in incidents or accidents. • These defenses can be portrayed diagrammatically, as several slices of Swiss cheese (and hence the model has become known as Professor Reason’s “Swiss cheese” model) This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

‘Swiss Cheese Model’

• Some failures are ‘latent’, meaning that they have been made at some point in the past and lay dormant. • This may be introduced at the time a well barrier was designed or may be associated with management decisions and policies. • Errors made by front line personnel, such as Supervisors, Drillers etc, are ‘active’ failures. • The more holes in a system’s defenses, the more likely it is that errors result in incidents or accidents. • In certain circumstances, when all holes ‘line up’, blowouts occur. This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

Simple ‘Swiss Cheese Model’ explaining how a blowout could happen Shear rams fail to shear pipe causing escape of hydrocarbons and explosion on rig floor. Latent & Active Failures. Secondary barrier element breached due to incorrect procedures (Tool joint across pipe rams).

Latent & Active failures: Delayed detection. Well monitoring not done resulting in increased kick size. Annular Fails to seal.

Reservoir Hydrocarbons

Active failure: Fluid barrier breached when pulling pipe too fast reduced hydrostatic pressure and allowed the well to flow.

Latent failure: Inadequate mud checks failed to pick up on reduced mud weight? This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

© IWCF 2014

This presentation is not intended to amount to advice or guidance which you should rely upon. It does not represent an official industry standard or recommended practice. IWCF makes no representation, warranty or guarantee that the content is accurate, complete or up-to-date. IWCF shall not be liable in any way for any claims, losses or demands relating to your use of this presentation.

Instructor's Copy

Day1: Exercises

Classified as General

Day 1: exercises

Blank Page

IWCF combined surface & subsea student book L3/4 Classified as General

2

Day 1: exercises

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2

2

Instructor's Copy

Introduction & Definitions

IWCF combined surface & subsea student book L3/4 Classified as General

3

Day 1: exercises Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for the use for course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training.

Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

IWCF combined surface & subsea student book L3/4 Classified as General

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Day 1: exercises

Q1) Normal formation pressure gradient is generally assumed to be: a) 0.496 psi/ft b) 0.564 psi/ft c) 0.376 psi/ft d) 0.465 psi/ft Q2) Referring to the last question, what mud weight would be required to Balance normal formation pressure?

8.94

ppg

Q3) Which of the following statements best describes formation porosity? a) The ratio of the pore spaces to the total volume of the rock b) The ability of the fluid and gas to move within the rock c) The presence of sufficient water volume to provide gas lift d) When hydrostatic pressure prevents a kick Q4) Which of the following statements best describes formation permeability? a) The ratio of the pore spaces to the total volume of the rock b) The ability of fluid and gas to move within a rock c) The presence of sufficient water volume to provide gas lift d) When hydrostatic pressure prevents a kick Q5) What steps can be taken to prevent over regulation of the drilling industry by governments? a) Conducting consistent and uniform training for all personnel with well control responsibilities no matter how small b) Ensuring all paper work is in place and has been crosschecked by the QA department in the main office c) Using drilling rigs with a greater capability than required for the job to demonstrate that the well will be drilled safely d) Having a crew compliment made up of international senior personnel and a high percentage of locally based personnel

IWCF combined surface & subsea student book L3/4 Classified as General

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Day 1: exercises

Q6) Which of the following best describes what the BOP does? a) Allows for well circulation. Without it there would not be a flow path from the well b) Maintains well integrity. It keeps bottom hole pressure above formation pressure c) Nothing most of the time. It is there to close if needed in the event of a kick d) Prevents kicks coming in the well. There is no other way to prevent kicks Q7) Which of the following best describes secondary well control pressure? a) Hydrostatic pressure equals formation pressure b) Hydrostatic pressure plus APL while circulating equals formation pressure c) Hydrostatic pressure plus degree of overbalance equals formation pressure d) Hydrostatic pressure plus surface backpressure while shut in equals formation pressure Q8) Which of the following best describes hydrostatic pressure? a) Hydrostatic pressure is the pressure exerted on the bottom of the hole by the mud in the annulus. Pump off b) Hydrostatic pressure is the pressure exerted at any point in the well by a vertical column of fluid above that point. Pump on c) Hydrostatic pressure is the pressure exerted at any point in the well by a vertical column of fluid above that point. Pump off d) Hydrostatic pressure is the pressure exerted on the bottom of the hole by the mud in the annulus. Pump on Q9) Which of the following best describes primary well control? a) b) c) d)

Bottom hole pressure is greater than formation pressure Hydrostatic pressure is greater than formation pressure Fracture pressure is greater than formation pressure Circulating pressure is greater than formation pressure

IWCF combined surface & subsea student book L3/4 Classified as General

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Day 1: exercises

Q10) What is the purpose of the BOP stack? (TWO ANSWERS) a) b) c) d) e)

Allows you to close the well in when it is flowing Can always be relied on when primary well control fails Ensures that the well can always be shut in regardless of tubular Gives you a choice of circulating routes when killing a kick Allows you to move to another well in the event of a problem

Q11) What is the best definition of a kick? a) b) c) d)

Any entry of formation fluids into the well Formation fluids entering the well during testing An uncontrolled entry of formation fluids into the well An uncontrolled exit of formation fluids at surface

Q12) What is the best definition of a blowout? a) An controlled entry of formation fluids into the well b) Formation fluids exiting the well at surface c) Formation fluids exiting the well at surface during testing d) An uncontrolled exit of formation fluids at surface

IWCF combined surface & subsea student book L3/4 Classified as General

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Day 1: exercises

IWCF combined surface & subsea student book L3/4 Classified as General

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Day 1: exercises

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2

2

Hydrostatic & Circulating Pressure Instructor's Copy

IWCF combined surface & subsea student book L3/4 Classified as General

9

Day 1: exercises Manual standard clause

This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for the use for course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training.

Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

IWCF combined surface & subsea student book L3/4 Classified as General

10

Day 1: exercises Q1) Calculate the hydrostatic pressure in the well below: MD ft

= 14,750 ft

Answer:

Mud Weight = 13.8 ppg

8,970

TVD = 12,500

psi

Q2) Calculate mud weight from the following gradients: a) 0.465 psi/ft

=

8.94 ppg

b) 0.533 psi/ft

=

10.25 ppg

c) 0.6656 psi/ft

=

12.8 ppg

Q3) Calculate mud gradients from following mud weights: a) 9.2 ppg

=

0.4784 psi/ft

b) 12.2 ppg

=

0.6344 psi/ft

c) 14.9 ppg

=

0.7748 psi/ft

Q4) When pumping at 80 SPM the pump pressure = 4000 psi. What would be approximate pump pressure if pumps were slowed to 40 SPM? a) 500 psi b) 800psi c) 1000 psi d) 2000 psi

formula #9

Q5) Equivalent circulating density (ECD) can be used to determine the effect on bottom hole pressure while circulating. Which part of the system pressure losses is used to calculate ECD? a) The pressure loss in the annulus b) The pressure loss in the open hole section only c) The pressure loss across the nozzles d) The pressure loss in the drill string.

IWCF combined surface & subsea student book L3/4 Classified as General

11

Day 1: exercises Q6) A vertical well is 5500 feet deep and filled with 11.2 ppg mud. While circulating at 100 spm the friction losses in the well are as follows: 150 psi through surface equipment 1,700 psi through bit nozzles 900 psi in drill string. 100 psi in annulus What is the bottom hole pressure when the pumps are running at 100 spm? Answer: 3303 Q7) Mud density = 12 ppg

psi Pump pressure = 750 psi at 60 SPM

Formula #10

Calculate approximate pump pressure if mud weight is: a) Increased to 13 ppg

Answer

812

psi

b) Decreased to 11 ppg

Answer

687

psi

Q8) The following data has been recorded: Drilling fluid density = 10 ppg Pump rate = 60 SPM Pump efficiency = 92% Standpipe pressure = 3180 psi What pressure will be seen on the standpipe if the pump rate is reduced to 35 SPM and drilling fluid density is increased to 10.3 ppg in the well? a) 1740 psi b) 1115 psi c) 870 psi d) 435 psi

F# 9 & F#10

IWCF combined surface & subsea student book L3/4 Classified as General

12

Day 1: exercises Q9) A 15 bbl light pill which is 2.00 ppg lower than the current drilling fluid density is circulated into an 8030 ft TVD well. Which one of the options is correctly stating the moment when hydrostatic bottom hole pressure starts to decrease? a) When the entire pill has been displaced into the annulus b) When the entire pill has been displaced into the drill string c) When the pill starts to be displaced into the drill string d) When the pill starts to be displaced into the annulus Q10) Use the data below to answer the following two questions: TVD = 8045 ft

Current Mud Weight = 10.3 ppg

a) Calculate static bottom hole pressure =

APL = 90 psi psi

4,309

b) Calculate Equivalent Circulating Density = 10.58 ppg

F#7

Q11) If the fluid level dropped 550 feet in a 9,600 foot hole containing 10.6 ppg mud, what would the hydrostatic pressure be? a) 5,596 psi b) 4,988 psi c) 5,843 psi d) 5,100 psi Q12) If the pump speed is increased, what happens to the friction losses in the annulus? a) Decreases b) Stays the same c) Increases

IWCF combined surface & subsea student book L3/4 Classified as General

13

Day 1: exercises Q13) Choose six (6) situations from the following list when you would consider taking a new SCRP: a) Every shift b) Mud weight changes c) Significant mud property changes d) Before and after a leak-off test e) After each connection when drilling with a top drive f) When long sections of hole are drilled rapidly g) After recharging pulsation dampeners h) When returning to drilling after killing a kick Q14) There are many factors that should be considered when selecting a kill pump rate; however, the main objective should be to regain control of the well. Choose the one answer that meets this objective. a) By using the slowest pump rate the pumps will not “jack off” at b) At the rate used during the most recent choke drill c) As safe as possible considering all aspects of the kill d) As fast as possible for the mud gas separator Q15) The following slow circulating rate pressures (SCRP) were recorded. Which one does not seem to be correct? a) 30 spm @ 100 psi b) 40 spm @ 180 psi c) 50 spm @ 400 psi Q16) TVD = 8000 ft

Mud weight = 10 ppg, APL = 250 psi

What is the BHCP – Bottom Hole Circulating Pressure? a) 4160 psi b) 4410 psi c) 3910 psi Q17) Which gauge is used to measure the slow circulating pressure loss? a) The pressure gauge at the Drillers console b) The pressure gauge on the standpipe manifold c) The pressure gauge in the pump room d) The pressure gauge on the remote choke panel

IWCF combined surface & subsea student book L3/4 Classified as General

14

Day 1: exercises Q18) Convert the following pressure gradients into mud weights in ppg. a) 0.65 psi/ft

= 12.5

ppg

b) 0.884 psi/ft

= 17.0

ppg

Q19) Change the ECD values below to BHCP for the given depths: ECD (ppg)

TVD (ft)

BHCP (psi)

5,532

a)

13.3

8000

b)

11.5

11400

6,817

c)

9.8

12500

6,370

Q20) Which of the following statements about slow circulating rates (SCR) is wrong? a) SCR’s should be taken through the choke manifold b) SCR’s are needed to calculate approximate ICP c) SCR’s should be taken when mud properties are changed d) SCR’s should be taken with the bit near the bottom Q21 Which of the following would cause pump pressure to increase if pumping at a constant SPM? (Choose TWO answers). a) Using larger nozzles. b) Drilling deeper. c) When the mud weight is reduced. d) Increasing the mud viscosity. Q22) Which of the following should be considered when choosing the slow circulation rates to be measured? (THREE ANSWERS) a) Trip tank volume b) The mud/gas separator handling capacity c) The volume of mud the choke can handle d) Capacity of mud mixing equipment e) Annular friction loss during the kill f) The burst pressure of the casing g) The rates used at the last choke/strip drill

IWCF combined surface & subsea student book L3/4 Classified as General

15

Day 1: exercises

SUBSEA QUESTIONS Q23) Which of the following are correct ways of measuring CLF? (Three answers) a) Pump down choke line taking returns up the riser. Pump pressure is the CLF b) Pump down the kill line with returns up the drill pipe. Pump pressure is the CLF c) Pump down the riser up the choke line. Pump pressure is half the CLF d) Take SCRS up the riser then circulate at the same rates up the choke line with the BOP closed. The difference is the CLF e) Pump down the kill up the choke with the riser and well isolated. The pump pressure is twice the CLF f) Pump down the string and up the annulus with the riser and choke line open. Pump pressure is CLF Q24) Use the data provided to answer the three questions below. Depth = 13500 ft

Mud weight = 12.1 ppg

SCR through riser at 40 SPM = 650 psi Circulating pressure up choke line at 40 SPM = 900 psi a) Current choke line friction (CLF) @ 40 SPM = b) CLF with current mud weight @ 30 SPM = c) CLF @ 40 SPM with 13.5 ppg mud =

IWCF combined surface & subsea student book L3/4 Classified as General

250 141 279

psi psi psi

16

Day 1: exercises

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2  N1  P2 = P1 ×    N 2

2

Formation Strength Instructor's Copy

IWCF combined surface & subsea student book L3/4 Classified as General

17

Day 1: exercises Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for the use for course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training.

Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

IWCF combined surface & subsea student book L3/4 Classified as General

18

Day 1: exercises Q1) When should a leak-off test be carried out? a) Before drilling out casing shoe b) Before running casing c) Immediately after running and cementing casing d) After drilling out the casing shoe and 5 to 15 feet of new formation Q2) Which of the following are needed for the calculation of accurate formation strength at the shoe? (Choose THREE answers.) a) Accurate pressure gauge b) Accurate stroke counter c) Accurate hole capacity d) Exact vertical depth of casing shoe e) Installation of retrievable packer approximately 1000 feet below the rig floor f) Constant mud weight around the well Q3) Which of the following have to be performed before taking a leak-off test? (Choose THREE answers) a) b) c) d) e)

Circulate the mud to get same weight all the way around Line up through kill line and pump at the slow circulating rate To prevent damaging the formation raise the bit up inside the shoe Drill out the Casing Shoe and 15 ft into new formation To minimize chance of stuck pipe raise the bit up inside the shoe

Q4) Which of the following could influence the leak-off test result? a) Volume of mud in the well b) The slow circulating rate (SCR) c) Having mud of different densities around the well d) Maximum pressure mud pump can handle

IWCF combined surface & subsea student book L3/4 Classified as General

19

Day 1: exercises Q5) Which of the following is a definition of MAASP? a) The pressure in excess of mud hydrostatic that, if exceeded, may cause losses at the shoe b) The maximum pressure allowed in the hole during a kill operation c) The maximum pressure allowed on the drill pipe gauge during a kill operation d) The total pressure applied at the shoe that is likely to cause losses Q6) Use the following data to calculate the maximum allowable mud weight: Shoe TVD = 6000 feet Test Mud Weight = 11 ppg Surface Leak-off Test Pressure = 900 psi

13.8

ppg

F#11

Q7) What will happen to MAASP if Mud Weight is increased? a) MAASP will stay the same b) MAASP will increase c) MAASP will decrease Q8) Which of the following affects Maximum Allowable Annular Surface Pressure (MAASP)? (Choose THREE answers.) a) The TVD of the last casing shoe b) The maximum pump pressure c) The mud weight in the hole d) Viscosity and water loss of the mud e) The fracture pressure of the formation at the shoe f) The ID of the last casing string Q9) When should MAASP be recalculated? a) At the beginning of each shift b) Immediately before entering a reservoir c) After each bit change d) After changing the mud weight

IWCF combined surface & subsea student book L3/4 Classified as General

20

Day 1: exercises

Pressure applied at surface

Q10) Use the graph and data below to answer the following two questions:

1200 1100 1000 900 800

Volume Pumped Shoe TVD = 8500 ft

Mud Weight at Test = 11.6 ppg

a) What pressure was applied to the casing shoe when the leak off took place in excess of Hydrostatic pressure?

900 b) What is the maximum mud weight? ppg

IWCF combined surface & subsea student book L3/4 Classified as General

psi

13.6 ppg

21

Day 1: exercises Q11) Casing has been set and cemented. The well program calls for a leak-off test but the mud weight in the active pits has been increased to .5 ppg higher than the mud weight in the hole. Which of the following would provide the most accurate leak-off test results? a) Use cement pump to pump down the drill pipe and record pressures and barrels pumped b) Circulate and condition the mud until the density is the same throughout the system c) Use cement pump to pump down the annulus and record pressures and barrels pumped d) It is impossible to obtain accurate test results so use pressures from a previous test Q12) What is the main purpose of a Leak-Off Test? a) Determine formation pressure at the shoe b) Test the surface equipment for pressure integrity c) Determine the strength of the formation below the casing shoe d) Test the cement and casing for pressure leaks Q13) Which of the following best describes fracture pressure? a) The pressure in excess of mud hydrostatic, that if exceeded, is likely to causes losses at the shoe formation b) The total pressure applied to the shoe formation that is likely to cause losses c) The maximum BHP during a kill operation d) The maximum pressure allowed on the drill pipe gauge during a kill operation Q14) Which 2 (TWO) of the following would contribute to higher fracture gradients? a) Casing setting depth close to the surface b) Casing setting depth far from the surface c) A small difference existing between the mud hydrostatic pressure and fracture pressure d) A large difference existing between the mud hydrostatic pressure and fracture pressure

IWCF combined surface & subsea student book L3/4 Classified as General

22

Day 1: exercises Q15) The mud weight in the well was increased by 1.2 ppg. What will the new MAASP be if the casing shoe is set at 5,675 feet MD and 5,125 feet TVD? a) 354 psi lower than previous MAASP b) 320 psi higher than previous MAASP c) 320 psi lower than previous MAASP d) 354 psi higher than previous MAASP Q16) The fracture gradient of an open hole formation at 3680 feet is 0.618 psi/ft. The drilling mud currently in use is 9.8 ppg. Approximately how much surface casing pressure can be applied to the well before the formation breaks down? a) 350 to 375 psi b) 2275 to 1195 psi c) 630 to 692 psi d) 382 to 398 psi DATA FOR QUESTIONS 17 & 18 13 3/8” surface casing is set and cemented at 3126’ TVD. The cement is drilled out together with 15 feet of new hole using 10.2 ppg mud. A Leak-Off Pressure of 670 psi is observed. Q17) What is the formation fracture gradient? a) 0.619 psi/ft b) 0.837 psi/ft c) 0.7447 psi/ft d) 0.530 psi/ft Q18) What is the Maximum Allowable Annular Surface Pressure if 11.4 ppg mud is in use at 6500 feet TVD? a) 970 to 975 psi b) 471 to 475 psi c) 449 to 454 psi d) 563 to 569 psi

IWCF combined surface & subsea student book L3/4 Classified as General

23

Day 1: exercises

SUBSEA QUESTIONS Q19) Use the following information to calculate the MAASP if the choke line was filled with glycol/water mix. Well TVD = 10000 ft Riser length = 1000 ft ppg Current mud weight = 12.4 ppg

Casing TVD = 7000ft Maximum mud weight = 15.2 Glycol/water density = 9.3 ppg

a) 1180psi b) 5530psi c) 1020psi d) 6450psi Q20) Use the following information to calculate the MAASP if the choke line was filled with glycol/water mix. Well TVD = 11500 ft Riser length = 1175 ft ppg Current mud weight = 13.6 ppg

Casing TVD = 8740ft Maximum mud weight = 17.6 Glycol/water density = 9.25 ppg

2,083

psi

Q21) A floating rig is drilling 26” hole with returns up the riser. data: Air gap Sea water depth TVD Sea water gradient Overburden gradient Max APL @ TVD a)

80 ft 210 ft 650 ft 0.44 psi/ft 0.68 psi/ft 15 psi

What is the maximum mud weight that can be used withut fracturing the formation?

9.9 b)

ppg

What is the maximum mud weigh that can be circulated?

9.4

IWCF combined surface & subsea student book L3/4 Classified as General

Well

ppg

24

Day 1: exercises

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2

2

Causes Of Kicks Instructor's Copy

IWCF combined surface & subsea student book L3/4 Classified as General

25

Day 1: exercises Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for the use for course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training.

Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

IWCF combined surface & subsea student book L3/4 Classified as General

26

Day 1: exercises Q1)

Abnormally high formation pressures form usually when: a) b) c) d)

Q2)

An impermeable zone doesn’t allow formation fluids to escape WOB and ROP are increased rapidly Shales are compacted and allow formation fluids to escape Depleted sandstone has a high porosity

What is the most common cause of abnormally pressured formations throughout the world? a) b) c) d)

Thick sandstone sections Under compacted shales Faults Uplift and erosion

Q3) How will bottom hole pressure be affected by gas cut mud whilst drilling? a) b) c) Q4)

In a well with gas cut mud, when is the reduction in bottom hole pressure greatest? a) b) c)

Q5)

There will be a small decrease There will be a large decrease There will be no change

When the gas is at the casing shoe When the gas is at bottom When the gas reaches the surface

Which of the following would be the immediate effect of swabbing? a) b) c) d)

Decrease in bottom hole pressure A kick Losses Increase in bottom hole pressure

IWCF combined surface & subsea student book L3/4 Classified as General

27

Day 1: exercises Q6) Which of the following are likely to increase the chance of swabbing? (THREE ANSWERS) a) b) c) d) e) f)

Pulling through tight hole with the pump off Pulling pipe too quickly Pulling pipe too slowly High mud viscosity Pumping out of the hole Pulling through tight hole with the pump on

Q7) Which of the following increase the risk of swabbing? (THREE ANSWERS) a) b) c) d) e) Q8)

Overpull while tripping out is a stuck pipe warning sign. What well control problem may be associated with overpull? a) b) c) d)

Q9)

Low permeability formation Viscous mud Spiral drill collars in the BHA Tripping out too fast Balled up stabilisers

Swabbing Losses Hydrogen Sulphide gas Surging

Which of the following increase surge pressures when running in the hole? (TWO ANSWERS) a) b) c) d) e) f)

Small annular clearance High gel strength mud Large bit nozzles Large annular clearance Running-in slowly Low gel strength mud

IWCF combined surface & subsea student book L3/4 Classified as General

28

Day 1: exercises Q10) Does a kick always occur after a total loss of circulation? a) b) c) d)

Yes - total losses always means that you lose primary well control No - it depends on how much hydrostatic pressure is actually lost Yes - but only if losses occur above any potential kick zone No - it depends on the reduction in drill string weight

Q11) While drilling ahead through a faulted formation, the flow meter drops from 65% to 40%. What is the most likely cause of this? a) b) c) d)

There is a washout in the string Partial lost circulation has occurred A kick has been swabbed in Total lost circulation has occurred

Q12) The flow sensor shows a total loss of returns and the mud level cannot be seen in the annulus. What should you do? a) b) c) d)

Shut the well in and pump lost circulation material followed by kill mud that gives extra overbalance Fill the annulus with water (or lightest drilling fluid available) and record volume pumped Pump at reduced rate adding lost circulation material as you circulate until returns are re-established Continue to drill ahead cautiously while reducing the mud weight until you re-establish returns at surface

Q13) What is the most common cause of abnormal formation pressure? a) b) c) d)

Trapped fluid in Shale Carbonate layers Depleted sands Salt domes

Q14) What is meant by abnormal pressure? a) b) c) d)

The excess pressure due to circulating mud at high rates The excess pressure that needs to be applied to cause leak-off Heavy weight mud used to give an overbalance The formation fluid pressure that exceeds formation water hydrostatic pressure

IWCF combined surface & subsea student book L3/4 Classified as General

29

Day 1: exercises Q15) Which of the following causes of kicks is avoidable and due to the Driller not being alert? a) b) c) d)

Lost circulation Gas cut mud Not keeping the hole full Abnormal pressures

Q16) With the pumps running continuously a heavy mud pill is circulated. When will bottom hole pressure start to increase (ignore any dynamic pressure losses in the well)? a) b) c) d)

Once all the pill is in the annulus Once the pill starts to be displaced into the annulus As soon as the pill is pumped into the drillstring Once all the pill is about to exit the bit

Q17) With the pumps running continuously a light mud pill is circulated. When will bottom hole pressure have decreased the most (ignore any dynamic pressure losses in the well)? a) b) c) d)

As soon as the pill starts to be pumped down the drillstring Once all the pill is about to exit the bit Once the pill starts to be displaced into the annulus Once all the pill is in the annulus

Q18) During normal drilling operations 30 bbls of light mud is pumped into the string followed by original mud. The Driller shuts down with the light mud still inside the drill pipe and observes the well. WELL DATA Well depth (TVD) Drill pipe capacity Original mud weight Light mud weight Which of the following a) b) c) d)

9,000 feet 0.0176 bbls/ft 12 ppg 10 ppg is correct?

Bottom hole pressure will remain the same but a back pressure of 177 psi will be seen on the drill pipe pressure gauge Bottom hole pressure will increase 177 psi Bottom hole pressure will drop by 177 psi Bottom hole pressure will remain the same but a back pressure of 177 psi will be seen on the casing pressure gauge

IWCF combined surface & subsea student book L3/4 Classified as General

30

Day 1: exercises Q19) Severe losses occurred while drilling. The pumps were stopped and the mud in the well could not be seen. The well was then filled to the top with water. Mud weight 12.3 ppg Sea water weight 8.6 ppg DP - Casing Annulus capacity - 0.052 bbl/ft What is the reduction in bottom hole pressure if 10.4 bbls of water were pumped to re-establish returns at surface compared to when the well was full of mud? a) b) c) d)

128 psi 104 psi 89 psi 38 psi

Q20) At 17 ½ inch hole is being drilled at 4,230 feet TVD. The formation fluid pressure is 2,095 psi at this depth. Is the formation fluid pressure: a) b) c)

Above normal Below normal Normal

Q21) A gas bearing formation is over pressured by the artesian effect. Which of the following has created the overpressure? a)

The difference in density between formation gas and formation fluid b) A formation water source located at a higher level than the drill floor c) Compaction of the formation caused by shallow overlying formations d) The artesian well effect will have no effect on formation pressure

IWCF combined surface & subsea student book L3/4 Classified as General

31

Day 1: exercises Q22) Gas with a gradient of 0.12 psi/ft is trapped below a dome shaped cap rock with communication to a normally pressured permeable and porous formation at 8,000 ft TVD. The top of the cap rock is at 7,200 ft TVD and is 50 ft thick. What pressure will you encounter when you drill through the cap rock?

7,200 8,000

50 ft THICK CAP ROCK

GAS 0.12 psi/ft

NORMALLY PRESSURED FORMATION

3,630 psi

IWCF combined surface & subsea student book L3/4 Classified as General

32

Day 1: exercises

SUBSEA QUESTION Q23) The subsea BOP is accidentally disconnected during drilling operations on a semi-submersible drilling rig. Use the data below to answer the three questions. Well TVD Mud weight in use Sea water gradient Sea water depth Air gap a)

3,570 ft 9.9 ppg 0.456 psi/ft 470 ft 75 ft

What will be the overall reduction in hydrostatic pressure on the bottom of the hole after the riser has been disconnected?

66 b)

Assuming that 9.9 ppg is a balance mud weight how much will the mud weight have to be increased by to ensure the well does not go underbalance if the riser is disconnected?

0.5 c)

ppg

What mud weight would you need in the well to ensure the well does not go underbalance if the riser is disconnected?

10.4

IWCF combined surface & subsea student book L3/4 Classified as General

psi

ppg

33

Day 1: exercises BLANK PAGE

IWCF combined surface & subsea student book L3/4 Classified as General

34

Day 1: exercises

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2

2

Kick Warning Signs & Kick Indicators Instructor's Copy

IWCF combined surface & subsea student book L3/4 Classified as General

35

Day 1: exercises Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for the use for course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training.

Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

IWCF combined surface & subsea student book L3/4 Classified as General

36

Day 1: exercises Q1)

Which TWO of the following indications suggest that mud hydrostatic pressure and formation pressure are almost equal? a) b) c) d) e)

Q2)

Which of the following is the FIRST POSITIVE INDICATOR that you have taken a kick while drilling? a) b) c) d)

Q3)

Increase in torque Gas cut mud Decrease in pump pressure Increase in return flow

Which of the following could be considered as the SECOND POSITIVE INDICATOR that an influx has entered the well while drilling? a) b) c) d)

Q4)

Increase in flow out of the well Increase in background gas, trip gas, and connection gas Temperature anomalies Pit gain All of the above

Gas cut mud A drilling break A decrease in pump pressure Gain in pit volume

Which TWO of the following drilling practices should be considered when connection gas is noticed? a) b) c) d) e)

Pump a low viscosity pill around the bit to assist in reduction of balled bit or stabilizers Control drilling rate so that only one slug of connection gas is in the hole at any one time Pulling out of the hole to change the bit Raising the mud yield point Minimizing the time during connections when the pumps are switched off

IWCF combined surface & subsea student book L3/4 Classified as General

37

Day 1: exercises Q5) Which one of the following would not be a warning sign that the bottom hole pressure is approaching formation pressure? a) b) c) d) Q6)

While drilling along at a steady rate the Derrickman asks to slow the mud pumps down so that the shakers can handle the amount of cuttings being returned. Which of the following would be the safest course of action? a) b) c) d)

Q7)

Continue at the same drilling rate allowing the excess solids to by-pass the shakers and get caught in the sand trap Pick up and check for flow. If there is no flow circulate bottoms up at a reduced rate so the shakers can handle the volume of cuttings Slow down the mud pump until the shakers can handle the cuttings volume while continuing to drill Slow down the drilling rate and pump rate until the shakers clear up then go back to the original drilling rate

If WOB, RPM, and SPM are held constant which of the following may be a warning of increasing formation pressure? (THREE ANSWERS) a) b) c) d) e) f)

Q8)

Large crescent shaped cuttings Well flowing with pumps off Increase in chloride content of the mud Increase in connection gas

Increase size of cuttings Increase in pump pressure Increase in penetration rate Connection gas Increase in Shale Density Increased trip tank level

What is the situation if mud flows from the flow line when the pump is off but there is no gain when the pump is running? a) b) c) d)

Low mud weight inside the drill string Mud hydrostatic pressure is greater than formation pressure Pump pressure is greater than mud hydrostatic pressure APL is giving an overbalance against formation pressure

IWCF combined surface & subsea student book L3/4 Classified as General

38

Day 1: exercises Q9)

While drilling, which of the following situations make kick detection with a P.V.T more difficult? a) b) c) d)

Allowing mud to overflow the shakers Reducing the pit level alarm settings from 10 bbls to 5 bbls Keeping active mud system transfers to a minimum when drilling By-passing the solids control pits

Q10) It can be said that closing in the well promptly is one of the most important duties of a driller. Any delay may make the well potentially more difficult to kill. From the list of practices below, choose the SIX MOST LIKELY to lead to an increase in the size of the influx. a) b) c) d) e) f) g) h) i) j)

Switching off the flow meter alarms Regular briefings for the Derrickman on his duties regarding the monitoring of pit levels Drilling a further 20 feet after a drilling break before checking for flow Running regular pit drills for crews Maintaining stab-in valves Testing stab-in valves during regular BOP tests Excluding the draw works from the SCR assignment Keeping air pressure at the choke panel at 10 psi Calling the tool pusher to the floor prior to shutting in the well Not holding down the master air valve on the remote BOP control panel while functioning a preventer

Q11) What is the first action a driller should take after getting a drilling break? a) b) c) d)

Circulate bottoms up Flow check Shut the well in Reduce WOB

IWCF combined surface & subsea student book L3/4 Classified as General

39

Day 1: exercises

SUBSEA QUESTION Q12) Which of the following may influence the accuracy of drilling fluid volume and drilling fluid flow readings when monitoring an open well on a floating rig? (Select three answers) a) b) c) d) e) f)

Sea water depth Rig pitch and roll Crane operations Number of generators on line Riser tension Vessel heave

IWCF combined surface & subsea student book L3/4 Classified as General

40

Day 1: exercises

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2

2

Shut In Methods & Data To Collect Instructor's Copy

IWCF combined surface & subsea student book L3/4 Classified as General

41

Day 1: exercises Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for the use for course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training.

Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

IWCF combined surface & subsea student book L3/4 Classified as General

42

Day 1: exercises Q1) Mud weight increase required to kill a kick should be based upon: a) SIDPP b) SICP c) OMW plus slow circulating rate pressure d) SICP minus the SIDPP Q2) A flowing well is closed in. Which pressure gauge is used to determine formation pressure? a) BOP manifold gauge b) Choke console drill pipe pressure gauge c) Driller’s console drill pipe pressure gauge d) Choke console casing pressure gauge Q3) What is the choke manifold line up for a hard shut-in procedure whilst drilling? a) BOP side outlet hydraulic valve (HCR/FAILSAFE) Choke line open to remote choke. Remote choke closed. b) BOP side outlet hydraulic valve (HCR/FAILSAFE) Choke line open to remote choke. Remote choke open. c) BOP side outlet hydraulic valve (HCR/FAILSAFE) Choke line open to remote choke. Remote choke open. d) BOP side outlet hydraulic valve (HCR/FAILSAFE) Choke line open through manual choke. Manual choke open.

closed. open. closed. closed.

Q4) As detailed in API which type of BOP must be used for the hard shutin? a) Annular BOP b) Either type of BOP can be used c) Ram BOP

IWCF combined surface & subsea student book L3/4 Classified as General

43

Day 1: exercises Q5) The well kicks while tripping. Which of the following actions should be taken to shut the well in using the hard shut in? a)

Stab full opening safety valve. Open BOP side outlet hydraulic valve (HCR/FAILSAFE). Space out for tool joint. Close BOP. Close choke. Record pressure.

b)

Space out for tool joint. Close the BOP. Stab full opening safety valve. Close the safety valve. Open choke. Record pressure.

c)

Stab full opening safety valve. Close the safety valve. Space out for tool joint. Close BOP. Open BOP side outlet hydraulic valve (HCR/FAILSAFE). Record pressure.

d)

Open side outlet hydraulic valve (HCR/FAILSAFE) and remote choke. Space out for tool joint. Close BOP. Stab full opening safety valve. Close safety valve. Record pressure.

Q6) When picking up to check for flow the pumps are usually kept running, why? (TWO ANSWERS) a) To take a slow circulating rate pressure. b) To check the pressure losses in the Annulus. c) To clean the bottom of the hole of cuttings. d) To maximise the pressure on the bottom of the hole. e) To minimise swabbing extra kick into the well. f) It is a throw back to kelly rigs - there is no need with a top drive.

IWCF combined surface & subsea student book L3/4 Classified as General

44

Day 1: exercises Q7) Which of the following affect the Shut In Drill Pipe Pressure? (TWO ANSWERS) a) Mud weight in drill string. b) Size of Influx. c) Annular volume from Bit to Shoe. d) Influx gradient. e) Formation fluid pressure. Q8) A vertical well with a surface BOP stack is shut in on a kick. The pressure readings are as follows: Shut In Drill Pipe Pressure Shut In Casing Pressure

350 psi 450 psi

What is the reason for the difference in the two readings? a) The influx is inside the drill string. b) The influx has a lower density than the mud. c) The BOP was closed too fast causing trapped pressure. d) The influx has a higher density than the mud. Q9) A well has been shut in on a kick. The drill pipe pressure is zero because there is a float (non-return) valve in the string. How can you find the Shut In Drill Pipe Pressure? a) Bring the pump up to kill rate holding the casing pressure constant by opening the choke. The pressure shown when the pump is at kill rate is the Shut In Drill Pipe pressure. b) Use the last recorded slow circulating rate pressure and subtract it from shut in casing pressure. Then bring the pump to kill rate holding casing pressure constant and subtract the previous value from this to get SIDPP. c) Pump very slowly into the drill string with the well shut in. When drillpipe pressure increase flattens out and/or casing pressure starts to rise, stop the pump and read the pressure. This is the Shut In Drill Pipe pressure. d) Pump at 2 barrels per minute into the annulus with the well shut in. When the pressure equalizes, the float will open. This pump pressure is the Shut In Drill Pipe pressure.

IWCF combined surface & subsea student book L3/4 Classified as General

45

Day 1: exercises Q10) When drilling, the well kicks and is shut in. Drill pipe pressure and casing pressure both start to build up, but before stabilising both start to drop quite rapidly. Which of the following might have occurred? a) Gas has started migrating up the well. b) The drill string has washed out. c) The bottom hole assembly has packed off. d) A weak formation has broken down. Q11) Once the well is shut in, which one of the following will affect the time taken for Shut In Drill Pipe Pressure and Shut In Casing Pressure to stabilise? a) Porosity. b) Permeability. c) Gas migration. d) Friction losses. Q12) Which of the following parameters affect the value of Shut In Casing Pressure after a well is shut in during a kick? (THREE ANSWERS) a) The formation fluid pressure (pore pressure). b) Mud viscosity at shut in. c) Annulus capacity. d) The kick volume. e) Cased hole measured length. f) Drill string capacity. Q13) A well is shut in with a gas kick. The bit is 200 feet off bottom and the influx is on bottom and 30 feet long (all the influx is below the bit). Shut In Drill Pipe Pressure is 300 psi. What is the Shut In casing Pressure likely to be? a) Lower than the Shut In Drill Pipe Pressure. b) Higher than the Shut In Drill Pipe Pressure. c) The same as the Shut In Drill Pipe Pressure. Q14) What could happen if gas migrates after a well is shut in and the pressures have stabilised - there is no float in string? a) Only the drill pipe pressure will increase. b) Shut in pressures will remain constant. c) Both drill pipe and casing pressures will increase. d) Only the casing pressure will increase.

IWCF combined surface & subsea student book L3/4 Classified as General

46

Day 1: exercises

SUBSEA QUESTIONS Q15) Why would you circulate over the well on the trip tank after shutting in on a kick with a subsea BOP stack? two ans. a) To check the BOP in use is not leaking b) To check if the influx was above the BOP at the time of shut in c) It is easier to circulate the influx out the well d) To ensure current mud does not contaminate the kill mud e) To allow the string to be hung off on a set of pipe rams Q16) Why should a Driller on a floating rig have information regarding tides? a) To adjust the operating pressures on the BOP b) To work out correct space out for shutting in and hang-off c) To adjust the WOB and RPM to compensate for movement d) To compensate the return flow from the well for current conditions Q17) What value is used to work out kill mud weight when using a subsea BOP stack? a) SIDPP minus CLF b) SIDPP plus CLF c) SIDPP d) SICP minus CLF Q18) The well is shut in on a kick using a subsea BOP stack. The stabilised shut in drill pipe pressure is 400 psi and the stabilised shut in casing pressure is 600 psi. The kill line was opened and the gauge reads 700 psi. What could be the reason for the different readings on the casing and kill gauges? a) The failsafe on the kill line is not functioning correctly b) The failsafe on the choke line is not functioning correctly c) The fluid in the kill line has a lower density than in the choke line d) The fluid in the kill line has a higher density than in the choke line

IWCF combined surface & subsea student book L3/4 Classified as General

47

Day 1: exercises

Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771 Dubai United Arab Emirates [email protected] www.maersktraining.com

IWCF combined surface & subsea student book L3/4 Classified as General

48

P  MW  0.052  TVD

P1  V1  P2  V2  N1  P2  P1     N 2 Instructor's Copy

Subsea Stack Kill Sheet One

2

Subsea Stack Kill Sheet One Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for use on a course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Trai ni ng with or to any third party and neither shall such third party be entitled to repl y upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited t o di rect , punitive, incidental, or consequential damages resulting from or ari s i ng out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training. Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

-1-

Subsea Stack Kill Sheet One

Use the data below to complete an IWCF Subsea BOP Stack (Vertical Well) Kill Sheet API Units and then answer the questions on the following pages: Well data: Hole depth from RKB (MD) Hole depth from RKB (TVD) Casing shoe depth - 9 5 /8 in OD (TVD/MD) Internal capacities: Drill pipe - 5 in OD Heavy wall drill pipe 5 in OD length 750 ft Drill collars size 6 1 /4 in OD length 1000 ft Marine riser length 700 ft Choke line length 715 ft Annulus capacities between: Drill collars x open hole Drill pipe/HWDP x open hole Drill pipe/HWDP x casing Mud pump data: Displacement at 98% volumetric efficiency Circulating pressure through riser at 40 SPM Circulating pressure through choke line at 40 SPM Circulating pressure while drilling at 80 SPM Other relevant information: Active system surface volume Surface line volume Drill pipe 5 in OD closed end displacement Sea water depth Sea water gradient Formation strength test data: Drilling fluid density at formation strength test Surface leak off test pressure Kick data: SIDPP SICP Mud weight in use at time of kick Pit gain

-2-

12900 ft 12200 ft 9000 ft 0.0142 0.0088 0.008 0.36 0.0087

bbl/ft bbl/ft bbl/ft bbl/ft bbl/ft

0.03 bbl/ft 0.0505 bbl/ft 0.0562 bbl/ft 0.117 740 900 2700 250 15 0.0243 640 0.455

bbl/stroke psi psi psi bbl bbl bbl/ft ft psi/ft

11.0 ppg 2350 psi 300 450 12.5 9

psi psi ppg bbl

Subsea Stack Kill Sheet One

ANSWER THE FOLLOWING QUESTIONS Q1)

What is the maximum allowable mud weight that would not fracture the casing shoe?

16 ppg Q2)

Based on the leak off test, what is the current MAASP?

1,638 psi Q3)

What is the annular velocity around the drill collars when drilling?

312 ft/min Q4)

Calculate the formation pressure when shut in on the kick and stable pressures at surface.

8,230 psi Q5)

What kill mud is required to balance formation pressure?

13.0 Q6)

What will the Initial Circulating Pressure (ICP) be at 40 spm?

1040 Q7)

ppg

psi

What will the Final Circulating Pressure (FCP) be at 40 spm?

770 -3-

psi

Subsea Stack Kill Sheet One Q8)

After reaching FCP if it is decided to decrease the pump speed to 30 s pm what would the new (approximate) drill pipe pressure be?

433 psi Q9)

Calculate the hydrostatic pressure at the bottom of the hole before the kick.

7,930 psi Q10) Calculate bottom hole ECD while drilling. APL = 325 psi

13 ppg Q11) How many strokes to go from ICP to FCP.?

1,478 stks Q12) How many strokes to go from bit to surface?

5,548 stks Q13) How long will it take to circulate from bit to surface at a pump speed of 40 spm?

139

minutes

Q14) What is the pressure step down from ICP to FCP in psi/100 strokes?

18

-4-

psi/100 stks

Subsea Stack Kill Sheet One Q15) Calculate the new MAASP after the well is killed.

1,404 psi Q16) How many strokes will it take to circulate from shoe to surface?

4,042

stks

Q17) How many strokes need to be pumped to get kill mud from the pump room to the rig floor?

128

stks

Q18) What will be the initial dynamic casing pressure at kill rate?

290

psi

Q19) Assuming that kill mud weight balances formation pressure, what mud weight would be needed in the well after the kill to compensate for any loss in hydrostatic pressure if the riser was accidentally disconnected?

F#28 13.4

-5-

ppg

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2 Instructor's Copy

Surface Stack Kill Sheet One

2

Surface Stack Kill Sheet One Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for use on a course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training. Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

-1-

Surface Stack Kill Sheet One

Use the data below to complete an IWCF Surface BOP Stack (Vertical Well) Kill Sheet API Units and then answer the questions on the following pages: Well data: Hole depth from RKB (MD) Hole depth from RKB (TVD) Casing shoe depth - 9 5/ 8 in OD (TVD/MD) Internal capacities: Drill pipe - 5 in OD Heavy wall drill pipe 5 in OD length 750 ft Drill collars size 6 1/ 4 in OD length 1000 ft Annulus capacities between: Drill collars x open hole Drill pipe/HWDP x open hole Drill pipe/HWDP x casing Mud pump data: Displacement at 98% volumetric efficiency Circulating pressure at 40 SPM Circulating pressure while drilling at 80 SPM Other relevant information: Active system surface volume Surface line volume Drill pipe 5 in OD closed end displacement Formation strength test data: Drilling fluid density at formation strength test Surface leak off test pressure Kick data: SIDPP SICP Mud weight in use at time of kick Pit gain

-2-

12900 ft 12200 ft 9000 ft 0.0142 bbl/ft 0.0088 bbl/ft 0.008 bbl/ft 0.03 bbl/ft 0.0505 bbl/ft 0.0562 bbl/ft 0.117 bbl/stroke 740 psi 2700 psi 250 bbl 15 bbl 0.0243 bbl/ft 11.0 ppg 2350 psi 300 450 12.5 9

psi psi ppg bbl

Surface Stack Kill Sheet One

ANSWER THE FOLLOWING QUESTIONS Q1)

What is the maximum allowable mud weight that would not fracture the casing shoe?

16

Q2)

Based on the leak off test, what is the current MAASP?

1,638 Q3)

ppg

What will the Initial Circulating Pressure (ICP) be at 40 spm?

1,040 Q7)

psi

What kill mud is required to balance formation pressure?

13 Q6)

ft/min

Calculate the formation pressure when shut in on the kick and stable pressures at surface.

8,230 Q5)

psi

What is the annular velocity around the drill collars when drilling?

312 Q4)

ppg

psi

What will the Final Circulating Pressure (FCP) be at 40 spm?

770

-3-

psi

Surface Stack Kill Sheet One Q8)

After reaching FCP if it is decided to decrease the pump speed to 30 spm what would the new (approximate) drill pipe pressure be?

433 Q9)

psi

Calculate the hydrostatic pressure at the bottom of the hole before the kick.

7,930

psi

Q10) Calculate bottom hole ECD while drilling. APL = 325 psi

13

ppg

Q11) How many strokes to go from ICP to FCP.?

1,478

stks

Q12) How many strokes to go from bit to surface?

5,831

stks

Q13) How long will it take to circulate from bit to surface at a pump speed of 40 spm?

146

minutes

Q14) What is the pressure step down from ICP to FCP in psi/100 strokes?

18

-4-

psi/100 stks

Surface Stack Kill Sheet One Q15) Calculate the new MAASP after the well is killed.

1,404

psi

Q16) How many strokes will it take to circulate from shoe to surface?

4,323

stks

Q17) How many strokes need to be pumped to get kill mud from the pump room to the rig floor?

128

-5-

stks

Day 2: Exercises Instructor's Copy

Classified as General

Day 2: exercises

Blank Page

IWCF combined surface & subsea student book L3/4 Classified as General

2

Day 2: exercises

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2 Kill Methods Instructor's Copy

IWCF combined surface & subsea student book L3/4 Classified as General

3

2

Day 2: exercises Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for the use for course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training.

Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

IWCF combined surface & subsea student book L3/4 Classified as General

4

Day 2: exercises Q1) The principle involved in the Constant Bottom Hole Pressure method of well control is to maintain a pressure that is: a) Equal to the slow circulating rate pressure b) At least equal to formation pressure c) Equal to the SIDPP d) At least equal to the SICP Q2) Company policy states: “…while killing a well you will always attempt to kill the well using a method that minimizes the pressure on the stack and upper casing.” Which method would you choose? a) Wait and Weight b) Driller’s c) Lubricate and Bleed d) Volumetric Q3) Why do we need to take into account surface line volume (from the mud pumps to the rig floor) when preparing the kill sheet with the Wait and Weight method? (TWO ANSWERS) a) If we don’t, following the drill pipe pressure graph will result in a BHP that is too low b) If we don’t, there will be no effect on BHP c) If we don’t, following the drill pipe pressure graph will result in a BHP that is too high d) If we don’t, the well would not be killed after calculated strokes. Q4) While killing the well with a surface stack BOP, as the pump speed is increased, what should happen to the casing pressure in order to keep BHP constant? a) Casing pressure should be held steady during a SPM change b) Casing pressure should be allowed to rise during a SPM change c) Casing pressure should be allowed to fall during a SPM change Q5) A gas kick is being circulated up the hole. What is the surface pit volume most likely to do? a) Increase b) Stay the same c) Decrease

IWCF combined surface & subsea student book L3/4 Classified as General

5

Day 2: exercises Q6) When starting a kill operation with a surface BOP, the choke pressure is held constant while bringing the pump up to speed. The drill pipe pressure gauge now reads 50 psi higher than the calculated initial circulating pressure. To maintain constant BHP, what is the best action to take? a) Open the choke and let the standpipe pressure drop to the calculated initial circulating pressure b) Shut down the kill and calculate the new initial circulating pressure and adjust the drill pipe graph accordingly c) There will now be a 50 psi overbalance on the bottom, which is acceptable, nothing needs to be done d) Shut down the kill and allow the pressures to stabilise properly before restarting the kill operation Q7) On the second circulation of the Driller’s method if the casing pressure was held constant until KWM reached the surface what would happen to BHP? a) Increase b) Decrease c) Stay the same Q8) Under which circumstances would the Wait and Weight method provide lower equivalent pressure at the casing shoe than the Driller’s method? a) When the drill string volume is greater than the open hole annular volume b) When the drill string volume is less than the open hole annular volume c) The pressure at the casing shoe will be the same regardless of the method used Q9) Place the following stages of a kill operation with a surface bop stack (labeled A, B, C, D & E) following the correct order for a wait and weight method kill. A = Follow the pressure reduction schedule B = Hold drillpipe pressure constant C = Zero stroke counter when kill mud is at rotary table. D = Bring pump to kill rate holding casing pressure constant E = Shut down when kill mud returns at surface 1

D

2

C

3

A

IWCF combined surface & subsea student book L3/4 Classified as General

4

B

5

E

6

Day 2: exercises Q10) Place the following stages of a kill operation with a surface bop stack (labeled A, B, C, D, E, F, G & H) following the correct order for a driller’s method kill. A = Pump kill mud to bit following pressure reduction schedule while casing pressure remains constant B = Line up on kill mud C = Hold drillpipe pressure while pumping kill mud D = Start kill by bringing pump to kill rate holding casing pressure constant E = Shut down and check for zero pressure F = Bring pump to kill rate holding casing pressure constant at original SIDPP G = Shut down and check pressures are equal H = Remove influx holding drillpipe pressure constant 1

D

2

H

3

G

4

B

5

F

6

A

7

C

8

E

.

Q11) Why is it important to monitor the pit volumes when killing a well? (TWO ANSWERS) a) To measure the volume of added weight material b) To adjust the pump rate c) To maintain constant bottom hole pressure d) To monitor the gas expansion e) To check for drilling fluid losses Q12) The Drillers Method is going to be used to kill a well that has been shut in on a gas kick. Which procedure best describes the first circulation? a) Displace the annulus to original drilling fluid density maintaining constant casing pressure b) Displace the annulus to original drilling fluid density following a pre-calculated drill pipe pressure schedule c) Displace the annulus to original drilling fluid density maintaining the Initial Circulating Pressure (ICP)

IWCF combined surface & subsea student book L3/4 Classified as General

7

Day 2: exercises Q13) WELL DATA Slow circulation rate pressure is 400 psi at 40 spm The well has been shut in after a kick: Shut In Drill Pipe Pressure Shut In Casing Pressure

300 psi 700 psi

Circulation is started with the original mud. While the pump is being brought up to 40 SPM which pressure must be held constant to maintain the correct bottom hole pressure? a) 1000 psi on the casing gauge b) 700 psi on the casing gauge c) 700 psi on the drill pipe gauge d) 1100 psi on the drill pipe gauge Q14) When operating the choke there is normally a time delay before the drillpipe pressure changes. What is the ‘rule of thumb’ for this time delay in pressure transmission from choke to drillpipe gauge? a) 3 – 5 seconds b) 750 feet/minute c) 1 minute per 1000 feet of travel d) 1 second per 1000 feet of travel Q15) When killing a vertical well when is Final Circulating Pressure reached? a) When kill mud reaches the casing shoe b) When the influx is out of the hole c) When kill mud reaches the bit d) When starting to pump kill mud down the drill string Q16) The Driller’s Method is used to kill a salt-water kick. What will happen to the casing pressure when the influx moves up the annulus? a) Casing pressure will slowly decrease as influx is circulated up the annulus b) Salt water will behave in the same way as a gas influx c) As influx expands Casing Pressure will increase d) Casing pressure will only change due to changes in annular size

IWCF combined surface & subsea student book L3/4 Classified as General

8

Day 2: exercises Q17) While circulating out a gas kick, when is it possible for the pressure at the casing shoe to be at its maximum? (TWO ANSWERS) a) When kill mud reaches the casing shoe b) At initial shut in c) When kill mud reaches the bit d) When top of gas reaches the casing shoe Q18) At what stage during a kill operation can choke pressure reading exceed MAASP without breaking down the formation at the shoe? a) When the influx is b) When the influx is c) When the kill mud d) When the influx is

in the open hole section on bottom is at the bit above the casing shoe

Q19) A kick is being circulated out at 50 spm on a surface stack rig. Drill pipe pressure reads 850 psi and casing pressure 1150 psi. It is decided to slow the pumps to 30 spm while maintaining 1150 psi on the casing gauge. How will this affect bottom hole pressure (exclude any annular friction losses)? a) Increase b) Stay the same c) Decrease Q20) The Drillers Method is being used to kill a well. The standpipe pressure at this stage is 1070 psi with 35 SPM. The pressure in the mud/gas separator is increasing and it is decided to reduce the pump rate. What will happen to bottom hole pressure if 1070 psi is maintained on the standpipe as the pump rate is decreased to 30 SPM? a) Increase b) Stay the same c) Decrease

IWCF combined surface & subsea student book L3/4 Classified as General

9

Day 2: exercises Q21) Which of the following are Well Control Methods and which are Well Kill Methods? Delete as appropriate a) Wait & Weight Method

Well Control or Well Kill

b) Drillers Method 1st circulation - underbalance kick Well Control or Well Kill c) Drillers Method 1st circulation - swabbed kick Well Control or Well Kill d) Drillers method 2nd Circulation e) Volumetric method

Well Control or Well Kill Well Control or Well Kill

Q22) You have shut in a vertical well on a kick using a surface stack BOP and the pressures have stabilised. You have recorded the following information: SIDPP - 750 psi – pressure stabilised and constant for past hour SICP - 950 psi – pressure stabilised and constant for past hour MAASP - 1200 psi ICP - 1100 psi Surface to bit strokes - 1400 stk Bit to shoe strokes - 3700 stk What is the best reason for choosing your kill method? a) b) c) d)

Use the Driller’s Method. You need to start killing the well immediately as the gas may start migrating if you do nothing while kill mud weight is being prepared Use the Driller’s Method. There is no reduction in annular pressure when using the Wait and Weight Method in a vertical well Use the Wait and Weight Method. The safety margin at the shoe is small and the long open hole section means you will have lower casing shoe pressures Use the Wait & Weight Method. It requires less circulation time than the Drillers’ Method and will reduce the abrasive wear at the weak casing shoe

IWCF combined surface & subsea student book L3/4 Classified as General

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Day 2: exercises

SUBSEA QUESTIONS Q23) What is the main reason for an independent kill line gauge during a kill? a) As a back up to the casing gauge b) To use as a static gauge (no CLF effects) when bringing pump to speed c) To measure CLF d) As a back up to the drill pipe gauge Q24) A well is being killed from a semi submersible rig. What will happen to bottom hole pressure if the choke is not adjusted during the period of time from when the top of the gas kick enters the choke line until the gas reaches the choke at surface? a) Bottom hole pressure will increase giving risk for formation fracture b) Bottom hole pressure will remain constant c) Bottom hole pressure will decrease giving risk for an additional influx Q25) How do you maintain a constant bottom hole pressure while starting a kill operation with a subsea BOP stack? (TWO ANSWERS) a) Bring the pump to kill rate while holding casing pressure constant at it’s current value b) Bring the pump to kill rate while reducing casing pressure by an amount equal to choke line friction c) Bring the pump to kill rate ensuring that drillpipe pressure is reading calculated ICP when you reach kill rate d) Bring the pump to kill rate while holding the static line (kill gauge) pressure constant e) Bring the pump to kill rate while increasing casing pressure by an amount equal to choke line friction Q26) Choke line friction losses could be reduced by: (TWO ANSWERS) a) Circulating up the choke and kill lines at the same time b) Reducing the pump speed c) Increasing the pump speed d) Opening the choke to full open e) Closing a failsafe valve f) Opening the hang off rams

IWCF combined surface & subsea student book L3/4 Classified as General

11

Day 2: exercises Q27) A well is to be killed on a floating rig with a subsea BOP stack. Use the data given to answer the following five questions. TVD = 12350 ft Original mud weight = 13.6 ppg SIDPP = 675 psi SICP = 1000 psi Kick size = 17 bbl Riser length = 1230 ft Volume of trapped gas at end of kill = 0.8 bbl SCR through riser @ 30 SPM = 450 psi CLF @ 30 SPM = 150 psi Atmospheric pressure at surface = 14.7 psi a) What kill mud is required? ppg

14.7 ppg

b) What will ICP be?

1125 486

c) What will FCP be?

psi psi

d) What should casing pressure read when the pumps are at kill rate if bottom hole pressure was held constant during the start up? psi

850

e) What will the drill pipe circulating pressure be at the end of the kill with kill mud at surface and the pumps circulating at 30 SPM?

648

psi

f) How much gas would come to surface if the BOP stack was opened up at the end of the kill without any other action being taken?

51

IWCF combined surface & subsea student book L3/4 Classified as General

bbl

12

Day 2: exercises

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2

2

Kill Problems Instructor's Copy

IWCF combined surface & subsea student book L3/4 Classified as General

13

Day 2: exercises Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for the use for course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training.

Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

IWCF combined surface & subsea student book L3/4 Classified as General

14

Day 2: exercises Q1) Which practice will increase bottom hole pressure during a well kill? a) Holding drill pipe pressure constant while pumping kill mud to the bit b) Holding casing pressure constant while bringing gas bubble to surface c) Holding drill pipe pressure constant whilst increasing the pump speed d) Holding casing pressure constant whilst increasing the pump speed Q2) How would you find the initial circulating pressure on a surface BOP stack when the slow pump rate circulating pressure is not known and a kick has been taken? a) Circulate at the desired SPM to circulate out the kick, while holding 200 psi back pressure on the drill pipe gauge with the choke. Once the gas is out you can work out ICP b) Add 200 psi to the shut in casing pressure then bring the pump up to the selected kill rate while using the choke to maintain the extra 200 psi on the casing gauge c) Bring the pump up to the kill rate while holding the SICP constant by choke manipulation. After the hydraulic delay, the pressure shown on the drill pipe gauge is the initial circulating pressure d) There is no way to determine initial circulating pressure in this example. Wait for the gas to start migrating then use the volumetric method of well control to get rid of the influx Q3) You plan to circulate out a gas kick using the Wait & Weight method. What will happen to BHP in each of the following situations? a) If drill pipe pressure is held constant while kill mud is being pumped to the bit a. Increase

b. Decrease

c. Stay the same

b) If drill pipe pressure is held constant while kill weight mud is pumped up the annulus a. Increase

b. Decrease

c. Stay the same

c) If SPM is increased and drill pipe pressure is held constant a. Increase

b. Decrease

c. Stay the same

d) If the gas bubble volume is not allowed to expand a. Increase

b. Decrease

IWCF combined surface & subsea student book L3/4 Classified as General

c. Stay the same

15

Day 2: exercises Q4) Below is a list of possible problems that may occur during a kill. Match the cause to the problem. PROBLEM

CAUSE

a. b. c. d.

1. 2. 3. 4.

Both gauges falling Both gauges rising D.P. gauge rising D.P. gauge falling

Choke plugging Bit plugging Choke washout Nozzle/pipe washout

a. matches ___________

b. matches ____________

c. matches ___________

d. matches ___________

3

2

1

4

Q5) The mud pump fails while circulating out a kick. What is the first action to take? a) Shut the well in b) Fix the pump as soon as possible c) Change over to No 2 pump on the run d) Divert the well Q6) i) What would be the first action to take as a driller if the mud supply hose split during a kill operation? a) Close the Shear Rams b) Divert the influx overboard c) Stop pump and close the full opening safety valve on the drill string d) Close the choke ii) What would be the first action to take as choke operator if the mud supply hose split during a kill operation? a) Close the Shear Rams b) Divert the influx overboard c) Stop pump and close the full opening safety valve on the drill string d) Close the choke Q7) What action should be taken if the choke line parted during a kick? a) Continue to kill the well only if influx is past the shoe b) Stop the pumps, shear the pipe and monitor on the kill c) Stop pumps, close choke and divert the influx overboard d) Stop pumps and close the hydraulic valve on BOP side outlet

IWCF combined surface & subsea student book L3/4 Classified as General

16

Day 2: exercises Q8) Why can a pressure build up in the Mud Gas Separator be dangerous? a) It may allow gas to enter shale shaker area b) It will affect the circulating pressure c) It will increase risk of lost circulation d) It will allow gas to be blown through the vent line Q9) The well started flowing while drilling and was shut in correctly. The following readings were recorded: Pit gain 13 bbl Shut-in casing pressure = 0 psi Shut-in drill pipe pressure = 435 psi The annulus is observed through the choke and there is no flow. What is the most likely reason for what you see? a) The kick was swabbed in hence no SICP or annular flow b) The hole packed off around BHA after the well was shut in c) The formation at the shoe fractured after the well was shut in d) The drill string twisted off after the well was shut in Q10) When killing a well using the Driller’s Method the choke pressure suddenly increases by 200 psi. Shortly after the choke operator sees the same pressure increase on the drill pipe pressure gauge. What is the most likely cause of this pressure increase? a) A restriction in the rotary (kelly) hose b) A plugged nozzle in the bit c) The choke is partly plugged d) A second influx has entered the well

IWCF combined surface & subsea student book L3/4 Classified as General

17

Day 2: exercises

SUBSEA QUESTIONS Q11) A well is being killed on a floating rig using the drillers’ method. A piston swab on the kill pump started washing out in the middle of the first circulation. How would you keep bottom hole pressure is kept constant while shutting down the kill operation? a) Keep casing pressure constant whilst reducing the pump rate to 0 SPM b) Keep drillpipe pressure constant whilst reducing the pump rate to 0 SPM c) Allow casing pressure to fall by an amount equal to CLF while reducing the pump rate to 0 SPM d) Allow casing pressure to increase by an amount equal to CLF while reducing the pump rate to 0 SPM Q12) What can be done to reduce the effects of high choke line friction when killing a well? (TWO ANSWERS) a) Use the driller’s method b) Use a fast pump rate c) Use a slower pump rate d) Take returns up both choke and kill lines e) Divert all returns directly overboard

IWCF combined surface & subsea student book L3/4 Classified as General

18

Day 2: exercises

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2

2

Gas Behaviour & Volumetric Well Control Instructor's Copy

IWCF combined surface & subsea student book L3/4 Classified as General

19

Day 2: exercises Manual standard clause

This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for the use for course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training.

Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

IWCF combined surface & subsea student book L3/4 Classified as General

20

Day 2: exercises Q1) A 10 bbl gas kick is swabbed in at 12500 ft TVD. The drilling fluid density is 14.0 ppg. Calculate the expanded gas volume when the top of the gas is circulated to 5000 ft. a) 23 bbl b) 24 bbl c) 25 bbl d) 26 bbl Q2) While tripping out of the well with the bit 3000 ft from bottom the well started to flow and it was shut in. The following data was recorded: SIDPP = 250 psi

SICP = 250 psi

It is not possible to strip back to bottom. The gas starts to migrate up the well and the Volumetric Method is used to hold the bottom hole pressure constant. a) How will the drill pipe pressure behave as the gas migrates up towards the bit? i) Drill pipe pressure will remain constant ii) Drill pipe pressure will increase iii) Drill pipe pressure will decrease b) How will the drill pipe pressure behave as the gas continues to migrate after having passed the bit? i) Drill pipe pressure will remain constant ii) Drill pipe pressure will increase iii) Drill pipe pressure will decrease Q3) As a gas kick is being circulated up the hole what is the surface pit volume most likely to do? a) Increase b) Stay the same c) Decrease

IWCF combined surface & subsea student book L3/4 Classified as General

21

Day 2: exercises Q4) Select the statement that is TRUE concerning wellbore pressures when circulating a gas influx to surface on the first circulation of the drillers method. a) So long as the correct kill procedure is followed that part of the wellbore, which is above the gas influx, will have a constant pressure b) So long as the correct kill procedure is followed that part of the wellbore, which is below the gas influx, will have a constant pressure c) So long as the correct kill procedure is followed that part of the wellbore, which is below a gas influx, will have an increasing pressure Q5) You cannot start the kill operation and the gas is migrating. Which pressure should be held constant to maintain the correct bottom hole pressure? (Assume that no safety margin or working pressure is required) a) Casing pressure b) Initial circulating pressure c) Drill pipe pressure d) Gas bubble pressure Q6) Gas is migrating and no action is taken. What happens to bottom hole pressure? a) Stays the same b) Increases c) Decreases Q7) A gas bubble enters the well bore, the well is not shut in and the gas migrates. What will happen to the gas bubble pressure? a) Increase b) Stay the same c) Decrease

IWCF combined surface & subsea student book L3/4 Classified as General

22

Day 2: exercises Q8) A 13 bbl kick is taken and the well is shut in. The following data is recorded: SIDPP = 500 psi Current mud weight = 12.7 ppg

SICP = 750 psi Well TVD = 11750 ft

After 30 minutes the SIDPP and SICP have both increased by 150 psi. a) What is the rate of migration in ft/hr? i) ii) iii) iv)

227 ft/hr 454 ft/hr 1136 ft/hr 1590 ft/hr

b) How much mud would you need to bleed off after one hour of gas migration to return bottom hole pressure back to the original stabilised shut in value?

0.49

bbl

Q9) A gas kick entering a well with oil based mud will give a larger pit gain than if the same volume of gas entered a well with water based mud. TRUE / FALSE

IWCF combined surface & subsea student book L3/4 Classified as General

23

Day 2: exercises

SUBSEA QUESTIONS Q10) A well has just been killed with a subsea BOP stack and kill mud is returning at surface. The kill is shut down and the well is flow checked through the choke. There is no flow. Nothing else has been done. The BOP tables tell you there could be 1 ½ bbls of gas trapped in the BOP stack. Use the data given to answer the two questions that follow. Well TVD = 14350 ft Riser length = 3550 ft Choke line length = 3565 ft Original mud weight = 13.9 ppg Kill mud weight = 14.9 ppg Atmospheric pressure at surface = 14.7 psi a) What pressure is the gas at the BOP stack?

2762

psi

b) How much gas would come to surface if the BOP stack was opened and the gas allowed to migrate to surface?

281

IWCF combined surface & subsea student book L3/4 Classified as General

bbl

24

Day 2: exercises

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2 Tripping & Stripping Instructor's Copy

IWCF combined surface & subsea student book L3/4 Classified as General

25

2

Day 2: exercises Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for the use for course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training.

Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

IWCF combined surface & subsea student book L3/4 Classified as General

26

Day 2: exercises

Q1)

The driller is tripping pipe out of a 12 ¼” diameter hole. 25 X 92 foot stands of 5” pipe have been removed. There are 85 more stands to pull. The calculated displacement of the 9 ½” collars is 0.08 bbl/ft. The capacity of the drill pipe is 0.01776 bbl/ft and the metal displacement is 0.0075 bbl/ft. The trip tank volume has reduced from 27 BBL to 15 BBL. What action should be taken in this situation? a) Flow check, if negative continue to pull out the hole - all is well b) Shut the well in and circulate the hole clean through the choke c) Flow check, if negative, pump a slug and continue to POOH d) Flow check, if negative, return to bottom and circulate B/U

Use the following well data to answer questions 2, 3 & 4 TVD Current mud weight Drillpipe capacity Slug volume Slug weight Q2)

What is the drop in bottom hole pressure due to pumping the slug into position? a) b) c) d)

Q3)

10,485 feet 10.4 ppg 0.01776 bbl/ft 25 bbl 12.0 ppg

0 psi 25 psi 117 psi 135 psi

How many bbl of mud will return to the mud pits due to the U-Tube effect? a) b) c) d)

3.24 3.85 4.75 6.26

bbl bbl bbl bbl

IWCF combined surface & subsea student book L3/4 Classified as General

27

Day 2: exercises

Q4)

How many feet of dry pipe will there be after the slug is in position? a) b) c) d)

Q5)

182 217 267 352

feet feet feet feet

A well was drilled to a TVD of 8,200 feet. Casing Shoe TVD Mud Density Open Hole Capacity Pipe Metal Displacement Casing Capacity Pore Pressure Length of 1 stand

4,500 feet 13.9 ppg 0.0702 bbl/ft 0.0080 bbl/ft 0.157 bbl/ft 0.700 psi/ft F#23 93 feet

How many complete stands of drill pipe can the driller pull dry before the drop in mud level reduces the bottom hole pressure enough to cause the well to go underbalanced?

51 __________ Stands Q6)

DATA: Drill pipe capacity Drill pipe displacement Average stand length

0.01776 bbl/ft 0.0076 bbl/ft 93 feet

Calculate: a) Mud required to fill the hole per stand when pulling dry.

0.7068

__________bbl b) Mud required to fill the hole per stand when pulling wet. __________bbl 2.358

IWCF combined surface & subsea student book L3/4 Classified as General

28

Day 2: exercises

Q7)

What would be the reduction in bottom hole pressure if the driller pulls 400 feet of 8” collars from the hole dry, including the bit, without filling the hole? Mud weight Casing capacity Metal displacement

11.8 ppg 0.1545 bbl/ft 0.0545 bbl/ft

F#22 86 __________psi

Q8)

Calculate the reduction in bottom hole pressure if 520 ft of 5” drill pipe is pulled wet without filling the hole. The mud from the mud bucket goes to the active mud pit. Current mud weight Casing capacity Casing steel displacement Drill pipe capacity Drill pipe metal displacement a) b) c) d)

Q9)

13 psi 31 psi 152 psi 286 psi

10.2 ppg 0.0731 bbl/ft 0.0169 bbl/ft 0.01743 bbl/ft 0.00852 bbl/ft

F#20

On a trip out of the hole the first 25 stands of pipe are pulled from the hole dry. The hole was not filled. Using the following data calculate the reduction in bottom hole pressure. Stand length DP steel displacement DP capacity Casing capacity Mud Weight

92 ft 0.00764 bbls/ft 0.01776 bbls/ft 0.0758 bbls/ft 12.7 ppg

170

psi

F#19

IWCF combined surface & subsea student book L3/4 Classified as General

29

Day 2: exercises

Q10) The Driller is going to pump a slug before tripping out the hole. He wants to have 3 stands of dry drill pipe after the slug had been pumped and the U-tube effect has balanced out. DATA: TVD Open hole capacity Casing capacity Average stand length DP steel displacement DP capacity Current mud weight Slug weight a)

9,900 ft 0.0703 bbl/ft 0.073 bbl/ft 93 ft 0.0243 bbl/ft 0.0177 bbl/ft 10.2 ppg 11.7 ppg

Calculate the volume of slug to pump.F#26

33.58

bbl

The slug was pumped and the surface lines displaced with original mud after the slug. The trip tank was then lined-up and the top drive was disconnected allowing the slug to drop. b)

Calculate gain in the trip tank caused by the slug U-tubing.

F#27

4.938

bbl

Q11) Which one of the following actions should be taken to maintain an acceptable bottom hole pressure while stripping drill pipe back into the well? Assume there is no gas migration. a) b) c) d)

Pump a volume of mud into the well equal to drill pipe metal displacement Pump a volume of mud into the well equal to the drill pipe closed end displacement Bleed off drill pipe closed end displacement at regular intervals Bleed the drill pipe steel displacement at regular intervals

IWCF combined surface & subsea student book L3/4 Classified as General

30

Day 2: exercises

Q12) The driller shut the well in during a trip out the hole because it was flowing. Well Data: MD/TVD Pipe capacity Pipe metal displacement Current bit depth a)

9,850 ft. 0.01776 bbls/ft 0.00764 bbls/ft 6,280 ft

Using the data above calculate how much mud will need to be bled off from the annulus while stripping the pipe back to bottom? (Assume the influx is on bottom with no gas migration)

90.7 bbl b)

Using the data above calculate how much mud will need to be pumped into the drill string while stripping the pipe back to bottom?

63.4

Q13)

bbl

When pulling out of the hole from the top of the reservoir swab pressures are calculated to be 150 psi. TVD Mud weight Formation pressure

10,362 ft 11.6 ppg 5,950 psi

Will the well flow? Yes

/

No

IWCF combined surface & subsea student book L3/4 Classified as General

31

Day 2: exercises

SUBSEA QUESTION Q14)

When stripping back into the hole with a subsea BOP you must always file and grease the tool joints as they pass through the rotary table. a) b) c) d)

True. If you do not do this then the annular element will be damaged. False. It is wrong to assume the annular element will be damaged due to stripping. True. If you do not do this then the annular closing pressure will have to be reduced and it may not seal. False. You only need to do this to tool joints that actually will pass through the annular element.

!!!!

IWCF combined surface & subsea student book L3/4 Classified as General

32

Instructor's Copy

P  MW  0.052  TVD

P1  V1  P2  V2  N1  P2  P1     N 2 Subsea Stack Gauge Questions LEVEL 4 ONLY

Classified as General

2

Subsea Stack Gauge Questions Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for use on a course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training. Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

-1Classified as General

Subsea Stack Gauge Questions

Use the completed IWCF Subsea BOP Stack (Vertical Well) Kill Sheet API Units to answer the following questions. All questions run sequentially. The well will be killed using the Driller’s Method at 40 spm. Following the normal IWCF standards there will be no tolerance below the expected/calculated pressure and up to 69 psi above. Q1 Data: Drillpipe Pressure: 1040 psi

Casing Pressure:

Pump Speed: 40 spm

Strokes Pumped: 400 stk

Time: 10 mins

Choke Position: 38% open

The start up went well however the casing gauge failed after 150 strokes had been pumped. It was decided to continue the kill while the gauge is repaired. How is the kill going? a) b) c) d)

The kill is going well - continue. Pressure is too low - close the choke to bring it up a bit. Pressure is too high - open the choke to bring it down a bit. There is no way to tell - shut down and re-evaluate the pressures.

Q2) Data: Drillpipe Pressure: 1040 psi

Casing Pressure: 310

psi

Pump Speed: 40 spm

Strokes Pumped: 500 stk

Time: 12 mins

Choke Position: 38% open

The casing gauge is back on line. It has been suggested that casing pressure is higher than it was after you started the kill. What should you do? a) b) c) d)

Pressure is too high - open the choke to bring it down a bit. Pressure is too low - close the choke to bring it up a bit. The kill is going well - continue. There is no way to tell - shut down and re-evaluate the pressures. -2-

Classified as General

Subsea Stack Gauge Questions

Q3) Data: Drillpipe Pressure: 1020 psi

Casing Pressure: 480

Pump Speed: 40 spm

Strokes Pumped: 800 stk

Time: 20 mins

Choke Position: 40% open

How is the kill going? a) b) c) d)

The kill is going well - continue. Pressure is too low - close the choke to bring it up a bit. Pressure is too high - open the choke to bring it down a bit. There is no way to tell - shut down and re-evaluate the pressures.

Q4) Data: Drillpipe Pressure: 1040 psi

Casing Pressure: 600

Pump Speed: 40 spm

Strokes Pumped: 1300 stk

Time: 33 mins

Choke Position: 38% open

You have to shut down because of a mud supply problem. What will the drillpipe pressure be once the well has been shut in correctly?

300

-3Classified as General

psi

Subsea Stack Gauge Questions

Q5) Data: Drillpipe Pressure: 1040 psi

Casing Pressure: 600

Pump Speed: 40 spm

Strokes Pumped: 1300 stk

Time: 33 mins

Choke Position: 38% open

You have to shut down because of a mud supply problem. What will the casing pressure be once the well has been shut in correctly?

760

psi

Q6) Data: Drillpipe Pressure: 890 psi

Casing Pressure: 1340 psi

Pump Speed: 37 spm

Strokes Pumped: 5400 stk

Time: 135 mins

Choke Position: 22% open

Gas is now venting through the choke. Pit volume and casing pressure are both falling. What is happening? a) b) c) d)

The kill is going well - continue. Correct the pump speed. Pressure is too low - close the choke to bring it up. Casing pressure is too high - open the choke to bring it down a bit.

-4Classified as General

Subsea Stack Gauge Questions Q7) Data: Drillpipe Pressure: 1160 psi

Casing Pressure: 260 psi

Pump Speed: 40 spm

Strokes Pumped: 6000 stk

Time: 150 mins

Choke Position: 34% open

The gas is all out and mud returns have been re-established. The pit volume has settled out. What is happening? a) b) c) d)

The kill is going well - continue. Casing pressure is too low - close the choke to bring it up a bit. Shut down and check for zero drillpipe pressure. Pressure is too high - open the choke to bring it down a bit.

Q8) Data: Drillpipe Pressure: 1040 psi

Casing Pressure:

Pump Speed: 40 spm

Strokes Pumped: 6100 stk

Time: 153 mins

Choke Position: 38% open

The first circulation has been successful and you are about to shut down. What will the casing pressure be just before you start to shut in?

140

-5Classified as General

psi

Subsea Stack Gauge Questions

Q9) Data: Drillpipe Pressure:

Casing Pressure:

Pump Speed: 0 spm

Strokes Pumped: 6160 stk

Time: 154 mins

Choke Position: 0% open

You have just shut in correctly at the end of the first circulation. What readings will you see on the gauges? Drillpipe Pressure

300

psi

Casing Pressure

300

psi

Q10) Data: Drillpipe Pressure: 966 psi

Casing Pressure: 120 psi

Pump Speed: 40 spm

Strokes Pumped: 300 stk

Time: 8 mins

Choke Position: 34% open

The second circulation has been under way for some time now. Strokes and time were both reset when kill mud reached the rig floor. How are things going? a) b) c) d)

Pressure is too low - close the choke to bring it up a bit. Casing pressure is too high - open the choke to bring it down a bit. Shut down and check for zero drillpipe pressure. The kill is going well - continue.

-6Classified as General

Subsea Stack Gauge Questions

Q11) Data: Drillpipe Pressure:

Casing Pressure: 140 psi

Pump Speed: 40 spm

Strokes Pumped: 760 stk

Time: 19 mins

Choke Position: 38% open

The drillpipe pressure gauge has gone off line. It will be back on line in a minute or so. How are things going? a) b) c) d)

Casing pressure is too high - open the choke to bring it down a bit. Pressure is too low - close the choke to bring it up a bit. Shut down and check for zero drillpipe pressure. The kill is going well - continue.

Q12) Data: Drillpipe Pressure: 842 psi

Casing Pressure: 100 psi

Pump Speed: 40 spm

Strokes Pumped: 1100 stk

Time: 28 mins

Choke Position: 40% open

You have just made a choke adjustment. How are things going? a) b) c) d)

The kill is going well - continue. Pressure is too low - close the choke to bring it up a bit. Shut down and check for zero drillpipe pressure. Casing pressure is too high - open the choke to bring it down a bit.

-7Classified as General

Subsea Stack Gauge Questions

Q13) Data: Drillpipe Pressure: 770 psi

Casing Pressure: 140 psi

Pump Speed: 40 spm

Strokes Pumped: 1478 stk

Time: 37 mins

Choke Position: 38% open

Kill mud is at the bit and you have been asked to shut down because of a mud supply problem. What will the drillpipe pressure be once the well is correctly shut back in?

ZERO

psi

Q14) Data: Drillpipe Pressure: 770 psi

Casing Pressure: 140 psi

Pump Speed: 40 spm

Strokes Pumped: 1478 stk

Time: 37 mins

Choke Position: 38% open

Kill mud is at the bit and you have been asked to shut down because of a mud supply problem. What will the safety margin at the shoe be once the well is correctly shut back in?

1388

-8Classified as General

psi

Subsea Stack Gauge Questions

Q15) Data: Drillpipe Pressure: 770 psi

Casing Pressure: 110 psi

Pump Speed: 40 spm

Strokes Pumped: 4000 stk

Time: 100 mins

Choke Position: 42% open

How are things going? a) b) c) d)

Pressure is too high - open the choke to bring it down a bit. Pressure is too low - close the choke to bring it up a bit. Shut down and check for zero drillpipe pressure. The kill is going well - continue.

Q16) Data: Drillpipe Pressure: 900 psi

Casing Pressure: 100 psi

Pump Speed: 40 spm

Strokes Pumped: 6000 stk

Time: 150 mins

Choke Position: 45% open

How are things going? a) b) c) d)

Pressure is too high - open the choke to bring it down a bit. Pressure is too low - close the choke to bring it up a bit. Shut down and check for zero drillpipe pressure. The kill is going well - continue.

-9Classified as General

Subsea Stack Gauge Questions

- 10 Classified as General

Subsea Stack Gauge Questions

- 11 Classified as General

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2 Instructor's Copy

Subsea Stack Kill Sheet Two

2

Subsea Stack Kill Sheet Two

Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for use on a course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training. Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

-1-

Subsea Stack Kill Sheet Two

Use the data below to complete an IWCF Subsea BOP Stack (Vertical Well) Kill Sheet API Units and then answer the questions on the following pages: Well data: Bit size 8 1/ 2 in Hole depth from RKB (MD) 11000 ft Hole depth from RKB (TVD) 9000 ft Casing shoe depth - 9 5/ 8 in (TVD/MD) 7500 ft Internal capacities: Drill pipe - 5 in OD 0.01776 bbl/ft Heavy wall drill pipe 5 in OD length 850 ft 0.0088 bbl/ft 1 Drill collars size 6 / 2 in OD length 750 ft 0.00768 bbl/ft Choke line length 835 ft 0.0087 bbl/ft Annulus capacities between: Drill collars x open hole 0.0292 bbl/ft Drill pipe/HWDP x open hole 0.0459 bbl/ft Drill pipe/HWDP x casing 0.0505 bbl/ft Drill pipe x marine riser 0.336 bbl/ft Mud pump data: Displacement at 98% volumetric efficiency 0.119 bbl/stroke Circulating pressure through riser at 30 SPM 270 psi Circulating pressure through choke line at 30 SPM 360 psi Circulating pressure while drilling at 80 SPM 2600 psi APL while drilling 310 psi Other relevant information: Active system surface volume 320 bbl Surface line volume 15 bbl Marine riser length 820 ft Air gap 75 ft Sea water gradient 0.45 psi/ft Formation strength test data: Fracture gradient at shoe 0.91 psi/ft Kick data: SIDPP 500 psi SICP 720 psi Mud weight in use at time of kick 13.2 ppg Pit gain 10 bbl

-2-

Subsea Stack Kill Sheet Two

ANSWER THE FOLLOWING QUESTIONS Q1)

What is the total volume of the drill string?

180.18 bbls Q2)

What is the total annulus volume with the well closed in?

492.73 Q3)

What is the surface to bit time while drilling at 80 spm?

19 Q4)

Q6)

mins

What kill mud is required to balance formation pressure?

14.3

ppg

What will the Initial Circulating Pressure (ICP) be at 30 spm?

770 Q7)

mins

How long would it take to circulate bottoms up while drilling at 80 spm?

80 Q5)

bbls

psi

What will the Final Circulating Pressure (FCP) be at 30 spm?

292

-3-

psi

Subsea Stack Kill Sheet Two

Q8)

After reaching FCP it is decided to increase the pump speed to 40 spm. What would happen to BHP if the choke operator holds drill pipe pressure constant at the original FCP value. a) b) c)

Q9)

Increase Decrease Remain constant

What was the hydrostatic pressure at the bottom of the hole before the kick was taken?

6178

psi

Q10) What was the ECD on bottom while drilling?

13.9

ppg

Q11) At 80 spm what was the annular velocity around the drill collars?

236

ft/min

Q12) What is the maximum allowable mud weight.

Q13) How many strokes to go from ICP to FCP?

17.5

1514

ppg

stks

Q14) How many strokes will it require to go from bit to shoe?

1245

-4-

stks

Subsea Stack Kill Sheet Two

Q15) How long would it take to circulate from bit to shoe at a pump speed of 30 spm?

41.5

mins

Q16) At 30 spm what is shoe to surface circulating time?

97

mins

Q17) The casing shoe was tested with a 12.5 ppg mud in the hole. How much pressure was applied at surface to give a fracture gradient of 0.91 psi/ft?

1950

psi

Q18) What would the new MAASP be once the well has been killed?

1248

psi

Q19) At 30 spm how long will it take to pump kill mud from surface to bit?

50

mins

Q20) What would be the pressure step down per 100 strokes of kill mud pumped down the drill string?

31 psi /100 stks Q21) How many strokes need to be pumped to get kill mud from the pump room to the rig floor?

126

-5-

stks

Subsea Stack Kill Sheet Two

Q22) What will be the initial dynamic casing pressure at kill rate?

630

psi

Q23) What will dynamic MAASP be at the start of a Drillers Method Kill?

1587

psi

Q24) Assuming that kill mud weight balances formation pressure, what mud weight would be needed in the well after the kill to compensate for any loss in hydrostatic pressure if the riser was accidentally disconnected?

15

ppg

Q25) What will FCP be with kill mud back at surface and the choke fully open?

390

-7-

psi

Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771 Dubai United Arab Emirates [email protected] www.maersktraining.com

Instructor's Copy

P  MW  0.052  TVD

P1  V1  P2  V2  N1  P2  P1     N 2 Surface Stack Gauge Questions LEVEL 4 ONLY Classified as General

2

Surface Stack Gauge Questions Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for use on a course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training. Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

-1Classified as General

Surface Stack Gauge Questions

Use the completed IWCF Surface BOP Stack (Vertical Well) Kill Sheet API Units to answer the following questions. All questions run sequentially. The well will be killed using the Driller’s Method at 40 spm. Following the normal IWCF standards there will be no tolerance below the expected/calculated pressure and up to 69 psi above. Q1 Data: Drillpipe Pressure: 1040 psi

Casing Pressure:

Pump Speed: 40 spm

Strokes Pumped: 400 stk

Time: 10 mins

Choke Position: 38% open

The start up went well however the casing gauge failed after 150 strokes had been pumped. It was decided to continue the kill while the gauge is repaired. How is the kill going? a) b) c) d)

The kill is going well - continue. Pressure is too low - close the choke to bring it up a bit. Pressure is too high - open the choke to bring it down a bit. There is no way to tell - shut down and re-evaluate the pressures.

Q2) Data: Drillpipe Pressure: 1040 psi

Casing Pressure: 510

psi

Pump Speed: 40 spm

Strokes Pumped: 500 stk

Time: 12 mins

Choke Position: 38% open

The casing gauge is back on line. It has been suggested that casing pressure is higher than it was after you started the kill. What should you do? a) b) c) d)

Pressure is too high - open the choke to bring it down a bit. Pressure is too low - close the choke to bring it up a bit. The kill is going well - continue. There is no way to tell - shut down and re-evaluate the pressures. -2-

Classified as General

Surface Stack Gauge Questions

Q3) Data: Drillpipe Pressure: 1020 psi

Casing Pressure: 580

Pump Speed: 40 spm

Strokes Pumped: 800 stk

Time: 20 mins

Choke Position: 40% open

How is the kill going? a) b) c) d)

The kill is going well - continue. Pressure is too low - close the choke to bring it up a bit. Pressure is too high - open the choke to bring it down a bit. There is no way to tell - shut down and re-evaluate the pressures.

Q4) Data: Drillpipe Pressure: 1040 psi

Casing Pressure: 700

Pump Speed: 40 spm

Strokes Pumped: 1300 stk

Time: 33 mins

Choke Position: 38% open

You have to shut down because of a mud supply problem. What will the drillpipe pressure be once the well has been shut in correctly?

300

-3Classified as General

psi

Surface Stack Gauge Questions

Q5) Data: Drillpipe Pressure: 1040 psi

Casing Pressure: 700

Pump Speed: 40 spm

Strokes Pumped: 1300 stk

Time: 33 mins

Choke Position: 38% open

You have to shut down because of a mud supply problem. What will the casing pressure be once the well has been shut in correctly?

700

psi

Q6) Data: Drillpipe Pressure: 890 psi

Casing Pressure: 1500 psi

Pump Speed: 37 spm

Strokes Pumped: 5700 stk

Time: 143 mins

Choke Position: 22% open

Gas is now venting through the choke. Pit volume and casing pressure are both falling. What is happening? a) b) c) d)

The kill is going well - continue. Correct the pump speed. Pressure is too low - close the choke to bring it up. Casing pressure is too high - open the choke to bring it down a bit.

-4Classified as General

Surface Stack Gauge Questions Q7) Data: Drillpipe Pressure: 1160 psi

Casing Pressure: 420 psi

Pump Speed: 40 spm

Strokes Pumped: 6000 stk

Time: 150 mins

Choke Position: 34% open

The gas is all out and mud returns have been re-established. The pit volume has settled out. What is happening? a) b) c) d)

The kill is going well - continue. Casing pressure is too low - close the choke to bring it up a bit. Shut down and check for zero drillpipe pressure. Pressure is too high - open the choke to bring it down a bit.

Q8) Data: Drillpipe Pressure: 1040 psi

Casing Pressure:

Pump Speed: 40 spm

Strokes Pumped: 6100 stk

Time: 153 mins

Choke Position: 38% open

The first circulation has been successful and you are about to shut down. What will the casing pressure be just before you start to shut in?

300

-5Classified as General

psi

Surface Stack Gauge Questions

Q9) Data: Drillpipe Pressure:

Casing Pressure:

Pump Speed: 0 spm

Strokes Pumped: 6160 stk

Time: 154 mins

Choke Position: 0% open

You have just shut in correctly at the end of the first circulation. What readings will you see on the gauges? Drillpipe Pressure

300

psi

Casing Pressure

300

psi

Q10) Data: Drillpipe Pressure: 966 psi

Casing Pressure: 280 psi

Pump Speed: 40 spm

Strokes Pumped: 300 stk

Time: 8 mins

Choke Position: 34% open

The second circulation has been under way for some time now. Strokes and time were both reset when kill mud reached the rig floor. How are things going? a) b) c) d)

Pressure is too low - close the choke to bring it up a bit. Casing pressure is too high - open the choke to bring it down a bit. Shut down and check for zero drillpipe pressure. The kill is going well - continue.

-6Classified as General

Surface Stack Gauge Questions

Q11) Data: Drillpipe Pressure:

Casing Pressure: 300 psi

Pump Speed: 40 spm

Strokes Pumped: 760 stk

Time: 19 mins

Choke Position: 38% open

The drillpipe pressure gauge has gone off line. It will be back on line in a minute or so. How are things going? a) b) c) d)

Casing pressure is too high - open the choke to bring it down a bit. Pressure is too low - close the choke to bring it up a bit. Shut down and check for zero drillpipe pressure. The kill is going well - continue.

Q12) Data: Drillpipe Pressure: 842 psi

Casing Pressure: 260 psi

Pump Speed: 40 spm

Strokes Pumped: 1100 stk

Time: 28 mins

Choke Position: 40% open

You have just made a choke adjustment. How are things going? a) b) c) d)

The kill is going well - continue. Pressure is too low - close the choke to bring it up a bit. Shut down and check for zero drillpipe pressure. Casing pressure is too high - open the choke to bring it down a bit.

-7Classified as General

Surface Stack Gauge Questions

Q13) Data: Drillpipe Pressure: 770 psi

Casing Pressure: 300 psi

Pump Speed: 40 spm

Strokes Pumped: 1478 stk

Time: 37 mins

Choke Position: 38% open

Kill mud is at the bit and you have been asked to shut down because of a mud supply problem. What will the drillpipe pressure be once the well is correctly shut back in?

ZERO

psi

Q14) Data: Drillpipe Pressure: 770 psi

Casing Pressure: 300 psi

Pump Speed: 40 spm

Strokes Pumped: 1478 stk

Time: 37 mins

Choke Position: 38% open

Kill mud is at the bit and you have been asked to shut down because of a mud supply problem. What will the safety margin at the shoe be once the well is correctly shut back in?

1338

-8Classified as General

psi

Surface Stack Gauge Questions

Q15) Data: Drillpipe Pressure: 770 psi

Casing Pressure: 250 psi

Pump Speed: 40 spm

Strokes Pumped: 4000 stk

Time: 100 mins

Choke Position: 42% open

How are things going? a) b) c) d)

Pressure is too high - open the choke to bring it down a bit. Pressure is too low - close the choke to bring it up a bit. Shut down and check for zero drillpipe pressure. The kill is going well - continue.

Q16) Data: Drillpipe Pressure: 900 psi

Casing Pressure: 150 psi

Pump Speed: 40 spm

Strokes Pumped: 6000 stk

Time: 150 mins

Choke Position: 45% open

How are things going? a) b) c) d)

Pressure is too high - open the choke to bring it down a bit. Pressure is too low - close the choke to bring it up a bit. Shut down and check for zero drillpipe pressure. The kill is going well - continue.

-9Classified as General

Surface Stack Gauge Questions

- 10 Classified as General

Surface Stack Gauge Questions

- 11 Classified as General

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2 Instructor's Copy

Surface Stack Kill Sheet Two

2

Surface Stack Kill Sheet Two Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for use on a course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training. Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

-1-

Surface Stack Kill Sheet Two

Use the data below to complete an IWCF Surface BOP Stack (Vertical Well) Kill Sheet API Units and then answer the questions on the following pages: Well data: Bit size 8 1/ 2 in Hole depth from RKB (MD) 11000 ft Hole depth from RKB (TVD) 9000 ft Casing shoe depth - 9 5/ 8 in (TVD/MD) 7500 ft Internal capacities: Drill pipe - 5 in OD 0.01776 bbl/ft Heavy wall drill pipe 5 in OD length 850 ft 0.0088 bbl/ft 1 Drill collars size 6 / 2 in OD length 750 ft 0.00768 bbl/ft Annulus capacities between: Drill collars x open hole 0.0292 bbl/ft Drill pipe/HWDP x open hole 0.0459 bbl/ft Drill pipe/HWDP x casing 0.0505 bbl/ft Mud pump data: Displacement at 98% volumetric efficiency 0.119 bbl/stroke Circulating pressure at 30 SPM 270 psi Circulating pressure while drilling at 80 SPM 2600 psi APL while drilling 310 psi Other relevant information: Active system surface volume 320 bbl Surface line volume 15 bbl Drill pipe 5 in OD closed end displacement 0.0243 bbl/ft Formation strength test data: Fracture gradient at shoe 0.91 psi/ft Kick data: SIDPP 500 psi SICP 720 psi Mud weight in use at time of kick 13.2 ppg Pit gain 10 bbl

-2-

Surface Stack Kill Sheet Two

ANSWER THE FOLLOWING QUESTIONS Q1)

What is the total volume of the drill string?

180 Q2)

What is the total annulus volume with the well closed in?

527 Q3)

ppg

What will the Initial Circulating Pressure (ICP) be at 30 spm?

770 Q7)

mins

What kill mud is required to balance formation pressure?

14.3 Q6)

mins

How long would it take to circulate bottoms up while drilling at 80 spm?

55 Q5)

bbls

What is the surface to bit time while drilling at 80 spm?

19 Q4)

bbls

psi

What will the Final Circulating Pressure (FCP) be at 30 spm?

292

-3-

psi

Surface Stack Kill Sheet Two Q8)

After reaching FCP it is decided to increase the pump speed to 40 spm. What would happen to BHP if the choke operator holds drill pipe pressure constant at the original FCP value. a) b) c)

Q9)

Increase Decrease Remain constant

What was the hydrostatic pressure at the bottom of the hole before the kick was taken?

6178

psi

Q10) What was the ECD on bottom while drilling?

13.9

ppg

Q11) At 80 spm what was the annular velocity around the drill collars?

326

ft/min

Q12) What is the maximum allowable mud weight.

17.5 ppg Q13) How many strokes to go from ICP to FCP?

1514

stks

Q14) How many strokes will it require to go from bit to shoe?

1245 stks

-4-

Surface Stack Kill Sheet Two Q15) How long would it take to circulate from bit to shoe at a pump speed of 30 spm?

41

mins

Q16) At 30 spm what is shoe to surface circulating time?

106

mins

Q17) The casing shoe was tested with a 12.5 ppg mud in the hole. How much pressure was applied at surface to give a fracture gradient of 0.91 psi/ft?

1950

psi

Q18) What would the new MAASP be once the well has been killed?

1248

psi

Q19) At 30 spm how long will it take to pump kill mud from surface to bit?

50

mins

Q20) What would be the pressure step down per 100 strokes of kill mud pumped down the drill string?

31 psi /100 stks Q21) How many strokes need to be pumped to get kill mud from the pump room to the rig floor?

126

-5-

stks

Day 3: Exercises Instructor's Copy

Classified as General

Blank Page

IWCF combined surface & subsea student book L3/4

Classified as General

2

P  MW  0.052  TVD

P1  V1  P2  V2  N1  P2  P1     N 2

2

Top Hole, Shallow Gas & Horizontal Instructor's Copy

IWCF combined surface & subsea student book L3/4

Classified as General

3

Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for the use for course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training.

Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates

E-mail:

[email protected]

Homepage

www.maersktraining.com

IWCF combined surface & subsea student book L3/4

Classified as General

4

Q1)

The main purpose of the diverter system is to: a) b) c) d)

Q2)

Kicks taken while drilling shallow formations should be: a) b) c) d)

Q3)

Closed in with the annular preventer Closed in with the rams Ignored because the pressure is minimal Diverted

Which of the following statements are good operating practices in top hole (surface hole) that have a risk of gas bearing formations? (Two answers required) a) b) c) d)

Q4)

Shut in the well Divert shallow gas away from the rig To prevent gas from entering the wellbore Buy time to mix kill mud

Use a high mud weight to create maximum overbalance Pump out of the hole on trips Control the drilling rate Regularly pump a fresh water pill to clean cuttings from the hole

During top hole drilling from a jack-up rig the well suddenly starts to flow due to a shallow gas kick. What would be the safest actions to take for the rig and personnel? (Choose two answers) a) b) c) d)

Activate the blind/shear rams to shut in the well Activate the diverter system and remove all non-essential personnel from the rig floor and hazardous areas Shut in the well and prepare for kill operations immediately Start pumping fluid into the well at the highest possible rate

IWCF combined surface & subsea student book L3/4

Classified as General

5

Q5)

What is the best definition of top hole from those given below. a) b) c) d)

Q6)

What procedures should be considered on an offshore jack up rig drilling top hole in a shallow gas area? (Three answers) a) b) c) d) e)

Q7)

Any section of the well that is drilled without a BOP because there is no well-head assembly in place to latch onto Any section of the well that is drilled without a BOP because the formation strength may not withstand shut in pressures Any section of the well that is drilled without a BOP because the drilling programme has not called for one to be in place Any section of the well that is drilled without a BOP because the bit size is too big to run through the BOP

Drill a large diameter hole Drill a small diameter pilot hole Pump out of hole on trips Maintain high mud viscosity Run a drill string float

What well control problems can drilling horizontal wells give you? (Choose three answers) a) b) c) d) e) f)

The long exposed reservoir can lead to big kicks if primary well control is lost Stabilised SICP will be considerably higher than stabilised SIDPP meaning a greater risk of fracturing at the shoe Pipe lies on the low side of the well, meaning potential stuck pipe issue take precedence over well control Swabbing can easily happen at any point along the horizontal section and into the cased hole section When shut in, the calculation used to work out kill mud weight must take build angle into consideration Following a conventional vertical kill sheet as kill mud is pumped can lead to excessively high pressures

IWCF combined surface & subsea student book L3/4

Classified as General

6

Q8)

Due to the long open hole section in a horizontal well it is always best to use the Wait & Weight method as this minimises pressure at the casing shoe. TRUE / FALSE

Q9)

Well Data: TVD MD Start of horizontal section @ Surface to bit strokes Current mud weight Kill mud weight SIDPP SCR @ 40 SPM ICP FCP

10,000 ft 20,000 ft 10,000 ft TVD/MD 8,240 stk 10 ppg 11 ppg 500 psi 500 psi 1,000 psi 550 psi

A wait & weight kill has been started but needs to be shut down when 4,120 strokes of kill mud have been pumped down the string. Bottom hole pressure was held exactly on balance as the kill was stopped and the well shut in. What will the drill pipe pressure gauge read once the well is shut in?

Zero

IWCF combined surface & subsea student book L3/4

Classified as General

Psi

7

IWCF combined surface & subsea student book L3/4

Classified as General

8

P  MW  0.052  TVD

P1  V1  P2  V2  N1  P2  P1     N 2

2

Casing, Cementing & Wireline Operations Instructor's Copy

IWCF combined surface & subsea student book L3/4

Classified as General

9

Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for the use for course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training.

Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates

E-mail:

[email protected]

Homepage

www.maersktraining.com

IWCF combined surface & subsea student book L3/4

Classified as General

10

Q1)

Twelve 40 ft joints of 13 3/8” casing are run in the hole with a conventional float valve. The casing capacity is 0.1521 bbl/ft. There was a problem with the fill up line and the casing was not filled. If the float valve were to suddenly fail how would this affect bottom hole pressure? The mud weight is 11.5 ppg and the annular capacity is 0.124 bbl/ft. a) b) c) d)

Q2)

by by by by

73 psi 158 psi 264 psi 480 psi

Self-filling float valve Standard float valve Both types require the casing to be filled regularly

If you wanted to reduce surge pressures and the casing run time, which type of float equipment would you use? a) b) c)

Q4)

decreases decreases decreases decreases

Which type of casing float valve requires the casing to be filled regularly? a) b) c)

Q3)

BHP BHP BHP BHP

Standard float valve Self-filling float valve It makes no difference which one is used

What are two advantages of a self-filling casing float system? a) b) c) d) e)

You will have higher surge pressures as casing is run in the hole using a self-filling float system compared to a conventional float A self-filling float system prevents the entry of drilling fluid into the casing as it is run in the hole A self-filling float system has large open bore, which help reduce surge pressures when you run casing in the hole A self-filling float system allows cement to re-enter the casing once the auto-fill has been deactivated A self-filling float system is better when you have small annular clearances and pressure sensitive formations

IWCF combined surface & subsea student book L3/4

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Q5)

What can happen if a self-filling float system fails to convert to a one-way check valve system for the cement job? a) The one-way check valve will still prevent fluids from u-tubing into the casing after completing the cement job b) The one-way check valve will not work during the whole cement job so you will need to compensate with pump pressure c) You will see no lift pressure on the casing side once you bleed off the pump pressure after completing the cement job d) Cement in the casing annulus could u-tube into the casing once you bleed off the pump pressure after completing the cement job

Q6)

What can help you keep accurate volume records while running and cementing casing? a) Take the returns from the well into the same tank that you are using to fill the casing string b) Take the returns from the well into a different tank than the one you are using to fill the casing string c) Transfer mud out of the monitoring tank while you are running the casing to prevent overflowing the tank d) Isolate the mud returns monitor when pumping the cement as you no longer need to monitor the returns

Q7)

You are running casing open ended into the well. Calculate the volume of mud that would be returned into the trip tank for every 5 joints you run using the following information: Casing Casing Casing Casing Casing a) b) c) d)

OD - 95/8 weight – 47 lb/ft capacity - 0.0733 bbl/ft metal displacement – 0.0168 bbl/ft joint length – 40 ft

3.36 bbl 11.3 bbl 14.66 bbl 18.02bbl

IWCF combined surface & subsea student book L3/4

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Q8)

You are running casing into the well with a non-return valve fitted in the casing string. You measure the volume of mud returned from the well as you run the casing into the hole. Calculate the volume of mud that would be returned into the trip tank for every 5 joints you run using the following information: Casing Casing Casing Casing Casing a) b) c) d)

Q9)

OD - 95/8“ weight – 47 lb/ft capacity - 0.0733 bbl/ft metal displacement – 0.0168 bbl/ft joint length – 40 ft

3.36 bbls 11.3 bbls 14.66 bbls 18.02 bbls

Mud filter cake should be removed from the walls of the well to help the cement bond properly with the formation. What can you do to help remove the mud cake? a) b) c) d)

Use casing scratchers on casing joints Keep the pipe still during the cement job Add a retarder to the cement mix Add an accelerator to the cement mix

Q10) A micro annulus can form during cementing operations. What could cause the formation of a micro annulus? (Choose two answers) a) A small amount of shrinkage in the cement as it sets b) Pumping a spacer in front of the cement c) Making sure there is only one float in the casing string d) Removing the mud filter cake from across a permeable formation e) Mud cake remaining between the cement and a permeable formation

IWCF combined surface & subsea student book L3/4

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Q11) What can you do to reduce the risk of surging before running casing? (Choose two answers) a) b) c) d) e)

Circulate and condition the mud in the well Allow the mud to sit 24 hours before running casing Fill the trip tank with current mud Identify tight spots in the running order Calculate mud displacement volumes

Q12) Choose two good well control practices you can use when conducting wireline operations. a) b) c) d) e)

Ignore the wireline when working out displacement volumes you only have to consider the displacement values of the tools Have an FOSV and wire line cutters ready on the rig floor - if the well flows cut the wire and close the FOSV Install wire line rams for use during all wireline operations failure to do so will mean you cannot shut the well in Know how far you need to pull to ensure the wireline will fall below the BOP stack if you need to cut the wire Isolate the annular so it cannot be used during wireline operations because closing the annular on wireline will damage the element

IWCF combined surface & subsea student book L3/4

Classified as General

14

P  MW  0.052  TVD

P1  V1  P2  V2  N1  P2  P1     N 2

2

Barriers & Inflow Testing Instructor's Copy

IWCF combined surface & subsea student book L3/4

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15

Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for the use for course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training.

Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates

E-mail:

[email protected]

Homepage

www.maersktraining.com

IWCF combined surface & subsea student book L3/4

Classified as General

16

Q1)

Which statement best describes a primary well barrier? a) b) c) d)

Q2)

b) c) d)

barrier is the second object that prevents flow barrier controls the closure of a blowout barrier will not prevent flow from a source

A secondary well barrier from a source A secondary well barrier flow from a source A secondary well barrier preventer A secondary well barrier

is the first object that prevents flow is the second object that prevents controls the closure of a blowout will not prevent flow from a source

A primary well barrier is the first object that prevents flow from a source. Which of the following is considered a primary barrier during drilling operations? a) b) c) d)

Q4)

barrier is the first object that prevents flow

Which statement describes a secondary well barrier? a)

Q3)

A primary well from a source A primary well from a source A primary well preventer A primary well

Drill Pipe Ram preventers Casing Drilling Mud

A Secondary Well Barrier is the second object that prevents flow from a source. Which of the following are considered secondary barriers during the well construction process? (Choose two answers) a) b) c) d)

Ram preventers Drilling mud Cement Drill string float valves

IWCF combined surface & subsea student book L3/4

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17

Q5)

Which statement below best describes a well barrier envelope? a) b) c) d)

Q6)

Which TWO statements are true for barrier test charts and documents? a) b) c) d) e)

Q7)

A well barrier envelope is a mechanical well barrier element that provides closure of the total well barrier envelope A well barrier envelope is the primary fluid barrier that is used to over balance the well along with the drilling fluid at surface A well barrier envelope is series of one or more dependent well barrier elements that will prevent unintentional flow of formation fluids A well barrier envelope is a series of one or more mechanical barriers designed to plug and abandon a well once drilling is completed

All test documents must be retained at head office for a period of 6 months Pressure tests are not documented if there is a successful function test The test document and chart must be signed by an authorised person BOP test pressures must be recorded on a pressure chart The barrier test chart can be destroyed after a successful test

Which of the statements below describes the purpose of an inflow test? a) b) c) d)

To check the integrity of the formation and surface equipment before running casing To check for communication between the BOP and Choke Manifold To check there is no communication between the casing, liner lap or cement plug To check the integrity of the surface equipment before drilling out the float and shoe

IWCF combined surface & subsea student book L3/4

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18

Q8)

When defining a barrier envelope two or more barrier elements must be in place and tested. From the list below select the elements that would form a secondary barrier envelope on a subsea rig during drilling operations. Intermediate casing has been run and the rig is currently drilling 12 ¼” hole. The water depth is 2500 ft. (Choose all that apply) a) b) c) d) e) f) g) h) i) j) k)

Q9)

Wellhead Riser Choke and kill lines BOP Casing FIT/LOT Conductor Drilling mud Casing hanger seals Casing cement track Casing Conductor cement track

What can you do to test the integrity of a barrier when test pressure cannot be directly applied from the direction in which flow is likely to come? a) b) side c) d)

There is nothing you can do so there is no need to test it Perform a negative test by reducing pressure on the other Apply extra pressure to the next barrier in the envelope Apply for dispensation from the operator representative

IWCF combined surface & subsea student book L3/4

Classified as General

19

IWCF combined surface & subsea student book L3/4

Classified as General

20

P  MW  0.052  TVD

P1  V1  P2  V2  N1  P2  P1     N 2

2

Equipment Instructor's Copy

IWCF combined surface & subsea student book L3/4

Classified as General

21

Manual standard clause

This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for the use for course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training.

Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates

E-mail:

[email protected]

Homepage

www.maersktraining.com

IWCF combined surface & subsea student book L3/4

Classified as General

22

Q1) The BOP stack from the wellhead upwards is made up of pipe rams 1, spool with choke and kill side outlets, pipe rams 2 and annular preventer. A drill string is in the hole. (Do not consider bullheading when answering the questions). a) Can the well be killed with ram 2 closed and ram 1 open?  

Yes. No.

b) Can the inside side outlet valve on the spool be repaired with ram 2 closed and a kick closed in?  

Yes. No.

c) Can the annular preventer be repaired with ram 1 closed?  

Yes. No.

d) Can the well be killed with ram 1 closed?  

IWCF combined surface & subsea student book L3/4

Classified as General

Yes. No.

23

Q2) The BOP stack from the wellhead upwards is made up of pipe rams 1, spool with choke and kill side outlets, pipe rams 2, blind/shear rams and annular preventer. a) Can the well be circulated and killed with ram 2 closed and ram 1 open, when a drill string is in the well?  

Yes. No.

b) Can the inside choke valve on the spool be repaired with the blind/shear rams closed and a kick closed in, if no drill string is in the well?  

Yes. No.

c) Is it good drilling practice to circulate and kill the well with rams 1 closed, when drill string is in the well?  

Yes. No.

d) Can the blind/shear rams be repaired with the well closed in on pipe rams 1?  

IWCF combined surface & subsea student book L3/4

Classified as General

Yes. No.

24

Q3) When selecting a Surface BOP stack for a specific job, what determines the Rated Working Pressure of the chosen BOP according to API standard 53? a)



Bottom hole pressure calculated according to well program.

b)



Maximum anticipated casing shoe pressure.

c)



Anticipated hydrostatic bottom hole pressure

d)



Maximum anticipated surface pressure (MASP).

Q4) Which one of the options describes the main purpose of a diverter? a)



To close in a shallow kick.

b)



c)



d)



To create a backpressure sufficient to stop influx from entering the well bore. To direct fluid or gas a safe distances away from the rig floor without closing-in the kick. To act as a back-up system if the annular preventer fails.

Q5) What is the normal hydraulic supply pressure to a diverter system? a)



3000 psi.

b)



1500 psi.

c)



1200 psi.

d)



1000 psi.

IWCF combined surface & subsea student book L3/4

Classified as General

25

Q6) The illustration shows a typical diverter system installed on a rig while drilling surface hole. The wind direction is from port to starboard. The system does not sequence the operation automatically.

DIVERTER PACKER OPEN CLOSED VALVE A OPEN CLOSED

OPEN CLOSED

VALVE B

PORT SIDE VENT

VALVE C

STARBOARD SIDE VENT

FLOWLINE SEALS PRESS VENT VALVE D SHALE SHAKERS OPEN CLOSED VALVE E VALVE F PRESS VENT

OVERSHOT PACKER

Select the correct operation sequence to divert flow from the rig. a)



Pressure A, then Close E, and then open C.

b)



Open C, then close E, then pressure A.

c)



Open C, then vent F, and then close E.

d)



Open B, then Close E, then pressure A.

Q7) Which two of the options give the correct reason for including a weep-hole on the ram type BOPs? a)



b)



c)



d)



e)



The weep hole prevents leakage through the ram shaft packing from the well bore to the hydraulic opening chamber and vice versa. The bull plug replaces a grease nipple. When removed the weep hole allows greasing the ram shaft. The weep hole allows visual inspection of the ram shaft and should be plugged with a bull plug between inspections. The weep hole is a grease release port that prevents overgreasing the ram shaft packing. The weep hole indicates if the ram shaft packing is leaking hydraulic fluid, well bore fluid or both types of fluid.

IWCF combined surface & subsea student book L3/4

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26

Q8) When should shear rams be used for immediate control? (Two answers) a)



To close the well in with no pipe in the hole.

b)



To close in a shallow kick.

c)



To control a blowout up through the drill pipe.

d)



To hang off the drill string.

Q9) The terminology "Primary Seal" and "Secondary Seal" is used in connection with ram type BOPs. Which one of the options explains the meaning? a)



b)



c)



d)



Primary Seal is the mechanical ram shaft packing alone. Secondary Seal is an injected plastic packing intended to activate an extra seal on the ram shaft in an emergency if the Primary Seal is leaking. Primary Seal is well control utilizing only mud hydrostatic pressure. Secondary Seal is well control utilizing both mud hydrostatic pressure and BOP to balance the formation pressure. Primary Seal is closing-in the well using the annular BOP. Secondary Seal is closing-in the well using the Rams after the annular BOP already has been closed. Primary Seal is a seal established by a ring gasket. Secondary Seal is a seal established by a ring gasket wound by teflon tape.

Q10) What is the definition of ” Closing Ratio” according to API: a)



b)



c)



d)



The ratio between Rated Working Pressure for the BOP and Rated Working Pressure for the hydraulic BOP control unit. The hydraulic pressure required closing a BOP at Rated Working Pressure. The area of the operating piston exposed to the close operating pressure, divided by the cross sectional area of the piston shaft exposed to well bore pressure. The maximum well bore pressure that will allow closing the ram having 1500 psi hydraulic closing pressure on the operating pistons.

IWCF combined surface & subsea student book L3/4

Classified as General

27

Q11) A ram BOP has a closing ratio = 10.56 Calculate the minimum required hydraulic closing pressure for the ram BOP if 11,000 psi wellbore pressure is contained in the BOP. a)



11 psi

b)



1,050 psi

c)



1,500 psi

d)



11,000 psi

Q12) According to API Standard 53 the Initial pressure tests for surface BOP Systems are defined as those tests that shall be performed on location before the equipment is put into operational service. What should the Initial High Pressure test be for Ram preventers? a)



b)



Rated Working pressure of ram BOPs or to the Rated Working Pressure of the wellhead system whichever is lower. 90 % of BOP Rated Working Pressure.

c)



70 % of BOP Rated Working Pressure.

d)



50 % of BOP Rated Working Pressure.

Q13) According to API Standard 53 the surface BOP Systems shall be tested after taken into operational service. These tests are named Subsequent tests. What should the Subsequent High Pressure test be for Ram preventers? a)



b)



To a pressure greater than the maximum anticipated surface pressure (MASP) of the hole section. 90 % of BOP Rated Working Pressure.

c)



70 % of BOP Rated Working Pressure.

d)



Working pressure of ram BOPs

IWCF combined surface & subsea student book L3/4

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28

Q14)The anti-extrusion plates have two main functions. Please indicate the two main functions from the choices below: a)



Energize metal-to-metal seal

b)



Prevent rubber from extruding uncontrolled

c)



Add weight to the ram assembly

d)



Act as a piston pushing forward feedable rubber

e)



Support pipe weight when hung off

Q15)Which three statements about annular preventers are true? a)



b)



c)



Will allow reciprocating or rotating the drill string while maintaining a seal against well bore pressure. Requires a variable hydraulic closing pressure according to the task carried out. Can be used as a means of secondary well control.

d)



Can seal on a square or hexagonal kelly.

e)



Will not allow tool joints to pass through.

Q16) For annular BOPs the periodic field testing (Subsequent test) according to API (RP 53) should be? a)



Minimum 50 % of annular BOP Rated Working Pressure.

b)



c)



Minimum of MASP for the hole section or 70 % of annular BOP Rated Working Pressure, whichever is less. Minimum 90 % of annular BOP Rated Working Pressure.

d)



To a pressure greater than the maximum anticipated surface pressure, but not to exceed the Rated Working Pressure of the annular BOP.

IWCF combined surface & subsea student book L3/4

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29

Q17) Illustrations A, B, and C show the profile of three different types connections used on BOP’s.

A

B

C

Identify the types of connection by matching the correct letter to the description. a)

____

C

Clamp hub connection.

b)

____

Flanged connection.

c)

____

Studded connection.

B

A

IWCF combined surface & subsea student book L3/4

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30

Q18) The Assistant Driller has found a ring gasket in the store with the following identification stamped on it: 1 2 3 4

BX 159 S316-4 13-5/8

Match the correct number to the description below. a)

____ 1 Type of ring gasket.

d)

b)

____ Outside ring diameter.

e)

4 ____ 2 Ring number.

c)

____ Inside ring diameter.

f)

____ 3 Ring gasket material

____ Nominal flange size.

Q19) The Driller has stripped to bottom with an Inside Blowout Preventer IBOP (Gray valve) in the string. Which tasks below cannot be carried out? (choose three answers) a)



Directly readout the SIDPP.

b)



Circulate through the drill string.

c)



Reverse circulate.

d)



Run wireline to the bit.

e)



Use the Volumetric Method to control the well.

IWCF combined surface & subsea student book L3/4

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31

Q20) The drill string in the hole consist of 5” drill pipe with NC50 connections, 5” HWDP with NC50 connections, 8” DC with 6-5/8” REG box-pin, and 9-3/4” DC with 7-5/8” REG box-pin. The Drill Pipe Safety Valve has 4-1/2” IF (NC50) connections box and pin. Select from the list below the two cross-overs it is required to have ready on the rig floor, before starting to trip out of the hole. a)



4-1/2” IF pin x 6-5/8” REG box.

b)



6-5/8” pin x 7-5/8” REG pin.

c)



4-1/2” IF box x 6-5/8” REG box.

d)



4-1/2” IF box x 7-5/8” REG pin.

e)



4-1/2” IF box x 6-5/8” REG pin.

Q21) According to API Standard 53 the Safety Valves (DPSV, IBOP & TDS IBOP) have to be pressure tested according to a given frequency. When should the valves be pressure tested? (Choose 4 answers) a) 

Before the equipment is put into operational service.

b) 

Before every trip.

c) 

Not to exceed intervals of 21 days.

d) 

After the disconnection or repair of the equipment.

e) 

In accordance with the equipment owner’s PM (Programmed Maintenance) program.

IWCF combined surface & subsea student book L3/4

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32

Q22) Which statement is true for an Inside Blowout Preventer (Gray Valve)? a)



Mudflow inside the drill string towards the bit will close the valve.

b)



Requires a double box sub in order to be installed in the drill string.

c)



Should be installed as the first one of two valves if the well kicks during a trip.

d)



By turning a key connected to an operating crank 90 degrees the valve closes or opens.

e)



Will not allow reverse circulation when installed in the drill string.

Q23) What is the maximum available hydraulic pressure for closing pipe rams, in a 3000 psi rated working pressure system? a)



1000

psi

b)



1200

psi

c)



1500

psi

d)



3000

psi

Q24) Which three of the functions on the BOP-stack does the manifold regulator supply? a)



Annular BOP.

b)



BOP test line.

c)



Ram BOP.

d)



Kill line hydraulic valve.

e)



Choke line hydraulic valve.



IWCF combined surface & subsea student book L3/4

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33

Q25)Indicate the position in which the 3 position / 4 way valves (selector valves) on the hydraulic BOP control unit should be placed in a normal drilling operation a)



All closed.

b)



All open.

c)



Some open and some closed.

Q26) What is the main purpose of storing the hydraulic control fluid under pressure in the accumulator cylinders? a)



Allows operation of the BOP in case of power failure.

b)



Gives a quicker BOP response time.

c)



Allows rest periods for the hydraulic pumps.

d)



Provides a back up to the hydraulic pumps.

Q27) A BOP stack configuration is: 10M – 13-5/8” - class 5 - 1A - 4R There are 2 hydraulic operated valves on the BOP side outlets (one on the kill line and one on the choke line). BOP component

Volume to open gal

Volume to close gal

Annular BOP

15.80

16.00

Pipe and blind/shear rams

7.50

8.00

Choke and kill line valves

2.00

2.00

Calculate the required fluid volume to close, open and then close all the functions on the BOP stack a)



106.8

gal

b)



124.3

gal

c)



130.3

gal

d)



153.8

gal

IWCF combined surface & subsea student book L3/4

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34

Q28) When an operation of a ram or an annular BOP takes place from the Drillers electric remote control panel the instrumentation will confirm whether the operation was successfully carried out or a malfunction has occurred. Some reasons for malfunctions that can occur are: Code 1. 2. 3. 4.

Type of malfunction Leaking hydraulic line between the BOP control system and the BOP. Blocked hydraulic line between the BOP control system and the BOP. 3 position 4 way valve on the BOP control unit is stuck. Electric bulb blown.

Match the reason for the given observations made after a ram close function has been activated. Observations made a) b) c) d)

Manifold pressure dropped. Accumulator pressure dropped. Green light in open button went out. Red light did come on. Manifold pressure did not drop. Accumulator pressure did not drop. Green light in open button stayed on. Red light in close button stayed off. Manifold pressure did not drop. Accumulator pressure did not drop. Green light in open button went out. Red light in close button came on. Manifold pressure dropped and built up to 1500 psi. Accumulator pressure dropped and built slowly up to 3000 psi. Green light in open button went out. Red light did not come on.

IWCF combined surface & subsea student book L3/4

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Malfunction code number (Your answer)

1 3 2 4

35

Q29) What is the purpose of the "bypass" button on the Drillers electric remote control panel? a)



b)



c)



d)



To increase the hydraulic annular pressure to accumulator system pressure. To bypass hydraulic fluid from the accumulator to the reservoir. Increase the hydraulic manifold pressure to the same as accumulator pressure. To bypass the accumulator unit and allow bottle pressure to be directly applied to the BOP stack.

Q30) What is the main purpose of the choke in the overall BOP system? a)



To divert mud to the mud tanks.

b)



To control back pressure while circulating a kick.

c)



To close-in the well softly.

d)



To allow trapped pressure to be bled of remotely.

Q31) On which two gauges would you expect to see a change when stripping a tool joint through an annular BOP? a)



Pit volume totalizer.

b)



Regulated annular pressure gauge.

c)



Accumulator pressure gauge.

d)



Weight indicator.

e)



Drill pipe pressure gauge.

f)



Regulated manifold pressure gauge.

g)



Rig air pressure gauge.

IWCF combined surface & subsea student book L3/4

Classified as General

36

Q32) DERRICK VENT PIPE ID

DERRICK VENT PIPE HEIGHT

PRESSURE GAUGE

HOT MUD INLET

MUD/GAS INLET LINE ID

BODY ID

BODY HEIGHT

Which two dimensions of a mud / gas separator determine the pressure buildup in the separator? a) b) c)

SHAKER TANK

d) DIP TUBE HEIGHT

e)



   

Vent pipe inside diameter. Body height. Vent pipe height. Height of U-tube. Inside diameter of Utube.

DIP TUBE ID

f) MUGASE1.DRW

IWCF combined surface & subsea student book L3/4

Classified as General

g)

 

Body inside diameter. Inlet line inside diameter.

37

Q33)

DERRICK VENT PIPE ID = 8 IN

DERRICK VENT PIPE HEIGHT = 115 FT

PRESSURE GAUGE

HOT MUD INLET

MUD/GAS INLET LINE ID = 4 IN BODY ID = 4 FT

BODY HEIGHT = 12 FT

The mud/gas separator (poor boy degasser) has the dimensions shown in the illustration. What is maximum pressure allowed on the gauge before blow though would occur if a safety factor of 0.8 is required and the calculation is based on salt water density of 8.96 ppg? a)

SHAKER TANK

b)

DIP TUBE ID = 8 IN

DIP TUBE HEIGHT = 10 FT

c) d)

   

3.7

psi

4.6

psi

8.9

psi

10.0

psi

MUGASE2.DRW

IWCF combined surface & subsea student book L3/4

Classified as General

38

Q34) Based on the diagram below indicate the valves that must be open if a formation strength test is to be performed. The cement pump will be used and the fluid will be pumped into the wellbore through the drill string. Surface pressure is recorded on the cement unit. The pressure will be released at the cement unit. The Driller monitors the surface pressures on the standpipe pressure gauge and on the choke manifold pressure gauge. The BOP kill line valves are manually operated. On the BOP choke line the inner valve is manually operated and the outer valve is hydraulic operated.

a)



1-5-8-9-10-13

b)



2-4-5-8-9-10-12

c)



1-4-3-6-7-8-9-10-12

d)



1-4-5-8-9-10-12

IWCF combined surface & subsea student book L3/4

Classified as General

39

Q35) The BOP stack was nippled up on the wellhead for the first time on this well. Which of the options below gives the test pressure the ram BOPs should be tested to according to API standard 53? a)



70% of BOP Rated Working Pressure.

b)



100% of BOP Rated Working Pressure.

c)



150% of BOP Rated Working Pressure.

d)



To the Rated Working Pressure (RWP) of the ram BOPs or RWP of the wellhead system, whichever is lower.

Q36) You are going to test the BOP with a hanger type test plug. What is the most important reason for opening the side outlet valve on the wellhead or on the spool? a) 

To avoid damaging the casing and/or the formation.

b) 

To decrease tensile load on the drill pipe.

c) 

To decrease collapse forces on the drill pipe.

d) 

To prevent damaging the BOP connector seals.

Q37) Before a new BOP leaves the factory an acceptance shell test is performed that the BOP shall pass without leakage according to API RP 16A. To which minimum pressure will a 13-5/8” 15,000 psi Rated Working Pressure BOP be tested? a) 

15000 psi

b) 

20000 psi

c) 

22500 psi

d) 

30000 psi

IWCF combined surface & subsea student book L3/4

Classified as General

40

Q38) Drilling away reading the following on the BOP manifold gauges.

   

Everything is ok There is a leak in the hydraulic system Regulator fault Pressure switch malfunction

Q39) Drilling away the following is observed on the BOP panel, what could be the cause.

   

Everything is ok Leak in the hydraulic system Regulator fault Pressure switch fault

IWCF combined surface & subsea student book L3/4

Classified as General

41

Q40) Drilling away the following is observed on the BOP panel, what could be the cause.

   

Everything is ok Leak in the hydraulic system Regulator fault Pressure switch fault

Q41) Drilling away the following is observed on the BOP panel, what could be the cause.

   

Everything is ok Leak in the hydraulic system Regulator fault Pressure switch fault

IWCF combined surface & subsea student book L3/4

Classified as General

42

Q42) Drilling away the following was observed on the BOP control panel, what could be the cause.

   

Everything is ok Leak in the hydraulic system Regulator fault Pressure switch fault

Q43) Drilling away the following was observed on the BOP control panel, what could be the cause.

   

Everything is ok Leak in the hydraulic system Regulator fault Pressure switch fault

IWCF combined surface & subsea student book L3/4

Classified as General

43

Q44) Drilling away the following was observed on the BOP control panel, what could be the cause.

 Everything is ok  Regulator fault  Pressure switch fault Q45) The driller made an attempt to close the BOP rams the open green light went off and the red light came on, no pressure changed.

   

4 way 3 position valve did not change position Leak in hydraulic system Regulator malfunction Blocked hydraulic line

IWCF combined surface & subsea student book L3/4

Classified as General

44

Q46) The driller attempted to close the BOP rams the green light went off and the red light did not come on but the pressures went down and recovered as described below.

   

4 way 3 position valve did not change position Leak in hydraulic system Regulator malfunction Lamp malfunction (bulb blown)

Q47) Which of the following correctly describes the operation of the master valve on the BOP remote panel? a) b) c) d)

The master valve when operated moves the 3 position valve to the close position The master valve when operated will do a panel light test The master valve must be continually operated whilst functions on the panel are made Holding the master air valve for 5 seconds then releasing it will allow functions to take place.

IWCF combined surface & subsea student book L3/4

Classified as General

45

Q48) The illustration shows the cross sectional profile as well as the top view of a API type BX flange. Some of the diameters are identified by a number.

Mark the number that gives the Nominal Flange Size. a)



Dimension number 1.

b)



Dimension number 2.

c)



Dimension number 3.

d)



Dimension number 4.

IWCF combined surface & subsea student book L3/4

Classified as General

46

Q49) Under what circumstances a Cup-Type tester would be used in preference to a Test-Plug when testing a surface BOP? a) b) c) d)

Both plugs are interchangeable so it makes no difference To test the BOP stack without applying pressure to the wellhead To test the entire wellhead side outlets and seals and BOP The cup type tester is for subsea BOP stacks only

Q50) After connecting the open and close hoses to the stack you should: a) b) c) d)

Take slow circulating rates Bleed down the accumulator bottles and check the pre-charge Function test all items on the stack Place all functions in block position to charge up the hoses

Q51) A Cameron 13 5/8" 10,000 psi rated ram BOP has a closing ratio for pipe and shear rams of 7.0 - 1. a)

What is the minimum closing pressure required for the BOP?

1429 b)

If available accumulator pressure is 3000 psi and the opening ratio is 2.3 - 1, at what maximum wellbore pressure can we strip ram to ram?

6900

IWCF combined surface & subsea student book L3/4

Classified as General

psi

psi

47

Q52) a)

Of the 4 types of gasket listed, indicate which flange (API 6B, API 6BX) they would be used with. Type R Octagonal

6B

.

Type RX

6B 6BX

. .

Which two of the above gaskets are pressure energised?

Rx

and

IWCF combined surface & subsea student book L3/4

Classified as General

.

Type R Oval

Type BX b)

6B

Bx

.

48

Q53)

The illustration shows a Hydril GL Annular Preventer. Three hydraulic chambers are shown. Which two of the following statements are correct?

a)



Lowest required hydraulic closing pressure when closing chamber and secondary chamber are connected.

b)



Lowest required hydraulic closing pressure when opening chamber and secondary chamber are connected.

c)



Lowest required hydraulic fluid volume for closing when closing chamber and secondary chamber are connected.

d)



Lowest required hydraulic fluid volume for closing when opening chamber and secondary chamber are connected.

e)



Lowest required hydraulic closing pressure when opening chamber and closing chamber are connected.

IWCF combined surface & subsea student book L3/4

Classified as General

49

Q54) When slip and cutting drilling line what must you install? a)



Dart Sub

b)



FOSV and IBOP

c)



FOSV

d)



IBOP

IWCF combined surface & subsea student book L3/4

Classified as General

50

P  MW  0.052  TVD

P1  V1  P2  V2  N1  P2  P1     N 2

2

Subsea Equipment Instructor's Copy

IWCF combined surface & subsea student book L3/4

Classified as General

51

Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for the use for course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training.

Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates

E-mail:

[email protected]

Homepage

www.maersktraining.com

IWCF combined surface & subsea student book L3/4

Classified as General

52

Q1) The illustration shows the main components of the Lower Marine Riser Package (LMRP) with a subsea BOP. Match the correct number to the component description

a) b) c) d) e) f) g) h)

6___ 1 ___

5___

Annular(s) Conduit Line(s) Blue/Yellow Control Pod (MUX / Hydraulic operated)

2___ 3___

Flexible C/K Line(s)

7___ 4___

LMRP Support frame

8___

LMRP Connector

Flex / Ball joint

Subsea Accumulator bottle(s)

IWCF combined surface & subsea student book L3/4

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53

Q2)

Match the correct number to the component in the illustration below of a subsea BOP control system:

11 1

Stack mounted accumulators

10 5

Control pod

6

Subsea hose bundle reel

2 4

Emergency backup supply

8

Hose bundle clamp

Drillers electric panel

Hydraulic control unit

Mini panel

IWCF combined surface & subsea student book L3/4

Classified as General

54

Q3) The illustration shows a standard symbol for a 3 position / 4 way valve commonly used on a BOP control unit for a subsea installation. Which two statements are true for the illustrated symbol?

a)



Can be operated manually.

b)



Cannot be pilot operated by air.

c)



Can be placed in 4 positions.

d)



Has 4 active connections (inlets/outlets).

e)



Will not allow venting downstream pressure.

Q4) The hydraulic BOP control system for a subsea BOP is separated into a Control System and a Pilot System. Which two statements are correct with respect to the Pilot System? a)



The Pilot System is a closed dead-end system.

b)



The Pilot System dumps pilot fluid to the sea at every operation of BOP functions.

c)



The Pilot System controls the position of all shuttle valves on the BOP stack directly.

d)



The fluid in the Pilot System flows continuously while a function on the BOP takes place.

e)



Pilot fluid is used to fire the SPM valves in both pods at the same time.

IWCF combined surface & subsea student book L3/4

Classified as General

55

Q5) Which two statements are correct with respect to shuttle valves in a subsea BOP control system? a)



The shuttle valves are pilot operated.

b)



The shuttle valves allow retrieving a malfunctioning pod without losing hydraulic BOP control.

c)



The shuttle valves automatically seal any hydraulic leaks in the selected pod.

d) e)

 

The shuttle valves isolate the redundant pod. The shuttle valves have to be pre-selected at surface for each BOP function on the stack.

Q6) Which statement is true with respect to Subsea Plate Mounted valves (SPM valves) when a function is made at the surface to operate the annular BOP or the rams? a)



The SPM valves for the selected function in both pods fire.

b)



The SPM valve for the selected function in the active pod fires and the SPM valve in the redundant pod remains static.

c)



Both SPM valves for the selected function remain static.

d)



The SPM valve for the selected function in the active pod remains static and the SPM valve in the redundant pod fires.

Q7) There are dedicated accumulator bottles for pilot pressure. The pilot fluid pressure adjusts the subsea regulators in the pods and fires the SPM valves in the subsea pods. TRUE

/

FALSE

IWCF combined surface & subsea student book L3/4

Classified as General

56

Q8)

The illustration shows components of a subsea BOP control system.

Match the component to the number. Hose bundle sheave 11

Subsea accumulator bottle

8

Mini electric panel

1

Hose bundle

5

Subsea control pod

9

Master electric panel

3

Blue bundle reel

6

Emergency power supply

2

Flex Joint

7

Hose bundle clamp

10

Yellow hose bundle reel

12

Pod retrieving cable 4

IWCF combined surface & subsea student book L3/4

Classified as General

57

Q9) When a BOP function is activated from the Drillers electric panel a number of indications will confirm whether the BOP worked or not. Which four indicators should you see when an annular preventer is closed ? (4 answers) a)



Annular light changes from Green to Red.

b)



Annular light changes from Red to Green.

c)



Accumulator pressure decreases then builds back up.

d)



Manifold pilot pressure decreases then builds back up.

e)



Manifold readback pressure decreases then builds back up.

f)



Annular pilot pressure decreases then builds back up.

g)



Annular readback pressure decreases then builds back up.

h)



Flow meter run then stops.

Q10) The side outlet valves on the subsea BOP choke and kill lines are designed to: a)



b)



c) d)

 

Remain open if the hydraulic control fluid pressure is lost while the valve is open. Close if hydraulic control fluid pressure is lost while the valve is open. Close instantly if the flow rate through it is too large. None of the above.

Q11) Surface accumulators are normally pre-charged to 1,000 psi. If the riser length is 2,500 feet and the operating fluid has a gradient of 0.455 psi/ft what would be the correct pre-charge for the subsea bottles?

2,137______psi

IWCF combined surface & subsea student book L3/4

Classified as General

58

Q12) The fluid used in a normal hydraulic subsea control system is normally: a) b) c) d)

Oil Saltwater Methanol Pot water with additives

Q13) If a function is made to close the hang off rams and the fluid counter continues to register fluid movement after the correct closing volume has been reached. What would you consider doing? (One answer) a) b) c) d)

Call the subsea engineer and let him sort it out Probably a malfunction on the fluid counter Close another set of rams Put that function into block position

Q14) While drilling an alarm goes off indicating a rapid loss of accumulator pressure and the flow meter registers fluid movement. What would be your best option? (One answer) a) b) c) d)

Stop drilling and call the subsea engineer Stop drilling and shut the well in Stop drilling and put all functions into block Pull back into shoe and evaluate the problem

Q15) Which of the following ram locking systems locks in a unique position and does not automatically compensate for wear on the ram front packer? a) b) c) d)

   

Cameron type Wedgelock. NL-Shaffer type Poslock. NL-Shaffer type Ultralock. Hydril type MPL.

Q16)From the following pick what statements are true about a SPM valve. a)



Functioned open by spring force and Pilot pressure

b)



Functioned open by Pilot pressure

c)



Functioned closed by Hydrostatic pressure

d)



Functioned closed spring force

IWCF combined surface & subsea student book L3/4

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59

Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771 Dubai United Arab Emirates [email protected] www.maersktraining.com

IWCF combined surface & subsea student book L3/4

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60

P  MW  0.052  TVD

P1  V1  P2  V2  N1  P2  P1     N 2 Instructor's Copy

Subsea Stack Gauge Questions 2 LEVEL 4 ONLY Classified as General

2

Subsea Stack Gauge Questions 2 Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for use on a course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training. Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

-1Classified as General

Subsea Stack Gauge Questions 2

Use the completed IWCF Subsea BOP Stack (Vertical Well) Kill Sheet API Units to answer the following questions. All questions run sequentially. The well will be killed using the Wait & Weight Method at 30 spm. Following the normal IWCF standards there will be no tolerance below the expected/calculated pressure and up to 69 psi above. Q1 Data: Drillpipe Pressure:

Casing Pressure: 630 psi

Pump Speed: 30 spm

Strokes Pumped: 100 stk

Time: 3 mins

Choke Position: 38% open

The start up went well and then both the stroke counter and time were reset to zero when kill mud reached the rig floor. What should the drill pipe pressure gauge be reading after 100 strokes have been pumped? 739

psi

Q2) Data: Drillpipe Pressure: 690 psi

Casing Pressure: 645 psi

Pump Speed: 30 spm

Strokes Pumped: 300 stk

Time: 10 mins

Choke Position: 38% open

This is what you see. What should you do? a) b) c) d)

Pressure is too high - open the choke to bring it down a bit. Pressure is too low - close the choke to bring it up a bit. The kill is going well - continue. There is no way to tell - shut down and re-evaluate the pressures.

-2Classified as General

Subsea Stack Gauge Questions 2

Q3) Data: Drillpipe Pressure: 500 psi

Casing Pressure: 660 psi

Pump Speed: 30 spm

Strokes Pumped: 850 stk

Time: 28 mins

Choke Position: 40% open

How is the kill going? a) b) c) d)

The kill is going well - continue. Pressure is too low - close the choke to bring it up a bit. Pressure is too high - open the choke to bring it down a bit. There is no way to tell - shut down and re-evaluate the pressures.

Q4) Data: Drillpipe Pressure: 170 psi

Casing Pressure: 840 psi

Pump Speed: 0 spm

Strokes Pumped: 1100 stk

Time: 37 mins

Choke Position: closed

You have shut down the kill because of a mud supply problem. How is the kill going? a) b) c) d)

Pressure is too high - bleed off 50 psi before re-starting. Pressure is too low - charge the well up with the pump before continuing. Pressure is a little high - but within what is allowed. There is no way to tell.

-3Classified as General

Subsea Stack Gauge Questions 2

Q5) Data: Drillpipe Pressure: 410 psi

Casing Pressure: 720

Pump Speed: 27 spm

Strokes Pumped: 1150 stk

Time: 38 mins

Choke Position: 34% open

How is the kill going? a) b) c) d)

The kill is going well - continue. Correct the pump speed. Pressure is too low - close the choke to bring it up. Casing pressure is too high - open the choke to bring it down a bit.

Q6) Data: Drillpipe Pressure: 390 psi

Casing Pressure: 800 psi

Pump Speed: 30 spm

Strokes Pumped: 1200 stk

Time: 40 mins

Choke Position: 40% open

How is the kill going? a) b) c) d)

The kill is going well - continue. Correct the pump speed. Pressure is too low - close the choke to bring it up. Casing pressure is too high - open the choke to bring it down a bit.

-4Classified as General

Subsea Stack Gauge Questions 2 Q7) Data: Drillpipe Pressure:

Casing Pressure: 870 psi

Pump Speed: 30 spm

Strokes Pumped: 1514 stk

Time: 50 mins

Choke Position: 38% open

The kill is going correctly. What should the drill pipe pressure gauge be reading? 292

psi

Q8) Data: Drillpipe Pressure: 0 psi

Casing Pressure:

Pump Speed: 0 spm

Strokes Pumped: 1514 stk

Time: 50 mins

Choke Position: closed

The kill was shut down correctly. What should the casing pressure gauge be reading now the well is shut in?

960

-5Classified as General

psi

Subsea Stack Gauge Questions 2

Q9) Data: Drillpipe Pressure: 300 psi

Casing Pressure: 1210 psi

Pump Speed: 30 spm

Strokes Pumped: 3000 stk

Time: 100 mins

Choke Position: 39% open

How is the kill going? a) b) c) d)

The kill is going well - continue. Correct the pump speed. Pressure is too low - close the choke to bring it up. Casing pressure is too high - open the choke to bring it down a bit.

Q10) Data: Drillpipe Pressure: 340 psi

Casing Pressure: 1690 psi

Pump Speed: 30 spm

Strokes Pumped: 3810 stk

Time: 127 mins

Choke Position: 41% open

Casing pressure is now higher than dynamic MAASP. What should you do? a) b) c) d)

Open the choke to reduce casing pressure to approximately 1560 psi. Reduce the pump speed. Shut down and see what the casing gauge reads then. The kill is going well - continue.

-6Classified as General

Subsea Stack Gauge Questions 2

Q11) Data: Drillpipe Pressure: 280 psi

Casing Pressure:

Pump Speed: 30 spm

Strokes Pumped: 3900 stk

Time: 130 mins

Choke Position: 30% open

Gas is at the choke. The casing gauge is fluctuating wildly and is very difficult to read. How are things going? a) b) c) d)

It is impossible to tell how the kill is going until mud returns at surface. Pressure is too low - close the choke to bring it up a bit. Shut down and calibrate the casing gauge. The kill is going well - continue.

Q12) Data: Drillpipe Pressure: 390 psi

Casing Pressure: 410 psi

Pump Speed: 30 spm

Strokes Pumped: 4500 stk

Time: 150 mins

Choke Position: 34% open

Gas is out and original mud weight is being returned at surface. How are things going? a) b) c) d)

The kill is going well - continue. Pressure is too low - close the choke to bring it up a bit. Check for losses - kill mud should be coming back. Pressure is too high - open the choke to bring it down a bit.

-7Classified as General

Subsea Stack Gauge Questions 2

Q13) Data: Drillpipe Pressure: 300 psi

Casing Pressure: 210 psi

Pump Speed: 30 spm

Strokes Pumped: 5200 stk

Time: 173 mins

Choke Position: 54% open

How is the kill going? a) b) c) d)

Pressure is too high - open the choke to bring it down a bit. Pressure is too low - close the choke to bring it up a bit. Shut down immediately casing pressure is wrong. The kill is going well - continue.

Q14) Data: Drillpipe Pressure:

Casing Pressure: 110 psi

Pump Speed: 30 spm

Strokes Pumped: 5500 stk

Time: 183 mins

Choke Position: 68% open

Drill pipe pressure is fluctuating and the top drive hose is bouncing around in the derrick. What should you do? a) b) c) d)

Pressure is too high - open the choke to bring it down a bit. Pressure is too low - close the choke to bring it up a bit. Shut down immediately and check for blockages. The kill is going well - continue.

-8Classified as General

Subsea Stack Gauge Questions 2

Q15) Data: Drillpipe Pressure: 395 psi

Casing Pressure: 0 psi

Pump Speed: 30 spm

Strokes Pumped: 6000 stk

Time: 200 mins

Choke Position: 100% open

The previous issue has been resolved correctly. What do you think? a) b) c) d)

The The The The

choke indicator is faulty it should not be fully open. casing gauge is faulty it should not be reading zero. drill pipe gauge is faulty it should not be higher than FCP. kill is going well - get ready to shut in.

-9Classified as General

Subsea Stack Gauge Questions 2

- 10 Classified as General

Subsea Stack Gauge Questions 2

- 11 Classified as General

Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771 Dubai United Arab Emirates [email protected] www.maersktraining.com

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2 Instructor's Copy

Subsea Stack Kill Sheet Three

2

Subsea Stack Kill Sheet Three Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for use on a course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training. Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

-2-

Subsea Stack Kill Sheet Three

Use the data below to complete an IWCF Subsea BOP Stack (Vertical Well) Kill Sheet API Units and then answer the questions on the following pages: Well data: Bit size 12 1/ 4 in Hole depth from RKB (MD) 9950 ft Hole depth from RKB (TVD) 7800 ft Casing shoe depth - 13 3/ 8 in OD (MD) 5910 ft 3 Casing shoe depth - 13 / 8 in OD (TVD) 5780 ft Internal capacities: Drill pipe - 5 in OD 0.01887 bbl/ft Heavy wall drill pipe 5 in OD length 835 ft 0.0087 bbl/ft Drill collars size 8 1/ 2 in OD length 550 ft 0.0061 bbl/ft Choke line length 475 ft 0.0087 bbl/ft Annulus capacities between: Drill collars x open hole 0.0756 bbl/ft Drill pipe/HWDP x open hole 0.1215 bbl/ft Drill pipe/HWDP x casing 0.1279 bbl/ft Drill pipe x marine riser 0.336 bbl/ft Mud pump data: Displacement at 97% volumetric efficiency 0.117 bbl/stroke Circulating pressure through riser at 30 SPM 520 psi Circulating pressure through choke line at 30 SPM 730 psi Circulating pressure while drilling at 85 SPM 3125 psi APL while drilling 230 psi Other relevant information: Active system surface volume 270 bbl Surface line volume 8 bbl Sea water depth 400 ft Air gap 60 ft Sea water gradient 0.456 psi/ft Formation strength test data: Surface leak off test pressure 1950 psi Mud weight used at leak off test 10.2 ppg Kick data: SIDPP 570 psi SICP 720 psi Mud weight in use at time of kick 11.2 ppg Pit gain 20 bbl

-3-

Subsea Stack Kill Sheet Three

ANSWER THE FOLLOWING QUESTIONS Q1)

What is the maximum allowable mud weight based on the leak off test data?

16.6 Q2)

What is the maximum allowable annular surface pressure (MAASP) with the well shut in and the pressures stable?

1,623 Q3)

Q6)

Q7)

psi

Calculate the formation pressure based on the shut in data.

5,113 Q5)

psi

What is the safety margin at the shoe with the well shut in?

903 Q4)

ppg

psi

What kill mud is required to balance formation pressure?

12.7

ppg

1,540

stk

466

bbl

How many strokes to get kill mud from pump to bit?

What is the volume of the open hole?

-4-

Subsea Stack Kill Sheet Three Q8)

What is the total annulus volume with the well closed in?

1,166 Q9)

bbls

What will the Initial Circulating Pressure (ICP) be at 30 spm?

1.090

psi

Q10) What will the Final Circulating Pressure (FCP) be at 30 spm?

590

psi

Q11) After reaching FCP it is decided to increase the pump speed to 40 spm. What would happen to BHP if the choke operator holds casing pressure constant at what ever it is reading at the time as the pump speed is increased. a) b) c)

Increase Decrease Remain constant

Q12) How many strokes to go from ICP to FCP?

1,472

stks

Q13) What would the new MAASP be once the well has been killed?

1,172

psi

Q14) What would be the pressure step down per 100 strokes of kill mud pumped down the drill string? 34 psi /100 stks

-5-

Subsea Stack Kill Sheet Three Q15) What will be the initial dynamic casing pressure at kill rate?

510

psi

Q16) What will dynamic MAASP be at the start of a Drillers Method Kill?

1,413

psi

Q17) Assuming that kill mud weight balances formation pressure, what mud weight would be needed in the well after the kill to compensate for any loss in hydrostatic pressure if the riser was accidentally disconnected?

13.1

ppg

Q18) What will FCP be with kill mud back at surface and the choke fully open?

828

-6-

psi

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2 Surface Stack Gauge Questions 2 LEVEL 4 ONLY Instructor's Copy

Classified as General

2

Surface Stack Gauge Questions 2 Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for use on a course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training. Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

-1Classified as General

Surface Stack Gauge Questions 2

Use the completed IWCF Surface BOP Stack (Vertical Well) Kill Sheet API Units to answer the following questions. All questions run sequentially. The well will be killed using the Wait & Weight Method at 30 spm. Following the normal IWCF standards there will be no tolerance below the expected/calculated pressure and up to 69 psi above. Q1 Data: Drillpipe Pressure:

Casing Pressure: 720 psi

Pump Speed: 30 spm

Strokes Pumped: 100 stk

Time: 3 mins

Choke Position: 38% open

The start up went well and then both the stroke counter and time were reset to zero when kill mud reached the rig floor. What should the drill pipe pressure gauge be reading after 100 strokes have been pumped? 739

psi

Q2) Data: Drillpipe Pressure: 690 psi

Casing Pressure: 735 psi

Pump Speed: 30 spm

Strokes Pumped: 300 stk

Time: 10 mins

Choke Position: 38% open

This is what you see. What should you do? a) b) c) d)

Pressure is too high - open the choke to bring it down a bit. Pressure is too low - close the choke to bring it up a bit. The kill is going well - continue. There is no way to tell - shut down and re-evaluate the pressures.

-2Classified as General

Surface Stack Gauge Questions 2

Q3) Data: Drillpipe Pressure: 500 psi

Casing Pressure: 780 psi

Pump Speed: 30 spm

Strokes Pumped: 850 stk

Time: 28 mins

Choke Position: 40% open

How is the kill going? a) b) c) d)

The kill is going well - continue. Pressure is too low - close the choke to bring it up a bit. Pressure is too high - open the choke to bring it down a bit. There is no way to tell - shut down and re-evaluate the pressures.

Q4) Data: Drillpipe Pressure: 170 psi

Casing Pressure: 840 psi

Pump Speed: 0 spm

Strokes Pumped: 1100 stk

Time: 37 mins

Choke Position: closed

You have shut down the kill because of a mud supply problem. How is the kill going? a) b) c) d)

Pressure is too high - bleed off 50 psi before re-starting. Pressure is too low - charge the well up with the pump before continuing. Pressure is a little high - but within what is allowed. There is no way to tell.

-3Classified as General

Surface Stack Gauge Questions 2

Q5) Data: Drillpipe Pressure: 410 psi

Casing Pressure: 840

Pump Speed: 27 spm

Strokes Pumped: 1150 stk

Time: 38 mins

Choke Position: 34% open

How is the kill going? a) b) c) d)

The kill is going well - continue. Correct the pump speed. Pressure is too low - close the choke to bring it up. Casing pressure is too high - open the choke to bring it down a bit.

Q6) Data: Drillpipe Pressure: 390 psi

Casing Pressure: 890 psi

Pump Speed: 30 spm

Strokes Pumped: 1200 stk

Time: 40 mins

Choke Position: 40% open

How is the kill going? a) b) c) d)

The kill is going well - continue. Correct the pump speed. Pressure is too low - close the choke to bring it up. Casing pressure is too high - open the choke to bring it down a bit.

-4Classified as General

Surface Stack Gauge Questions 2 Q7) Data: Drillpipe Pressure:

Casing Pressure: 970 psi

Pump Speed: 30 spm

Strokes Pumped: 1514 stk

Time: 50 mins

Choke Position: 38% open

The kill is going correctly. What should the drill pipe pressure gauge be reading? 292

psi

Q8) Data: Drillpipe Pressure:

Casing Pressure: 970 psi

Pump Speed: 30 spm

Strokes Pumped: 1514 stk

Time: 50 mins

Choke Position: 38% open

The kill is going correctly. What should the drill pipe pressure gauge read if the kill is shut down while holding casing pressure constant at 970 psi?

Zero

-5Classified as General

psi

Surface Stack Gauge Questions 2

Q9) Data: Drillpipe Pressure: 300 psi

Casing Pressure: 1300 psi

Pump Speed: 30 spm

Strokes Pumped: 3000 stk

Time: 100 mins

Choke Position: 39% open

How is the kill going? a) b) c) d)

The kill is going well - continue. Correct the pump speed. Pressure is too low - close the choke to bring it up. Casing pressure is too high - open the choke to bring it down a bit.

Q10) Data: Drillpipe Pressure: 340 psi

Casing Pressure: 1780 psi

Pump Speed: 30 spm

Strokes Pumped: 3810 stk

Time: 127 mins

Choke Position: 41% open

Casing pressure is now higher than MAASP. What should you do? a) b) c) d)

Open the choke to reduce casing pressure to approximately 1650 psi. Reduce the pump speed. Shut down and see what the casing gauge reads then. The kill is going well - continue.

-6Classified as General

Surface Stack Gauge Questions 2

Q11) Data: Drillpipe Pressure: 280 psi

Casing Pressure:

Pump Speed: 30 spm

Strokes Pumped: 4200 stk

Time: 140 mins

Choke Position: 30% open

Gas is at the choke. The casing gauge is fluctuating wildly and is very difficult to read. How are things going? a) b) c) d)

It is impossible to tell how the kill is going until mud returns at surface. Pressure is too low - close the choke to bring it up a bit. Shut down and calibrate the casing gauge. The kill is going well - continue.

Q12) Data: Drillpipe Pressure: 390 psi

Casing Pressure: 500 psi

Pump Speed: 30 spm

Strokes Pumped: 4500 stk

Time: 150 mins

Choke Position: 34% open

Gas is out and original mud weight is being returned at surface. How are things going? a) b) c) d)

The kill is going well - continue. Pressure is too low - close the choke to bring it up a bit. Check for losses - kill mud should be coming back. Pressure is too high - open the choke to bring it down a bit.

-7Classified as General

Surface Stack Gauge Questions 2

Q13) Data: Drillpipe Pressure: 300 psi

Casing Pressure: 300 psi

Pump Speed: 30 spm

Strokes Pumped: 5200 stk

Time: 173 mins

Choke Position: 54% open

How is the kill going? a) b) c) d)

Pressure is too high - open the choke to bring it down a bit. Pressure is too low - close the choke to bring it up a bit. Shut down immediately casing pressure is wrong. The kill is going well - continue.

Q14) Data: Drillpipe Pressure:

Casing Pressure: 200 psi

Pump Speed: 30 spm

Strokes Pumped: 5500 stk

Time: 183 mins

Choke Position: 68% open

Drill pipe pressure is fluctuating and the top drive hose is bouncing around wildly. What should you do? a) b) c) d)

Pressure is too high - open the choke to bring it down a bit. Pressure is too low - close the choke to bring it up a bit. Shut down immediately and check for blockages. The kill is going well - continue.

-8Classified as General

Surface Stack Gauge Questions 2

Q15) Data: Drillpipe Pressure: 295 psi

Casing Pressure: 0 psi

Pump Speed: 30 spm

Strokes Pumped: 6000 stk

Time: 200 mins

Choke Position: 100% open

The previous issue has been resolved correctly. What do you think? a) b) c) d)

The choke indicator is faulty it should not be fully open. The casing gauge has failed it should not be reading zero. There is no way to tell how the kill is going until we shut in. The kill is going well - get ready to shut in.

-9Classified as General

Surface Stack Gauge Questions 2

- 10 Classified as General

Surface Stack Gauge Questions 2

- 11 Classified as General

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2 Instructor's Copy

Surface Stack Kill Sheet Three

2

Surface Stack Kill Sheet Three Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for use on a course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training. Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

2

Surface Stack Kill Sheet Three

Use the data below to complete an IWCF Surface BOP Stack (Vertical Well) Kill Sheet API Units and then answer the questions on the following pages: Well data: Bit size 12 1/ 4 in Hole depth from RKB (MD) 9950 ft Hole depth from RKB (TVD) 7800 ft Casing shoe depth - 13 3/ 8 in OD (MD) 5910 ft 3 Casing shoe depth - 13 / 8 in OD (TVD) 5780 ft Internal capacities: Drill pipe - 5 in OD 0.01887 bbl/ft Heavy wall drill pipe 5 in OD length 835 ft 0.0087 bbl/ft Drill collars size 8 1/ 2 in OD length 550 ft 0.0061 bbl/ft Annulus capacities between: Drill collars x open hole 0.0756 bbl/ft Drill pipe/HWDP x open hole 0.1215 bbl/ft Drill pipe/HWDP x casing 0.1279 bbl/ft Mud pump data: Displacement at 97% volumetric efficiency 0.117 bbl/stroke Circulating pressure at 30 SPM 520 psi Circulating pressure while drilling at 85 SPM 3125 psi APL while drilling 230 psi Other relevant information: Active system surface volume 270 bbl Surface line volume 8 bbl Formation strength test data: Surface leak off test pressure 1950 psi Mud weight used at leak off test 10.2 ppg Kick data: SIDPP 570 psi SICP 720 psi Mud weight in use at time of kick 11.2 ppg Pit gain 20 bbl

3

Surface Stack Kill Sheet Three

ANSWER THE FOLLOWING QUESTIONS Q1)

What is the maximum allowable mud weight based on the leak off test data?

16.6 Q2)

What is the maximum allowable annular surface pressure (MAASP) with the well shut in and the pressures stable?

1,623 Q3)

Q6)

Q7)

psi

Calculate the formation pressure based on the shut in data.

5,113 Q5)

psi

What is the safety margin at the shoe with the well shut in?

903 Q4)

ppg

psi

What kill mud is required to balance formation pressure?

12.7

ppg

1,540

stk

466

bbl

How many strokes to get kill mud from pump to bit?

What is the volume of the open hole?

4

Surface Stack Kill Sheet Three Q8)

What is the total annulus volume with the well closed in? 1,221 bbls

Q9)

What will the Initial Circulating Pressure (ICP) be at 30 spm?

1,090

psi

Q10) What will the Final Circulating Pressure (FCP) be at 30 spm?

590

psi

Q11) After reaching FCP it is decided to increase the pump speed to 40 spm. What would happen to BHP if the choke operator holds casing pressure constant at what ever it is reading at the time as the pump speed is increased. a) b) c)

Increase Decrease Remain constant

Q12) How many strokes to go from ICP to FCP? 1,472 stks Q13) What would the new MAASP be once the well has been killed?

1,172

psi

Q14) What would be the pressure step down per 100 strokes of kill mud pumped down the drill string? 34 psi /100 stks

5

Surface Stack Kill Sheet Three

Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771 Dubai United Arab Emirates [email protected] www.maersktraining.com

6

Day 4: Exercises Instructor's Copy

Classified as General

Day 4: exercises

Blank Page

IWCF combined surface & subsea student book L3/4 Classified as General

3

Day 4: exercises

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2

2

New Ad-Hoc Topics Instructor's Copy

IWCF combined surface & subsea student book L3/4 Classified as General

4

Day 4: exercises

Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for the use for course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training.

Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

IWCF combined surface & subsea student book L3/4 Classified as General

5

Day 4: exercises

Q1)

A well is to be killed using the Wait & Weight method at 40 spm with a surface stack BOP. Using the well data below answer the following questions. TVD Current mud weight SCR @ 40 spm SIDPP Surface to bit strokes

11,780 ft 12.3 ppg 460 psi 680 psi 1,962 stk

a)

What is the required kill mud weight?

b)

What is ICP @ 40 spm?

c)

What is FCP @ 40 spm?

d)

What is the pressure step down psi/100 stk?

e)

You are following the pressure reduction schedule as kill mud is pumped to the bit. After 850 strokes of kill mud have been pumped you realise that at the current pump speed you will exceed the working parameters of the mud gas separator when the gas reaches surface. You slow the pump speed down to 30 spm while holding casing pressure constant. What will your new circulating pressure be once the pump speed change has been made correctly?

13.5

ppg

1140

psi

505

psi

32

psi/100 stk

653 - 660

Psi

Q2)

Which of the following best describes a trip drill? a) b) c) d)

While tripping, the driller will shout blowout and the rig floor crew must stab the full opening safety valve While drilling, mud will be transferred from the reserve pit to the active pit without telling the derrickman While drilling, mud from the trip tank will be returned to the active pit via the shakers without telling the derrickman While tripping, the trip tank contents will be returned to the active pit via the shakers without telling the driller

IWCF combined surface & subsea student book L3/4 Classified as General

6

Day 4: exercises

Q3)

Checklists can help you manage well control situations. Choose three things from the following list that you should consider having on a well control checklist if you are about to run casing? (Choose three answers) a) b) c) d) e) f)

Q4)

Checklists can help you manage well control situations. Choose three things from the following list that you should consider having on a well control checklist if you are about to trip out the hole for a bit change? (Choose three answers) a) b) c) d) e) f)

Q5)

That the driller knows the correct running speeds to prevent surging That breaks have been planned in advance to allow reliefs to know when they take over That the casing tong does not obstruct the driller’s view of the choke manifold That you know when the self-filling float should convert and how to confirm it has That the crown-o-matic has been disabled to allow you to pick up the kill stand That pits identified for returns and hole fill have operational monitoring devices

That power is assigned to the draw-works and rotary table That a trip sheet is ready and has displacement details That the first ten stands are pulled before hole fill is checked That the pipe wiper is ready to be dropped once the slug is pumped That the rig floor safety valves are on the rig floor, open and operational That the trip tank is lined up and circulating over the well

You are circulating a gas influx to surface during a well kill operation. The influx is still in open hole and surface casing pressure is approaching MAASP. What could you do to help prevent losses? (Choose two answers) a) b) c) d) e)

Reduce the mud weight being circulated to below maximum mud weight Reduce the kill rate pump speed while maintaining bottom hole pressure constant Open the choke to keep surface casing pressure below MAASP Bleed off any safety margin you are holding at surface Shut the kill operation down then bullhead the influx back down the well

IWCF combined surface & subsea student book L3/4 Classified as General

7

Day 4: exercises

Q6)

What can you do to reduce the risk of surging when running casing? a) b) c) d)

Q7)

How would you recognise if a self filling float had converted while running casing? a) b) c) d)

Q8)

Displacement volumes would decrease from closed end to steel displacement Displacement volumes would increase to casing closed end displacement There is no way of telling until the bottom plug bumps during the cement job Drop a heavy barite ball down the casing and time for the splash

When circulating out a kick the pop-off valve (pressure relief valve) opened on the pump. What is the first action you should take? a)

Close the well in.

b)

Activate the diverter.

c)

Call the mechanic and tell him to repair the valve as soon as possible. Change over to pump no 2.

d)

Q9)

Reduce the time between connections Reduce the casing fill time Use a self filling float in the casing string Reduce the trip tank pump speed

The Driller is circulating out a kick and the mud hose (rotary hose) that connects the top drive to the stand pipe manifold started leaking. What first action should be taken? a) Stop the pump. Close the upper IBOP on the top drive and close the choke. b) Close the choke. c) Close the well in on the shear rams (located just below the annular preventer).

IWCF combined surface & subsea student book L3/4 Classified as General

8

Day 4: exercises

Q10) During a trip out of the hole the Driller stops the operation, places a tooljoint just above the slips while shouting "Blowout" to the roughnecks. What should the roughnecks do as their first reaction? a) b)

Install the Inside Blowout Preventer. Install the fully opened Drill Pipe Safety Valve. Then close it.

c) d)

Call the Assistant Driller. Run to a safe place until the danger is over.

Q11) The Drillers Method is going to be used to kill a well. procedure is correct to follow on the first circulation? a) b) c)

Displace the annulus to original drilling fluid density maintaining constant casing pressure. Displace the annulus to original drilling fluid density following a precalculated drill pipe pressure schedule. Displace the annulus to original drilling fluid density maintaining the Initial Circulating Pressure (ICP).

Q12) The Drillers Method is going to be used to kill a well. procedure is correct to follow on the second circulation? a) b) c)

Which

Which

Displace the drill string to kill fluid density while maintaining constant casing pressure. Then displace the annulus to kill fluid density maintaining constant drill pipe pressure. Displace the drill string and annulus to kill fluid density while maintaining constant casing pressure. Displace the drill string and annulus to kill fluid density while maintaining the Initial Circulating Pressure.

Q13) Select the one situation below when you could not use the Volumetric Method of well control. a)

No gas migration takes place.

b)

Wash out in the string is confirmed.

c)

Closed-in pressure increasing due to gas migration.

d)

No drill string in the well.

Q14) When should MAASP be re-calculated? a) b) c) d)

After each bit change After a change in mud weight After every 500 foot interval is drilled At the start of each shift

IWCF combined surface & subsea student book L3/4 Classified as General

9

Day 4: exercises

Q15) After a round trip at 8960 feet with 10.9 ppg mud we kick the pump in and start circulating. An increase in flow is noticed and the well is shut-in with 0 psi on the drill pipe and 300 psi on the casing. What is the required mud weight to kill the well? (there is no float in the drill string) a) b) c) d)

Pump slowly into the well until casing pressure starts to increase and use the drillpipe value at this time to work out kill mud weight 11.5 ppg 10.9 ppg 12.0 ppg

Q16) What was the most probable cause of the influx in the last question? a) b) c) d)

Abnormal formation pressure The original mud weight was not high enough to provide primary well control against formation pressure The well was swabbed in or the hole was not adequately filled during the trip It’s impossible to tell based on the information given

Q17) Which of the following would be more difficult to detect? a) b)

A gas kick in oil-based mud A gas kick in water-based mud

Q18) Why is it important to monitor the pit volume during a well control operation? (Two answers required) a) b) c) d) e)

To check for mud losses Tells you when to adjust drill pipe pressure To monitor the gas expansion To maintain bottom hole pressure constant Tells you when to adjust pump speed

IWCF combined surface & subsea student book L3/4 Classified as General

10

Day 4: exercises

Q19) While drilling ahead you experience a sudden loss of returns at surface. The well is top filled down the annulus with sea water until returns are re-established at which point the well is on balance. Use the data below to calculate what volume of sea water was pumped into the annulus to recover returns. TVD Mud weight in use Formation pressure @ TVD Sea water gradient Drill collar - open hole annular capacity Drill pipe - cased hole annular capacity

11,500 ft 12.3 ppg 7,000 psi 0.456 psi/ft 0.03 bbl/ft 0.0505 bbl/ft

97

bbl

Q20) Which of the following are needed for the calculation of accurate formation strength at the shoe? (choose three answers) a) b) c) d) e) f)

Accurate pressure gauge Accurate stroke counter Accurate hole capacity Exact vertical depth of casing shoe Installation of retrievable packer approximately 1000 feet below the rig floor Constant mud weight around the well

Q21) The well is shut in on a kick. You cannot start the kill operation and the gas is migrating. Which pressure should be held constant to maintain the correct bottom hole pressure? (assume no safety margin or working pressure is required) a) b) c) d)

Casing pressure Fracture pressure Drill pipe pressure Leak off test pressure

IWCF combined surface & subsea student book L3/4 Classified as General

11

Day 4: exercises

Q22) The well is shut in on a kick. Gas is migrating and no action is taken. What happens to bottom hole pressure? a) b) c)

Stays the same. Increases Decreases

Q23) A gas bubble enters the well bore, the well is not shut in and the gas migrates. What will happen to the gas bubble pressure? a) b) c)

Increase Stay the same Decrease

Q24) A gas bubble enters the well bore, the well is shut in and the gas migrates. What will happen to the casing shoe pressure? a) b) c)

Increase Stay the same Decrease

Q25) How many pump strokes are required for the Wait & Weight Method? a) b) c) d)

String volume strokes Annulus plus string volume strokes Bottoms up strokes Two full circulations

Q26) What is the minimum number of strokes in the First Circulation of the Drillers Method? a) b) c) d)

Drill string volume Drill string volume plus annulus volume Surface line volume plus drill string volume plus annulus volume Annulus Volume

Q27) What is the minimum number of strokes in the Second Circulation of the Drillers Method? a) b) c) d)

Drill string volume Annulus volume Pit volume plus drill string volume plus annulus volume Drill string volume plus annulus volume

IWCF combined surface & subsea student book L3/4 Classified as General

12

Day 4: exercises

Q28) What is the main purpose of the choke in the overall BOP system? a) b) c) d)

To divert drilling fluid through the mud/gas separator and back to the mud pits To control the correct back pressure while circulating out an influx To close in the well softly when the annular BOP is being used To close in the well in softly when a ram BOP is being used

Q29) The ratio of storage space for a fluid and gases to the bulk volume of a rock is called: a) b) c) d)

Permeability Porosity Sedimentation Hydrocarbons

Q30) How easily a fluid will flow through the rock is called: a) b) c) d)

Permeability Porosity Free flow Sedimentation

Q31) Define MAASP: a) b) c) d)

Pressure in excess of mud hydrostatic that, if exceeded, is likely to cause losses at the casing shoe Total pressure applied at the shoe that will cause losses Maximum BHP allowed on the drill pipe during a kill operation Maximum pressure allowed on the drill pipe during a kill operation

Q32) Use the following data to answer the questions below. Well depth 8935’ (TVD/MD) Mud weight in use 11.3 ppg Annular Pressure Loss @ 80 SPM 110 psi a) What is the ECD while circulating on bottom @ 80 SPM? 11.53 ________________ppg b)

What is bottom hole circulating pressure? 5360 _______________psi

IWCF combined surface & subsea student book L3/4 Classified as General

13

Day 4: exercises

Q33) If casing pressure is allowed to increase above MAASP during a kill operation, will it cause the casing shoe to break down? a) b) c)

Yes, it will always break the shoe down It depends on the size of the influx It depends on the position of the influx in the well bore

Q34) What is the definition of Kick tolerance? a) b) c) d)

Determine maximum volume of kick that can be initially taken Determine maximum kick size that can be circulated out without breaking down the formation Determine maximum volume of influx that can safely be taken in and circulated out without breaking down the formation Determine how much gas can be circulated through the mud gas separator at a chosen kill rate without blowing the liquid mud seal

Q35)A well is shut in with the bit 500’ off bottom and the top of the influx is calculated to be 200’ below the bit. SIDPP is 250 psi. What do you think SICP would be? Note: No float in string. a) Higher than SIDPP b) The same as SIDPP c) Lower than SIDPP Q36) What affects Shut In Casing Pressure? (Three answers) a) b) c) d) e) f)

Formation permeability Time for pressures to stabilise SCR at kill rate Kill Mud Weight Influx volume SIDPP

Q37) What will happen to bottom hole pressure during a kill operation if drill pipe pressure is held constant as the pump speed is increased? a) It increases b) It decreases c) It is maintained

IWCF combined surface & subsea student book L3/4 Classified as General

14

Day 4: exercises

Q38)

Which of the following is commonly used to prevent hydrate formation? (Choose two answers.) a) b) c) d)

Q39)

On a surface stack, kill rate is 35 SPM. Pump Pressure = 700 and Casing Pressure = 1000. Pump speed is decreased to 25 SPM holding 1000 psi on Casing. How will this affect bottom hole pressure (ignore any ECD effect). a) b) c)

Q40)

Methanol Glycol Diesel Nitrogen

Decrease Stay the same Increase

Gas cutting of mud can be prevented by having a mud weight that gives a high overbalance. True

Q41)

/

When circulating at 35 SPM, the stand pipe pressure is 800 psi. If the pump was increased to 60 SPM, what would the new stand pipe pressure be? a) b) c) d)

2351 psi 1372 psi 467 psi 272 psi

IWCF combined surface & subsea student book L3/4 Classified as General

False

15

Day 4: exercises

Q42)

Referring to the above stack arrangement answer the following questions: a)

With the blind rams closed. Could the well be bull-headed? Y / N

b)

With blind rams closed could the Drillers’ Method be used to remove an influx? Y/N

c)

Due to a damaged gasket there is a leak at the spool. If the well was shut-in with no pipe in the hole could pressure be contained? Y/N

d)

Could ram-to-ram stripping be carried out, maintaining constant bottom hole pressure? Y/N

e)

With Pipe in the hole could the blind rams be changed to pipe rams? Y/N

IWCF combined surface & subsea student book L3/4 Classified as General

16

Day 4: exercises

Q43) What is the main reason why you conduct a trip drill when pulling out of the hole? a) b) c) d)

To give you time to safely grease the travelling block from a riding belt To give you time to check the pipe tally and hole fill volume To give the drill floor crew a chance to practice for taking a kick while tripping To allow you to time how long it takes to shut the well in

Q44) Why do you kill a well at a slow pump rate? (Choose three answers) a) b) c) d) e) f) g)

To minimize the extra pressure applied to the bottom of the hole during the circulation To allow the drill crew time to take breaks as the circulation is taking place To ensure the mud/gas separator vent line and dip tube can handle the anticipated volume of gas at surface To allow the company man time to amend the plan as the kill is progressing To allow you time to work out the kill sheet, draw a graph and have it approved by your supervisor To give the choke operator time to think about what is happening before making choke adjustments To ensure the job is done properly and with the least cost

Q45) Which of the following best describes a pit drill? a) b) c) d)

While drilling, mud from the trip tank will be returned to the active pit via the shakers without telling the derrickman While drilling, mud will be transferred from the reserve pit to the active pit without telling the derrickman While tripping, the driller will shout blowout and the rig floor crew must stab the full opening safety valve While tripping, the trip tank contents will be returned to the active pit via the shakers without telling the driller

IWCF combined surface & subsea student book L3/4 Classified as General

17

Day 4: exercises

Q46) What steps can be taken to prevent over regulation of the drilling industry by governments? a) b) c) d)

Conducting consistent and uniform training for all personnel with well control responsibilities no matter how small Ensuring all paper work is in place and has been crosschecked by the QA department in the main office Using drilling rigs with a greater capability than required for the job to demonstrate that the well will be drilled safely Having a crew compliment made up of international senior personnel and a high percentage of locally based personnel

Q47) The drilling plan has been drawn up using offset data from previous wells. What could be the implication if the plan is followed to the letter? a) b) c) d)

The plan is only there to help the drilling engineer. The driller should not refer to the plan except for BHA components Drilling will progress smoothly and quickly. By following the plan the section will be drilled ahead of time and under budget Formation and fracture pressures may not be as per the plan. This may result in too little or too much pressure being applied to the well The plan is usually very technical and confusing. By following the plan there is an increased chance of problems while drilling

Q48) What are the only two ways you can lose primary well control if you have it? a) b) c) d)

Either formation pressure goes up or the hole is not monitored Either formation pressure goes up or APL is lost Either hydrostatic pressure is lost or fracture pressure decreases Either hydrostatic pressure goes down or formation pressure goes up

IWCF combined surface & subsea student book L3/4 Classified as General

18

Day 4: exercises

Q49) Which of the following are causes of abnormal formation pressure? (Choose three answers) a) b) c) d) e) f)

Faulted formations moving upwards Gas migrating up the well Excess annular pressure losses Gas gaps Leaks around casing strings Wash down operations on the rig floor

Q50) Which of the following best describes fracture pressure? a) b) c) d)

Fracture pressure is the pressure applied at surface, which will cause the formation at the shoe to break down Fracture pressure is the pressure applied to the formation at the shoe by the column of mud in the well Fracture pressure is the maximum pressure that can be applied to the formation at the shoe before it breaks down Fracture pressure is the pressure applied to the formation at the bottom of the well by the column of mud in the well

IWCF combined surface & subsea student book L3/4 Classified as General

19

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2 Instructor's Copy

Subsea Stack Kill Sheet Four

2

Subsea Stack Kill Sheet Four Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for use on a course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training. Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

2

Subsea Stack Kill Sheet Four

Use the data below to complete an IWCF Subsea BOP Stack (Vertical Well) Kill Sheet API Units and then answer the questions on the following pages: Well data: Bit size Hole depth from RKB (MD) Hole depth from RKB (TVD) Casing shoe depth - 9 5/ 8 in OD (MD) Casing shoe depth - 9 5/ 8 in OD (TVD) Internal capacities: Drill pipe - 5 in OD Heavy wall drill pipe 5 in OD length 1035 ft Drill collars size 6 1/ 2 in OD length 940 ft Choke line length 1720 ft Marine riser Annulus capacities between: Drill collars x open hole Drill pipe/HWDP x open hole Drill pipe/HWDP x casing Drill pipe x marine riser Mud pump data: Displacement at 97% volumetric efficiency Circulating pressure through riser at 40 SPM with 12.4ppg Choke line friction at 40 SPM with 11 ppg mud Circulating pressure while drilling at 75 SPM APL while drilling Other relevant information: Active system surface volume Surface line volume Sea water depth Air gap Sea water gradient Formation strength test data: Surface leak off test pressure Mud weight used at leak off test Kick data: SIDPP SICP Mud weight in use at time of kick Pit gain

3

8 1/ 2 16500 15700 14200 14000

in ft ft ft ft

0.01776 0.0088 0.008 0.0087 0.36

bbl/ft bbl/ft bbl/ft bbl/ft bbl/ft

0.0292 0.0459 0.0489 0.336

bbl/ft bbl/ft bbl/ft bbl/ft

0.117 980 500 3500 270

bbl/stroke psi psi psi psi

250 9 1620 80 0.453

bbl bbl ft ft psi/ft

3650 psi 11 ppg 700 1150 12.4 30

psi psi ppg bbl

Subsea Stack Kill Sheet Four

ANSWER THE FOLLOWING QUESTIONS Q1)

What is the maximum allowable mud weight based on the leak off test data?

16 Q2)

What is the maximum allowable annular surface pressure (MAASP) with the well shut in and the pressures stable?

2620 Q3)

psi

What is the safety margin at the shoe with the well shut in?

1470 Q4)

ppg

psi

Calculate the formation pressure based on the shut in data.

10,823 psi Q5)

Q6)

Q7)

What kill mud is required to balance formation pressure?

13.3

ppg

2424

stk

90

bbl

How many strokes to get kill mud from pump to bit?

What is the volume of the open hole?

4

Subsea Stack Kill Sheet Four Q8)

What is the total annulus volume with the well closed in?

716.2 Q9)

bbls

What will the Initial Circulating Pressure (ICP) be at 40 spm?

1680

psi

Q10) What will the Final Circulating Pressure (FCP) be at 40 spm?

1051

psi

Q11) After reaching FCP it is decided to decrease the pump speed to 30 spm. What will the new FCP be if bottom hole pressure is held constant as the pump speed is reduced?

591

psi

2347

stks

Q12) How many strokes to go from ICP to FCP?

Q13) What would the new MAASP be once the well has been killed?

1965

psi

Q14) What would be the pressure step down per 100 strokes of kill mud pumped down the drill string?

27

5

psi /100 stks

Subsea Stack Kill Sheet Four Q15) What will be the initial dynamic casing pressure at kill rate?

650

psi

Q16) What will dynamic MAASP be at the start of a Drillers Method Kill?

2056

psi

Q17) Assuming that kill mud weight balances formation pressure, what mud weight would be needed in the well after the kill to compensate for any loss in hydrostatic pressure if the riser was accidentally disconnected?

14

ppg

Q18) What will FCP be with kill mud back at surface and the choke fully open if the well was killed at 40 SPM with no change of pump speed during the kill?

1655

6

psi

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2

2

Instructor's Copy

Deviated Gauge Questions Surface LEVEL 4 ONLY Classified as General

Surface Deviated Gauge Questions Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for use on a course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training. Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

-1Classified as General

Surface Deviated Gauge Questions

Use the completed IWCF Surface BOP Stack (Deviated Well) Kill Sheet API Units to answer the following questions. All questions run sequentially. The well will be killed using the Wait & Weight Method at 30 spm. Following the normal IWCF standards there will be no tolerance below the expected/calculated pressure and up to 69 psi above. Q1 Data: Drillpipe Pressure:

Casing Pressure: 895 psi

Pump Speed: 30 spm

Strokes Pumped: 100 stk

Time: 3 mins

Choke Position: 38% open

The start up went well and then both the stroke counter and time were reset to zero when kill mud reached the rig floor. What should the drill pipe pressure gauge be reading after 100 strokes have been pumped?

1392

psi

Q2) Data: Drillpipe Pressure: 1175 psi

Casing Pressure: 895 psi

Pump Speed: 30 spm

Strokes Pumped: 300 stk

Time: 10 mins

Choke Position: 38% open

This is what you see. What should you do? a) b) c) d)

Pressure is too high - open the choke to bring it down. Pressure is too low - close the choke to bring it up. The kill is going well - continue. There is no way to tell - shut down and re-evaluate the pressures.

-2Classified as General

Surface Deviated Gauge Questions

Q3) Data: Drillpipe Pressure: 1175 psi

Casing Pressure: 895 psi

Pump Speed: 30 spm

Strokes Pumped: 300 stk

Time: 10 mins

Choke Position: 38% open

The kill has to be shut down because of a mud supply problem. What will the drillpipe pressure gauge read if 895 psi is held constant on the casing gauge as the kill is shut down?

521 Q4) Data: Drillpipe Pressure: 1075 psi

Casing Pressure: 895 psi

Pump Speed: 30 spm

Strokes Pumped: 450 stk

Time: 15 mins

Choke Position: 38% open

How is the kill going? a) b) c) d)

Pressure is too high - open the choke. Pressure is too low - close the choke. Pressure is a little high - but within what is allowed. There is no way to tell.

-3Classified as General

psi

Surface Deviated Gauge Questions

Q5) Data: Drillpipe Pressure: 970 psi

Casing Pressure: 900 psi

Pump Speed: 30 spm

Strokes Pumped: 600 stk

Time: 20 mins

Choke Position: 38% open

Someone has pointed out that casing pressure has not changed since the kill started. What is happening? a) b) c) d)

The casing gauge must be faulty - shut down and fix it. The kick is in the horizontal section - continue the pressure is correct. Casing pressure is too low - close the choke to bring it up. Drillpipe pressure is too high - open the choke to bring it down.

Q6) Data: Drillpipe Pressure: 920 psi

Casing Pressure: 890 psi

Pump Speed: 30 spm

Strokes Pumped: 650 stk

Time: 22 mins

Choke Position: 40% open

How is the kill going? a) b) c) d)

The kill is going well - continue. Correct the pump speed. Pressure is too low - close the choke to bring it up. Pressure is too high - open the choke to bring it down.

-4Classified as General

Surface Deviated Gauge Questions Q7) Data: Drillpipe Pressure:

Casing Pressure: 900 psi

Pump Speed: 30 spm

Strokes Pumped: 800 stk

Time: 27 mins

Choke Position: 38% open

The kill is going correctly. What should the drill pipe pressure gauge be reading?

820

psi

Q8) Data: Drillpipe Pressure:

Casing Pressure: 900 psi

Pump Speed: 30 spm

Strokes Pumped: 800 stk

Time: 27 mins

Choke Position: 38% open

The kill is going correctly. What should the drill pipe pressure gauge read if the kill is shut down while holding casing pressure constant at 900 psi?

117

-5Classified as General

psi

Surface Deviated Gauge Questions

Q9) Data: Drillpipe Pressure: 820 psi

Casing Pressure: 925 psi

Pump Speed: 30 spm

Strokes Pumped: 1000 stk

Time: 33 mins

Choke Position: 39% open

How is the kill going? a) b) c) d)

The kill is going well - continue. Correct the pump speed. Pressure is too low - close the choke to bring it up. Casing pressure is too high - open the choke to bring it down a bit.

Q10) Data: Drillpipe Pressure: 820 psi

Casing Pressure: 950 psi

Pump Speed: 30 spm

Strokes Pumped: 1750 stk

Time: 58 mins

Choke Position: 41% open

What should you do? a) b) c) d)

Open the choke to reduce casing pressure. Correct the pump speed. Shut down and see what the drillpipe gauge reads. The kill is going well - continue.

-6Classified as General

Surface Deviated Gauge Questions

Q11) Data: Drillpipe Pressure: 820 psi

Casing Pressure: 970 psi

Pump Speed: 30 spm

Strokes Pumped: 2000 stk

Time: 67 mins

Choke Position: 42% open

You have to shut down due to a mud supply problem. What will the drillpipe gauge read if casing pressure is held at 970 psi as the kill is shut down?

0

psi

Q12) Data: Drillpipe Pressure: 815 psi

Casing Pressure:

Pump Speed: 29 spm

Strokes Pumped: 5490 stk

Time: 183 mins

Choke Position: 35% open

Gas is venting at surface. The casing gauge is fluctuating wildly. How are things going? a) b) c) d)

The kill is going well - continue. Pressure is too low - close the choke to bring it up. Pressure is too high - open the choke to bring it down. Correct the pump speed.

-7Classified as General

Surface Deviated Gauge Questions

Q13) Data: Drillpipe Pressure: 915 psi

Casing Pressure: 675 psi

Pump Speed: 30 spm

Strokes Pumped: 6000 stk

Time: 200 mins

Choke Position: 37% open

Gas is out and original mud is now returning at surface. How is the kill going? a) b) c) d)

Pressure is too high - open the choke to bring it down. Pressure is too low - close the choke to bring it up. Shut down immediately casing pressure is wrong. The kill is going well - continue.

Q14) Data: Drillpipe Pressure: 825 psi

Casing Pressure: 5 psi

Pump Speed: 30 spm

Strokes Pumped: 7620 stk

Time: 254 mins

Choke Position: 100% open

What do you think of the current situation? a) b) c) d)

The choke indicator is faulty it should not be fully open. The casing gauge has failed it should not be reading almost zero. There is no way to tell how the kill is going until we shut in. The kill is going well - get ready to shut in.

-8Classified as General

Surface Deviated Gauge Questions

1545

10.9

10.4

.5668

16.86 2,000 2,000 5,400

1425

4,285

.12

9 5/8

.12

9,000 4,600

8 1/2

30

13,600

625

5,000

2000

.0178

35.6

297

3400

60.5

7870 180

.0178 .0178 .0087

140.1 1.6

504 1167

150

.0061

0.9

13,600

238.7

150

.0323

4.85

4450

.0459

204.25

1989

66.3

58

3863

129

672.6

5605

187

911.3

7594

253

.0515

463.5

-9Classified as General

8

1743

209.1 9000

13

Surface Deviated Gauge Questions

875

895

875 5,000

10.9

625

15

14.3

875

14.3 10.9

1500

625

820 625

875

14.3

654

10.9

14.3

702

1500

117

819

2000 13,600

654

521

521

1175

10.9x

820

625

5400 13,600

702

4285

117

117

819

1175

325

32 297

109.4

819

365

365 504

70.6

-1

-1 1188

820

- 10 Classified as General

625

2000

625

875

820

-.00084

Surface Deviated Gauge Questions

- 11 Classified as General

P = MW × 0.052 × TVD

P1 × V1 = P2 × V2

 N1  P2 = P1 ×    N 2 Instructor's Copy

Surface Stack Kill Sheet Four

2

Surface Stack Kill Sheet Four Manual standard clause This manual is the property of Maersk Training A/S (hereinafter Maersk Training) and is only for use on a course conducted by Maersk Training. This manual shall not affect the legal relationship or liability of Maersk Training with or to any third party and neither shall such third party be entitled to reply upon it. Maersk Training shall have no liability for technical or editorial errors or omissions in this manual; nor any damage, including but not limited to direct, punitive, incidental, or consequential damages resulting from or arising out of its use. No part of this manual may be reproduced in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, without the prior permission of Maersk Training. Copyright  Maersk Training A/S

2017-July

Prepared by

DJMC

Modified & printed

July 2017

Modified by

AMT

Approved by Address

E-mail:

DVY Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771, Dubai United Arab Emirates [email protected]

Homepage

www.maersktraining.com

2

Surface Stack Kill Sheet Four

Use the data below to complete an IWCF Surface BOP Stack (Vertical Well) Kill Sheet API Units and then answer the questions on the following pages: Well data: Bit size 8 1/ 2 in Hole depth from RKB (MD) 16500 ft Hole depth from RKB (TVD) 15700 ft Casing shoe depth - 9 5/ 8 in OD (MD) 14200 ft 5 Casing shoe depth - 9 / 8 in OD (TVD) 14000 ft Internal capacities: Drill pipe - 5 in OD 0.01776 bbl/ft Heavy wall drill pipe 5 in OD length 1035 ft 0.0088 bbl/ft Drill collars size 6 1/ 2 in OD length 940 ft 0.008 bbl/ft Annulus capacities between: Drill collars x open hole 0.0292 bbl/ft Drill pipe/HWDP x open hole 0.0459 bbl/ft Drill pipe/HWDP x casing 0.0489 bbl/ft Mud pump data: Displacement at 97% volumetric efficiency 0.117 bbl/stroke Circulating pressure at 40 SPM 980 psi Circulating pressure while drilling at 75 SPM 3500 psi APL while drilling 270 psi Other relevant information: Active system surface volume 250 bbl Surface line volume 9 bbl Formation strength test data: Surface leak off test pressure 3650 psi Mud weight used at leak off test 11 ppg Kick data: SIDPP 700 psi SICP 1150 psi Mud weight in use at time of kick 12.4 ppg Pit gain 30 bbl

3

Surface Stack Kill Sheet Four

ANSWER THE FOLLOWING QUESTIONS Q1)

What is the maximum allowable mud weight based on the leak off test data?

16 Q2)

What is the maximum allowable annular surface pressure (MAASP) with the well shut in and the pressures stable?

2620 Q3)

Q5)

Q6)

Q7)

psi

What is the safety margin at the shoe with the well shut in?

1470 Q4)

ppg

psi

Calculate the formation pressure based on the shut in data.

10823

psi

13.3

ppg

2424

stk

90

bbl

What kill mud is required to balance formation pressure?

How many strokes to get kill mud from pump to bit?

What is the volume of the open hole?

4

Surface Stack Kill Sheet Four Q8)

What is the total annulus volume with the well closed in?

784 Q9)

bbls

What will the Initial Circulating Pressure (ICP) be at 40 spm?

1680

psi

Q10) What will the Final Circulating Pressure (FCP) be at 40 spm?

1051

psi

Q11) After reaching FCP it is decided to decrease the pump speed to 30 spm. What will the new FCP be if bottom hole pressure is held constant as the pump speed is reduced?

591

psi

Q12) How many strokes to go from ICP to FCP?

2347

stks

Q13) What would the new MAASP be once the well has been killed?

1965

psi

Q14) What would be the pressure step down per 100 strokes of kill mud pumped down the drill string?

27

5

psi /100 stks

Surface Stack Kill Sheet Four

Maersk Training DWC-LLC 101 First Floor, Building A2 DWC Business Park, Dubai World Central PO Box 393771 Dubai United Arab Emirates [email protected] www.maersktraining.com

6

IWCF Well Control Practice Test Combined Surface & Subsea Stack

Principles & Procedures Time allowed - One hour 40 marks in total Each question is 1 point No marks for partially correct answers

your score

(

/40) x 100 =

Instructor NAME : _________________ DATE : ______________

1 of 12 Classified as General

%

Q1)

Why is a kick circulated out from the well bore at a slow pump rate? a) To keep excess pressure on the formation to a minimum. b) To reduce the jetting action of the bit. c) To increase the amount of overbalance on the formation to make the kill safer. d) To prevent any gas expanding as it migrates up the well bore.

Q2)

Which of the following increases the chances of swabbing on a trip out the hole? a) b) c) d)

Q3)

While killing a well using a constant bottom hole pressure method, what will happen to the pressure at the casing shoe once the influx has been circulated inside the cased hole section? a) b) c) d)

Q4)

Large annular clearance between string & hole wall. Pulling pipe too fast. Thin mud. A large overbalance in your mud weight.

The pressure should decrease. The pressure should increase. The pressure should remain the same. There is not enough information to tell.

What will happen to the pit volume as a gas kick is circulated from bit to surface in a well containing water based drilling mud? a) Pit volume will decrease. b) Pit volume will remain constant. c) Pit volume will increase.

2 of 12 Classified as General

Q5)

Which of the following statements most accurately describes the Hard Shut In Method? a) With the remote choke closed for normal operations, open the HCR valves on the BOP stack and close the BOP. b) With the remote choke closed for normal operations, close the BOP and open the HCR valves on the BOP stack. c) With the remote choke open for normal operations, close the BOP, open the HCR valves on the BOP stack and close the remote choke. d) With the remote choke open for normal operations, open the HCR valves on the BOP stack, close the BOP and close the remote choke.

Q6) When should you consider re-taking your slow pump rate pressure losses? (4 answers required) a) b) c) d) e) f) Q7)

If practical at the beginning of every tour. Immediately before tripping in the hole. After major repairs or alterations to the rig pumps. After a change in mud weight. While slipping & cutting the drilling line. At least every 500 ft of new hole drilled.

If Gas Migration is taking place in a shut in well (no float in the string) you are likely to see both SIDPP & SICP increase by approximately the same amount True

Q8)

/

False

A leak off test was performed with 9.8 ppg test mud weight at a casing shoe set at 5,370 ft M.D. / 5,245 ft T.V.D. Surface Leak Off Pressure at the test was 1350 psi. What pressure was actually applied to the casing shoe? a) b) c) d)

4086 psi 4022 psi 1350 psi 5359 psi

3 of 12 Classified as General

Q9)

Which of the following is an indication that the well may be flowing while you are drilling? a) Reduced ROP combined with an increase in cuttings recovered at surface. b) A reduction in drill pipe pressure combined with a reduction in torque. c) An increase in hook load combined with a reduction in connection time. d) An increase in return flow combined with a decrease in pump pressure.

Q10) From the following list place the statements in the order that best describes the Drillers Method of Well Control – Surface Stack (7 answer) a) Casing pressure will reduce as kill mud is circulated to the bit. b) At the start of the first circulation the pump is brought up to kill rate speed while holding casing pressure constant. c) Kill Mud is pumped to the bit while following a calculated drill pipe pressure drop schedule. d) Drill pipe pressure is maintained constant as the influx is circulated from the well. e) Casing pressure will remain constant as a gas influx is circulated from the well. f) At the start of the second circulation casing pressure is held constant while the pump is brought up to kill rate speed. g) Drill pipe pressure is held constant as kill mud is pumped up the annulus to surface. h) At the end of the first circulation and with the well shut in both SIDPP & SICP should read the same. i) With the well shut in and kill mud at surface both SIDPP & SICP should read zero. j) With kill mud back at surface your casing pressure gauge will read FCP.

1

B

, 2

D

, 3 H

, 4 F

5

C

, 6

G

, 7 I

,

4 of 12 Classified as General

,

Q11) Which factor most influences the rate at which shut in pressures will stabilise after a well has been closed in on a kick? a) b) c) d)

Permeability. Friction Losses in the Annulus. Gas Migration. Type of Influx.

Q12) How often should MAASP be re-calculated? a) b) c) d)

After a change in mud weight. After a bit change. After circulating bottoms up on a trip. After every 1000 ft of new hole drilled.

Q13) During a kill operation you decide to hold drill pipe pressure constant as kill mud is circulated from surface to bit. What will happen to bottom hole pressure as a result of your actions? a) b) c) d)

Bottom hole pressure will decrease. Bottom hole pressure will remain constant. Bottom hole pressure will increase. There is not enough information to tell.

Q14) From the following information calculate the approximate reduction in bottom hole pressure if the first 30 stands are pulled dry from the well with no fill up? Mud weight in use Drill pipe capacity Drill pipe metal displacement Casing capacity Average stand length

11.2 ppg 0.01776 bbls/ft 0.00764 bbls/ft 0.0732 bbls/ft 93 ft 189 psi F#19

Q15) The Drillers Method of well control will always give you higher casing shoe pressures than the Wait & Weight method. True

/

False

5 of 12 Classified as General

Q16) You have shut a well in on a kick with a float in the string. How can you establish SIDPP? a) Read it off the gauge – whatever is showing is SIDPP. b) Pump slowly down the string and watch for an increase in SICP – whatever the drillpipe gauge is reading at this time will be SIDPP. c) You do not need SIDPP – simply increase your mud weight by 0.5ppg per 5,000ft of well TVD and use this as kill mud weight. d) SICP minus 150 psi. Q17) The fracture gradient at the shoe (3680 ft TVD) is 0.618 psi/ft. The mud weight currently in use is 9.8 ppg. Approximately what is the current MAASP? a) b) c) d)

326 psi 398 psi 405 psi 415 psi

Q18) From the following list place the statements in the order that best describes the Wait & Weight Method – Surface Stack (4 Answers) a) The pump is brought up to kill rate speed while holding casing pressure constant. b) Kill Mud is pumped to the bit while following a calculated drill pipe pressure drop schedule. c) Drill pipe pressure is maintained constant as the influx is circulated from the well. d) Casing pressure will remain constant as a gas influx is circulated from the well. e) Drill pipe pressure is held constant as kill mud is pumped up the annulus to surface. f) With the well shut in and kill mud at surface both SIDPP & SICP should read zero. g) With kill mud back at surface your casing pressure gauge will read FCP.

1

A

, 2

B

, 3

6 of 12 Classified as General

E

, 4

F

,

Q19) In a deviated well, casing pressure will remain constant until the gas enters the build section when it will begin to rise. True

/

False

Q20) On a trip out the hole for a bit change the trip tank level falls from 50 bbls to 43 bbls as the first ten stands are pulled wet from the hole. Due to problems with the mud bucket there were no returns from it to the trip tank. The planned flow check at ten stands indicates no flow. Based on the following well data choose your next action. Well TVD Mud weight in use Drill pipe capacity Drill Pipe metal displacement Average stand length

12,565 ft 13.4 ppg 0.01776 bbls/ft 0.00764 bbls/ft 92 ft

a) Continue with the trip everything is OK. b) Flow check for another fifteen minutes and if still no flow continue with the trip. c) Run immediately & cautiously back to bottom and circulate bottoms up. d) Circulated bottoms up at your current bit depth then continue with the trip. Q21) From the following well data calculate the number of stands that can be pulled dry from the hole, without fill up, before the well starts to flow. Well depth Current mud weight Formation pressure gradient Casing capacity Drill pipe capacity Drill pipe metal displacement Average stand length a) b) c) d)

36 stands 37 stands 38 stands 39 stands

F#23

7 of 12 Classified as General

8,880 MD/ 8,450 TVD 9.8 ppg 0.498 psi/ft 0.1521 bbls/ft 0.01725 bbls/ft 0.008 bbls/ft 93 ft

Q22) A gas kick is easier to detect in oil based mud than it is in water based mud. True

/

False

Q23) Slowly but regularly during a kill operation the choke operator has had to close the choke in to maintain the correct pressure reading on the drill pipe pressure gauge. From the list below what has probably been the cause of this? (2 answers) a) The gas is expanding as it is circulated up the annulus and his actions are as expected. b) The choke may be washing out. c) The annulus is plugging up. d) The kill pump is developing a leak. e) The kill mud is starting to reduce the circulating pressure. Q24) Mud hydrostatic can be reduced by: a) b) c) d) e)

Reducing the mud weight. Reducing the height of the column of mud. Gas cut mud. All of the above. None of the above.

Q25) Prior to pulling out the hole a 13.6 ppg slug is pumped and the mud level in the drill string falls some 130 ft. If the original mud weight was 12.4 ppg what has been the drop in bottom hole pressure? a) b) c) d)

92 psi 84 psi 10 psi 0 psi

8 of 12 Classified as General

Q26) Which of the following statements are good operating practice in TOP HOLE that has a high risk of gas bearing formations? (Choose two answers) a) Pump out of the hole on trips. b) Control ROP. c) Maintain high rate of penetration to ensure mud viscosity level is as high as possible. d) Regularly pump fresh water pill to clean cuttings from hole. e) Use a high density mud to create maximum overbalance. Q27) What happens to the pressure on the casing shoe while the gas influx is passing from the open hole into the casing? (BHP is being held constant) a) Increases b) Decreases c) Stays the same Q28) If the Driller pulls all 500 ft of 8” OD x 2 13/16” ID drill collars out of the hole dry, including the bit, without filling the hole, what will be the reduction in the bottom hole pressure? Mud weight Casing capacity Metal displacement

13.2 ppg 0.1545 bbl/ft 0.0545 bbl/ft

121 F#21 ___________________ psi Q29) In which situation is a gas kick more difficult to detect? a. b.

Gas kick in an oil based mud. Gas kick in a water based mud.

9 of 12 Classified as General

Q30) Under which circumstances would the Wait and Weight Method provide lower equivalent pressures at the casing shoe than the Driller's Method? a) When the drill string volume is greater than the annulus open hole volume. b) When the drill string volume is less than the annulus open hole volume. c) The pressures at the casing are the same regardless of the method used. Q31) When pulling out of the hole from the top of the reservoir swab pressures are calculated to be 100 psi. TVD Mud weight Formation pressure

7,954 ft 10.3 ppg 4,200 psi

Will the well flow? Yes

/

No

Q32) During top hole drilling from a jack-up rig. The well starts to flow due to shallow gas. What will be the safest actions to take to secure the safety of rig and personnel? (Choose two answers) a) Start pumping mud into the well at the highest possible rate. b) Shut-in the well and prepare for kill operations immediately. c) Activate the diverter system and remove non-essential personnel from the rig floor and hazardous areas. d) First line up the mud/gas separator then activate the diverter system and remove personnel from the rig floor. e) Activate the blind/shear rams to shut in the well.

10 of 12 Classified as General

Q33) A hydraulic delay exists between the time the choke is adjusted to the time the drill pipe pressure reacts. Approximately what is this delay? a) b) c) d)

Equal to the speed of sound. About 1 second per 300 meters of travel time. Always equal to 20 seconds. This is a myth, no hydraulic delay actually exists.

Q34) Why can pressure build up in the Mud Gas Separator while circulating out a kick be dangerous? a) Pressure build up will increase risk of lost circulation. b) Pressure build up will affect ability to make choke adjustments. c) Pressure build up may allow gas to be blown up the derrick vent line. d) Pressure build up may allow gas to enter shale shaker area. Q35) A light mud pill is circulated in the well. At what moment will the bottom hole pressure start to decrease? a) b) c) d)

As soon as the pill starts to be pumped into the drillstring. Once all the pill has been displaced into the annulus. Once the pill starts to be displaced into the annulus. Once all the pill is in the annulus.

Q36) Which three of the following options is an advantage for drilling top hole without a marine riser? a) b) c) d) e) f) g)

Pollution control. Avoid collapse of riser. Collection of formation samples while drilling. Time factor if moving off location is required. Minimise risk of gas at the rig. Formation pressure balance monitoring. Buoyancy effect on rig if shallow gas is encountered.

Q37) Which ones of the options can reduce friction losses in choke lines? (Select two answers.) a) Circulating through the choke line and the kill line at the same time. b) Reducing the pump stoke rate. c) Increasing the pump stoke rate. 11 of 12 Classified as General

Q38) On a floating rig a well is being killed by the Drillers Method. A piston swab on the pump washed out in the middle of the first circulation. Which one of the procedures are correct to use when the pump is being stopped and the bottom hole pressure is kept constant? a) Keep the casing pressure constant whilst reducing the pump rate to 0 SPM. b) Keep the drill pipe pressure constant whilst reducing the pump rate to zero SPM. c) Allow the casing pressure to decrease by the amount of choke line friction whilst reducing the pump rate to zero SPM. d) Allow the casing pressure to increase by the amount of choke line friction whilst reducing the pump rate to zero SPM.

Q39) The well is closed-in due to a kick on a floating drilling rig. The drill pipe pressure is 400 psi and the choke line pressure is 600 psi. The kill line pressure, however, reads 700 psi. Which two of the options give the possible reason for the different readings on the kill line- and choke line gauges? a) A partly blockage in the choke line. b) The hydraulic activated BOP side outlet valve for the kill line is not functioning correctly. c) The fluid in the kill line has a lower density than in the choke line. d) The fluid in the kill line has a higher density than in the choke line. e) The two gauges have not been calibrated properly.

Q40) A gas kick is being circulated out on a floating rig using the Wait & Weight method. At which of the following points will the circulation choke pressure change most rapidly? a) When kill weight mud enters the choke line. b) When the gas influx enters the choke line. c) When the gas influx reaches the casing shoe.

12 of 12 Classified as General

IWCF Well Control Practice Test Subsea Stack ONLY

Equipment Time allowed - One hour 32 marks in total Each question is 1 point No marks for partially correct answers

your score

(

/32) x 100 =

Instructor NAME : _________________ DATE : ______________

1 of 8

Classified as General

%

1)Which of the following hydraulic functions are activated by the manifold pressure on a drillship with an indirect hydraulic control system?5 ANSWERS a) Annular b) Ram’s c) Riser connector d) Wellhead connector e) Wedge locks f) Fail safe valves g) Mini collet connector h) Diverter 2) What is the maximum response time for a subsea annular preventer according to API? a) 30 seconds b) 45 seconds c) 60 seconds 3) Which of the following statements describe the function performed by the pilot fluid in the pod control hose? 3 ANSWERS a) Pilot fluid allow regulation of the subsea regulators inside the control pods. b) Pilot fluid are activated by the four way manipulator valves on the accumulator unit. c) Pilot fluid operate SPM valves which allow hydraulic fluid to flow to the relevant BOP functions. d) Pilot fluid are recharged by regulated manifold pressure. e) Pilot fluid have its own independent system that recharges the pressure to full operating pressure whilst in operation. f) Pilot fluid are operated by pilot pressure which is supplied by the accumulators. 4) What fluid functions the sub plate mounted valve (SPM) in the sub-sea BOP? a) Power fluid b) Pilot fluid c) Depending on what valve is used for Power or Pilot Fluid.

2 of 8

Classified as General

5) Power fluid through a SPM valve is? a) Un-regulated b) Regulated c) 3000psi. 6) What is the function of the “memory Button” found on the sub-sea BOP remote panels? a) To identify the correct position of the BOP’s if the remote panel lights fail. b) To identify which position a BOP was in prior to be before put in block. c) As a battery back up to identify what position the BOP’s are in. d) There is no a memory function, the driller has to remember what position the BOP’s are in. 7) Which of the following statements are correct? a) A manipulator valve is a 3 position 4 way valve that when activated allows power pressure to be directed to the relevant SPM valves in the control pods. b) A manipulator valve is a 3 position 4 way valve that when activated allows pilot pressure to be directed to the relevant SPM valves in the control pods. 8) When a BOP is put to the close position from the remote or central hydraulic control unit on a floating rig certain functions occur. What is the correct functions from the list below? a) A SPM valve fires in the active pod only. b) Both yellow and blue SPM valves fire as this assists with closing times. c) SPM valves fire in yellow and blue pods but only one pod is active at one time. d) The open function SPM valve or valves will be vented. e) The close function SPM valve or valves will be vented. 9) Sub-sea accumulators are usually pre-charged to? a) 1200 psi b) The same as surface accumulator bottles. c) Sea water hydrostatic pressure at BOP’s plus the same as surface accumulators. d) 3000 psi

3 of 8

Classified as General

10) What statement is true about Riser Fill Up Valves? a) The riser fill up valves are pressure sensitive and will automatically open when the pressure inside the riser drops 200-300psi below the ambient ocean pressure. b) The riser fill up valve can be remotely operated and reset through surface control lines. c) The riser fill up valves prevents the riser from collapse. d) All of the above are true. 11)Link the following automatic ram locking system to the BOP manufacturer. 2 a) MPL………………………………. b) Ultralock……………………….. 1 c) Poslock…………………………. 1 d) Wedgelock…………………….

3

1. Shaffer

2. Hydril

3. Cameron

4. Val-Con

12) What is the maximum response time for a subsea Ram BOP’s according to API? a) 30 seconds b) 45 seconds c) 60 seconds 13) When a Subsea BOP is placed in the block position, which ones of the following are correct? a) Pilot pressure is removed from the SPM valves. b) The SPM valves vent any pressure supplied to the BOP. c) The rams remain in the position that they were in prior to be putting in block. d) Block isolates a leak below the SPM valves. e) Power fluid is prevented from entering the BOP operating chambers. f) All of the above. 14) What is the maximum response time for a Subsea Shear Ram BOP’s according to API? a) 30 seconds b) 45 seconds c) 60 seconds

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Classified as General

15) Which of the following BOP ram locking systems require separate function to lock in place? a) Ultralock b) Poslock c) MPL d) Wedgelock e) ST-lock 16) Which of the following BOP ram locking systems is unique? a) Ultralock b) Poslock c) MPL d) Wedgelock e) ST-lock 17) Pilot pressure used to open a SPM Valve is regulated? a) At the surface control unit. b) At the subsea control pod. c) At the BOP panel on the rig floor. d) Pilot pressure is not regulated. 18) Pilot pressure is supplied from accumulator bottles separate from the main bank of bottles. With system pumps operational, can the pilot accumulators recharge the main accumulators system, if required? a) Yes b) No 19) With the BOP pumps operational, can the main accumulators recharge the pilot system if required? a) Yes b) No 20) The 3 position 4 way manipulator valve on the subsea control unit, when this valve is in the block position. a) The inlet pilot pressure will be blocked and both outlets blocked. b) The inlet pilot pressure will be blocked and both outlets vented. c) The inlet pilot pressure will be vented and both outlets vented. 21) Do annular preventers have a locking device? a) Yes b) No

5 of 8

Classified as General

22) Shuttle valves are activated by? a) Pilot pressure. b) Regulated power fluid. c) Air pressure. 23) Which statement is correct. Connectors will have a hydraulic system that a) Provide a higher force for latching than for unlatching. b) Provide a higher force for unlatching than latching. c) Provide the same force to latch and unlatch. 24) Shuttle valves can be found on a? a) In the subsea pod. b) On the preventers. c) At the drillers panel. 25) A hydraulic closing unit on a floating rig has two hydraulic systems. Which of these systems vent fluid to the sea when operated? a) The power hydraulic system. b) The pilot hydraulic system. 26) When determining the required number of subsea accumulators bottles. Which of the following will be taken into account? (2 answers) a) Sea water depth. b) Overall length of the hose (including the reel) c) The total volume of fluid required to operate all BOP functions. d) The capacity of the accumulator bottles and the pressure rating. e) The size of the line supplying power fluid to the BOP. 27) The annular is starting to leak, the driller attempts to function a ram. The lights change but the accumulator and manifold pressure remain steady. What could the problem be? a) Blocked hydraulic pilot fluid line. b) Blocked hydraulic power fluid line. c) Manipulator valve subsea stuck. d) Shuttle valve is stuck.

6 of 8

Classified as General

28) API states the charge pumps should be able to recharge the accumulator system from the minimum calculated operating pressure to the system maximum in less than what time? a) 16 minutes. b) 12 minutes. c) 13 minutes. d) 15 minutes. 29) What is a blow down line normally used for? a) Reduce the pressure in the buffer chamber. b) Vent pressure if the choke plugs. c) Reduce pressure on upstream of the choke. d) Prevent overloading the MGS. 30) Which statement is true about variable rams? a) They have serious temperature limitations. b) Hang off is not possible. c) Not recommended to strip through. 31) Why does a driller on a floating rig need to be aware of the tide and rig heave? ( 2 answers) a) For the riser tensioners adjustment. b) To ensure the driller is aware of the tool joints position in the BOP. c) To adjust the BOP guide wire tensioners. d) To hang off in the correct position.

7 of 8

Classified as General

32) The illustration shows the main components of the Lower Marine Riser Package (LMRP) used for subsea drilling .Match the correct number to the component description

a) b) c) d) e) f) g) h)

6 ___ ___ 1 ___ 5 ___ 2

Annular(s) Conduit Line(s) Blue/Yellow Control Pod (MUX / Hydraulic operated) Flexible C/K Line(s)

___ 3

Flex / Ball joint

___ 4

Subsea Accumulator bottle(s)

___ 7

8

___

LMRP Support frame LMRP Connector

8 of 8

Classified as General

IWCF Well Control Practice Test Surface Stack

Principles & Procedures Time allowed - One hour 35 marks in total Each question is 1 point No marks for partially correct answers

your score

(

/35) x 100 =

Instructor NAME : _________________ DATE : ______________

1 of 11 Classified as General

%

Q1)

Why is a kick circulated out from the well bore at a slow pump rate? a) To keep excess pressure on the formation to a minimum. b) To reduce the jetting action of the bit. c) To increase the amount of overbalance on the formation to make the kill safer. d) To prevent any gas expanding as it migrates up the well bore.

Q2)

Which of the following increases the chances of swabbing on a trip out the hole? a) b) c) d)

Q3)

While killing a well using a constant bottom hole pressure method, what will happen to the pressure at the casing shoe once the influx has been circulated inside the cased hole section? a) b) c) d)

Q4)

Large annular clearance between string & hole wall. Pulling pipe too fast. Thin mud. A large overbalance in your mud weight.

The pressure should decrease. The pressure should increase. The pressure should remain the same. There is not enough information to tell.

What will happen to the pit volume as a gas kick is circulated from bit to surface in a well containing water based drilling mud? a) Pit volume will decrease. b) Pit volume will remain constant. c) Pit volume will increase.

2 of 12 Classified as General

Q5)

Which of the following statements most accurately describes the Hard Shut In Method? a) With the remote choke closed for normal operations, open the HCR valves on the BOP stack and close the BOP. b) With the remote choke closed for normal operations, close the BOP and open the HCR valves on the BOP stack. c) With the remote choke open for normal operations, close the BOP, open the HCR valves on the BOP stack and close the remote choke. d) With the remote choke open for normal operations, open the HCR valves on the BOP stack, close the BOP and close the remote choke.

Q6) When should you consider re-taking your slow pump rate pressure losses? (4 answers required) a) b) c) d) e) f) Q7)

If practical at the beginning of every tour. Immediately before tripping in the hole. After major repairs or alterations to the rig pumps. After a change in mud weight. While slipping & cutting the drilling line. At least every 500 ft of new hole drilled.

If Gas Migration is taking place in a shut in well (no float in the string) you are likely to see both SIDPP & SICP increase by approximately the same amount True

Q8)

/

False

A leak off test was performed with 9.8 ppg test mud weight at a casing shoe set at 5,370 ft M.D. / 5,245 ft T.V.D. Surface Leak Off Pressure at the test was 1350 psi. What pressure was actually applied to the casing shoe? a) b) c) d)

4086 psi 4022 psi 1350 psi 5359 psi

3 of 12 Classified as General

Q9)

Which of the following is an indication that the well may be flowing while you are drilling? a) Reduced ROP combined with an increase in cuttings recovered at surface. b) A reduction in drill pipe pressure combined with a reduction in torque. c) An increase in hook load combined with a reduction in connection time. d) An increase in return flow combined with a decrease in pump pressure.

Q10) From the following list place the statements in the order that best describes the Drillers Method of Well Control – Surface Stack (7 answer) a) Casing pressure will reduce as kill mud is circulated to the bit. b) At the start of the first circulation the pump is brought up to kill rate speed while holding casing pressure constant. c) Kill Mud is pumped to the bit while following a calculated drill pipe pressure drop schedule. d) Drill pipe pressure is maintained constant as the influx is circulated from the well. e) Casing pressure will remain constant as a gas influx is circulated from the well. f) At the start of the second circulation casing pressure is held constant while the pump is brought up to kill rate speed. g) Drill pipe pressure is held constant as kill mud is pumped up the annulus to surface. h) At the end of the first circulation and with the well shut in both SIDPP & SICP should read the same. i) With the well shut in and kill mud at surface both SIDPP & SICP should read zero. j) With kill mud back at surface your casing pressure gauge will read FCP.

1

B

, 2

D

, 3 H

, 4 F

5

C

, 6

G

, 7 I

,

4 of 12 Classified as General

,

Q11) Which factor most influences the rate at which shut in pressures will stabilise after a well has been closed in on a kick? a) b) c) d)

Permeability. Friction Losses in the Annulus. Gas Migration. Type of Influx.

Q12) How often should MAASP be re-calculated? a) b) c) d)

After a change in mud weight. After a bit change. After circulating bottoms up on a trip. After every 1000 ft of new hole drilled.

Q13) During a kill operation you decide to hold drill pipe pressure constant as kill mud is circulated from surface to bit. What will happen to bottom hole pressure as a result of your actions? a) b) c) d)

Bottom hole pressure will decrease. Bottom hole pressure will remain constant. Bottom hole pressure will increase. There is not enough information to tell.

Q14) From the following information calculate the approximate reduction in bottom hole pressure if the first 30 stands are pulled dry from the well with no fill up? Mud weight in use Drill pipe capacity Drill pipe metal displacement Casing capacity Average stand length

11.2 ppg 0.01776 bbls/ft 0.00764 bbls/ft 0.0732 bbls/ft 93 ft 189 psi F#19

Q15) The Drillers Method of well control will always give you higher casing shoe pressures than the Wait & Weight method. True

/

False

5 of 12 Classified as General

Q16) You have shut a well in on a kick with a float in the string. How can you establish SIDPP? a) Read it off the gauge – whatever is showing is SIDPP. b) Pump slowly down the string and watch for an increase in SICP – whatever the drillpipe gauge is reading at this time will be SIDPP. c) You do not need SIDPP – simply increase your mud weight by 0.5ppg per 5,000ft of well TVD and use this as kill mud weight. d) SICP minus 150 psi. Q17) The fracture gradient at the shoe (3680 ft TVD) is 0.618 psi/ft. The mud weight currently in use is 9.8 ppg. Approximately what is the current MAASP? a) b) c) d)

326 psi 398 psi 405 psi 415 psi

Q18) From the following list place the statements in the order that best describes the Wait & Weight Method – Surface Stack (4 Answers) a) The pump is brought up to kill rate speed while holding casing pressure constant. b) Kill Mud is pumped to the bit while following a calculated drill pipe pressure drop schedule. c) Drill pipe pressure is maintained constant as the influx is circulated from the well. d) Casing pressure will remain constant as a gas influx is circulated from the well. e) Drill pipe pressure is held constant as kill mud is pumped up the annulus to surface. f) With the well shut in and kill mud at surface both SIDPP & SICP should read zero. g) With kill mud back at surface your casing pressure gauge will read FCP.

1

A

, 2

B

, 3

6 of 12 Classified as General

E

, 4

F

,

Q19) In a deviated well, casing pressure will remain constant until the gas enters the build section when it will begin to rise. True

/

False

Q20) On a trip out the hole for a bit change the trip tank level falls from 50 bbls to 43 bbls as the first ten stands are pulled wet from the hole. Due to problems with the mud bucket there were no returns from it to the trip tank. The planned flow check at ten stands indicates no flow. Based on the following well data choose your next action. Well TVD Mud weight in use Drill pipe capacity Drill Pipe metal displacement Average stand length

12,565 ft 13.4 ppg 0.01776 bbls/ft 0.00764 bbls/ft 92 ft

a) Continue with the trip everything is OK. b) Flow check for another fifteen minutes and if still no flow continue with the trip. c) Run immediately & cautiously back to bottom and circulate bottoms up. d) Circulated bottoms up at your current bit depth then continue with the trip. Q21) From the following well data calculate the number of stands that can be pulled dry from the hole, without fill up, before the well starts to flow. Well depth Current mud weight Formation pressure gradient Casing capacity Drill pipe capacity Drill pipe metal displacement Average stand length a) b) c) d)

36 stands 37 stands 38 stands 39 stands

F#23

7 of 12 Classified as General

8,880 MD/ 8,450 TVD 9.8 ppg 0.498 psi/ft 0.1521 bbls/ft 0.01725 bbls/ft 0.008 bbls/ft 93 ft

Q22) A gas kick is easier to detect in oil based mud than it is in water based mud. True

/

False

Q23) Slowly but regularly during a kill operation the choke operator has had to close the choke in to maintain the correct pressure reading on the drill pipe pressure gauge. From the list below what has probably been the cause of this? (2 answers) a) The gas is expanding as it is circulated up the annulus and his actions are as expected. b) The choke may be washing out. c) The annulus is plugging up. d) The kill pump is developing a leak. e) The kill mud is starting to reduce the circulating pressure. Q24) Mud hydrostatic can be reduced by: a) b) c) d) e)

Reducing the mud weight. Reducing the height of the column of mud. Gas cut mud. All of the above. None of the above.

Q25) Prior to pulling out the hole a 13.6 ppg slug is pumped and the mud level in the drill string falls some 130 ft. If the original mud weight was 12.4 ppg what has been the drop in bottom hole pressure? a) b) c) d)

92 psi 84 psi 10 psi 0 psi

8 of 12 Classified as General

Q26) Which of the following statements are good operating practice in TOP HOLE that has a high risk of gas bearing formations? (Choose two answers) a) Pump out of the hole on trips. b) Control ROP. c) Maintain high rate of penetration to ensure mud viscosity level is as high as possible. d) Regularly pump fresh water pill to clean cuttings from hole. e) Use a high density mud to create maximum overbalance. Q27) What happens to the pressure on the casing shoe while the gas influx is passing from the open hole into the casing? (BHP is being held constant) a) Increases b) Decreases c) Stays the same Q28) If the Driller pulls all 500 ft of 8” OD x 2 13/16” ID drill collars out of the hole dry, including the bit, without filling the hole, what will be the reduction in the bottom hole pressure? Mud weight Casing capacity Metal displacement

13.2 ppg 0.1545 bbl/ft 0.0545 bbl/ft

121 F#21 ___________________ psi Q29) In which situation is a gas kick more difficult to detect? a. b.

Gas kick in an oil based mud. Gas kick in a water based mud.

9 of 12 Classified as General

Q30) Under which circumstances would the Wait and Weight Method provide lower equivalent pressures at the casing shoe than the Driller's Method? a) When the drill string volume is greater than the annulus open hole volume. b) When the drill string volume is less than the annulus open hole volume. c) The pressures at the casing are the same regardless of the method used. Q31) When pulling out of the hole from the top of the reservoir swab pressures are calculated to be 100 psi. TVD Mud weight Formation pressure

7,954 ft 10.3 ppg 4,200 psi

Will the well flow? Yes

/

No

Q32) During top hole drilling from a jack-up rig. The well starts to flow due to shallow gas. What will be the safest actions to take to secure the safety of rig and personnel? (Choose two answers) a) Start pumping mud into the well at the highest possible rate. b) Shut-in the well and prepare for kill operations immediately. c) Activate the diverter system and remove non-essential personnel from the rig floor and hazardous areas. d) First line up the mud/gas separator then activate the diverter system and remove personnel from the rig floor. e) Activate the blind/shear rams to shut in the well.

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Q33) A hydraulic delay exists between the time the choke is adjusted to the time the drill pipe pressure reacts. Approximately what is this delay? a) b) c) d)

Equal to the speed of sound. About 1 second per 300 meters of travel time. Always equal to 20 seconds. This is a myth, no hydraulic delay actually exists.

Q34) Why can pressure build up in the Mud Gas Separator while circulating out a kick be dangerous? a) Pressure build up will increase risk of lost circulation. b) Pressure build up will affect ability to make choke adjustments. c) Pressure build up may allow gas to be blown up the derrick vent line. d) Pressure build up may allow gas to enter shale shaker area. Q35) A light mud pill is circulated in the well. At what moment will the bottom hole pressure start to decrease? a) b) c) d)

As soon as the pill starts to be pumped into the drillstring. Once all the pill has been displaced into the annulus. Once the pill starts to be displaced into the annulus. Once all the pill is in the annulus.

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IWCF Well Control Practice Test Surface Stack

Equipment Time allowed - One hour 30 Marks in total Each question is 1 point No marks for partially correct answers

your score

(

/30) x 100 =

%

Instructor NAME : _________________ DATE : __________

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1. During the well operation, a driller observes that the drill-pipe pressure goes up quickly from 1200 psi to 1600 psi and remains stable but the casing pressure remained constant at 800 psi. what should the driller do next? a) He should mark 1600psi as new circulating pressure b) He should reduce drill-pipe pressure to 1200 psi c) He should maintain casing pressure constant instead

2. How often you need to test the BOP as per API a) 28 days b) 21 days c) 14 days

3. How manty times can you re-use BOP ring gaskets before they are out of specification a) Several times or until you can see they are worn on the gasket body b) No more than 5 times c) Only one time use d) Until the start leaking

4. MGS has following spec • MGS seal leg height=15ft • Mud density in mud leg=13.0ppg • Vent line length=210ft • Height of MGS= 25FT How much pressure will a blow through be occurred?10.14 ________psi

5. What is the blowout preventer control system? a) It’s a high pressure hydraulic power unit fitted with directional control valves to safely control kicks and prevent blowouts b) It’s a system which helps control bottom hole pressure c) It’s a low pressure hydraulic power unit

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6. What are the two main types of accumulators available and which sizes are they? a) Fat and thin types with square and octagon sizes b) Bladder and float types with cylindrical or ball styles c) Shallow types with triangular and hexagon shapes

7. The following are the components of a surface stack BOP control system EXCEPT a) Reservoir, accumulator piping b) Air pump assembly, electric pump assembly c) Standpipe manifold d) Cement manifold

8. What one of the following is in-correct statement about electric pump assembly a) It is connected to the reservoir high pressure operating fluid for BOP control system b) It is available in a variety of horsepower and voltage ranges c) It consists of a duplex or triplex reciprocating plunger type pump driven by an explosion proof electric motor

9. What is the recommended fluid for BOP test? a) Water based mud b) Water c) Oil based mud d) Any fluid

10. What are the positions of a 4 way valve a) Normal left and right b) Pre-charge and fully open c) Open, close, block

11. When would you put the 4 way valve in block position? a) Rig move or repair b) While drilling c) While logging d) While tripping

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12. Which one is not a correct statement regarding pump power requirement? a) Power for closing unit must be available to the accumulator at all times such that the pumps will automatically start when the closing unit manifold pressure has decreased to less than 90% of the accumulator operating pressure. b) Two or three independent sources of power should be available on each closing unit c) A dual air and electric system is not recommended at any time.

13. How often do personnel need to do a function test on all operational equipment? a) At least once a week b) Every 21 days c) Every month d) Yearly

14. What is the correct requirement about valves and fittings for closing unit on BOP? a) All valves and fittings between the closing unit and BOP stack can be made of plastic b) All valves and fittings between the closing unit and the BOP stack should be of steel construction with a rated pressure at least equal to the working pressure rating of the BOP stack up to 3000 psi c) All valves and fittings between the closing unit and the BOP stack should be of a steel construction with a rated pressure at least equal to the working pressure rating of the BOP up to 1500 psi

15. What is the minimum required capacity of the reservoir tank? a) 1 times the capacity of the usable fluid capacity b) 1.5 times the capacity of the usable fluid capacity c) 2 times the capacity of the usable fluid capacity d) 3 times the capacity of the usable fluid capacity

16. What is the main purpose of the choke in the overall BOP system? a) To divert mud to the mud pits b) To control back pressure while circulating a kick c) To close the well in safely d) To close the well in softly

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17. At what pressure should the hydro pneumatic pressure switch start the air operated hydraulic pumps? a) 2900 psi b) 2800 psi c) 2700 psi d) 2600 psi

18. A ram BOP has a closing ratio =10.56 calculate the minimum required hydraulic pressure for the ram BOP if 11000 psi well bore pressure is contained in the BOP? a) 110 psi b) 1050 psi c) 1500 psi d) 1850 psi

19. What is the normal hydraulic supply pressure to the diverter system? a) 3000 psi b) 1500 psi c) 1000 psi d) 1250 psi

20. What is the main purpose of a diverter system? a) To close in on a shallow kick b) To create a back pressure sufficient to stop influx from entering the well bore c) To direct fluid or gas a safe distance away from the rig floor with out closing in the kick d) To act as a back up system if the annular preventer fails

21. When circulating out a kick the pop off valve opened on the pump. What is the first action you should take. a) Close the well in b) Activate the diverter c) Change to pump 2 d) Reset the pop off quickly and carry on

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22. While circulating out a kick the mud hose starts to leak. What action should be taken. a) Close the choke b) Stop the pump close the IBOP on the top drive then close the choke. c) Close the well in with the shear rams

23. On which combination of TWO gauges would you expect to observe a reaction when stripping a tool joint through an annular? a) PVT b) Regulated annular pressure gauge c) Accumulator pressure gauge d) Weight indicator e) Drill pipe pressure gauge f) Manifold pressure gauge

24. What is the required response time for closing a 18 ¾ annular preventer on surface BOP stack? a) Less than 15 seconds b) Less than 30 seconds c) Less than 45 seconds d) Less than 60 seconds

25. What is the required response time for closing an 18 ¾ ram preventer in a surface BOP stack? a) Less than 15 seconds b) Less than 30 seconds c) Less than 45 seconds d) Less than 60 seconds

26. When should shear rams be used for immediate control. TWO answers a) To close the well in with no pipe in the hole b) To close in on a shallow kick c) To control a blow out up through the pipe d) To hang off the drill string

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27. The driller has stripped to bottom with an IBOP installed. What tasks cannot be carried out? THREE answers a) Directly readout SIDPP b) Circulate through the drill string c) Reverse circulate d) Run wireline to bottom e) Use the volumetric method to control the well

28. What three functions on the BOP stack does the manifold regulator supply? a) Annular b) BOP test line c) Rams d) Kill line valve e) Choke line valve

29. After connecting the open and close hoses to the stack you should…….. a) Take SCRS b) Bleed down accumulator bottles and check pre charge c) Function test all items on the stack d) Place all items in block position

30. Where should the suction line of vacuum degasser be connected? a) Inside the MGS b) From the MGS vent line c) Upstream of the MGS d) Downstream of the MGS

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