Edition 1

Sanction Mar Date 2011

UNDERBALANCED DRILLING AND MANAGED PRESSURE DRILLING OPERATIONS USING JOINTED PIPE

AN INDUSTRY RECOMMENDED PRACTICE (IRP) FOR THE CANADIAN OIL AND GAS INDUSTRY

VOLUME 22 - 2011

COPYRIGHT/RIGHT TO REPRODUCE

Copyright for this Industry Recommended Practice is held by Enform, 2011. All rights reserved. No part of this IRP may be reproduced, republished, redistributed, stored in a retrieval system, or transmitted unless the user references the copyright ownership of Enform.

DISCLAIMER

This Industry Recommended Practice (IRP) is a set of best practices and guidelines compiled by knowledgeable and experienced industry and government personnel. It is intended to provide the Operator with advice regarding the specific topic. It was developed under the auspices of the Drilling and Completions Committee (DACC).

The recommendations set out in this IRP are meant to allow flexibility and must be used in conjunction with competent technical judgment. It remains the responsibility of the user of the IRP to judge its suitability for a particular application.

If there is any inconsistency or conflict between any of the recommended practices contained in the IRP and the applicable legislative requirement, the legislative requirement shall prevail.

Every effort has been made to ensure the accuracy and reliability of the data and recommendations contained in the IRP. However, DACC, its subcommittees, and individual contributors make no representation, warranty, or guarantee in connection with the publication of the contents of any IRP recommendation, and hereby disclaim liability or responsibility for loss or damage resulting from the use of this IRP, or for any violation of any legislative requirements.

AVAILABILITY

This document, as well as future revisions and additions, is available from

Enform Canada 5055 11th Street N.E. Calgary, AB T2E 8N4 Phone: 403.516.8000 Fax: 403.516.8166 Website: www.enform.ca

http://www.enform.ca/

IRP 22: UBD/MPD Operations March 2011 Page i

TABLE OF CONTENTS Table of Contents ...................................................................... i List of Figures ........................................................................... v

List of Tables ........................................................................... vi Preface ................................................................................... vii

Purpose ........................................................................................... vii

Audience ........................................................................................... viii

Scope ........................................................................................... viii

Revision Process .................................................................................. viii

Sanction ............................................................................................ ix

Acknowledgements ................................................................................ ix

22.1 Planning ........................................................................... 1 22.1.1 Project Management Process ....................................................... 1

22.1.1.1 Project Approval .......................................................... 1

22.1.2 Hazard and Risk Assessment Process ........................................... 4

22.1.2.1 Hazard and Risk Register .............................................. 5 22.1.2.2 Risk Tolerance and Severity .......................................... 7 22.1.2.3 Using the Hazard and Risk Register Tool ......................... 9

22.1.3 Well Parameter Review ............................................................. 10

22.1.3.1 Wellhead Pressure ..................................................... 11 22.1.3.2 Reservoir Pressure ..................................................... 11 22.1.3.3 Flow Rate Potential .................................................... 11 22.1.3.4 Drilling Fluids ............................................................ 12 22.1.3.5 Sweet or Sour Fluids .................................................. 13 22.1.3.6 Wellbore Integrity ..................................................... 13 22.1.3.7 Temperatures ........................................................... 14 22.1.3.8 Hydrate Risks ........................................................... 14 22.1.3.9 Erosion Concerns / Corrosion Risks .............................. 15 22.1.3.10 Uphole Nuisance Gas ................................................. 16

22.1.4 Well Control, BOP Stack-ups, and Process Flow Diagrams ............. 16

22.1.4.1 Common PFD System Practices ................................... 16 22.1.4.2 Specific PFD System Practices ..................................... 21

22.1.5 Engineering Requirements for High Risk Scenarios ....................... 22

22.1.5.1 Equipment Specifications ............................................ 23 22.1.5.2 Lease and Wellsite Spacing for Equipment .................... 24 22.1.5.3 UBD Flow Control Matrix ............................................. 27 22.1.5.4 Emergency/Unplanned Operations ............................... 30

Page ii IRP 22: UBD/MPD Operations March 2011

22.1.5.5 Fire and Explosion Hazard Management ....................... 31

22.1.6 Environment and Public ............................................................ 31

22.1.6.1 UBD/MPD Hazard Assessment ..................................... 32 22.1.6.2 Flaring, Venting and Conservation ............................... 34 22.1.6.3 Emergency Response Plans ......................................... 37 22.1.6.4 Public Concerns ......................................................... 37 22.1.6.5 Additional Resources .................................................. 39

22.1.7 Minimum Recommended Experience and Training ........................ 39

22.1.7.1 Personnel Roles, Responsibilities and Duties ................. 40 22.1.7.2 Personnel Experience Recommendations ...................... 40 22.1.7.3 Personnel Industry Certification Recommendations ........ 42 22.1.7.4 Additional Technical Training Recommendations ............ 47 22.1.7.5 Operator Readiness Review ........................................ 48

22.2 Equipment ...................................................................... 51 22.2.1 Mechanical Wellbore Integrity.................................................... 51

22.2.1.1 Wellbore Integrity Issues ............................................ 53

22.2.2 Surface Well Control Equipment................................................. 54

22.2.2.1 Blowout Preventer (BOP) Stack ................................... 55 22.2.2.2 Primary Flow Line Emergency Shut-Down Valve ............ 57 22.2.2.3 Rotating Control Device (RCD) .................................... 58 22.2.2.4 Erosion Hazard Management ....................................... 62 22.2.2.5 Snubbing Equipment .................................................. 64

22.2.3 Subsurface Well Control Equipment ............................................ 64

22.2.3.1 Drillstring: NRV Recommendations .............................. 64

22.2.4 Surface Circulating System ....................................................... 65

22.2.4.1 Piping ...................................................................... 66 22.2.4.2 Chokes ..................................................................... 67 22.2.4.3 Standpipe bleed-off ................................................... 68 22.2.4.4 Open Tank Systems ................................................... 68 22.2.4.5 Separator ................................................................. 69 22.2.4.6 Pump Lines (liquid and gas) ........................................ 70

22.2.5 Circulating Media ..................................................................... 70

22.2.6 Drillstring & Drilling Rig ............................................................ 71

22.2.6.1 Drillstring Requirements ............................................. 71 22.2.6.2 Drilling Rig ............................................................... 71 22.2.6.3 Rig Alignment ........................................................... 72 22.2.6.4 Kelly Hose ................................................................ 72

22.3 Operation Practices ........................................................ 73 22.3.1 UBD/MPD Operational Risk ........................................................ 73

22.3.2 Project Communications ........................................................... 74

22.3.2.1 Planning Communications ........................................... 74 22.3.2.2 Operational Communications ...................................... 75 22.3.2.3 Lessons Learned ........................................................ 76

IRP 22: UBD/MPD Operations March 2011 Page iii

22.3.3 Wellsite Safety ........................................................................ 76

22.3.3.1 Location Planning and Preparation ............................... 76 22.3.3.2 Lease Lighting ........................................................... 76 22.3.3.3 Communications ........................................................ 77 22.3.3.4 Site Access and Security ............................................ 77 22.3.3.5 Onsite Wind / Gas Monitoring ...................................... 77 22.3.3.6 Emergency Egress ..................................................... 78 22.3.3.7 Confined Space Entry ................................................. 78 22.3.3.8 Pre-Job Orientation .................................................... 78 22.3.3.9 Safety Meetings ........................................................ 79 22.3.3.10 Emergency Preparedness ........................................... 79 22.3.3.11 Safety Supervision..................................................... 79 22.3.3.12 Safety Equipment Requirements .................................. 79 22.3.3.13 PPE Requirements ..................................................... 80

22.3.4 Concurrent Rig-Up/Out Operations ............................................. 80

22.3.5 Lifting Hazards ........................................................................ 81

22.3.6 Drillout/Hole Conditioning ......................................................... 81

22.3.6.1 Drillout Pre-planning .................................................. 82 22.3.6.2 Drillout Practice Trials ................................................ 82 22.3.6.3 Well Control Considerations ........................................ 83 22.3.6.4 Displacing Hole to UBD/MPD Drilling Fluids ................... 83

22.3.7 Tripping with Surface Pressure .................................................. 83

22.3.7.1 Trip-out of hole ......................................................... 83 22.3.7.2 Trip-in hole ............................................................... 83 22.3.7.3 Servicing the RCD element ......................................... 83 22.3.7.4 Determining the pipe light point .................................. 84 22.3.7.5 NRV procedures: bleed-off / install .............................. 84

22.3.8 Well Suspension ...................................................................... 85

22.3.9 Planned and Unplanned Shutdowns ............................................ 85

22.3.10 Unplanned Oil/Condensate Production ........................................ 86

22.3.11 Drillstring Failure ..................................................................... 86

22.3.12 MPD Back Pressure Management ............................................... 87

22.3.13 Considerations for Sour Operations ............................................ 88

22.3.14 Drilling and Produced Fluids Hazard Management ........................ 89

22.3.15 Air Drilling Operations .............................................................. 90

22.3.16 Coil Operations ........................................................................ 92

22.3.17 Pressure Equalization ............................................................... 93

22.3.18 Non-Routine Operations ........................................................... 93

Page iv IRP 22: UBD/MPD Operations March 2011

References ............................................................................. 95

Acronyms ............................................................................... 98 Glossary ............................................................................... 100

Appendix A: Atmospheric ..................................................... 102 Appendix A: Atmospheric ..................................................... 102

Appendix B: Sweet UBD/MPD Less than 14 MPa ................... 103 Appendix C: Sweet UBD/MPD Greater than 14 MPa .............. 104

Appendix D: Sour UBD/MPD System ..................................... 105 Appendix E: Canadian Resources .......................................... 106

Appendix F: Alberta Resources ............................................. 107 Appendix G: British Columbia Resources .............................. 109

Appendix H: Saskatchewan Resources ................................. 110 Appendix I: Recommended Training Topics for Supervisors . 111

Appendix J: Recommended Training Topics for Operations .. 115 Appendix K: Recommended Training Topics for Orientation . 118

IRP 22: UBD/MPD Operations March 2011 Page v

LIST OF FIGURES Figure 1. Project Management Process .......................................................................... 3

Figure 2. Risk Tolerability Framework ........................................................................... 7

Figure 3. Risk Severity Matrix ...................................................................................... 8

Figure 4. UBD/MPD Surface Equipment Spacing Diagram .............................................. 26

Figure 5. UBD Flow Control Matrix .............................................................................. 28

Figure 6. Emergency Planning and Response Zones ...................................................... 33

Page vi IRP 22: UBD/MPD Operations March 2011

LIST OF TABLES Table 1. Recommended Wellsite Personnel Experience Expectations ............................... 41

Table 2. Recommended Personnel Industry Certifications or Courses .............................. 44

IRP 22: UBD/MPD Operations March 2011 Page vii

PREFACE PURPOSE This document contains a collection of Industry Recommended Practices (IRPs) to ensure that guidelines for Underbalanced Drilling (UBD) and Managed Pressure Drilling (MPD) operations are in place and readily available for all organizations and personnel involved in the development, planning, and completion of a UBD/MPD program. It may be used as a reference for the intended audience, act as a guideline for UBD/MPD companies in training employees, or assist in developing internal procedures for safe UBD/MPD practices.

Throughout this document the terms must, shall, should, may, and can are used as follows:

Must A specific or general regulatory and /or legal requirement

Shall An accepted industry practice or provision that the reader is obliged to satisfy to comply with this IRP

Should A recommendation or action that is advised

May An option or action that is permissible within the limits of the IRP

Can Possibility or capability

Alternatives that diverge from this IRP are acceptable provided they are clearly indicated as follows:

The planning documentation defines which recommendations have been modified and what alternative will be implemented. Alternatives shall be supported by a completed hazard assessment and mitigation methods.

The proposed alternative provides an equivalent degree of safety and technical integrity as that stated in the IRP.

The alternative is reviewed and endorsed by a qualified technical expert (see 22.1.1.1 Project Approval, Qualified Technical Expert).

If there is any inconsistency or conflict among any of the recommended practices contained in this IRP and applicable legislative requirements, the legislative requirement must prevail. It is the readers responsibility to refer to the most recent editions of all regulations and supporting documents. This publication was produced in the province of Alberta and emphasizes Alberta legislation; however, all operations must adhere to jurisdictional regulations. A full disclaimer is noted on the inside cover of this document.

Page viii IRP 22: UBD/MPD Operations March 2011

AUDIENCE This document is primarily intended for UBD/MPD planners. All UBD/MPD personnel may find all or portions of this IRP of interest.

SCOPE This document discusses UBD, MPD and air drilling. It was developed primarily with Western Canadian operations in mind. It is organized procedurally starting with planning, through equipment considerations and concluding with operational practices. A key component to this IRP is the IRP 22 Risk Register. The Risk Register is a tool designed to allow UBD professionals to transfer this IRP into practice (see 22.1.2.7 Using the Hazard and Risk Register).

UBD is a technique that intentionally encourages formation flow to surface. By manipulating fluid density/properties, circulation rate, and wellhead pressurebottomhole pressure is kept intentionally below formation pressure allowing formation fluid influx into the wellbore.

MPD manages bottomhole pressure above pore pressure by combining annular flowing friction, fluid density, and retained wellhead pressure; thereby, suppressing well influx and avoiding exceeding fracture gradients.

Air drilling is a performance drilling technique that primarily uses air to circulate and minimize bottomhole pressure while maximizing the rate of penetration. Air drilling is normally used through wellbore sections that do not contain hydrocarbons.

REVISION PROCESS This is the first version of IRP 22. It is based on issues brought to the DACC by industry and government stakeholders. Technical issues brought forward to the DACC, as well as scheduled review dates, can trigger a re-evaluation and review of this IRP, in whole or in part. For details on the specific process for the creation and revision of IRPs, visit the Enform website at www.enform.ca.

Revision History

Edition Sanction Date Scheduled Review Date

Remarks/Changes

1 March 2011 IRP 22 initially published April, 2011

http://www.enform.ca/

IRP 22: UBD/MPD Operations March 2011 Page ix

SANCTION The following organizations have sanctioned this document:

Canadian Association of Oilwell Drilling Contractors

Canadian Association of Petroleum Producers

Energy Resources Conservation Board

Intervention and Coiled Tubing Association

Oil and Gas Commission

Petroleum Services Association of Canada

Small Explorers and Producers Association of Canada

WorkSafeBC

Alberta Employment and Immigration has reviewed IRP Vol. 22 - Underbalanced and Managed Pressure Drilling Operations Using Jointed Pipe and, as of the date of adoption, finds the set out information meets occupational health and safety legislative requirements. Users are cautioned that IRP Vol. 22 - Underbalanced and Managed Pressure Drilling Operations Using Jointed Pipe is a guideline only and that proper compliance requires a customized program that addresses the conditions of the specific worksite

Saskatchewan Occupational Health and Safety has reviewed IRP Vol. 22 - Underbalanced and Managed Pressure Drilling Operations Using Jointed Pipe and, as of the date of adoption, finds the set out information meets occupational health and safety legislative requirements. Users are cautioned that IRP Vol. 22 - Underbalanced and Managed Pressure Drilling Operations Using Jointed Pipe is a guideline only and that proper compliance requires a customized program that addresses the conditions of the specific worksite

ACKNOWLEDGEMENTS The following individuals helped develop this IRP through a subcommittee of DACC. They represent a wide cross-section of UBD/MPD experts that provided forward-thinking views as well as insightful recommendations to address known hazards and challenges in UBD/MPD operations. We are grateful for each participants efforts. We also wish to acknowledge the support of committee members employers.

Development Committee Name Company Organization

Represented Jeff Saponja (Co-Chair)

TriAxon Oil Corp. SEPAC

Adrian Steiner (Co-Chair)

EnCana Corporation CAPP

Alek Ozegovic Weatherford Canada Partnership PSAC Bill Ellsworth Husky Energy CAPP Camille Jensen Scribe Solutions Chad Mitchell Ensign Enhanced Drill Systems CAODC Darren Kisinger Nexen Inc. CAPP

Page x IRP 22: UBD/MPD Operations March 2011

Name Company Organization Represented

Derek Hibbard Weatherford International Inc. PSAC Dick Bissett Bissett Resource Consultants Ltd. PSAC Don Buckland BC Oil and Gas Commission Gary Ericson Saskatchewan Energy Resources Hank Nychkalo Energy Resources Conservation Board Maksim Xhaferllari Energy Resources Conservation Board Manuel Macias Enform Mike Grossman Sanjel ICoTA, PSAC Mike Read Nabors CAODC; PSAC Mike Sagenschneider WorkSafe BC Nick van Regen 716011 Alberta Ltd. Randy Fasick Ensign Enhanced Drill Systems CAODC Roger Walker EnCana Corporation CAPP

Other Acknowledgements The Committee would like to recognize the numerous contributors who played an important role in the development of this document. Notable contributions were made by:

Aaron Nemish, Sonic Energy; Bill Mulloy, Encana Corporation; Bob Teichrob, Seven Generations Inc.; Carole Sterenbergy, Enform; David Baillargeon, Flow Drilling Engineering; Dean Pylypuk, Saskatchewan Energy Resources; Don Dahr, WorkSafe BC; Earl Dietrich, Blade Energy Partners; Gary Neilson, Energy Resources Conservation Board; James Vaughan, Energy Resources Conservation Board; Jason Winsor, Enform; Jim Benum, Energy Resources Conservation Board; Joy Piehl, WorkSafe BC; Kenn Hample, Alberta Employment, Immigration and Industry; Kevin Boyd, Weatherford Canada Partnership; Lee Campbell, Sonic Energy; Lorne Polzin, Enform; Marilyn Craig, Energy Resources Conservation Borad; Matt McCaffrey, Packers Plus Energy Services Inc.; Milt McCoy, Encana Corporation; Murray Sunstrum, Encana; Robert Ross, Enform.

IRP 22: UBD/MPD Operations March 2011 Page 1

22.1 PLANNING Note. UBD/MPD operations are complex drilling projects. IRP 22 recommendations are meant to allow flexibility for continuous improvement regarding safety and operational efficiency with consideration for the complex nature of UBD/MPD operations.

Competent technical judgment shall be used in combination with these recommendations. It is the Operators responsibility to ensure that required and/or appropriate technical judgment is used to develop the project plan and will continue to be used during the execution of the project.

22.1.1 PROJECT MANAGEMENT PROCESS The Project Management Process outlines planning and review practices to be conducted to ensure the technical and safety integrity of a UBD/MPD drilling project.

Figure 1, the Project Management Process diagram below, illustrates planning and execution stages of the UBD/MPD well program.

22.1.1.1 Project Approval

When engaging in a UBD/MPD project, the project plan along with application to the appropriate Regulator should be developed and signed by a qualified technical expert authorized by, and representing, the Operator.

The signature of the representative confirms that

all the requirements of this IRP have been addressed in the plan and that the terms of the project plan will be applied during the execution of the plan,

appropriate input from qualified technical experts has been obtained where required, and

the qualifications of the technical experts are valid.

Qualified Technical Expert

IRP 22 allows flexible practices in most instances provided an expert qualified in the relevant practice or technology has approved the options suggested.

It is the Operators responsibility to ensure that the expert is qualified by normal industry standards (e.g. years of technical/operational experience, review of applicable completed projects, references, etc.) and should be able to demonstrate this upon audit.

Project Management Process

Figure 1 below illustrates the Project Management Process (PMP) from well design through execution and includes the change management process. IRP 22 is based on this process. The PMP, or a similar process, should be part of planning and executing UBD/MPD operations.

Page 2 IRP 22: UBD/MPD Operations March 2011

IRP 22: UBD/MPD Operations March 2011 Page 3

1. CONCEPTUAL WELL DESIGN Define well objectives Assess reservoir parameters Initial casing design Resolve UBD/MPD suitability and methodology Draft Operations Plan

2. UBD/MPD DETAILED OPERATIONS PLAN Drilling circulation system / fluids Drillstring Flow modeling Tripping method Logging requirements and deployment method Completion / well suspension method Bridge UBD/MPD and well control Wellhead and casing design Equipment selection Process Flow Diagram (PFD) Draft operational procedures

3. HSE PLAN Personnel experience and training Environment and public Validate equipment SOP's Communications Wellsite safety

4. HAZARD AND RISK ASSESSMENT Perform site-specific risk assessment using Risk Register

tool/process Compile, assign and timeline actions required for risk

mitigation

6. WELL PROGRAM Freeze UBD/MPD operations plan Compile operations plan into Well Program Final project plan approvals Gain Regulatory approvals

5. CHANGE MANAGEMENT Resolve and close-out all

Hazard and Risk Register actions

7. RIG IN / OUT Logistics Lifting hazards Concurrent operations Commission equipment

8. WELLSITE PROCEDURAL AND HAZARDS COMPREHENSION Onsite orientation and hazard identification Communications process/protocol validation Train wellsite personnel Conduct appropriate procedural familiarization trials with all

crews Verify procedural comprehension and confirmation of fit for

purpose

9. PROGRAM DEVIATIONS Prepare/document wellsite program amendment Amendment reviewed and approved by qualified office base

staff following Hazard and Risk Hazard Assessment by difference

11. EXECUTE PROGRAM HSE Monitoring Conduct frequent tailgate and safety meetings Document learning and feedback

10. CHANGE MANAGEMENT Conduct Hazard and Risk

Assessment by difference Issue program amendment

PL

AN

NI

NG

EX

EC

UT

IO

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Figure 1. Project Management Process

Page 4 IRP 22: UBD/MPD Operations March 2011

22.1.2 HAZARD AND RISK ASSESSMENT PROCESS Identifying potential hazards and assessing their risk is an important and fundamental part of planning to protect workers, the environment, and the Operators assets. It also provides an effective basis for well engineering, reduces operational Non-Productive Time (NPT), and ensures regulatory compliance.

It is recommended that during the planning stage the following be included for each hazard:

a complete, suitable, and sufficient risk assessment that determines the measures needed to ensure that risks for each hazard is adequately controlled; and

suitable controls/mitigations are in place for each hazard.

UBD/MPD operations are generally infrequent and often of short project duration. This low operational frequency is a key risk control/mitigation challenge for UBD/MPD operations. There are numerous hazards (all with a potential to give rise to unwanted consequences) that are unique to UBD/MPD operations. Each hazard shall be diligently identified, risk-assessed and appropriately controlled and/or mitigated.

IRP 22 hazard management requires that a risk assessment be conducted for all UBD/MPD operations. ISO (International Standards Organization) standards define risk as the combination of the probability of an event and its consequences.a

IRP 22s suggested risk assessment is not the only method available to evaluate hazards. Organizations may, and should, have existing and established risk assessment processes, hazard registers, and associated analysis tools. The IRP 22 Hazard and Risk Assessment Process is not intended to replace existing organizational risk assessment processes and associated risk analysis tools or registers, nor is it intended to provide a complete UBD/MPD risk analysis tool for organizations. Rather, the IRP 22 Hazard and Risk Assessment Process is intended to:

For UBD/MPD operations the consequences of events (i.e., hazard scenarios) can be understood, but the probability of occurrence is much more difficult to predict and quantify. To date the industry has not compiled hazard scenario statistics for effective quantitative risk assessment; therefore, IRP 22 uses a qualitative approach to determine risk-severity based on collective industry expert experience. Since the IRP 22 Hazard and Risk Assessment Process is qualitative, it is considered a minimum risk assessment.

provide minimum expectations for conducting risk assessments for UBD/MPD operations;

highlight industry identified UBD/MPD hazards scenarios and associated risk severity;

provide risk control/mitigation options for consideration;

act as a corollary tool, to work in conjunction with an existing tool, to augment and supplement existing risk assessment tools and practices; and

provide an effective means for regulatory conformance and inspection.

aISO/IEC Guide 73:2002 definition 3.1.1 Risk management Vocabulary Guidelines for use in standards

IRP 22: UBD/MPD Operations March 2011 Page 5

IRP 22 additionally sets the following hazard management expectations:

Identified risk controls/mitigations, at a minimum, shall achieve the standards of relevant good practice precautions, irrespective of specific risk estimates.

Where there is no relevant good practice, or the existing good practice is considered by the site-specific risk assessment to be insufficient or inadequate, suitable control measures should be formed by further risk assessment.

As control measures are introduced, the residual risks may fall so low that additional measures to reduce them further are likely to be grossly disproportionate to the risk reduction achieved, though the control measures should still be monitored in case the risks change over time.

There are some risks from certain activities, processes, or practices that are unacceptable, regardless the benefit. These activities shall be ruled out unless the activity or process can be modified to reduce the associated risks to a level that is As Low As Reasonably Practicable (ALARP)b

NPT events often lead to unplanned well operations and quite possibly inappropriately risk-assessed hazard scenarios. The IRP 22 Hazard and Risk Assessment process includes a required risk analysis of potential NPT events, consideration for NPT event avoidance and subsequent contingent well operations/procedures to return the operation back to the original Operational Plan.

.

22.1.2.1 Hazard and Risk Register

Presently, the UBD/MPD industry does not have the statistical data necessary to develop a quantitative risk analysis tool for UBD/MPD. In order to shift the subjective nature of qualitative risk analysis towards quantitative risk analysis the UBD/MPD industry requires a commitment to gathering quantifiable data. The IRP 22 Hazard and Risk Register attempts to provide a method to gather data for future quantitative analysis.

The IRP 22 Hazard and Risk Register, or the Risk Register, is intended to:

facilitate operational planning by identifying and mitigating potential hazards in UBD/MPD scenarios;

establish a baseline and industry standard for risk tolerance;

provide a process for establishing contingency planning; and

initiate a process to gather, review, and append an industry Risk Register.

b The concept of as low as reasonably practicable is simply explained in an industry guide available on the United Kingdom HSE website (http://www.hse.gov.uk/risk/theory/alarpglance.htm).

http://www.hse.gov.uk/risk/theory/alarpglance.htm

Page 6 IRP 22: UBD/MPD Operations March 2011

The IRP 22 Risk Register is available as an Excel file for download on the IRP 22 landing page at:

http://enform.ca/publications/irps/underbalanced_and_managed_pressure_drilling.aspx

The Risk Register was structured for UBD/MPD industry-wide use. It may not fall entirely within an organizations policy for hazard and risk analysis. However, the information contained within the Risk Register can easily be used, or adapted, to populate an organizations own internal hazard register.

The Risk Register was compiled by a group of UBD/MPD experts who comprised the IRP 22 Committee. It includes hazard scenarios known and experienced at the time of writing the IRP; therefore, the Risk Register is not necessarily an exhaustive listing. The Risk Register applies the concept of reasonably practicable for control/mitigation of hazard scenarios.c

In circumstances when a high risk hazard is identified and not listed in the Risk Register, a more in detailed risk analysis study like HAZOP or Bow Tie Study, should be initiated to ensure that the operation can be executed safely and that risks are reduced to ALARP.

The IRP 22 Committee strongly encourages that hazard scenarios not listed in the Risk Register be forwarded to Enform for review and amendment to the Risk Register as explained in Purpose of the Risk Register below.

Purpose of the Risk Register

The Risk Register and related IRPs are, as its title implies, recommended practices, not prescriptive procedures. It is the intention of this document, together with the Risk Register, to publicly share these recommended practices for the benefit of the entire UBD/MPD industry.

The Risk Register ensures

a document of known hazard scenarios is available to industry, and

a recommended mitigation is included in the IRP for any risk identified as a high-risk scenario (indicated by red HSE and red NPT in the Risk Register).

While the focus of any IRP is HSE (Health Safety and Environment), the committee elected to consider NPT as well. In many cases, HSE and NPT items are related. Designing a program that reduces the potential for NPT will typically result in the execution of a program with fewer HSE incidents.

As suggested above, the Risk Register is intended as a living document to be updated regularly by industry experts. As UBD/MPD experts experience new hazard scenarios and develop new controls/mitigations (with consideration to risk tolerance and severity, see 22.1.2.2 below), these hazard scenarios may be considered for inclusion in the Risk Register and made available for industry-wide use.

c The concept of as low as reasonably practicable is simply explained in an industry guide available on the United Kingdom HSE website (http://www.hse.gov.uk/risk/theory/alarpglance.htm).

http://enform.ca/publications/irps/underbalanced_and_managed_pressure_drilling.aspxhttp://www.hse.gov.uk/risk/theory/alarpglance.htm

IRP 22: UBD/MPD Operations March 2011 Page 7

The IRP 22 Committee invites organizations to share lessons learned and additions to the Register via the IRP 22 Risk Register Update Form available on the IRP 22 landing page on the Enform website at:

http://enform.ca/publications/irps/underbalanced_and_managed_pressure_drilling.aspx

Enform will forward suggested Risk Register additions to the IRP 22 Standing Committee for review and/or inclusion in the next version.

22.1.2.2 Risk Tolerance and Severity

Risk tolerance and severity ranking differs among organizations and even among individuals within organizations. The Risk Register is intended to bring about specific awareness and offer a UBD/MPD industry-wide risk severity ranking standard for common and known hazard scenarios, along with industry recommended practices and considerations for control and mitigation.

Figure 2 below sets out a risk tolerability framework. The colour coding indicates whether risks from an activity or process are broadly acceptable, tolerable or unacceptable along with each colours application in practice.

In this context, tolerable does not mean acceptable. Tolerable refers instead to a willingness to accept a risk so as to secure certain benefits in the confidence that the risk is one that is worth taking and that can be properly controlled. However, it does not imply that the risk will be acceptable to everyone (i.e., that everyone would agree without reservation to take the risk or have it imposed on them).

Figure 2. Risk Tolerability Framework

For each known hazard scenario identified in the Risk Register a qualitative assessment was conducted by IRP 22 subject matter experts to determine risk level.

During well planning, any additional or new hazard scenarios identified, beyond those listed in Risk Register, should use the Risk Severity Matrix (see Figure 3), as a minimum, to determine risk level.

BroadlyAcceptable

Tolerable Unacceptable

Colour indicates industry risk tolerability

RYG G Y R

http://enform.ca/publications/irps/underbalanced_and_managed_pressure_drilling.aspx

Page 8 IRP 22: UBD/MPD Operations March 2011

Figure 3. Risk Severity Matrix

Probability

High Y R R

Medium G Y R

Low G Y Y

Low Medium High

Consequence

Probability: refers to how likely the hazard is to occur during the operation

Consequence: refers to the severity of the result if the hazard scenario is realized

The following suitable controls or mitigation actions are required for each defined hazards risk severity level:

Engineering, procedures, and training

required

Procedures and training required, should

consider engineering

Training required, should consider

engineering and procedures

Regarding engineering, IRP 22 supports good engineering design principles that aim to:

eliminate hazards over controlling hazards, and

control hazards over providing personal protective equipment.

R

Y

G

IRP 22: UBD/MPD Operations March 2011 Page 9

22.1.2.3 Using the Hazard and Risk Register Tool

The Risk Register is a downloadable tool developed in Microsoft Excel that allows users to customize the Risk Register to site-specific operations. The IRP 22 Risk Register is available for download on the IRP 22 landing page at:

http://enform.ca/publications/irps/underbalanced_and_managed_pressure_drilling.aspx

It is comprised of two worksheets: Intro Sheet and Hazard Register.

Intro Sheet

The Intro Sheet includes three sections: Column Headings, Risk Ranking and General Comments. The Column Headings provide a summary of the intention for each column heading in the Hazard Register worksheet. The Risk Ranking identifies colour coordination to risk tolerability level (high, medium and low) as described in Figure 2 above. The final section, General Comments, overviews general notes about the Risk Register.

Risk Register

The Risk Register contains over 200 items and can be customized as required by the end user. Items are listed according to a Hazard Scenario What If? To use the Register most effectively, refer to the following steps:

1. Determine whether each scenario applies or not. Modify the Applicable column to Y for yes or N for no as required.

2. Conduct a preliminary assessment of the Considerations and Actions to be taken.

3. Next, sort the hazard register worksheet by the Applicable category so that all applicable items appear above items that are not applicable.

4. Conduct additional sorting as per user preference. Users can sort the Register by the operational phase (the default for the Register), or by the primary responsible party, after sorting by HSE risk level. Some may find sorting the Register by categories such as Primary Responsible Party or Primary (service) Category allows service companies to focus on addressing issues that fall in a particular area of expertise.

High risk scenarios in the Risk Register are noted as red in both the HSE and NPT columns. Each high risk scenario is addressed directly in the IRP with recommended mitigations. At the date of publication of the IRP approximately 70 high risk items have been identified.

http://enform.ca/publications/irps/underbalanced_and_managed_pressure_drilling.aspx

Page 10 IRP 22: UBD/MPD Operations March 2011

22.1.3 WELL PARAMETER REVIEW The topics listed below document the specific and critical design details for an entire UBD/MPD project. Whether the project is actually executed as desired is dependent on some, or all, of the factors.

A well parameter review begins by gathering pertinent information to make knowledgeable planning decisions and reduce the potential for unexpected hazardous situations. Prior to drilling a UBD/MPD well, it is important to focus preliminary planning efforts with the following types of questions:

Does the operation require conventional rig or coiled tubing?

Is lift gas (UBD) required? If so, how will it be arranged?

Have drilling fluids been evaluated to address, as thoroughly as possible, the specific requirements for all stakeholders?

Have casing strings and wellhead assemblies been selected based on maximum shut-in potential and casing wear?

Once preliminary decisions are in place, specifics of the project may include, but not be limited to, the following:

Conduct flow modeling to determine whether it is possible to drill the well, and to establish an operating envelope for the project.

Estimate the range of possible operational well behaviours.

From the set of possible well behaviours, derive equipment specifications and procedural requirements.

Evaluate each situation for risk. Additional resources may be required to create safe working conditions.

Managing risk involves managing events within known and acceptable limits. Potential risk is unpredictable without knowledge of, or investigation into, the range of events which could occur. Effective well design is dependent on thorough analysis of the well parameters. Experienced well designers are aware of the possibility of uncertainty, unpredictability, and change. Good well design incorporates a plan for a range of possibilities to ensure equipment and operational requirements are capable of safely executing the full spectrum of possibilities in the well program.

A thorough planning process includes a review of the following well parameters presented in the numbered topics 22.1.3.1 through 22.1.3.10.

IRP 22: UBD/MPD Operations March 2011 Page 11

22.1.3.1 Wellhead Pressure

When compared to conventional drilling, UBD/MPD processes create greater pressure variation at higher points on the annulus side. Particularly for re-entry projects, consider the effect higher pressures may have on the existing casing string or on the wellhead.

Stability, in terms of wellhead pressure and inflow rate, is one aim of all UBD/MPD flows. Multiphase simulations should be performed to define injection rates for liquid and gas, with a preference to those combinations that offer maximum flexibility to maintain bottomhole pressure within the target window, hole cleaning, and reasonable wellhead pressures.

22.1.3.2 Reservoir Pressure

Knowledge of the reservoir pressure is key to well design. It is recommended to sample reservoir pressures over a range, in the event that a single measurement is not accurate.

If the actual reservoir pressure is only marginally lower than predicted, additional gas injection may be needed to achieve an underbalanced state. Otherwise, liquid injection rates may be compromised, possibly hampering the ability to remain within tolerable drilling rates or hole cleaning limits. A much lower pressure can result in equipment limits that require more inert gas or a lower pump rate than possible with equipment on site. Subsequent logistics and equipment supply issues can severely disrupt programs and costs.

If UBD/MPD hole sections are planned to penetrate two individual potentially productive sections, each hole section shall be reviewed carefully to ensure there is not too much difference in reservoir pressures. A large difference in reservoir pressures can cause competition between the two zones (i.e., it may be difficult to keep one of the zones underbalanced because of competition from the other). A difference in reservoir pressures can also lead to excessive zonal production, creating high surface rates (and possibly surface storage problems) and pressures.

Depending on the situation, the productivity of the zones can be a natural mitigating factor. Regardless, each situation potentially involving two (or more) productive sections with different reservoir pressures needs to be carefully reviewed.

22.1.3.3 Flow Rate Potential

The flow rate potential of the productive section is the product of its permeability and reservoir pressure. Multiphase simulations should be performed to determine probable well flow rates. Results will drive the specifications for the piping, separation, choking, monitoring/measurement and fluid storage systems. Designing for a range of permeabilities and reservoir pressures can ensure the system still functions safely even if there is error in assumed properties.

Flush production refers to the initial high production rate exhibited by a permeable feature when first encountered in a UBD operation. The high initial flow rate, as a

Page 12 IRP 22: UBD/MPD Operations March 2011

result of the underbalanced margin, lessens with time, but the increase in overall flow rate can be significant. The separation equipment shall be capable of dealing with these fluctuations.

Failure to provide a system with sufficient throughput to deal with flush production events can result in significantly more time spent circulating and achieving system parameters to return back to within a Flow Control Matrix green zone (see Figure 5 UBD Flow Control Matrix).

A process system with insufficient flow capacity can result in inadequately tested wells. As an example, a flare system with insufficient throughput capacity can result in restricting flow rates to the point that essential reservoir information cannot be derived. Inability to achieve a reasonable flow rate may be dependent on other issues such as: liquids storage or separation capacity, excessive erosion or hydrate formation, among others.

22.1.3.4 Drilling Fluids

Knowledge of all fluids potentially involved in operations is critical to ensure project objectives can be met without involving fluid incompatibilities or other operational issues. Knowledge of the reservoir fluid is primary, as it drives other fluid selections. Planned drilling fluids may interact negatively with native liquid hydrocarbons or other produced fluids and form emulsions or react with drilled solids and plug lines.

Note. Presence of even low levels of H2S changes risk levels significantly.

If the objective reservoir contains primarily gas, drilling fluids may be either oil-based or water. If any significant volumes of condensate are involved, both oil-based fluids and water may be problematic (e.g., foaming or other gas-breakout issues). Oil-based fluids may mix with the condensate and create additional issues.

Plans should be made to mitigate the effects of density, viscosity, and rheology changes in the drilling fluid as a result of reservoir fluid contamination, or plan for other mitigations to deal with the changing fluid situation.

Regardless, drilling fluid selection is a compromise among hole cleaning, ease of separation, reservoir damage, and other factors.

According to the ERCBs ID 94-3: Underbalanced Drilling, underbalanced wells must have one hole volume of available kill weight mud ready for use on site. The API Recommended Practice 92U Underbalanced Drilling Operations recommends a surface kill mud volume of 150% of hole volume for wells above Risk Level 2 in the IADC Well Classification System for Underbalanced Operations and Managed Pressure Drilling.

Upon review of ID 94-03 and the IADC document, the IRP 22 Committee recommends the following:

http://www.ercb.ca/portal/server.pt/gateway/PTARGS_0_0_323_253_0_43/http%3B/ercbContent/publishedcontent/publish/ercb_home/industry_zone/rules__regulations__requirements/information_letters__interim_directives/interim_directives__id_/id94_03.aspxhttp://global.ihs.com/doc_detail.cfm?currency_code=USD&customer_id=2125482C4C0A&shopping_cart_id=2824383F254B50284B5A2D58230A&rid=API1&country_code=US&lang_code=ENGL&item_s_key=00514759&item_key_date=991231&input_doc_number=&input_doc_title=underbalancehttp://global.ihs.com/doc_detail.cfm?currency_code=USD&customer_id=2125482C4C0A&shopping_cart_id=2824383F254B50284B5A2D58230A&rid=API1&country_code=US&lang_code=ENGL&item_s_key=00514759&item_key_date=991231&input_doc_number=&input_doc_title=underbalancehttp://www.iadc.org/committees/ubo_mpd/Documents/IADC%20Classification%20system%20for%20Managed%20Pressure%20Control%20and%20Underbalanced%20Wells.pdfhttp://www.iadc.org/committees/ubo_mpd/Documents/IADC%20Classification%20system%20for%20Managed%20Pressure%20Control%20and%20Underbalanced%20Wells.pdf

IRP 22: UBD/MPD Operations March 2011 Page 13

If the liquid phase of the drilling fluid being used is of sufficient kill weight density, 100% of the hole volume on surface should be available.

If the liquid phase of the drilling fluid being used is not of sufficient kill weight density, 150% of the hole volume on surface should be available.

Note. The two bullets above refer to a surface kill mud volume. The planning process should assess the ability to logistically transport additional fluid volumes as required.

22.1.3.5 Sweet or Sour Fluids

Most drilling systems do not tolerate sour fluids (H2S). If the planned program is designed for sweet operations and sour gas is detected in the returns, there will be a major impact on operations and operational safety. The risk of encountering sour fluids shall be fully assessed during planning to attempt to predict unanticipated consequences (e.g., ability to kill the well immediately when sour fluids are encountered).

22.1.3.6 Wellbore Integrity

UBD/MPD drilling operations commonly exhibit the following wellbore integrity conditions:

exposure of the wellbore to reservoir fluids;

reduced bottomhole pressure and temperature;

high and variable surface pressures;

high flow rates; and

sometimes in gas wells, full static reservoir pressure to surface.

Note. Greater wellbore stability challenges are faced by open hole formations in UBD.

MPD uses a lighter-than-kill-weight drilling fluid and is intended to not allow any formation flow. As a result of the lighter-than-kill-weight drilling fluid, well control situations can result in higher pressure (i.e., higher than typically seen in conventional situations) in some sections of the wellbore. This may pose integrity challenges. The desired bottomhole pressure is achieved via a combination of fluid density and annular fluid friction, fluid rheology, or surface backpressure (among other parameters).

UBD wells are usually drilled primarily within productive sections, predominantly horizontal or nearly so, but MPD occurs at any wellbore angle.

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Shale sections are frequently encountered on UBD/MPD depleted sections. Permeable and porous sections are able to pressure-deplete as field development progresses. Shales, with no effective permeability, usually retain original pressure. Designing for an underbalanced borehole relative to the partly de-pressured pay section will see considerably higher underbalanced states in the shale which can cause hole collapse.

MPD wells within a pay section can face shale stability issues as well. If pressure is being managed at a level to prevent fluid loss to the formation, that pressure level may still be well below original pressure in the shale sections.

The following design parameters are recommended when drilling UBD/MPD hole intervals or sections that require casing and cementing:

complete hole interval integrity testing at pressures equivalent to the planned casing cementing program to ensure the highest probability of a successful cementing operation and effective zonal isolation, and

an integrity test should be conducted prior to running casing to ensure the planned cementing program is appropriate and well control risks have been addressed.

Note. Mud system adjustments that require increasing the mud weight to combat hole instability problems can compromise the surface separation equipment (e.g., can increase erosion).

22.1.3.7 Temperatures

Flowing UBD/MPD well temperatures can be higher in the returning fluids due to less liquid in the wellbore (e.g., two-phase drilling) and/or with the inflow of reservoir fluids (e.g., UBD case). If higher temperatures are anticipated, expect an increased frequency of RCD servicing.

Low temperatures, as can occur in choke manifolds with substantial gas throughput, can also impact operations. If choking is required to reduce pressure significantly, consider using multiple pressure drop devices to minimize velocity changes through any one individual device. This will also impact erosion potential and the possibility for hydrate formation. As an example, rather than using a choke manifold with a single variable choke, consider one with single fixed bean and one variable.

22.1.3.8 Hydrate Risks

Hydrates are complex mixtures of gas-water solids which can form in areas of temperature / pressure decrease. Under the right conditions, hydrates can completely block flow.

Failure to plan for hydrate problems can impact obtaining sufficient flow information. If there is a possibility for a combination of gas and liquid water (either as a result of production with the gas, or from condensation as fluids transit the wellbore through the surface facilities), there is a possibility for hydrate formation, even at temperatures significantly above 0oC. If hydrates are possible, installation of facilities to mitigate potential effects may include:

IRP 22: UBD/MPD Operations March 2011 Page 15

additional pressure drop stages (e.g. use two chokes, one fixed and one variable) instead of one to stage pressure drop

using a dual-leg choke to allow alternate use if plugging occurs

dissolving hydrate plugs with neat ethylene glycol (i.e., MEG) or with a 50:50, methanol : water mixture (Methanol is faster but there are fewer safe handling and pumping issues with MEG. Methanol or glycol injection can inhibit hydrate formation.) see IRP 4: Well Testing and Fluid Handling, IRP 15: Snubbing Operations Note. Review safe work procedures with each service companys handling and injecting methanol. The use of methanol (or similar hydrate treatment products such as glycols) should be compatibility checked with all fluids used on site. The use of methanol should be risk and hazard assessed: meaning personnel exposure, circulation system contamination, flammability, elastomeric seal impacts should be resolved.

including provision for supply, storage, and use of specialty chemicals in overall HSE plan; (see Guideline on Managing Chemical Hazards)

installing line heaters for gas wells to allow preheating prior to a choke to ensure hydrate conditions cannot occur

22.1.3.9 Erosion Concerns / Corrosion Risks

Erosion and corrosion concerns should be addressed in the well design (refer to API Recommended Practice 92U Underbalanced Drilling Operations, Section 6, Process Control Equipment). It is recommended to

discuss specifications for surface process equipment and piping with the drilling and separation/compression Contractor(s) to agree upon a final design;

integrate items from this interchange, together with those from the Drilling Contractor and possibly other third-party concerns, into the PFD (The PFD should depict the intended surface equipment rig-up.); and

integrate all erosion concerns regarding line size (e.g. straight lines wherever possible, maximum pressure rating, connection type, permissible flow rates, solids loading, etc.) into the design.

To avoid NPT, discuss all necessary items required for the installation with contractors prior to rig-up. However, contractors sometimes substitute equipment at the last minute, and there may be some variation between the PFD and the exact rig-up. Regardless, the issued PFD is the intended rig-up, and the one which has been risk-assessed. If the ultimate installation is markedly different than the PFD issued for the program, differences (including those raising erosion and corrosion concerns) should be risk-assessed and mitigations for any potential hazardous situations expedited before putting that individual segment of the process equipment into play.

http://enform.ca/publications/irps/well_testing_and_fluid_handling.aspxhttp://enform.ca/publications/irps/well_testing_and_fluid_handling.aspxhttp://enform.ca/publications/irps/snubbingoperations.aspxhttp://courses.enform.ca/publications/guidelinesandbestpractices/managing_chemical_hazards.aspxhttp://global.ihs.com/doc_detail.cfm?currency_code=USD&customer_id=2125482C4C0A&shopping_cart_id=2824383F254B50284B5A2D58230A&rid=API1&country_code=US&lang_code=ENGL&item_s_key=00514759&item_key_date=991231&input_doc_number=&input_doc_title=underbalancehttp://global.ihs.com/doc_detail.cfm?currency_code=USD&customer_id=2125482C4C0A&shopping_cart_id=2824383F254B50284B5A2D58230A&rid=API1&country_code=US&lang_code=ENGL&item_s_key=00514759&item_key_date=991231&input_doc_number=&input_doc_title=underbalance

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When using drilling fluids that are water based and, in particular containing salts, corrosion of the BHA or drillstring components is a major concern. This risk is compounded by any presence of O2 in the circulation system (e.g., O2 content within membrane-generated N2).

Monitoring with corrosion rings in the drillpipe should be included in the general program. Corrosion within a re-entry well should be evaluated prior to starting a UBD/MPD program. Any resulting relevant information should be included in the well program.

22.1.3.10 Uphole Nuisance Gas

The potential for any uphole nuisance gas above the target pay zone should be managed in accordance with the IRP 22 Project Management Process (see Figure 1, Project Management Process) and risk assessment.

22.1.4 WELL CONTROL, BOP STACK-UPS, AND PROCESS FLOW DIAGRAMS Effective hazard management utilizes a PFD when integrating a UBD/MPD system to a conventional drilling system. There are several system configurations possible when applying UBD/MPD technology. Standardization of systems is challenging as the broad variability of well parameters and the versatility of the technology impose numerous potential risks. In order to control these risks and to achieve a level of industry standardization, four specific systems have been identified and recommended to cover the majority of the applications anticipated within the Western Canadian Sedimentary Basin.

The four recommended minimum PFD systems are located in the appendices as follows:

Appendix A: Atmospheric System

Appendix B: Sweet UBD/MPD System Less Than 14 MPa Reservoir Pore Pressure

Appendix C: Sweet UBD/MPD System Greater Than 14 MPa Reservoir Pore Pressure

Appendix D: Sour UBD/MPD System

The rationale for the two sweet systems, greater than and less than 14 MPa reservoir pore pressure, was risk-based from industry well control event experience. Experience has indicated that for reservoirs possessing greater than 14 MPa pore pressure, the likelihood of a well control event increases significantly (primarily from erosion of surface pipework and RCD element wear). It is also common for UBD/MPD surface separation systems to have specification breaks at 14 MPa.

Note. All UBD/MPD programs shall contain a site-specific and hazard assessed PFD. At the wellsite the PFD shall be readily available in the doghouse, at a minimum, and the command centre, if present.

22.1.4.1 Common PFD System Practices

The following summarizes recommended practices and associated rationale common to all four PFD systems.

IRP 22: UBD/MPD Operations March 2011 Page 17

Well Control

As much as reasonably possible, the rigs well control equipment should be independent from the UBD/MPD system. The rigs conventional well control equipment and conventional well control practices should remain unchanged. Well control equipment and well control practices must be in accordance with jurisdictional regulations. A rig pump, Hydraulic Control Remote (HCR), choke manifold, degasser, and flare tank should also be rigged-in and usable.

Rig personnel are highly trained and knowledgeable on conventional well control equipment and practices. To mitigate risks associated with UBD/MPD complexities, the UBD/MPD well control methodology should remain unchanged from conventional practices. It is safety critical to ensure all UBD/MPD operations are bridged to conventional well control practices and are clearly communicated (i.e., procedures, onsite training, etc). All possible UBD/MPD well control events should be defined and anticipated in planning documents such as the UBD flow control matrix. Procedures that support UBD/MPD events and allow conventional well control practices are essential.

Barriers

The NEB and British Columbia requires at least two independent and tested well barriers must be in place during oil and gas drilling and production operations (see Canada Oil and Gas Drilling and Production Regulations, Section 36 (2)).

In the province of Alberta, the ERCB does not specify barrier requirements. Conventional drilling practices state that an effective drilling fluid barrier is monitorable and exerts an overbalanced hydrostatic pressure that exceeds non-cased hole formation pressures by a minimum 1400 kPa (200psi); however, in UBD/MPD, drilling fluids cannot be considered an effective barrier.

In either UBD and/or MPD conditions, the well is contained on a single barrier (e.g., the lowermost BOP ring gasket). In jurisdictions where dual barriers are required, appropriate dispensation must be obtained from the Regulator by the operating company when operating on a single barrier.

Well Kill

If a well control event requires the well be killed, well kill procedures shall consider the volume of gas phase in the well. If the well contains significant gas volumes, greater than 30% by volume, the bullhead kill method is recommended.

If a well is killed for operational reasons other than for well controlsuch as trips planned to be overbalanced, suspending operations in low/no flow scenarios, or to conduct other operations requiring an overbalanced state (e.g., fishing, logging, coring, etc.)then use of the UBD/MPD system for dynamic circulation and constant BHCP (Bottom Hole Circulating Pressure) killing of the well is acceptable.

BOP Configurations

http://canadagazette.gc.ca/rp-pr/p1/2009/2009-04-18/html/reg1-eng.html

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BOP configurations are recommended in accordance with ERCB classifications documented in Directive 036: Drilling Blowout Prevention Requirements and Procedures.

The integrity of the drillstring and its connections below the NRV shall be verified during tripping operations. (see 22.2.3.1 Drillstring: NRV Recommendations)

Note. Drillstring integrity below any NRV (including the lowermost NRV) is unknown.

It must be noted that the integrity of the drillstring below the lowermost NRV is unknown until the drillstring is integrity tested. Refer to the Risk Register for integrity testing options, and the PFD for options for increasing lubricating space.

Ensure all BHA components are accurately measured and BOP stack measurements are also accurately recorded. The blind ram to base of RCD and top of annular preventer to the base of the RCD element are critical.

If complex assemblies are required to minimize risks, a Downhole Isolation Valve (DIV) is recommended; however, the least amount of change from conventional practices is considered inherently less risky. Well control events are most likely to occur when a drillstring is in the well; therefore, conventional configuration of rams can create the potential for problematic well control events (e.g., when servicing a failed HCR system including washing an HCR outlet spool).

For example, when servicing a failed annular preventer, double isolation is possible with a drillstring hang-off on the lowermost pipe rams and by closing the blind ram. When a washed-out or eroded secondary flowline outlet spool occurs, isolation is possible (i.e., closing of the pipe rams) when pipe rams are below the blind rams and a secondary flowline outlet spool is above the pipe rams.

Immediate bullhead killing of the well is recommended for all well control events that occur when the drillstring is out of the hole and the blind ram is closed.

Rig Choke System

In the PFDs the HCR is positioned outside of the secondary flow path to the UBD/MPD separation system. It is recommended that the rig choke system, including the HCR system, be as independent from the UBD/MPD system as possible. The HCR should not be used as part of normal UBD/MPD operations and should be independent.

It is recommended that the rig flare tank be tied into the rig choke manifold during all UBD/MPD operations to ensure that the UBD/MPD surface equipment remains isolated during a well control event.

It is recommended to NOT tie-in the rig choke manifold to the UBD/MPD surface separator (see PFDs in Appendices A - D).

Tubing Spool

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A tubing spool is recommended as single barrier isolation to supplement well control. It also assists in running/snubbing complex completion assemblies. Isolation using a tubing hanger assembly can allow for installation of the snubbing unit.

A tubing spool simplifies UBD completion procedures. It provides a means for isolating the well to remove drilling BOPs and install a wellhead.

In the event the pipe rams are closed, a kill line should be installed to the tubing spool to allow for bullhead killing. A bleed/choke is not recommended on the tubing spool due to the potential consequences from erosion washout (i.e., if the lowermost outlet loses integrity, there will be no well control means for isolation or closing in the well).

Optional UBD/MPD Equipment

Optional site-specific UBD/MPD equipment is indicated by dashed boxed areas on the PFDs.

Rotating Control Device and Primary Flowline Outlet

The Rotating Control Device (RCD) and the primary flowline outlet shall be positioned above the BOP stack. The RCD requires frequent inspection, intervention (particularly during tripping operations), and servicing. The BOP annular preventer and rams can be used to isolate the RCD and primary flowline outlet spool (e.g., servicing the RCD element). An isolation valve on the primary flowline is not required adjacent to the RCD, but a valve is required for isolation from the separator choke manifold and the secondary flowline.

Positioning large valves in the primary flowline adjacent to the RCD imposes significant hazards to personnel during rig-up/down. The likelihood of erosion washout between the RCD and upstream of the UBD/MPD choke manifold is very low. Any erosion washout of the UBD/MPD primary flowline is deemed a well control event and requires immediate closure of the appropriate BOP. An independent pressure bleed-off system is required between the RCD and BOP stack to allow for bleeding-off pressure during RCD servicing and to manage potentially trapped pressure.

Casing Pressure Monitoring

The casing and/or annulus pressure shall be monitorable at all times during UBD/MPD operations. To allow pressure to be monitored during tripping operations when the blind rams are closed, it is recommended to monitor pressure on the secondary flow line or an outlet on the tubing spool if available (i.e., below blind ram). BOP valve configuration accommodations shall be made to ensure that the casing pressure monitoring gauge / sensor is exposed to casing pressure during all UBD/MPD operations.

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Standpipe Manifold

Independent high and low pressure bleed-offs are recommended, with the low pressure capable of pressure relieving to atmospheric pressure and the high pressure routed to the separation system. Trapped pressure energized by a gas phase imposes a significant hazard to rig floor personnel during drillstring connections. Equipment and procedures shall be utilized in the drillstring to prevent trapped pressure hazards during drillstring connections.

Non-return valves (NRV) should be installed to prevent undesirable reverse flow to the rig mud pumps, to the mist pumps, and to the gas injection source. A NRV shall be installed in the standpipe manifold bleed-off line to prevent undesirable reverse flow from the separator to the standpipe/rig floor.

Separator Pressure Maintenance

Site-specific operations also impose risk to the separation system. For example, an MPD operation may have a risk of lost circulation and the well going on vacuum. Separation systems are not designed for a vacuum condition and thus a gas source for separator pressure maintenance is safety critical.

In the case of UBD/MPD drilling operations where only small amounts of gas phase is present in the returns, there is a risk that the separator will not be able to retain appropriate operating pressure. Therefore, a gas source is required for separator pressure maintenance. A site-specific risk and hazard assessment should be conducted to ensure the separator will retain its operating pressure at all times and contingency plans are in place in the event it does not.

Pressurized Sample Catchers

Pressurized sample catchers can impose hazards to personnel such as:

system over-pressured with blocked flow due to sample catchers not being pressure rated equivalent to choke manifold (i.e., pressure specification break) Note. When incompressible circulation systems are used, the response time to over-pressure is significantly less; therefore, blocked flow risk is significantly higher.

while catching samples during normal operations, gas/liquid/solids release due to trapped pressures within the system.

It is recommended to catch samples by conventional practice at the shale shaker, factoring in additional cuttings residence time with the separation system.

The use of pressurized sample catchers shall be appropriately hazard assessed and mitigations identified.

Potential mitigations may include:

pressure relief system (i.e., protection of specification break),

avoid diverting all flow through the pressurized sample catcher system, and

IRP 22: UBD/MPD Operations March 2011 Page 21

design the sample catcher system to be the same pressure rating as the UBD/MPD choke manifold.

22.1.4.2 Specific PFD System Practices

Atmospheric System

Hazard management for the atmospheric system focuses on fire and explosion risks. If hydrocarbons are expected, an inert gas should be used.

If an atmospheric system is to be used with air as the drilling medium and the risk of encountering hydrocarbons is present, then consider the following factors:

The primary flowline and separation system should be designed to avoid backpressure to the well (i.e., no choke manifold or shut-off valves).

The build-up of pressure significantly increases the fire and explosion risk when drilling with air.

The separation system used for air drilling operations shall operate at atmospheric pressure and thus provide the function of separating returning drilled solids and liquids from the gas phase.

During air drilling operations it is recommended to never let the wellbore pressure build to the point flammable/explosive conditions exist. As such, a gas detector measuring methane content, UEL and LELs must be installed in the return line in accordance with jurisdictional regulations. Operators planning air drilling operations with potential for natural gas inflow should be familiar with IRP Volume 18: Fire and Explosion Hazard Management.

Cold venting of the returning gas phase is recommended to avoid fire/explosion ignition source risks (sweet gas only). Site-specific dispersion modeling shall be conducted to ensure the flammable plume above the vented area does not impose explosion and/or flammability hazards.

Designs shall consider the possibility of encountering liquid hydrocarbons and/or coal.

The well control practice of soft shut-in (i.e., rig choke is always open) shall be used until the fire/explosion risk conditions in the well allow for a complete hard shut-in. (see 22.3.15 Air Drilling Operations, Air Drilling Recommended Practices regarding shut-in training)

A de-dusting pump is recommended to avoid hazards associated with dust. Optional chemical injection systems may be considered for foam drilling operations.

Sweet UBD/MPD System - Greater Than 14 MPa Reservoir Pressure

In general, higher pore pressures are accompanied by a greater likelihood of higher reservoir fluid flow rates, both for short term transient flow when the section is first penetrated, and for longer-term flow rates. With the higher possibility of erosional washout of the flow line or BOP components, the addition of a second pipe ram is

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recommended. The addition of a blind/shear ram may be a possible substitute for the second pipe ram based on a site-specific risk assessment. A secondary choke line is not recommended due to a higher risk of erosion with UBD/MPD operations.

Sour UBD/MPD System

The addition of a blind/shear ram is recommended due to the high risk of erosional washout of flow line and BOP components. Generally, higher pore pressures have a greater likelihood of higher reservoir fluid flow rates, both short transient flush production and longer term rates. Tripping operations should consider inert gas capping of the well to minimize the risk of H2S release.

The RCD should be monitored consistently and 24-hours a day by either a trained RCD technician or equivalent monitoring method as soon as the RCD is installed. A no-leak policy is recommended.

In accordance with ID 94-3: Underbalanced Drilling, the existence of H2S is defined by a representative wellhead sample. A closed circulating system is recommended for any H2S > 10 ppm. If any level of H2S is anticipated, operations shall be designed and conducted for zero worker exposure and zero uncontrolled H2S release.

A UBD/MPD closed circulating system is a handling system in which any re-circulated fluids are contained and/or not exposed to the atmosphere at any point. All solids and fluids handling at surface should be via closed tanks that have appropriately designed pressure maintenance and venting/flaring systems. (In this instance, venting refers to tank vapours that have been scrubbed of H2S.) In particular, closed mud pump suction tanks should account for significant change in liquid volumes (e.g., regulated positive pressure maintenance system).

A multi-stage separation system is recommended for site-specific scenarios that require re-circulation of drilling fluids. Sour fluids shall not be re-circulated down the drillstring; therefore, an H2S scrubbing system is required. Installation of an independent drilling fluid storage system that allows for uncontaminated fluid displacement throughout the surface standpipe system and an appropriate drillstring volume prior to making drillstring connections is recommended.

22.1.5 ENGINEERING REQUIREMENTS FOR HIGH RISK SCENARIOS Both UBD and MPD rely on more precise information than conventional drilling such as: reservoir type, location, contents, pressures, temperatures, stability, etc. UBD/MPD operations are complex. Successful delivery is contingent on the personnel, equipment, processes, and procedures all operating within expected limits.

Errors, omissions, or failures to plan adequately for specific situations can impact operational hazards as well as equipment requirements, and can easily negatively impact project execution time.

http://www.ercb.ca/portal/server.pt/gateway/PTARGS_0_0_322_252_0_43/http%3B/ercbContent/publishedcontent/publish/ercb_home/industry_zone/rules__regulations__requirements/information_letters__interim_directives/interim_directives__id_/id94_03.aspx

IRP 22: UBD/MPD Operations March 2011 Page 23

22.1.5.1 Equipment Specifications

The operating envelope, as determined by the safety-critical well parameters, defines specific equipment and procedural requirements. Multiphase flow modeling is commonly used in all aspects of planning and implementing UBD programs, and may be a component of MPD programs as well. Sophisticated multiphase flow models simulate well conditions to investigate factors ranging from UBD/MPD feasibility to optimizing changes in operating parameters caused by changing conditions during the UBD operations. Simulation results can be used to

establish operating parameters including injection rates along with wellhead and downhole pressures,

ensure adequate hole cleaning or motor performance,

evaluate fluids to achieve UBD or MPD conditions,

identify equipment technical specifications,

define the operating envelope for UBD/MPD,

monitor drilling to determine whether changes are needed to achieve operating parameters, or

develop an understanding of reservoir performance.

Once fundamentals for the UBD operation have been defined, one of the most valuable products of flow modeling is the operating envelope. This shows the range of conditions for which UBD/MPD conditions can be safely achieved and provides guidance in making appropriate changes to maintain UBD/MPD conditions while satisfying other operational requirements.

The list of equipment specifications necessary to execute a specific program include, but are not limited to, the following:

separator sizing,

volume requirements,

drillstring requirements,

wellhead requirements,

rotating diverters,

choke requirements,

flow line sizing,

flare stack height and sizing,

liquid and gas injection rates,

operational BOP equipment versus well control BOP equipment,

specialized tripping equipment (e.g., snubbing, DIV), and

surface tank fluid handling and management.

Page 24 IRP 22: UBD/MPD Operations March 2011

Risks associated with the specific program shall be evaluated. Procedures, equipment, and personnel to mitigate those hazards should be arranged prior to starting operations.

If conditions on site do not closely match the operational envelope evaluated, then risks for the specific situation should be evaluated, and the program should not proceed until a risk assessment is completed and communicated to onsite personnel.

22.1.5.2 Lease and Wellsite Spacing for Equipment

UBD and MPD operations involve more equipment than conventional drilling or completion activity. Frequently, extensive conventional activity precedes other operations. Careful consideration should be given to lease layout and spacing to allow positioning or commissioning of specialized gear when required.

At a minimum, lease and wellsite spacing must be in compliance with appropriate jurisdictionally regulated spacing requirements (see Figure 4 below). Spacing should agree with the prepared rig-up plan, while maintaining safe vehicle/equipment access and personnel access/escape routes throughout the operation.

Lease and spacing considerations for well designers include:

verify lease survey accuracy,

verify rig specifics layout accuracy,

primary UBD/MPD service supplier to provide site-specific lease spacing diagram,

primary UBD/MPD service provider to conduct site inspection as soon as possible,

if possible use drill side pipe racks only, and

verify regulatory stack height / flaring requirements.

Potential threats and consequences from inadequate lease layout planning include:

poor emergency response,

problems fitting equipment on location,

decreased access / egress in case of emergency,

inadequate flare spacing on location,

tree clearance could cause forest fires, and

program disruption / delays / costs impacts.

IRP 22: UBD/MPD Operations March 2011 Page 25

Provincial and federal (i.e., National Energy Board) lease and wellsite spacing requirements are available in

IRP Volume 20: Wellsite Design Spacing Recommendations.

IRP 20 covers the following:

Alberta / BC / Saskatchewan spacing requirements,

flare pit and stacks,

lease construction spacing checklist,

critical concerns,

positioning of flare stacks,

turning radius on access roads,

sewage (tanks/trenches/pits),

wellsite lighting, and

escape lines.

Required wellsite spacing has been considered in accordance with IRP 20, Figure 12 for Figure 4 below.

http://enform.ca/publications/irps/wellsitedesign.aspxhttp://enform.ca/media/3616/irp20_final_2008.pdf#page=51

Page 26 IRP 22: UBD/MPD Operations March 2011

Figure 4. UBD/MPD Surface Equipment Spacing Diagram

IRP 22: UBD/MPD Operations March 2011 Page 27

22.1.5.3 UBD Flow Control Matrix

Primary well control during conventional operations is provided by the hydrostatic pressure of the drilling fluid in use. In UBD, this is replaced by flow control where gas/liquid injection rates and wellhead pressure are manipulated to produce a targeted dynamic drawdown.

Reservoir inflow combines with injected fluids at the formation face. Surface flow of energized fluids and bottomhole pressure is controlled by managing surface wellhead pressure. Controlling bottomhole pressure limits the reservoir drawdown, or the pressure difference between existing reservoir pressure and the prevailing pressure in the wellbore; thereby, controlling the reservoir production rate.

Manageable wellhead pressures and returning reservoir fluids flow rates (particularly the gas phase) shall be clearly defined to ensure continuous and safe drilling operations. Defined pressures and flow rates allow for sufficient reaction time for crews to adjust the system in the event manageable levels are temporarily exceeded. As such, the maximum pressure and flow rate ratings of equipment are safety-factored to the manageable operating envelope and provide an appropriate range for allowing adjustments when nearing the systems operability maximums.

The UBD Flow Control Matrix defines an equipment operating envelope for drilling operations and bridges the UBD operation to well control. Unexpected pressures and flows (i.e., geological uncertainties) are most likely during drilling operations.

Figure 5 below, the Flow Control Matrix, summarizes flow and well control actions as functions of reservoir hydrocarbon inflow rate and flowing wellhead pressure. It provides illustration of appropriate actions for the UBD/MPD personnel to return the well flow rate and wellhead pressure parameters to the manageable operating envelope. It is intended for UBD drilling situations only and excludes any other operations.

Page 28 IRP 22: UBD/MPD Operations March 2011

Figure 5. UBD Flow Control Matrix

Wellhead Flowing Pressure (unit)

Range 1

(Min1-Max1)

Range 2

(Max1-Max2)

Range 3 >

Max 2

Su

rfac

e Fl

ow R

ates

(u

nit

s/d

ay)

Range 1

(0 Max1) Manageable

Stop drilling and adjust rates to increase BHP

SHUT IN on rigs BOP

Range 2

(Max1 Max2)

Stop drilling and adjust rates to increase BHP

Stop drilling and adjust rates to increase BHP

SHUT IN on rigs BOP

Range 3 > Max2

SHUT IN on rigs BOP

SHUT IN on rigs BOP

SHUT IN on rigs BOP

This UBD Flow Control Matrix is intended as a baseline template. Operators SHALL develop their own site-specific risk-based matrix.

Manageable

In the green Manageable area, flow rate and wellhead pressure are as expected and controllable.

Drilling ahead is permitted.

Downhole conditions are within the underbalanced target range, regarding:

formation flow capacity, formation stability limits, appropriate drawdown, drilling fluids in use, capability to control wellhead pressure, reliable measurement and flow capacity of the entire

circulation system, erosion potential, maximization of element service life of the RCD, and casing/wellhead design limits.

All of the above factors, and possibly more, dependent on the site-specific requirements, should be risk-assessed for all conditions in the UBD Flow Control Matrix.

IRP 22: UBD/MPD Operations March 2011 Page 29

Stop drilling and adjust

rates to increase BHP

If the operation strays into the yellow area, either the observed flow rate or wellhead pressure is too high.

Initially, injection rates and possibly surface backpressure should be adjusted until operations return to the green Manageable area. If these measures fail to achieve system stability, appropriate reactions should progress to ceasing drilling while adjustments are made, then to ceasing ro