Chief Counsel’s Report | 2011

the gulf oil D I SAS TE R

National Commission on the BP Deepwater Horizon Oil Spill And Offshore Drilling | Report to the President

National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Chief Counsel’s Report — Acknowledgments | i

Acknowledgments

irst and foremost, we thank the Commission and its co-chairs, William Reilly 

and Senator Bob Graham, for supporting our investigation throughout. We 

also thank the Commission‘s executive director, Richard Lazarus, for his 

extraordinary leadership. 

Richard Sears, the Commission‘s senior science and engineering advisor, was an integral part of 

our team from the very beginning. We relied heavily on his considerable technical expertise as 

well as his deep understanding of industry business practices and culture. On the rare instances 

in which Richard could not answer a question himself, he summoned support from the broad 

network of industry professionals he created over his 33 years at Shell.

Many individuals involved in the Macondo incident spoke with us voluntarily. They included rig 

crew members, cementers, mudloggers, equipment suppliers, and shore-based engineers. 

Notably, many members of BP‘s Macondo well team met repeatedly with us to explain the chain 

of events that led to the blowout. BP also released a report of its own nonprivileged investigation 

of the blowout, and then provided us access to supporting documents. While BP‘s report differs 

from ours in scope, purpose, and conclusions, it aided our efforts, and we commend BP for 

undertaking it. Transocean graciously invited us to visit one of its deepwater drilling rigs to 

appreciate firsthand the scale and complexity of its operations. Halliburton provided samples of 

cement materials for testing. And regulators from the former Minerals Management Service 

spoke candidly about their roles and capabilities.

To support the work of our own retained experts, experts from every corner of the drilling 

industry met with us, sometimes at great length, to help us understand both the basic science and 

engineering of offshore drilling and the possible causes of the blowout. Chevron went even 

further by providing cement testing services and the assistance of a uniquely qualified group of 

cement testing experts. We also extend special thanks to Darryl Bourgoyne, Steve Lewis, 

Erik Nelson, and Dr. John Smith. 

Megan O‘Leary, William Lane, Devin Price, Vincent Yuen, Christina Crankshaw, Sammy Joe 

Osborne, Corinne Bilyeu, and the rest of the staff at TrialGraphix created the sophisticated 

graphics and animations that we have used to explain the story of the Macondo blowout, and 

produced the Web and print versions of this Report. Their results speak for themselves. In 

addition, Paul Ortiz of Cisco Systems assisted in preparing our public hearing presentation.

Finally, we thank most of all our own very dedicated staff: counsels J. Jackson Eaton, 

Brent C. Harris, Jon Izak Monger, and Saritha Komatireddy Tice, our paralegal 

Joseph Hernandez, and our assistant Michelle Farmer. They showed once again how much a 

small group of talented and hardworking individuals can accomplish. We and the Commission 

owe them great thanks.

_________________

Fred H. Bartlit, Jr., Chief Counsel

_________________

Sambhav N. Sankar

Deputy Chief Counsel

_________________

Sean C. Grimsley

Deputy Chief Counsel

F
ii | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Table of Contents

Foreword ................................................................................................................. ix

Executive Summary of Findings .............................................................................. x

Technical Findings x

Management Findings x

Regulatory Findings xi

Chapter 1|Scope of Investigation and Methodology ................................................1

Nature of Report 1

Scope of Investigation and Report 1

Investigation Methodology 2

Structure of the Report 3

Chapter 2|Drilling for Oil in Deepwater.................................................................. 5

Oil and Gas in Deepwater 5

How to Drill a Deepwater Well 8

Chapter 3| Background on the Macondo Well, the Deepwater Horizon,

and the Companies Involved ................................................................................. 25

The Macondo Well 25

The Deepwater Horizon 26

Companies and Individuals Involved in the Macondo Blowout 30

Chapter 4|Technical Findings................................................................................ 35

Underlying Technical Causes 35

Underlying Management Causes 37

Chapter 4.1|Flow Path............................................................................................39

Potential Flow Paths 40

Forensic Evidence Suggests That Hydrocarbons Did Not Flow up the Annulus 

and Through the Seal Assembly 42

Hydrocarbons Appear to Have Flowed Into and up the Production Casing 48

Technical Findings 52

Chapter 4.2|Well Design........................................................................................ 53

Deepwater Well Design 53

The Macondo Well Design 55

Drilling the Macondo Well 58

Technical Findings 62

Management Findings 64

Chapter 4.3|Cement............................................................................................... 67

Well Cementing 67

Preparing for the Macondo Cement Job 77

Designing the Macondo Cement Job 78

Planning for and Installing Centralizers at Macondo 81

Float Collar Installation and Conversion at Macondo 87

Pre-Cementing Wellbore Conditioning at Macondo 90

Cementing Process at Macondo 92

The Float Check at Macondo 93

Cement Evaluation at Macondo 94

Technical Findings 95

Management Findings 102
Chief Counsel’s Report — Table of Contents | iii

Chapter 4.4|Foamed Cement Stability ................................................................. 111

Foamed Cement 111

Foamed Cement at Macondo 113

Technical Findings 120

Management Findings 123

Chapter 4.5|Temporary Abandonment ............................................................... 127

Temporary Abandonment 127

Temporary Abandonment at Macondo 128

Technical Findings 135

Management Findings 139

Chapter 4.6|Negative Pressure Test .................................................................... 143

Well Integrity Tests 143

Negative Pressure Test at Macondo 147

Technical Findings 160

Management Findings 161

Chapter 4.7|Kick Detection.................................................................................. 165

Well Monitoring and Kick Detection 165

Well Monitoring at Macondo 174

Technical Findings 182

Management Findings 184

Chapter 4.8|Kick Response.................................................................................. 193

Well Control Equipment 193

Kick Response at Macondo 195

Technical Findings 198

Management Findings 200

Chapter 4.9|The Blowout Preventer ................................................................... 203

Blind Shear Rams 204

Blind Shear Ram Activation at Macondo 206

ROV Hot Stab Activation at Macondo 208

Automatic Blind Shear Ram Activation at Macondo 208

Potential Reasons the Blind Shear Ram Failed to Seal 212

BOP Recertification 215

Technical Findings 216

Management Findings 217

Chapter 4.10|Maintenance................................................................................... 221

Transocean‘s Rig Management System 221

Competing Interests Between Drilling and Maintenance 222

Lack of Onshore Maintenance 222

Maintenance Audits and Inspections 223

Maintenance Findings 224

Chapter 5|Overarching Failures of Management ...............................................225

Leadership 225

Communication 227

Procedures 232

Employees 235

Contractors 237

Technology 240

Risk 242

Closing 249
iv | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Chapter 6|Regulatory Observations .....................................................................251

MMS Background 251

MMS Regulations Did Not Address Many Key Risk Factors for the Blowout 253

BOP Recertification 260

Ethical Considerations 261

Endnotes ..............................................................................................................262

Appendix A|Blowout Investigation Team ...........................................................346

Appendix B|Commission Staff............................................................................. 347

Appendix C|Acronyms .........................................................................................349

Appendix D|Chevron Laboratory Report Cover Letter ........................................351

Appendix E|Nile and Kaskida.............................................................................. 353

Schedule When the Deepwater Horizon Arrived at Macondo 353

Request to Suspend Operations at Kaskida 354
Chief Counsel’s Report — Figures and Tables | v

Figures and Tables

Figures

Chapter 2|Drilling for Oil in Deepwater

Figure 2.1. Schematic geological cross section. 5

Figure 2.2. Drilling. 9

Figure 2.3. Pore pressure and fracture gradients. 10

Figure 2.4. Casing strings (greatly simplified). 11

Figure 2.5. Rig structures. 12

Figure 2.6. Rig structures. 12

Figure 2.7. Early drilling phases. 14

Figure 2.8. Wellhead assemblies. 15

Figure 2.9. BOP components. 16

Figure 2.10. Flow in a typical mud system. 17

Figure 2.11. Casing hanger. 18

Figure 2.12. Wiper plugs. 18

Figure 2.13. Cementing. 19

Figure 2.14. Perforating the production casing. 20

Figure 2.15. Barriers in a well. 21

Figure 2.16. Simplified AMF control system schematic. 22

Chapter 3| Background on the Macondo Well, the Deepwater Horizon, and the 

Companies Involved

The Deepwater Horizon. 24

Figure 3.1. Deepwater Horizon. 26

Figure 3.2. Main deck. 27

Figure 3.3. Decks. 28

Figure 3.4. Mud pits and moon pool. 28

Figure 3.5. Subsurface portion of the Deepwater Horizon. 29

Figure 3.6. Blowout preventer. 29

Figure 3.7. Blowout preventer. 30

Figure 3.8. Deepwater Horizon‘s organizational structure. 31

Chapter 4.1| Flow Path

Figure 4.1.1. Possible flow paths for hydrocarbons. 39

Figure 4.1.2. Flow through the seal assembly. 40

Figure 4.1.3. Flow up the production casing. 41

Figure 4.1.4. Exterior of the Macondo production casing hanger and seal assembly. 44

Figure 4.1.5. Interior of the Macondo production casing hanger compared to new 

equipment. 45

Figure 4.1.6. Undamaged metal edges of the casing hanger and seal assembly. 46

Figure 4.1.7. Halliburton post-cement-job report. 48

Figure 4.1.8. Erosion of the inside of the casing hanger. 49

Figure 4.1.9. 16-inch casing and rupture disks. 50

Chapter 4.2| Well Design

Figure 4.2.1. Artist‘s rendering of the Macondo well. 53

Figure 4.2.2. Narrow drilling margins. 54

Figure 4.2.3. Annular pressure buildup (APB). 55

Figure 4.2.4. Offset wells and seismic data. 56

Figure 4.2.5. Rupture disks. 57

Figure 4.2.6. Protective casing. 57

Figure 4.2.7. Casing options in deepwater drilling. 58

Figure 4.2.8. Timeline of drilling events. 59

Figure 4.2.9. Cementing a long string vs. cementing a liner. 62
vi | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Chapter 4.3| Cement

Figure 4.3.1. Typical completed cement job. 67

Figure 4.3.2. Sample caliper log data showing open hole diameter by depth. 68

Figure 4.3.3. Centralizer. 68

Figure 4.3.4. Top view of off-centered casing. 69

Figure 4.3.5. Centralizer sub. 69

Figure 4.3.6. Float valve conversion. 70

Figure 4.3.7. Full bottoms up. 70

Figure 4.3.8. Wiper plugs cause cement contamination. 71

Figure 4.3.9. Lift pressure. 72

Figure 4.3.10. Bumping the plugs. 73

Figure 4.3.11. Cement bond log tool. 74

Figure 4.3.12. Remedial cementing—squeeze job. 75

Figure 4.3.13. Centralizer sub (top) and slip-on centralizer with stop collars (bottom). 83

Figure 4.3.14. Gregg Walz April 16, 2010 email to John Guide about centralizers. 84

Figure 4.3.15. Centralizers delivered to the Deepwater Horizon on April 16, 2010. 85

Figure 4.3.16. John Guide April 16, 2010 email to Gregg Walz about centralizers. 85

Figure 4.3.17. Auto-fill float collar. 88

Figure 4.3.18. BP‘s pre-cementing mud circulation. 91

Figure 4.3.19. Decision tree. 94

Figure 4.3.20. Clogged reamer shoe. 101

Figure 4.3.21. Ball forced through tube. 101

Figure 4.3.22. Page 23 of Halliburton‘s April 18, 2010 OptiCemTM report. 109

Chapter 4.4| Foamed Cement Stability 

Figure 4.4.1. Foam testing apparatus. 112

Figure 4.4.2. Foam testing apparatus. 112

Figure 4.4.3. Foam testing apparatus. 112

Figure 4.4.4. Halliburton evidence of test times. 118

Chapter 4.5| Temporary Abandonment 

Figure 4.5.1. Planned configuration after temporary abandonment. 128

Figure 4.5.2. Lockdown sleeve. 129

Figure 4.5.3. BP subsea wells organization. 130

Figure 4.5.4. Multiple last-minute revisions to the temporary 

abandonment procedure. 132

Figure 4.5.5. Bridge plug. 137

Chapter 4.6| Negative Pressure Test

Figure 4.6.1. Well integrity tests. 143

Figure 4.6.2. Seal assembly test. 144

Figure 4.6.3. Positive pressure test. 145

Figure 4.6.4. Negative pressure test. 146

Figure 4.6.5. End of cement to temporary abandonment. 146

Figure 4.6.6. Preparations for the negative pressure test. 147

Figure 4.6.7. First test failure. 148

Figure 4.6.8. Second test failure. 148

Figure 4.6.9. Negative pressure test progress, 3 p.m. on April 20, 2010. 149

Figure 4.6.10. 4 p.m. 150

Figure 4.6.11. 4:53 p.m. 151

Figure 4.6.12. 4:55 p.m. 152

Figure 4.6.13. 4:58 p.m. 153

Figure 4.6.14. 5:10 p.m. 154

Figure 4.6.15. 5:26 p.m. 155

Figure 4.6.16. 5:53 p.m. 156

Figure 4.6.17. Bladder effect. 157

Figure 4.6.18. 6:40 p.m. 158

Figure 4.6.19. Spacer migration. 159
Chief Counsel’s Report — Figures and Tables | vii

Chapter 4.7| Kick Detection

Figure 4.7.1. Active pit volume in a closed-loop system. 166

Figure 4.7.2. Active pit volume in a non-closed-loop system. 167

Figure 4.7.3. Hitec data display. 169

Figure 4.7.4. Sperry-Sun data display. 169

Figure 4.7.5. Flow-out sensors and flow line camera. 170

Figure 4.7.6. Transocean‘s Deepwater Horizon Emergency Response Manual. 171

Figure 4.7.7. Rig personnel on duty during the final displacement. 174

Figure 4.7.8. Erratic vs. normal flow-out. 175

Figure 4.7.9. Typical flow-out signature vs. spike at 9:08 p.m. 178

Figure 4.7.10. Drill pipe pressure anomalies from 9:01 to 9:14 p.m. 179

Figure 4.7.11. Drill pipe pressure and kill line pressure anomalies from 

9:27 to 9:40 p.m. 180

Figure 4.7.12. Last two hours of Sperry-Sun data. 191

Chapter 4.8| Kick Response

Figure 4.8.1. Diverter system. 195

Figure 4.8.2. BOP control panels on the rig floor and bridge. 197

Figure 4.8.3. BOP control panels on the rig floor and bridge. 197

Figure 4.8.4. Transocean‘s ―procedures for handling gas in the riser.‖ 201

Chapter 4.9| The Blowout Preventer

Figure 4.9.1. Transporting the Deepwater Horizon BOP. 203

Figure 4.9.2. The Deepwater Horizon blowout preventer stack. 204

Figure 4.9.3. The Deepwater Horizon blowout preventer stack. 204

Figure 4.9.4. Blind shear ram. 204

Figure 4.9.5. Tool joint in the blind shear ram. 205

Figure 4.9.6. Deepwater Horizon blowout preventer‘s closed blind shear ram 

(top view). 207

Figure 4.9.7. AMF system. 209

Figure 4.9.8. BOP‘s electrical schematic. 211

Figure 4.9.9. Erosion in the BOP. 212

Chapter 5| Overarching Failures of Management

Figure 5.1. BP internal presentation slide. 226

Chapter 6| Regulatory Observations

Figure 6.1. Chapter 3 of the Commission‘s full report. 251

Figure 6.2. BOEMRE organizational chart for the Gulf of Mexico region 

in July 2010. 252

Figure 6.3. MMS regulation 30 C.F.R. § 250.428. 255

Figure 6.4. MMS regulation 30 C.F.R. § 250.401. 257

Figure 6.5. BP‘s April 16 application for permit to modify. 258

Tables

Chapter 4.3| Cement

Table 4.3.1. Low pressure observed after circulation established. 90

Table 4.3.2. Plans reduce pre-cement circulation volumes and rates. 92

Table 4.3.3. Cementing volumes. 93

Table 4.3.4. Flow rate and differential pressure needed to convert. 100
viii | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Chapter 4.4| Foamed Cement Stability 

Table 4.4.1. Halliburton‘s internal laboratory data concerning the stability of the 

Macondo cement slurry. 122

Chapter 4.7| Kick Detection

Table 4.7.1. Personnel and places with access to the rig‘s Sperry-Sun data. 173

Chapter 4.9| The Blowout Preventer

Table 4.9.1. Control pod battery replacements (based on available records). 211

Table 4.9.2. Leaks on the Deepwater Horizon blowout preventer (partial list). 214

Table 4.9.3. Modifications to the Deepwater Horizon blowout preventer. 218-19 

Chapter 5| Overarching Failures of Management

Table 5.1. Timeline of changes to the temporary abandonment procedure. 233

Table 5.2. Examples of decisions that increased risk at Macondo while potentially 

saving time. 246
Chief Counsel’s Report — Foreword | ix

Foreword

hen President Obama created the National Commission on the 

BP Deepwater Horizon Oil Spill and Offshore Drilling he 

instructed the Commission to ―examine the relevant facts and 

circumstances concerning the root causes of the Deepwater 

Horizon oil disaster.‖ This Chief Counsel‘s Report is the result of an 

extraordinary effort to carry out that mission. It is essential reading for 

anyone looking to extract the lessons of Macondo and avoid a repeat of that 

terrible tragedy.

Notwithstanding demanding time constraints, the Commission‘s Chief Counsel Fred Bartlit and 

his investigative team have provided the most comprehensive, coherent, and detailed account of 

the events leading up to the blowout and explosion. The wealth of material presented here offers 

new details and documentation in support of the Commission‘s final report, Deep Water: The 

Gulf Oil Disaster and the Future of Offshore Drilling, released on January 11, 2011.

What the investigation makes clear, above all else, is that management failures, not mechanical 

failings, were the ultimate source of the disaster. In clear, precise, and unflinching detail, this 

Report lays out the confusion, lack of communication, disorganization, and inattention to crucial 

safety issues and test results that led to the deaths of 11 men and the largest offshore oil spill in 

our nation‘s history.

The Chief Counsel‘s efforts were integral to the Commission‘s deliberations and findings. For that 

reason, this report is an important companion to the full report of the Commission. It stands on 

its own as well—a durable contribution to our understanding of the importance of responsible 

management systems and state-of-the-art practices, and the dire consequences when they fail.

_________________

Senator Bob Graham

Commission Co-Chair

_________________

William K. Reilly 

Commission Co-Chair

W
x | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Executive Summary of Findings

he Macondo blowout happened because a number of separate risk 

factors, oversights, and outright mistakes combined to overwhelm the 

safeguards meant to prevent such an event. The Chief Counsel‘s team 

identified a number of technical risk factors in the design, execution, 

and testing of the Macondo well. The team was also able to trace all of these 

failures back to an overarching failure of management. Better management of 

personnel, risk, and communications by BP and its contractors would almost 

certainly have prevented the blowout. The Macondo disaster was not inevitable.

Technical Findings

The root technical cause of the blowout is now clear: The cement that BP and Halliburton 

pumped to the bottom of the well did not seal off hydrocarbons in the formation. While we may 

never know for certain the exact reason why the cement failed, several factors increased the risk 

of cement failure at Macondo. They include the following: First, drilling complications forced 

engineers to plan a ―finesse‖ cement job that called for, among other things, a low overall volume 

of cement. Second, the cement slurry itself was poorly designed—some of Halliburton‘s own 

internal tests showed that the design was unstable, and subsequent testing by the Chief Counsel‘s 

team raised further concerns. Third, BP‘s temporary abandonment procedures—finalized only at 

the last minute—called for rig personnel to severely ―underbalance‖ the well before installing any 

additional barriers to back up the cement job. 

BP missed a key opportunity to recognize the cement failure during the negative pressure test that 

its well site leaders and Transocean personnel conducted on April 20. The test clearly showed 

that hydrocarbons were leaking into the well, but BP‘s well site leaders misinterpreted the result. 

It appears they did so in part because they accepted a facially implausible theory suggested by 

certain experienced members of the Transocean rig crew. Transocean and Sperry Drilling rig 

personnel then missed a number of further signals that hydrocarbons had entered the well and 

were rising to the surface during the final hour before the blowout actually occurred. By the time 

they recognized a blowout was occurring and activated the rig‘s blowout preventer, it was too late 

for that device to prevent an explosion. By that time, hydrocarbons had already flowed past the 

blowout preventer and were rushing upward through the riser pipe to the rig floor.

Management Findings

The Chief Counsel‘s team concluded that all of the technical failures at Macondo can be traced 

back to management errors by the companies involved in the incident. BP did not fully appreciate 

all of the risks that Macondo presented. It did not adequately supervise the work of its 

contractors, who in turn did not deliver to BP all of the benefits of their expertise. BP personnel 

on the rig were not properly trained and supported, and all three companies failed to 

communicate key information to people who could have made a difference. 

T
Chief Counsel’s Report — Executive Summary| xi

Among other things:

 BP did not adequately identify or address risks created by last-minute changes to well 

design and procedures. BP changed its plans repeatedly and up to the very last minute, 

sometimes causing confusion and frustration among BP employees and rig personnel.

 When BP did send instructions and procedures to rig personnel, it often provided 

inadequate detail and guidance.

 It is common in the offshore oil industry to focus on increasing efficiency to save rig time 

and associated costs. But management processes must ensure that measures taken to 

save time and reduce costs do not adversely affect overall risk. BP‘s management 

processes did not do so.

 Halliburton appears to have done little to supervise the work of its key cementing 

personnel and does not appear to have meaningfully reviewed data that should have 

prompted it to redesign the Macondo cement slurry.

 Transocean did not adequately train its employees in emergency procedures and kick 

detection, and did not inform them of crucial lessons learned from a similar and recent 

near-miss drilling incident.

What the men and women who worked on Macondo lacked—and what every drilling operation 

requires—was a culture of leadership responsibility. In remote offshore environments, 

individuals must take personal ownership of safety issues with a single-minded determination to 

ask questions and pursue advice until they are certain they get it right.

Regulatory Findings

The Commission‘s full report examines in depth the history of Minerals Management Service 

(MMS) regulatory programs and makes specific recommendations for regulatory reform of what 

is now the Bureau of Offshore Energy Management, Regulation, and Enforcement (BOEMRE). 

The Chief Counsel‘s team found that the MMS regulatory structure in place in April 2010 was 

inadequate to address the risks of deepwater drilling projects like Macondo. Then-existing 

regulations had little relevance to the technical and management problems that contributed to the 

blowout. Regulatory personnel did not have the training or experience to adequately evaluate the 

overall safety or risk of the project. 
4 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling
Chief Counsel’s Report — Chapter 1: Scope of Investigation and Methodology | 1

Chapter 1|Scope of Investigation 

and Methodology

Nature of Report

On May 21, 2010, President Barack Obama signed an Executive 

Order establishing the National Commission on the BP Deepwater 

Horizon Oil Spill and Offshore Drilling (“the Commission”).1 The 

Order directed the Commission to “examine the relevant facts 

and circumstances concerning the root causes of the Deepwater Horizon oil 

disaster.”2

 The Order instructed the Commission to present a final public report 

of its findings to the President within six months of the date of its first meeting. 

The Commission first met on July 12, 2010.

The Commission appointed Fred H. Bartlit, Jr. as Chief Counsel to investigate and present to 

the Commission findings regarding the root causes of the Macondo explosion and blowout.3

 At 

public hearings on November 8 and 9, 2010, Bartlit and his team (“the Chief Counsel’s team”) 

presented preliminary findings to the Commission regarding the technical, managerial, and 

regulatory causes of the rig explosion and well blowout. Bartlit and the Chief 

Counsel’s team emphasized at the time that their investigation was 

ongoing and that these findings were preliminary. 

The Commission set forth its findings regarding the root causes 

of the blowout in a report that it released on January 11, 

2011. Several of the Commission’s findings were based on the 

work of the Chief Counsel. Given the factual and technical 

complexity of some of the underlying causes of the blowout, 

the Commission asked the Chief Counsel’s team to issue a 

separate Chief Counsel’s Report setting forth in greater detail 

their findings and conclusions regarding the technical, managerial, 

and regulatory causes of the blowout. This document is that report. 

Certain sections of this Report are accompanied by video clips accessible on the Commission’s 

website at www.oilspillcommission.gov. The video clips contain graphics and narration to 

better explain many of the concepts and findings contained in this Report. They are meant to 

supplement, not to replace, the Report itself. 

Scope of Investigation and Report

The Chief Counsel focused his investigation on the technical, managerial, and regulatory causes 

of the blowout. This Report sets forth the conclusions of that investigation. 

The Report does not discuss containment or response issues, except insofar as certain technical 

issues related to the blowout also bear on those issues. A separate Commission investigative 
2 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

team addressed these issues. The results of that team’s work are reflected in Chapter 5 

of the Commission’s report and in several Commission staff papers, available on the 

Commission website.

Similarly, this Report does not extensively review or analyze the regulatory structure in place 

prior to the spill, but rather addresses the extent to which the absence of particular regulations or 

enforcement may have contributed to the blowout. This Report also does not broadly review or 

critique oil and gas industry practices prior to the spill, except to the extent such practices related 

directly to the Macondo blowout. Other members of the Commission’s staff focused on these 

broader issues, all of which are addressed in the Commission’s report and staff papers. 

The Chief Counsel’s team has worked to provide as exhaustive an analysis of the blowout’s causes 

as is possible given the evidence currently available. Limitations in that evidence prevent the 

team from issuing findings on some issues.

The Chief Counsel’s team cannot offer any final conclusions regarding whether and to what extent 

the Macondo well’s blowout preventer (BOP) failed. The government has engaged the Norwegian 

engineering firm DNV (Det Norske Veritas) to perform a forensic analysis on the BOP and 

determine whether it worked as expected and, if not, how and why it failed. The Chief Counsel’s 

team believes that its technical and management findings will stand following the outcome of 

the pending BOP tests. Information available from those on the rig on April 20 indicates that 

the BOP was activated, at best, only moments prior to mud overflowing onto the rig floor. And 

all available evidence shows that by the time it was activated, hydrocarbons were in the riser and 

expanding rapidly to the surface and the rig. It thus appears that the initial explosions and fire 

would have occurred, and 11 men would have died, regardless of the function and state of the BOP 

at the time of the blowout.

As of the date of this Report, DNV is still conducting its analysis. It would be premature for the 

Chief Counsel’s team to issue conclusive findings concerning potential BOP failures before that 

analysis is complete.

The Chief Counsel’s team based its findings on evidence and information available to date. In 

some instances, that evidence or information was not available when the Commission issued its 

findings on January 11. And to the extent that new or additional information is revealed regarding 

issues in this Report, the team may alter or supplement its findings. 

Investigation Methodology

The Chief Counsel’s team’s investigation was extensive. The team collected documents from 

the companies involved, interviewed percipient and other witnesses, met repeatedly with the 

companies principally involved in the blowout, reviewed materials gathered by other investigative 

bodies, engaged and consulted experts, met with industry representatives, and met with 

representatives from non-industry interest groups. The Chief Counsel’s team conducted hearings 

on November 8 and 9, 2010, during which it questioned, on the record, representatives from BP, 

Halliburton, and Transocean as well as industry experts, regulators, and the executive officers of 

Shell and Exxon. 

Congress did not provide the Commission with subpoena power. The Chief Counsel’s team 

therefore obtained information about the blowout through the cooperation of many of the 

companies and individuals involved, and through the cooperation of technical experts in the 

oil and gas industry. The team encouraged cooperation by conducting its investigation in a 
Chief Counsel’s Report — Chapter 1: Scope of Investigation and Methodology | 3

completely transparent manner, allowing all of the companies and individuals involved to 

review and refute the team’s preliminary findings. With a few exceptions, these companies 

and individuals cooperated in an unprecedented fashion. The Commission also obtained the 

cooperation of other investigative bodies, including most notably the joint Coast Guard-BOEMRE 

investigation. The lack of subpoena power therefore did not meaningfully hinder the 

team’s investigation. 

Every offshore drilling incident deserves serious scrutiny, if only to identify lessons for the oil and 

gas industry as a whole. But the Deepwater Horizon incident involved special circumstances; 

not every offshore accident will merit the creation of a Presidential Commission. Government 

and industry should therefore create a standing organization or pre-existing structure that will 

facilitate future investigations similar to the one the Chief Counsel’s team conducted. That 

entity should have all of the following: (1) pre-existing subject-matter expertise; (2) investigative 

experience and a clear investigative mandate; (3) a focus on finding facts rather than determining 

or evaluating legal liability; and (4) the power to compel testimony and the production of 

evidence. The oil and gas industry and Congress should consider creating such an organization 

or clarifying that an existing organization fulfills that role. The structure and organization of the 

National Transportation Safety Board may provide a useful model.

Structure of the Report

Chapter 2 provides introductory and background material, including a detailed explanation of 

how to drill a deepwater well. Chapter 3 presents a timeline of relevant events leading up to the 

blowout and a description of the parties and witnesses involved.

Chapter 4 is the lengthiest chapter in the Report. It sets forth the Chief Counsel’s team’s technical 

findings and conclusions regarding the technical causes of the blowout. Chapter 4 lists actual 

causes, potential causes that the Chief Counsel’s team cannot rule out, and potential causes 

that the team can rule out even though they appeared credible in the months soon after the 

blowout. Chapter 4 also briefly describes management failures that may have contributed to each 

technical cause. 

Chapter 5 identifies broader management failures that contributed to the blowout. 

Finally, Chapter 6 addresses regulatory failures that may have contributed to the blowout. 

Chief Counsel’s Report — Chapter 2: Drilling for Oil in Deepwater | 5

Figure 2.1. Schematic geological cross section. 

TrialGraphix

Hydrocarbons trapped beneath an impermeable layer.

Chapter 2|Drilling for Oil in Deepwater

Oil and Gas in Deepwater

How Oil and Gas Form 

Offshore oil and gas reservoirs are formed from sediments deposited 

by rivers flowing from land into the ocean. Those sediments 

originate hundreds and sometimes thousands of miles away, in 

the mountains and broad uplands of an adjoining continent. If the 

sediments contain organic materials, and if geological processes later subject 

these sediments to intense pressure and heat, the organic materials can be 

transformed into liquid and gaseous hydrocarbons over the course of millions of 

years. The hydrocarbons may remain in the source rock where they originally 

formed, or they can be expelled from the source rock and into other, more porous 

rock layers. The hydrocarbons tend to migrate upward because they are lighter 

than other fluids in the pore spaces. 

River Delta

Impermeable Trap Layer

Seafloor

Sediment Layers

Ocean

TrialGraphix

Reservoir Zone 

“Hydrocarbons”
6 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

If a path of porous rock layers leads to the surface, the hydrocarbons will emerge above ground 

in a seep or tar pit. If an impermeable trap layer instead blocks the way, the hydrocarbons can 

collect in porous rock beneath this seal (see Figure 2.1). Drilling for oil consists first of finding 

“reservoir zones” (or “pay zones”) of trapped hydrocarbons and then drilling through the trap 

layers into the oil. 

The weight of sediments and fluids above the oil-bearing zone exert tremendous 

pressure on the trapped hydrocarbons. The pressure can be sufficient to force 

the hydrocarbons all the way to the surface once a well is drilled. Over time, the 

reservoir pressures can drop as hydrocarbons are extracted, and the hydrocarbons 

then may need to be pumped out of the well. 

Deepwater Oil and Gas Reservoirs in the Gulf of Mexico

The Gulf of Mexico is a rich hydrocarbon province. The Mississippi and other 

coastal rivers have been eroding the North American continent and have deposited 

tens of thousands of feet of organic sediments in the Gulf over the past few tens of 

millions of years. The sedimentary section beneath the sea bed of the central Gulf of 

Mexico is made up primarily of sand and finer grained shale deposited slowly over 

time in successive layers. 

The thick sedimentary section of the Gulf of Mexico has been the focus of offshore oil and gas 

exploration efforts since the 1930s. Over many decades, the waters of the Gulf have developed 

into one of the world’s most prolific hydrocarbon provinces, yielding tens of billions of barrels 

equivalent of oil and natural gas. Today much of the submerged land in the Gulf is administered 

by the federal government and therefore considered part of the “outer continental shelf.” (The 

National Commission’s final report discusses the history of oil exploration in the Gulf of Mexico in 

Chapter 2.) 

Early exploration in the Gulf of Mexico focused on what is known as “shallow water” oil deposits 

as opposed to “deepwater” deposits. Shallow water wells are typically drilled into sediments that 

lie atop the continental shelf where it extends into the ocean. 

In the central Gulf of Mexico (south of Louisiana), the continental shelf slopes down gently to 

water depths of roughly 600 feet. At a water depth of about 600 feet, there is a marked transition 

from the continental shelf to continental slope. On the slope, water depth increases more quickly 

with distance from shore, and the sea bottom and underlying geology becomes more complex. 

Although there is no precise definition for the term, “deepwater” wells are typically drilled into 

sediments that lie on the continental slope and beyond.*

 

Deepwater wells involve markedly different conditions from shallow water wells. The water 

depth obviously increases, but the sea bottom and geological conditions become more complex 

too. The sedimentary layers in deeper water are also different. While there is generally 

continuous deposition of sand and shale on the shelf, deepwater sediments can be dominated by 

the deposition of turbidites. Turbidites are sediments that are deposited episodically during 

underwater avalanches or other discrete events. Such events can create thick layers of sand that 

can be very well sorted and display certain attractive reservoir properties: high porosity, the 

* Different companies and governmental organizations have adopted definitions for deepwater ranging from 

600 to 1,500 feet. The Commission’s report used 1,000 feet as the starting point of deepwater, a definition 

that is used by many in the oil and gas industry.

Porosity and Permeability. Rock 

layers vary according to two 

important measures: porosity 

and permeability. Porosity is the 

percentage of the rock that is made 

up of microscopic pore spaces—

places where fluid can reside. 

Permeability is the ease with which 

fluid can flow through a rock and is 

a measure of how well the rock’s 

pore spaces are connected. 
Chief Counsel’s Report — Chapter 2: Drilling for Oil in Deepwater | 7

fraction of rock volume available for holding oil and gas, and high permeability, the ability of 

fluids to move through the rock. These properties make turbidites some of the best oil and gas 

reservoirs. Individual turbidite layers in the Gulf of Mexico can be many tens of feet to more than 

several hundred feet thick. 

In addition to changes in the underlying geology, the greatly increased water depth requires 

different drilling approaches. In water depths greater than a few hundred feet, wells are drilled 

using floating rather than bottom-based rigs. 

In water depths greater than about 1,000 feet, it is increasingly impractical to conduct production 

operations from structures that are supported by the ocean floor, and floating facilities and subsea 

production systems dominate. 

These fundamental changes in drilling methods and reservoir geology combine to define the 

transition to deepwater. 

The Deepwater Opportunity, Attraction, and Challenge

Because of the complexities of deepwater operations, developing a major deepwater oil field 

can cost enormous sums of money—far more than shallow water development. To make such 

developments economically viable, oil companies must identify highly productive reservoirs and 

then install high-productivity wells and production systems. Deepwater turbidite reservoirs are 

ideal targets because of their high porosity and permeability. Good shallow water wells produce 

at rates of a few thousand barrels of oil a day. By contrast, deepwater wells commonly produce 

more than 10,000 barrels per day. 

In the early stages of deepwater exploration, operators were surprised by the productivity of 

deepwater reservoirs. For instance, when Shell developed the Auger Field in the early 1990s, 

the platform for collecting oil from the wells in the field was originally designed to handle about 

40,000 barrels per day of production. Shell was able to increase the platform’s capacity to 

greater than 100,000 barrels per day, despite the fact that it had drilled less than half the wells it 

originally planned to develop in the Auger Field. 

These kinds of reservoirs, which deliver high rates of flow for long periods of time, became the 

standard for deepwater developments. Drilling wells into these reservoirs became a critical 

factor for deepwater project success because these production rates justified the high cost of 

deepwater development. 

Favorable geology, while critical, does not alone guarantee deepwater success. It was important 

in early deepwater developments to establish a “learning curve” where successful engineering 

practices could be developed and replicated in successive field developments. 

In its early Gulf of Mexico deepwater developments in the 1990s, for instance, Shell was able to 

cut the per barrel development cost by nearly two-thirds over time. Further optimization by Shell 

and other operators continued to improve the economics of deepwater operations. 

As a result, with oil prices and price outlook low in the late 1990s, major oil companies moved 

aggressively into the deepwater Gulf of Mexico. While these operations were expensive in 

absolute terms, the development cost per barrel of a carefully executed deepwater project became 

comparable to shallow water and even small onshore developments. 
8 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Deepwater Reservoir Pressures

Another feature of deepwater Gulf of Mexico reservoirs that contributed to overall well 

productivity also made drilling in deepwater significantly more dangerous: The oil and gas in 

deepwater reservoirs was often under very high pressure. 

Pressure Gradient. In oil and gas drilling, pressure is usually described in terms of a pressure 

gradient measured from the surface and expressed as an equivalent density of a column of fluid. 

A “normal” gradient is similar to that produced by a column of seawater, or 8.6 pounds per gallon 

(ppg). Many deepwater reservoirs, however, are at pressures exceeding 12 ppg. These pressures 

are not uncommon in oil and gas exploration, but they represent a challenge in that they must 

be managed carefully. 

Managing high pressures in deepwater presents unique challenges. The oil found in 

deepwater Gulf of Mexico reservoirs typically contains a significant amount of dissolved natural 

gas. As the oil comes to the surface, the decrease in pressure allows much of this gas to come out 

of solution. Deepwater Gulf deposits also commonly contain “free gas,” which is natural 

gas that exists separate from the oil, either as a gas cap in the same reservoir sand or a separate 

gas-bearing zone. 

The pressure in a deepwater reservoir can often exceed 10,000 to 15,000 pounds per square 

inch (psi), several hundred to more than 1,000 times the pressure at the surface. As oil and gas 

come to the surface, they expand. While the expansion of the oil is moderate, the gas expands 

in proportion to the drop in pressure. As a result, 10 barrels (bbl) at 5,000 feet could be greater 

than 1,000 bbl at the surface.

For these reasons, the subsurface pressure and the expansion of fluids flowing to the surface must 

be carefully managed. The oil and gas industry has developed tools and techniques for doing so. 

The next section discusses the specific technical tools and methods used to contain and control 

these pressures. 

Rig personnel must be especially vigilant at a deepwater well; because of the pressures involved, 

it is critical that they detect and address hydrocarbon influxes into the well as early as possible. If 

they do not stop such influxes early, the rapid expansion of hydrocarbons as they near the surface 

can become difficult, if not impossible, to control. 

How to Drill a Deepwater Well

There are three phases to safely extracting hydrocarbons from an offshore deepwater reservoir. 

The first phase is drilling. During this phase, rig crews drill and reinforce a hole from the seafloor 

down through the trap layers and into the reservoir zone. During drilling, it is important for rig 

crews to prevent hydrocarbons in the reservoir from entering the hole they are drilling, which is 

called the wellbore. 

The second phase is completion. During completion, rig crews open the wellbore to allow 

hydrocarbons to flow into it and install equipment at the wellhead that allows them to control the 

flow and collect the hydrocarbons. 

The third phase is production. In the production phase the operator actually extracts 

hydrocarbons from the well. 
Chief Counsel’s Report — Chapter 2: Drilling for Oil in Deepwater | 9

This introduction to drilling a deepwater well focuses on 

the first phase—the actual drilling—and the concept of 

well control, which refers to the methods for controlling 

hydrocarbon flow and pressure in a well. 

Drilling Overview

Offshore drilling is similar in many ways to drilling on land. 

Like their onshore counterparts, offshore rig crews use 

drilling mud and rotary drill bits to bore a hole into the 

earth (see Figure 2.2). Drillers pump the mud down through 

a drill pipe that connects with and turns the bit. The mud 

flows out of holes in the bit and then circulates back to the 

rig through the space between the drill pipe and the sides 

of the well (the annulus or annular space). As it flows, 

the mud cools the bit and carries pulverized rock (called 

cuttings) away from the bottom of the well. When the mud 

returns to the surface, rig equipment sieves the cuttings out 

and pumps the mud back down the drill string. The mud 

thus travels in a closed loop. 

Pore Pressure and Fracture Pressure

In addition to carrying away cuttings, drilling mud also 

controls pressures inside the well as it is being drilled. The 

mud column inside a well exerts downward hydrostatic 

pressure that rig crews can control by varying the mud 

weight. 

The crew monitors and adjusts the mud weight to keep the 

pressure exerted by the mud inside the wellbore between 

two important points: the pore pressure and the fracture 

pressure. The pore pressure is the pressure exerted by 

fluids (such as hydrocarbons) in the pore space of rock. 

If the pore pressure exceeds the downward hydrostatic 

pressure exerted by mud inside the well, the fluids in the 

pore spaces can flow into the well, and unprotected sections 

of the well can collapse. 

An unwanted influx of fluid or gas into the well is called a 

kick. The fracture pressure is the pressure at which the 

geologic formation will break down or “fracture.” When 

fracture occurs, drilling mud can flow out of the well into 

the formation such that mud returns are lost instead of 

circulating back to the surface. 

Both pore pressure and fracture pressure vary by depth. The 

pore pressure gradient is a curve that shows how the 

pore pressure in the well changes by depth. The fracture 

gradient is a curve that shows how the fracture pressure in 

a well changes by depth (see Figure 2.3). Both gradients are 

typically expressed in terms of an equivalent mud weight. 

Figure 2.2. Drilling. Annulus

Annulus

Drilling Mud

Drill Bit

Formation

Drill Pipe

Mud

CuttingsCuttings

TrialGraphix

Typical onshore and 

offshore drilling consists of 

drilling mud, a drill bit, and 

circulating pressures to clear 

cuttings through the annulus 

to the surface.
10 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Both pore pressure and fracture pressure vary by depth. The pore 

pressure gradient is a curve that shows how the pore pressure in the well 

changes by depth. The fracture gradient is a curve that shows how the 

fracture pressure in a well changes by depth. Drilling engineers keep the 

mud weight between these curves.

Pore pressure gradient Mud weight Fracture gradient

MAINTAINING BALANCE

The pore pressure and fracture gradients define the boundaries of the drilling process. Drillers 

strive to keep the mud weight between these two curves. 

LOT and FIT. There are two ways to determine a formation’s fracture gradient: a leak off test

(LOT) and a formation integrity test (FIT). In a leak off test, the driller gradually increases 

the pressure on the formation and stops when the formation begins to give way. The driller can 

see this occurring by monitoring the pressure at the surface. In a formation integrity test, the 

driller gradually increases the pressure on the formation to a predetermined value less than 

the fracture pressure. This test stops before the formation actually begins to give way. In each 

case, the stopping point is recorded as the fracture gradient of the formation. 

Achieving this goal would be simple enough if the pore pressure remained constant from the 

seafloor all the way down to the hydrocarbon zone. But pore pressure and fracture pressure 

vary. They typically increase with increasing depth but can sometimes decrease depending on 

the nature of the formation. As the well goes deeper, drillers typically must increase the weight 

of drilling fluid to balance increasing pore pressure. 

Casing and Cement

At some point as the crew drills deeper, the pore pressure in the bottom of an open hole 

section will exceed the fracture pressure of the formation higher up in this open hole section. 

When this happens, the crew can no longer rely on mud to control pore pressure. If the crew 

increases the mud weight, it will fracture the formation higher up. If the crew keeps drilling 

but does not increase the mud weight, hydrocarbons or other fluids in the deeper formation 

will flow into the well. 

Figure 2.3. Pore pressure and fracture gradients.

TrialGraphix
Chief Counsel’s Report — Chapter 2: Drilling for Oil in Deepwater | 11

PRESSURE BALANCE

The sheer weight of rock 

exerts enormous pressures 

on the rock itself, fluids 

inside the rock, and any 

foreign bodies penetrating 

the rock.

Casing Segments

Rig crews attach casing 

segments together on the rig.

As drilling progresses, the 

mud pressure necessary to 

keep fluids from entering 

the bottom of the well 

at lower elevations can 

fracture the formation in 

upper elevations. At that 

point, engineers add casing.

Fluids

Twenty- to 40-foot casing segments are 

screwed together to make a “casing string.” 

Casing strings can be more than 1,000 feet 

long. Each casing string is narrower than 

the previous string. 

Drilling Mud

Figure 2.4. Casing strings (greatly simplified).

TrialGraphix
12 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

At this point, the crew stops and sets casing. Casing is high-strength steel pipe that comes in 

20- to 40-foot sections that rig crews screw together (or “make up”) on the rig to make a casing 

string (see Figure 2.4). Once placed in a well, the casing string serves at least two purposes. 

First, it protects more fragile sections of the hole outside the casing from the pressure of the 

drilling mud inside. Second, it prevents high-pressure fluids (like hydrocarbons) outside the 

casing from entering the well.

After a rig crew runs a casing string down a well, it must cement the casing string into place. 

Once it sets, the cement does two things. First, it seals the interior of the well (inside the casing) 

off from the formation outside the casing. Second, it anchors the casing to the rock around it, 

structurally reinforcing the wellbore to give it mechanical strength. 

Drilling in More Detail

The Drilling Rig

Both offshore and onshore drill crews use drilling rigs to raise and lower drilling tools and casing 

down the well, pump fluids down the wellbore, and turn the drill bit. An offshore drilling rig 

must also provide the crew with a stable platform from which to work. There are several types of 

offshore drilling rigs. 

A mobile offshore drilling unit (MODU) is able to move from location to location. In shallow 

water, rig crews can work from “jack-up” platforms that are towed onto location and then 

supported by mechanical legs lowered to the seafloor (see Figure 2.5). Deepwater operations 

require structures that float on the water’s surface. Some are floating structures that are moored 

in place with cables attached to giant anchors. Others are drillships—vessels that carry drilling 

rigs and support drilling operations (see Figure 2.6). 

A dynamically positioned (DP) semi-submersible like the Deepwater Horizon is yet another kind 

of rig that combines features of each of these other rig types. Once moved onto location, a DP rig 

Figures 2.5 and 2.6. Rig structures.

TrialGraphix

Various offshore drilling rigs.
Chief Counsel’s Report — Chapter 2: Drilling for Oil in Deepwater | 13

holds itself in place above a drilling location using satellite positioning technology and 

directional thrusters. 

Spudding the Well 

Drilling in deepwater starts when the rig crew “spuds” the well by lowering a first string of 

casing down to the seafloor. This “conductor casing” is typically 36 inches in diameter or more, 

and serves as part of the structural foundation for the rest of the well. Welded to the top of the 

conductor casing is a wellhead assembly. The wellhead assembly remains above the seafloor and 

serves as an anchoring point for future casing strings. The rig crew lowers the conductor casing 

into place using the drill string and a “running tool” that attaches the drill string to the wellhead.

The Drill String. The drill string is made up of “joints” of drill pipe that are 20 to 40 feet in 

length. Each joint has a threaded male end and a threaded female end that is larger than the 

overall pipe diameter; these tool joints connect one joint of drill pipe to the next. Drill pipe 

itself comes in different diameters (typically ranging from 51⁄2 to 65⁄8 inches in deepwater). In 

addition to standard drill pipe, rig crews can use drill collars or heavyweight drill pipe as well. 

Drill collars have much thicker walls than standard drill pipe. Rig crews often use drill collars to 

add weight to the bottom part of a drill string. Doing this helps keep the drill string from kinking 

or breaking and puts more weight on the bit. Heavyweight drill pipe is of an intermediate 

weight; it minimizes the stress between the drill collars at the bottom of the drill string and 

standard drill pipe at the top.

The sediments in the first several hundred feet below the seafloor in the Gulf of Mexico are 

typically unconsolidated materials that lack cohesive strength. They are little more than watery 

mud. Accordingly, the rig crew does not need to use drilling mud or even a rotary drill bit to 

create a hole for the conductor casing. The weight of the drill string and conductor casing alone 

can be more than enough to drive the casing down into the mud at the seafloor. The rig crew 

helps this process along by pumping seawater down the drill string at high pressure to “jet” 

away the sediments at the bottom of the conductor casing. The jetted water then carries the 

sediments up the inside of the conductor casing and out through ports in the wellhead into the 

surrounding seawater.
14 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Figure 2.7. Early drilling phases.

TrialGraphix 

Conductor in seafloor with early casing string attached.

Setting the Conductor Casing and Cementing Additional Early 

Casing Strings

Once the rig crew has jetted the conductor casing to its design depth, a second, smaller diameter 

casing string is installed, extending deeper into the seabed (see Figure 2.7). In a deepwater well, 

this second string is sometimes jetted into place, or large diameter drill bits might be used to drill 

the hole for it to be lowered into. If it is drilled, the hole diameter is slightly larger than the casing 

to leave room for the cement that secures it into place. 

To cement the casing, a cementing crew pumps cement down the drill string. The cement flows 

down the drill string, out the bottom of the casing and back up against gravity into the annular 

space around the casing (between the casing and open hole). When cementing is complete, 

the cement fills the annular space around the casing, reinforcing the casing and creating the 

mechanical foundation for further drilling. This process continues as the hole is drilled using 

progressively smaller diameter casing and cementing each in place.

Cement Slurry. The cement slurry that the rig crew pumps down a well is a high-tech blend of 

dry Portland cement, water, and numerous dry and liquid chemical additives. Operators typically 

employ specialized cementing contractors to design the slurry, provide the raw materials for the 

slurry, and pump it into place. Cementing specialists can adjust the cement slurry composition to 

reflect the needs of each well. For instance, they can add “accelerators” to increase the rate at 

which the cement sets, or “retarders” to decrease it. 

Conductor Casing

Smaller Diameter Casing String
Chief Counsel’s Report — Chapter 2: Drilling for Oil in Deepwater | 15

The Wellhead. A deepwater wellhead consists of a series of sophisticated interlocking components 

that are assembled together as the well is constructed. The outer portion of the wellhead is 

welded to the conductor casing and lowered to the bottom along with that casing. The outer 

wellhead accommodates multiple casing hangers that support the weight of early casing strings 

and seal the annular space at the top of those casing strings. Prior to lowering the BOP, drillers 

install an inner high-pressure wellhead assembly that is welded to a smaller diameter casing 

string. The high-pressure wellhead assembly interlocks with the outer wellhead assembly and 

includes fittings that allow the BOP to latch on to the integrated wellhead assembly. Like the 

outer wellhead assembly, the inner high-pressure wellhead assembly accommodates casing 

hangers inside it.

Lowering the Riser and BOP

When the sediments at the bottom of the well are strong enough that they can no longer be 

removed by jetting, the drilling crew must begin to use rotary drilling bits and may begin using 

drilling mud. 

The term “mud” was once descriptive—early drilling fluids were simple mixtures of water and 

clay. Nowadays mud is a complex blend of oil- or water-based fluids and additives that serves 

many functions in a well. Unlike the seawater used during the jetting process, which is discharged 

into the surrounding sea after use, drilling mud must be recovered after it is pumped down a 

drill string—it is expensive ($100 per barrel or more) and can damage the surrounding ocean 

environment if released. Federal law generally prohibits the discharge of oil-based drilling mud 

into the ocean. 

TrialGraphix

Figure 2.8. Wellhead assemblies.

Outer Wellhead Assembly

Inner High-Pressure Wellhead Assembly
16 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

In order to switch from using seawater as a drilling fluid to using drilling mud, the rig crew must 

add several elements to the emerging well system. The first is a blowout preventer, or BOP. 

The BOP is a giant assembly of valves that latches on to the wellhead. The BOP stack serves as 

both a drilling tool and a device for controlling wellbore pressures. The BOP stack is connected 

back to the rig by the lower marine riser package (LMRP) and the riser. The riser is a 

The Blowout Preventer. The BOP as a whole is 

called the “BOP stack”; it consists of a series 

of annular preventers and rams stacked in 

vertical sequence on top of one another.†

The term lower marine riser package (LMRP) 

refers to the top part of the BOP stack that 

contains the annular preventers and the 

control pods (described further in Chapter 3). 

An annular preventer is a large rubber element 

designed to close around the drill pipe and 

seal off the annulus. It is like a hard rubber 

donut. Upon activation, the annular preventer 

expands and fills the space within that part 

of the BOP; if there is something in the 

annular preventer (such as pipe), the annular 

preventer seals around it. If no drill pipe is in 

the hole, the annular preventer can close off 

and seal the entire opening. 

A pipe ram consists of two mirror-image metal 

blocks with semicircles cut out of the inner 

edges. The semicircular 

area is lined with a rubber 

seal. The pipe ram is 

designed to close around 

the drill pipe and seal off 

the annulus in the well 

below. Variable bore rams 

are a type of pipe ram 

with several concentric 

semicircular pieces; the 

concentric pieces allow 

the variable bore rams 

to seal around several 

different sizes of pipe. 

A blind shear ram consists 

of two metal blocks with 

blades on the inner edges. 

It is designed to cut the drill string and seal 

off the annulus and the drill string in the well 

below. It can withstand and seal a substantial 

amount of pressure from below. Blind shear 

rams are designed to cut through drill pipe 

but will not cut through a tool joint (the 

place where two pieces of pipe are threaded 

together), casing hangers, or multiple pieces 

of pipe. 

The casing shear ram is designed to 

cut through casing as it is being lowered into 

the wellbore and when there is no 

drill string in place. It does not seal the 

wellbore completely.

A test ram, if installed, sits at the bottom of 

the BOP stack. It is typically a pipe ram that 

is inverted—whereas the pipe ram is normally 

designed to hold pressure coming up from 

beneath it, the test ram is inverted and so 

holds pressure from above it. This allows the 

driller to test elements above the test ram. 

TrialGraphix

Figure 2.9. BOP components.

†

 Although not separately depicted in Figure 2.9, there are hydraulic, power, and communications lines 

(cables), as well as the choke, kill, and boost lines (pipes) running from the rig to the blowout preventer.
Chief Counsel’s Report — Chapter 2: Drilling for Oil in Deepwater | 17

sequence of large diameter high-strength steel pipes that serves as the umbilical cord between the 

rig and the BOP during all remaining drilling operations. Once rig crews lower the BOP and riser 

system into place atop the wellhead, they perform the rest of their drilling operations through this 

system. The drill string, drilling tools, and all the remaining casing strings for the well go down 

into the well through the riser and the BOP. 

With the riser and BOP stack in place, the drilling crew can begin using the rig’s drilling mud 

system (see Figure 2.10). The crew circulates mud down through the drill string, into the 

wellbore, back up the annular space around the drill string, up through the riser, and back to the 

rig. Once the mud reaches the rig, it goes through a series of devices including shale shakers and 

sand traps to remove cuttings and suspended debris from the mud. The mud then travels to mud 

tanks or pits where the mud is stored until being pumped back down into the well again. 

An operator typically contracts with mud engineers to prepare drilling mud and operate the 

mud systems, and mudloggers to monitor the drilling mud and other drilling parameters. Mud 

engineers can add additional fluids or solid materials to the circulating mud in order to change its 

characteristics. Most importantly, they can add weighting agents such as barite to the circulating 

mud to increase the pressure on the wellbore below. 

Engineers typically represent the density of drilling fluids in terms of pounds per gallon (ppg). 

Mudloggers regularly examine the mud and cuttings for clues to the nature of the geologic 

formation at the well bottom, and they check the mud to see if it contains hydrocarbons. 

Figure 2.10. Flow in a typical mud system.

TrialGraphix
18 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Well Logging. Well logging refers generally to the use of instruments to learn about the 

characteristics of a well during or after drilling operations. The oil and gas industry has 

developed many different types of instruments, or “logs.” For example, pressure while 

drilling logs measure the pressure inside and outside the drill bit in real time. Electric 

logs measure the electric potential and resistivity of the formation, and can identify the 

boundaries between formations and the fluids within them. Gamma ray logs measure the 

natural radioactivity of rock. Sonic and ultrasonic logs can be used to measure the porosity 

and lithology of a formation. Caliper logs measure the size of the hole that has been drilled. 

Temperature logs measure temperature gradients in a well. Cement evaluation logs can 

help identify the amount and quality of cement in the annular spacer.

Setting Subsequent Casing Strings

Using the drilling mud system and rotary drill bits, the drilling crew drills 

ahead through the previously set casing strings. The rig crew extends the 

open hole below the existing casing strings as far as the pore pressure and 

fracture gradient allow and then sets subsequent smaller diameter casing 

strings inside the existing ones. Each new string of casing has a smaller 

diameter than the previous string because it must be run through the 

previous string. Some of these subsequent casing strings extend all the 

way back up to the wellhead. Others, called liners, attach to the bottom 

segment of previous casing strings. A casing hanger or liner hanger

mechanically holds the casing in place (see Figure 2.11).

The basic method for installing a new casing string is the same whether 

that string will be hung from a hanger installed in the wellhead or hanger 

installed deeper in the well. 

Once the crew drills to a depth where a new casing string is needed, 

the rig crew removes the drill string from the well in a process called 

tripping out. Tripping out (or in) with the drill string is time-consuming; it typically 

takes a drilling crew an hour to trip in or out 1,000 feet, and tripping out of a deepwater well 

can be a day-long process. After tripping out, the drill crew attaches a running tool to the 

end of the drill string. The crew attaches the running tool to the casing hanger, which is in 

turn welded to the top of the casing. The drill crew then lowers the drill string, running tool, 

and casing string down the riser, through the BOP, and down into the well until the casing 

hanger is in position (either in the wellhead or the proper depth in the well). 

Cementing Casing Strings 

The process for cementing casing strings into place after installing the BOP is slightly 

different than cementing the early casing strings. Just as in earlier cementing steps, the rig 

crew pumps cement down the drill string and into place at the bottom of the well. However, 

because cement is typically incompatible with drilling mud, cementing crews employ two 

methods to keep the mud and cement separated as they flow down the well. The first 

involves separating the mud and cement with a water-based liquid spacer that is designed 

to be compatible with both oil-based drilling mud and water-based cement but that will 

prevent them from mixing. The second method involves further separating the spacer and 

cement with a plastic wiper plug that travels down the well between the spacer and the 

cement (see Figure 2.12).

TrialGraphix

TrialGraphix

Figure 2.12. 

Wiper plugs.

Figure 2.11. Casing hanger.
Chief Counsel’s Report — Chapter 2: Drilling for Oil in Deepwater | 19

TrialGraphix

Figure 2.13. Cementing. Figure 2.13 demonstrates cementing a casing string while using 

mud-based drilling techniques, the cementing crew starts by 

pumping spacer, followed by a “bottom” wiper plug, followed by a 

slug of cement, a “top” wiper plug, more spacer, and then drilling 

mud. The spacers, wiper plugs, and cement slug travel down 

in sequence. When the bottom plug reaches the float valve 

assembly near the bottom of the casing string, it ruptures, 

allowing the cement behind it to pass through. The cement flows 

through the float valves and out the bottom of the casing string. 

It then “turns the corner” and flows up into the annular space 

around the casing. When all of the cement has made it through 

the float valves, the top plug lands on top of the bottom plug. 

Unlike the bottom plug, the top plug is not designed to rupture. 

When it lands, it blocks the flow of mud, and the resulting 

pressure increase signals the end of the cementing process, at 

which time the crew turns off the pumps. Cement should fill the 

annular space around the bottom of the casing string and the 

portion of the casing between the bottom and the float valves 

(called the shoe track). Some companies even pump 

cement behind the top plug to improve the effectiveness of the 

cement job. 

Float Collar. A “float collar” is a component installed at the 

bottom of a casing string. It typically consists of a short length of 

casing fitted with one or more check valves (called float valves). 

The float collar both (1) stops wiper plugs from traveling farther 

down the casing string, and (2) prevents cement slurry from 

flowing back up the casing after it is pumped into the annular 

space around the casing. During casing installation, the float 

valves are typically propped open by a short “auto-fill tube.” The 

auto-fill tube allows mud to flow upward through the float collar 

as the casing string is lowered. Once the casing is in place, rig 

personnel “convert” the float collar. By circulating mud through 

holes in the auto-fill tube, the rig crew creates pressure that 

pushes the auto-fill tube down so that it no longer props the 

float valves open. Once the auto-fill tube is removed, the float 

valves “convert” to one-way valves that allow fluid flow down 

the casing but prevent fluid flow upward. Though a converted 

float collar should prevent cement slurry from flowing upward, it 

is typically not considered to be a barrier to hydrocarbon flow. 

After the cement slurry has set (which takes many hours), the 

rig crew pressure tests it to ensure that it has sealed the casing 

in place. They then continue the drilling process by removing 

the running tool, installing a smaller diameter drill bit on the 

end of the drill string, and lowering it back down to the bottom 

of the well. The crew then uses the smaller diameter drill bit to 

drill through the float valves and the cement in the shoe track, 

creating a path for drilling to continue. 

Spacer

Cement

Mud Mud

Top Wiper Plug

Bottom 

Wiper 

Plug

Float Collar

Annular SpaceAnnular Space

Shoe Track

Auto-Fill Tube
20 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

The Production Casing

If an operator drills a well purely to learn about 

the geology of an area and assess if oil or gas are 

present, the well is called an exploration well. If 

the operator uses the well to recover oil, it is called 

a production well. The bottomhole sections of 

exploration wells and production wells are different. 

Once an operator is finished drilling an exploration 

well, they typically fill the open bottomhole section 

with cement in a process called plugging and 

abandoning. By contrast, after drilling the final 

section of a production well, the operator typically 

installs a final string of production casing in the 

open hole section. The production casing extends 

past any hydrocarbon-bearing zones and down to the 

bottom of the well. After cementing the production 

casing into place, the operator can perforate the 

casing by shooting holes through it and the annular 

cement. This allows oil to flow into the well as shown 

in Figure 2.14.

Well Control 

During drilling, casing, and completion operations, rig personnel must ensure that 

hydrocarbons do not migrate from the reservoir into the well. Well control is the process of 

monitoring the well and addressing any hydrocarbon influxes that are detected.

Primary Barriers—Barriers Inside the Well

To maintain well control, rig personnel must create and maintain barriers inside the well that 

will control subsurface pressure and prevent hydrocarbon flow. Some barriers are part of the 

well design itself while others are operational barriers that a drilling crew employs during the 

drilling process. 

Drilling mud is a key operational barrier. As long as the column of drilling mud inside the 

well exerts pressure on the formation that exceeds the pore pressure, hydrocarbons should not 

flow out of the formation and into the well. 

It is important to understand the following: If mud pressure exceeds pore pressure, the well is 

said to be overbalanced. If pore pressure exceeds mud pressure, the well is underbalanced, 

meaning that the mud pressure is no longer sufficient on its own to prevent hydrocarbon flow. 

Physical components of the well also create barriers to flow. One is the casing installed in the 

well, along with the cement system in the bottom of the well. In a production casing string, 

the cement in the annular space and in the shoe track should prevent hydrocarbons in the 

formation from flowing up the annular space outside the production casing or up the inside of 

the well itself. 

Rig personnel can use additional barriers inside the well to increase the redundancy of the 

barrier system. For instance, rig personnel can pump cement inside the final casing string of 

a well to create cement plugs at various depths inside the well. Rig personnel can also install 

Figure 2.14. Perforating the production casing.

TrialGraphix
Chief Counsel’s Report — Chapter 2: Drilling for Oil in Deepwater | 21

metal or plastic mechanical plugs inside the well. Some 

mechanical plugs are designed to be removed and 

retrieved later in the drilling process while others are 

designed to be drilled out as necessary. 

Secondary Barrier—The Blowout Preventer

A BOP stack is also a potential barrier. By closing 

various individual rams in a BOP stack, rig personnel 

can close off the well, thereby preventing hydrocarbon 

flow up the well and into the riser. When a BOP ram 

is closed, it becomes a barrier to flow. However, the 

rams do not close instantaneously—they take anywhere 

from 40 seconds to a minute to close once activated. 

Accumulators are tanks that contain pressurized 

hydraulic fluid used to close the BOP. Subsea 

accumulators on the BOP stack are constantly charged 

through a conduit line from the rig. 

BOP rams can be activated in several ways: manually 

from the rig, robotically by remotely operated vehicles 

(ROVs), and automatically (when certain conditions are 

met). Each ram is activated separately. 

Manual activation is generally done by the driller but also 

can be done by other rig personnel including the subsea 

engineer. BOP control panels are located on the bridge 

and in the drill shack. To manually activate a given 

BOP ram, a rig worker presses a button on the control 

panel corresponding to that ram. Electrical signals are 

sent from the control panels to subsea control pods

on the BOP stack. The signals electrically open or close 

a solenoid valve, which in turn sends a pilot signal to 

activate the hydraulic pressure needed to operate the individual elements of a BOP stack. The 

control panel has a flow meter display that indicates how many gallons of hydraulic fluid are 

flowing into the ram, which helps the driller and subsea engineer to determine whether the ram is 

responding properly. 

The BOP can also be activated by a mobile underwater robot (ROV) that can carry and use tools. 

An ROV can activate the blind shear ram through the control system or by pumping hydraulic 

fluid through “hot stab” ports located on the outside of the BOP stack. 

Last, the BOP can be activated automatically. One automated system is the automatic mode 

function or deadman trigger. If the power, communications, and hydraulic lines running 

from the rig to the BOP are severed or otherwise lose functionality, circuits on the BOP stack 

will activate the blind shear rams to close off the well. An ROV can also create the conditions 

to activate the deadman by cutting power, communications, and hydraulic lines at the LMRP. 

Another automated system that activates the blind shear ram is the autoshear. A BOP system 

can be configured so that the autoshear activates where the rig is drifting off or driving off of its 

location. If the rig moves a sufficient distance, a rod between the LMRP and BOP stack is severed, 

and the autoshear activates. An ROV can also cut the rod between the LMRP and BOP stack to 

activate the autoshear system.

Figure 2.15. Barriers in a well.

TrialGraphix

Mud

BOP

Cement Plug

Mechanical Plug

Cement Plug

Production Casing

Annular Cement

Shoe Track Cement
22 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Well Monitoring 

If the primary hydrocarbon barriers in a well (such as the weight of drilling mud) are inadequate 

to contain the reservoir pressures, a kick of hydrocarbons can flow into the well. During well 

operations, rig personnel must always monitor the well for such kicks and respond to them 

quickly. Their options for responding to a kick diminish rapidly as the kick progresses. 

Rig personnel (primarily the driller) watch several different indicators to identify kicks. One is 

the amount of fluid coming out of the well. If flow out of the well exceeds flow in or the volume 

of mud in the mud pits increases anomalously, that may indicate that hydrocarbons are flowing 

into the well. Data from sensors that measure the gas content of returning drilling mud can also 

warn of hydrocarbon flow. Other indicators include unexplained changes in drill pipe or other 

pressures, and changes in the weight, temperatures, or electrical resistivity of the drilling mud. 

Once rig personnel detect a kick, they must take action to control it. The driller has a number 

of options for dealing with a kick depending on its size and severity. In a routine kick response 

scenario, the driller activates an annular preventer or a pipe ram to seal off the annular space 

in the well around the drill pipe. The driller then pumps heavier mud into the well. He can do 

this either through the drill pipe or through the kill line—one of three separate pipes that run 

from the rig to the BOP. The heavier mud is called “kill mud,” designed to counteract the pore 

pressure of the rock formation. Because the BOP has sealed off the annular space around the 

drill pipe, the driller opens the choke line (another one of the three separate pipes running from 

the rig to the BOP) to allow circulating mud to return to the rig. Once the weight of the heavier 

drilling mud overbalances the hydrocarbon pressure and any hydrocarbons that flowed into the 

well have been circulated out, the driller can reopen the BOP and safely resume operations. On 

modern rigs, kill lines can function as choke lines, and vice versa. A third pipe, a boost line, 

connects at the bottom of the riser and can help speed circulation of fluids. 

Figure 2.16. Simplified AMF control system schematic.

TrialGraphix

Activating the ram systems.
Chief Counsel’s Report — Chapter 2: Drilling for Oil in Deepwater | 23

If a kick progresses beyond the point where the driller can safely shut it in with an annular 

preventer or pipe ram, the driller can activate the blind shear ram. When the two elements of 

the blind shear ram close against each other, they simultaneously shut in the well and sever the 

drill string. 
24 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

The Deepwater Horizon
Chief Counsel’s Report — Chapter 3: Background on the Macondo Well, the Deepwater Horizon, and the Companies Involved | 25

Chapter 3|Background on the 

Macondo Well, the Deepwater Horizon, 

and the Companies Involved

The Macondo Well

Well Location

I

n February 2009, BP filed an exploration plan with the United States 

Minerals Management Service (MMS) indicating its intention to drill two 

exploration wells in Mississippi Canyon Block 252 (MC 252). Both wells 

were located 48 miles from shore in 4,992 feet of water, and both would be 

drilled to a total depth of 20,600 feet below sea level.1 BP planned to drill both 

using a semi-submersible drilling rig. BP stated that it would take 100 days to 

drill each well and that it would begin the first well on April 15, 2009, and the 

second well one year later on April 15, 2010. 

MMS approved BP’s Exploration Plan in early April 2009. BP later revised the plan slightly in 

mid-April 2009 to include a larger anchor pattern for its rig, and MMS approved the revised plan 

on April 21, 2009. MMS approved BP’s application for permit to drill (APD) the first of the two 

wells, the “A” location, on May 22, 2009.2

 

BP would drill the well in order to reach the Macondo prospect. The name “‘Macondo” was the 

result of a charitable donation. BP had donated naming rights to the United Way, which in turn 

auctioned the rights to a Colombian-American group. That group chose the name of the fictional 

Colombian village in Gabriel García Márquez’s novel One Hundred Years of Solitude.

3

The Geology and Exploration Objectives

BP had decided to drill at Macondo after examining 3-D seismic data, offset well data, and other 

information about the area. The 3-D data had included a prominent “amplitude anomaly” that 

suggested the presence of hydrocarbon-bearing sands. This information, combined with offset 

well data and knowledge of the overall geological structure of the area, strongly suggested to BP 

that it might find hydrocarbon-bearing sands.4

 

BP defined its primary geologic objectives as mid-Miocene age turbidite sands buried 13,000 

to 15,000 feet beneath the seafloor—18,000 to 20,000 feet below sea level. These sands were 

deposited on the ancient seabed some 12 million to 15 million years ago. BP’s plan called for 

drilling the well to a total depth of 20,600 feet to penetrate this primary objective interval. From 

the beginning, BP planned to use the well as a long-term production well if it penetrated the 

objective sands.

Operators are not required to include pre-drilling estimates of potential oil and gas reservoirs. 

However, during the containment efforts following the blowout of the Macondo well, BP 

estimated the volume of oil at Macondo to be 110 million barrels.5
26 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

The Deepwater Horizon

BP had intended to use Transocean’s Marianas to drill the entire Macondo well. The Marianas 

spudded the Macondo well on October 6, 2009. The crew of the Marianas drilled and set casing 

for the first 9,090 feet of the Macondo well but were forced to leave after the rig sustained damage 

from Hurricane Ida on November 9, 2009. The Deepwater Horizon took over and resumed 

drilling operations at Macondo in February 2010. 

The Deepwater Horizon was a semi-submersible mobile offshore drilling unit (MODU). 

Unlike fixed drilling platforms used in shallower water, MODUs can move from one location to 

another under their own power. Dynamically positioned MODUs utilize dynamic satellite 

positioning technology connected to powerful directional thrusters to maintain themselves 

in place over a subsea wellhead. 

The Deepwater Horizon entered service in 2001. It was built by Hyundai Heavy Industries 

and owned by Transocean. It initially sailed under the flag of Panama and later the Marshall 

Islands. In 1998, BP signed a contract with Transocean securing the services of Deepwater 

Horizon from the time it first left the shipyard for a period of three years.6

 After the initial three 

years, BP extended the contract in annual increments.7

 At the time of the blowout, BP’s contract 

required it to pay $533,495 per day, but under the contract BP was not obligated to pay for time 

in excess of 24 hours each month spent on certain equipment repairs.8

 With additional costs 

(fuel, expendables, and services), BP was paying approximately $1 million per day to operate the 

Horizon.

9

 

Figure 3.1 shows the basic dimensions of the Deepwater Horizon while drilling. The rig was 

256 feet wide (from port to starboard) and 396 feet long (from bow to stern). The main deck sat 

61 feet above the water’s surface while drilling, with the drill floor another 15 feet above that. 

The derrick was 244 feet tall, towering a total of 320 feet above the ocean while drilling.

Figure 3.1. Deepwater Horizon.

TrialGraphix
Chief Counsel’s Report — Chapter 3: Background on the Macondo Well, the Deepwater Horizon, and the Companies Involved | 27

Figure 3.2 is a close-up of the main deck with pertinent parts labeled in yellow. The drill floor

was located in the center of the main deck. The crew ran casing, drill pipe, and drilling tools 

through the rotary table, down the riser, and into the well. The drill shack was on the drill 

floor. It was a small windowed room that housed the drillers’ and assistant drillers’ chairs, 

along with well monitoring equipment and controls for the blowout preventer. The drillers and 

assistant drillers drilled and monitored the well from the drill shack.

The mudloggers shack was a structure installed on the starboard side of the drill floor. It 

was owned by Sperry Drilling and housed the mudloggers and their monitoring equipment. 

The bridge was located beneath the helipad on the front port (left) side of the rig. The bridge 

contained the dynamic satellite positioning system and was the helm of the rig when in transit. It 

also housed monitors and controls for the alarm systems, a second set of controls for the blowout 

preventer, and other rig and well monitoring equipment. 

Two sets of pipes are also shown in Figure 3.2. The first comprises the port and starboard 

overboard lines, through which the rig crew could send fluids flowing up from the well 

overboard into the ocean. The second is the mud gas separator pipe, through which the rig 

could route mud returning from the well to remove small amounts of hydrocarbon gas before 

sending the mud on to the mud pits. The overboard lines and mud gas separator were part of 

the rig’s diverter system, which provided the crew two alternative routes for diverting fluids 

coming up from the well. 

Figure 3.2. Main deck.

TrialGraphix
28 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Figure 3.3 shows the Deepwater Horizon’s three decks. Decks 2 and 3 housed the rig’s living 

quarters, engine rooms, and other work areas, including the mud pits and moon pool shown in 

Figure 3.4. The Deepwater Horizon had 20 mud pits, which were tanks for holding drilling 

fluids such as mud. The moon pool was located directly beneath the drill floor. It was a wide 

opening in the bottom of the rig through which the crew could lower and raise large pieces of 

equipment to and from the ocean, such as the blowout preventer. 

Figure 3.3. Decks.

Figure 3.4. Mud pits and moon pool.

TrialGraphix

TrialGraphix
Chief Counsel’s Report — Chapter 3: Background on the Macondo Well, the Deepwater Horizon, and the Companies Involved | 29

Figure 3.5 depicts the 

subsurface portion of the 

Deepwater Horizon. The rig sat 

atop two enormous pontoons

extending 30 feet below the 

ocean’s surface that stabilized 

the rig and kept it afloat. 

The rig had eight directional 

thrusters for propulsion and 

to keep the rig in place over 

the wellhead. Figure 3.5 also 

depicts the riser, which would 

have extended from the rotary 

table on the drill floor through 

the moon pool and down to the 

blowout preventer on the ocean 

floor below.*

 

Figures 3.6 and 3.7 depict the 

Deepwater Horizon’s blowout 

preventer (BOP) sitting atop 

the wellhead on the ocean floor. 

As discussed in Chapter 2, the 

*

 Although not separately depicted in Figures 3.5 and 3.6, there are hydraulic, power, and 

communications lines (cables), as well as the choke, kill, and boost lines (pipes) running from the rig 

to the blowout preventer.

Figure 3.5. Subsurface portion of the Deepwater Horizon.

Figure 3.6. Blowout preventer.

TrialGraphix

TrialGraphix
30 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

blowout preventer comprised a set of five vertically 

stacked rams and two vertically stacked annular 

preventers for closing in the well during routine 

well activities and emergency situations. As shown 

in Figure 3.6, the blowout preventer was more than 

five stories tall and weighed more than 300 tons. 

Figure 3.7 displays the various parts of the blowout 

preventer, including the blue and yellow 

control pods. 

Companies and 

Individuals Involved in 

the Macondo Blowout

By purchasing the rights to drill in Block 252, BP 

became the legal operator for any activities on that 

block. Like most operators, however, BP neither 

owned the rigs that drilled Macondo nor “operated” 

them in the normal sense of the word. 

Instead, the company’s shore-based engineering team 

designed the well and specified in detail how it was to 

be drilled. BP employed a number of contractors to perform the physical work of actually drilling 

and constructing the well. As a result, on the day of the Macondo blowout, only seven of the 126 

individuals on the rig were BP employees.10 The following sections list the core members of BP’s 

team as well as the principal contracting companies and their key employees.

BP is a large oil and gas company headquartered in the 

United Kingdom. With annual revenues of approximately 

$246 billion, BP is the world’s fourth-largest company of 

any kind.11 It is the world’s third-largest energy company12

and the largest producer of oil and gas in the Gulf of 

Mexico.13 BP held more than 500 lease blocks in the Gulf of 

Mexico, and more than 1,600 employees worked for BP in 

the region.14

A number of different individuals and groups at BP had a hand in designing and supervising the 

construction of the Macondo well. The initial design of the Macondo well involved more than 25 

professionals, ranging from drilling engineers to regulatory experts.15 During the drilling of the 

well, reports about operations on the rig went out to about 80 BP employees and contractors.16

Daily activity at Macondo centered on a handful of BP employees (see Figure 3.8). BP had two 

well site leaders on the Deepwater Horizon at any given time. In Houston, BP had a wells team 

leader, an engineering team leader, an operations engineer, and two drilling engineers. 

BP was in the process of reorganizing its management structure at the time of the blowout 

to clarify reporting relationships for engineers. The reorganization complicates the task of 

identifying the precise lines of authority and areas of responsibility, both at the time of and in 

the months leading up to the blowout. In addition, because of the reorganization, many of the 

Figure 3.7. Blowout preventer.

TrialGraphix
Chief Counsel’s Report — Chapter 3: Background on the Macondo Well, the Deepwater Horizon, and the Companies Involved | 31

Figure 3.8.

Deepwater Horizon’s 

organizational structure.

TrialGraphix
32 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

managers overseeing the Macondo team had only a few months of experience in their respective 

positions at the time of the blowout.17

Wells Team Leader 

The wells team leader is accountable for the safety and operations of the drilling rig.18 The 

wells team leader for Macondo was John Guide. He supervised the well site leaders on the rig and 

an operations engineer in Houston. Ian Little managed John Guide until David Sims took over 

from Little in March 2010.19

Well Site Leaders on the Drilling Rig

The top BP employees stationed on the rig were the well site leaders. The well site leaders 

served as the company’s eyes and ears, and made important decisions regarding the course 

of drilling operations. At any given time, two well site leaders served on the rig, splitting 

responsibility according to 12-hour shifts. The two-man team worked on the rig for several weeks 

at a time and then returned to shore for a similar period. 

At the time of the blowout, Bob Kaluza and Donald Vidrine were BP’s two well site leaders on 

the Deepwater Horizon. Lee Lambert, who was in training to become a well site leader, was also 

present. Kaluza was onboard as a temporary replacement for Ronnie Sepulvado, an experienced 

well site leader who had worked on the Deepwater Horizon since it set sail in 2001 but who had 

left the rig early to attend a training program. Murry Sepulvado (Ronnie Sepulvado’s brother) 

and Earl Lee were the prior regular BP well site leaders for the Deepwater Horizon. They were 

not on the rig at the time of the blowout.

Engineering Team Leader

The engineering team leader is accountable for well design.20 The engineering team leader 

supervises drilling engineers. David Sims was the engineering team leader until about a month 

before the blowout.21 In March, Sims moved from engineering to an operations role and handed 

his responsibilities over to Gregg Walz.

Other BP Engineers 

Other BP engineers closely involved with the Macondo project included Brian Morel, Mark 

Hafle, and Brett Cocales. Morel and Hafle were drilling engineers who designed wells 

and shepherded designs through BP’s processes, ensuring that they complied with internal 

guidelines.22 They planned the Macondo casing program and set out the steps to drill the well.23 

Morel and Hafle reported first to Sims, and then to Walz when he took over from Sims in March. 

Cocales was an operations engineer responsible for planning and preparing Deepwater Horizon’s 

future activity. Cocales focused on end-of-well operations and preparations for future work.24 He 

reported to Guide. 

Anadarko and MOEX

Anadarko and MOEX were BP’s partners at Macondo. Anadarko Petroleum is an independent oil 

exploration company and owned a 25% share of the Macondo well.25 MOEX Offshore 2007, an 

American subsidiary of the Japanese oil company Mitsui Oil Exploration, owned a 10% share of 

the well.26 The partners shared the costs to drill the well and expected to share profits

from production.
Chief Counsel’s Report — Chapter 3: Background on the Macondo Well, the Deepwater Horizon, and the Companies Involved | 33

Transocean is the world’s largest contractor of offshore drilling rigs.27 BP has entered into several 

contracts with Transocean to secure the long-term services of certain Transocean rigs, including 

the Deepwater Horizon. Transocean crews performed most of the basic work of drilling the 

Macondo well. 

OIM and Master

Two different Transocean employees were in charge of the rig at different times. Captain Curt 

Kuchta, Transocean’s master, was in charge when the rig was moving from location to location. 

Once the rig arrived at a given site and began drilling or drilling-related operations, Jimmy 

Harrell, Transocean’s offshore installation manager (OIM), took over. 

Senior Toolpusher and Toolpushers

The toolpushers on a Transocean rig are drilling managers who direct and supervise 

day-to-day drilling operations. The toolpushers stationed on the rig when the well blew out were 

Jason Anderson and Wyman Wheeler. Anderson was on duty and lost his life. Wheeler was 

severely injured. 

The senior toolpusher on a Transocean rig is a senior drilling operations supervisor, 

second only to the OIM in the chain of command. The senior toolpusher on the rig was Miles 

“Randy” Ezell. 

Rig Floor Personnel

The Transocean employees who served primarily on the rig floor included drillers, assistant 

drillers, floorhands, and roustabouts. Drillers and assistant drillers worked in the drill shack 

and were responsible for operating drilling machinery and monitoring and controlling the well. 

The drillers stationed on the rig when the well blew out were Dewey Revette and Micah Burgess. 

Revette was on duty and lost his life. The assistant drillers stationed on the rig when the well 

blew out were Donald Clark, Stephen Curtis, Patrick Kevin Morgan, and Allen Seraile. Clark and 

Curtis were on duty. Both lost their lives. Floorhands and roustabouts are the rig’s labor 

force for drilling operations. Three floorhands lost their lives in the blowout. They were Shane 

Roshto, Karl Kleppinger, and Adam Weise.

Other Transocean Employees

In all, Transocean had 79 employees onboard the Deepwater Horizon when it blew out, including 

welders, technicians, radio operators, and other specialized personnel. Aaron Burkeen, a crane 

operator, and Roy Wyatt Kemp, a derrickhand,†

 both lost their lives.

†

 A derrickhand works from the rig’s derrick to assist with drilling operations.
34 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Halliburton is one of the world’s largest oil field services providers and owns several other oil field 

services companies, including Baroid and Sperry Drilling. Halliburton designed and pumped the 

cement for all of the casing strings in the Macondo well. 

Jesse Gagliano was Halliburton’s lead cementing specialist for the project. Gagliano worked 

closely with BP and had an office in BP’s building near the offices of BP’s engineers. Halliburton 

also sent several individuals to the rig to actually perform cementing work. Those individuals 

included Nathaniel Chaisson, Vincent Tabler, Christopher Haire, and several foamed cement 

technicians. Tabler and Haire were on the rig at the time of the blowout.28 

Other Important Contractors and Suppliers

Cameron is a Houston-based company that manufactures well drilling equipment and well 

construction components. Cameron manufactured the Deepwater Horizon’s blowout preventer.

Dril-Quip is a Houston-based manufacturer of components used in the construction of oil wells. 

Dril-Quip manufactured the wellhead assembly used at Macondo, including the casing hanger, 

seal assembly, and lockdown sleeve components. A Dril-Quip technician named Charles Credeur 

was on the Deepwater Horizon when Macondo blew out.

M-I SWACO, a Schlumberger subsidiary, is a Houston-based company that provides drilling 

fluids and drilling fluid services. M-I SWACO provided drilling mud and spacer used at Macondo, 

and its personnel operated the Deepwater Horizon’s mud system. M-I SWACO had five mud 

engineers on the rig the day it blew out: Gordon Jones, Leo Lindner, Blair Manuel, Greg Meche, 

and John Quebodeaux. Jones and Manuel lost their lives.

Schlumberger is a multinational company that delivers a variety of oil field services through 

its own employees and through subsidiaries including M-I SWACO. BP hired Schlumberger to 

run cement evaluation logs for the primary cement job on the final Macondo production casing. 

Schlumberger also provided well logging services used in the evaluation of the Macondo well. 

Sperry Drilling, a Halliburton subsidiary, delivers oil field services. At Macondo, BP employed 

Sperry Drilling to collect data from sensors mounted on the rig and to provide trained personnel 

to monitor and interpret the data, including monitoring the well for kicks. Sperry Drilling had 

two of these “mudloggers” on the rig the day it blew out: Joseph Keith and Cathleenia Willis. 

Weatherford is a Houston-based manufacturer of well construction components. It 

manufactured float valves and centralizers used at Macondo. Four Weatherford technicians were 

on the rig the day it blew out. 
Chief Counsel’s Report — Chapter 4: Technical Findings | 35

Chapter 4|Technical Findings

he Chief Counsel‘s team‘s overall technical findings are 

straightforward. The Macondo well blew out because the cement that 

BP and Halliburton pumped down to the bottom of the production 

casing on April 19 failed to seal off, or ―isolate,‖ hydrocarbons in the 

formation. As rig personnel replaced heavy drilling mud in the well and riser 

with seawater on April 20, they steadily reduced the pressure inside the well. At 

approximately 8:50 p.m., the drilling fluid pressure no longer balanced the 

pressure of hydrocarbons in the pay zone at the bottom of the well. At this point, 

the well became ―underbalanced.‖ 

Once the well was underbalanced, hydrocarbons began to flow into the annular space around the 

production casing. In oil field terms, the Macondo well was ―taking a kick.‖ Those hydrocarbons 

flowed down through the annular space to the bottom of the well, into the production casing 

through the ―shoe track,‖ then up the well and into the riser. As they traveled up the well, the 

hydrocarbons expanded at an ever-increasing rate and the kick escalated into a full-scale blowout. 

Transocean‘s rig crew did not respond to the kick before hydrocarbons had entered the riser, and 

perhaps not until mud began flowing out of the riser onto the rig floor. Within 10 minutes of the 

rig crew‘s first response, hydrocarbon gas from the well ignited, triggering the first explosion.

Underlying Technical Causes

Behind this simple story is a complex web of human errors, engineering misjudgments, missed 

opportunities, and outright mistakes. Chapter 4 of the Chief Counsel‘s Report divides technical 

analysis of the blowout into 10 subchapters. Each subchapter presents the Chief Counsel‘s team‘s 

findings on specific technical issues. 

 Chapter 4.1 presents the basis for the Chief Counsel‘s team‘s conclusions regarding the 

precise flow path of hydrocarbons during the blowout. 

 Chapter 4.2 explains a number of the well design decisions that BP‘s engineering team 

made at Macondo and presents several findings regarding the impact of those decisions. 

The Chief Counsel‘s team finds that BP‘s decision to use a long string production casing 

increased the difficulty of achieving zonal isolation during the cement job. While the 

decision did not directly cause the blowout, it increased the risk of cementing failure. The 

Chief Counsel‘s team also finds that BP‘s decisions to include rupture disks and omit a 

protective casing from its well design complicated post-blowout containment efforts.

 Chapter 4.3 presents findings regarding the final cement job at Macondo. The cement job 

failed to isolate hydrocarbons. While it may never be possible to determine precisely 

why, the Chief Counsel‘s team identified a number of risk factors and other issues that 

T
36 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

could have contributed to cement failure. The rig crew, cement contractors, and 

engineering team do not appear to have fully appreciated these risk factors.

 Chapter 4.4 presents findings regarding pre- and post-blowout testing of the foamed 

cement slurry design used at Macondo. The Chief Counsel‘s team finds that the foamed 

cement used at the well was very likely unstable and that this could have been a major 

contributing factor to overall cement failure. 

 Chapter 4.5 presents findings regarding the temporary abandonment procedures that BP 

developed and employed at the Macondo well. The Chief Counsel‘s team finds that 

those procedures reduced the number of barriers that would be present in the well

when it became underbalanced, and significantly and unnecessarily increased the risk 

of a blowout. 

 Chapter 4.6 presents findings regarding the negative pressure test conducted on April 20. 

The Chief Counsel‘s team finds that the test clearly showed that the cement had failed to 

isolate hydrocarbons. BP and Transocean rig personnel both failed to interpret the test

properly and instead reached a consensus that the test had demonstrated well integrity. 

 Chapter 4.7 explains that the Transocean crew and Sperry-Sun mudloggers missed 

warning signs of a kick on the evening of April 20. The Chief Counsel‘s team finds that 

data from the rig show signs of an anomaly as early as 9:01 p.m. Some of the signs went 

unnoticed; others the crew detected. But even after rig personnel detected the anomaly, 

they did not identify it as a kick until after hydrocarbons had entered the riser. 

If rig personnel had identified the kick earlier, they could have prevented the 

Macondo blowout.

 Chapter 4.8 presents findings regarding the crew‘s response to the blowout after it 

occurred. The Chief Counsel‘s team finds that the crew might have mitigated the size and 

impact of the fires and explosions on April 20 if they had immediately diverted flow 

during the blowout overboard rather than to a mud gas separator system that was 

incapable of handling that extreme flow volume. 

 Chapter 4.9 presents findings regarding the rig‘s blowout preventer, or BOP. 

Hydrocarbons had entered the riser well before the crew attempted to activate the BOP, 

and even a perfectly functioning BOP could not have prevented the explosions that killed 

11 men on April 20. Nevertheless, BOP failures may have contributed to the magnitude of 

the oil spill. While BOP forensic testing is ongoing, the Chief Counsel‘s team presents 

findings regarding maintenance history and certain BOP failure theories. 

 Chapter 4.10 presents findings regarding the role of rig maintenance in the blowout. The 

Chief Counsel‘s team finds that Transocean did not maintain its BOP according to 

manufacturer recommendations. And the Chief Counsel‘s team cannot rule out that this 

may have contributed to BOP failures. While the Chief Counsel‘s team found some 
Chief Counsel’s Report — Chapter 4: Technical Findings | 37

indications of other maintenance problems on the Deepwater Horizon, it does not find 

that any of these contributed to the blowout.

Underlying Management Causes

Each of these chapters also presents management findings that relate specifically to the technical 

findings in the chapter. The Chief Counsel‘s team finds that management failures lay at the root 

of all of the technical failures discussed in this Report. Chapter 5 discusses management failures 

in detail.

Chief Counsel’s Report — Chapter 4.1: Flow Path | 39

Figure 4.1.1. Possible flow paths for hydrocarbons.

TrialGraphix

Hydrocarbons can reach the surface by traveling up the 

annulus and through the seal assembly (left). Hydrocarbons 

can also enter and migrate up the inside of the production 

casing, through a number of possible flow paths (right).

Chapter 4.1|Flow Path

efore addressing potential technical causes of the blowout, the Chief 

Counsel‘s team presents its findings regarding the flow path of 

hydrocarbons from the well. These findings form an important 

background to the subsequent technical analyses. Because different 

kinds of well failures cause hydrocarbons to flow through different paths, these 

findings can help to refine theories about what caused the blowout. 

The Chief Counsel‘s team 

finds that hydrocarbons came 

to the surface by traveling 

through the inside of the 

production casing, as seen on 

the right side of Figure 4.1.1. 

It is almost certain that 

hydrocarbons entered the 

production casing because of 

a failure of the shoe track 

cement. However, the Chief 

Counsel‘s team cannot 

entirely rule out the 

possibility that hydrocarbons 

may have entered the 

production casing from the 

annulus through a breach in 

the production casing 

somewhere near the bottom 

of the casing.

The analysis in this section 

reflects information currently 

available to the Chief 

Counsel‘s team. The team 

recognizes that various 

parties continue to gather 

additional information that 

may be relevant to flow 

path analysis.

1

 

B
40 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Figure 4.1.2. 

Flow through the 

seal assembly.

Potential Flow Paths

For the Macondo blowout to have occurred, hydrocarbons must have traveled from the formation 

into the wellbore and then up to the surface through the blowout preventer (BOP) and the riser. 

The fact that hydrocarbons entered the wellbore at all means, at the very least, that the annular 

cement did not isolate the pay zones.

2

 For hydrocarbons to have traveled up to the surface, they 

must either have gone up the annulus and through the seal assembly at the wellhead or into and 

up through the production casing.

Flow up the Annulus and Through the Seal Assembly

The seal assembly is in the wellhead. It seals the interface between the casing hanger for the 

production casing and the inside of the high-pressure wellhead housing. A lockdown sleeve

locks the casing hanger and seal assembly in place so that hydrocarbons traveling up the wellbore 

during production do not lift them up. 

As Figure 4.1.2 illustrates, there are small flow passages through the 

casing hanger connecting the annulus to the inside of the wellhead.3 The 

flow passages permit mud in the annulus to flow into the wellhead and up 

into the riser, thereby allowing the crew to circulate drilling fluids 

through the annulus even after the crew has set the production casing in 

place. The flow passages remain open prior to and during the final 

cement job.

The crew sets the seal assembly atop these flow passages to seal them off 

once there is no longer a need to circulate fluids in the annulus. At 

Macondo, the crew set the seal assembly shortly after pumping the 

bottomhole cement job.

The Macondo seal 

assembly included both 

metal and elastomeric 

sealing elements. The

primary seal was a metalto-metal seal between the 

polished bore of the 

wellhead, the seal 

assembly, and the polished 

mandrel of the casing 

hanger. The secondary 

seal was highly resilient 

elastomeric material. 

There were at least two 

ways in which 

hydrocarbons could have 

flowed up the annulus and 

through the seal assembly. 

TrialGraphix
Chief Counsel’s Report — Chapter 4.1: Flow Path | 41

Figure 4.1.3. Flow up the production casing.

First, there could have been a leak through the flow passages. This might have occurred because 

debris obstructed the seal area during the setting process, the seal failed to expand and set 

properly, or the seal dislodged after it was set.4 

Second, because the lockdown sleeve had not yet been set at the time of the blowout, pressure and 

forces from the well below could have lifted the casing hanger up and out of place in the wellhead. 

Several forces could have generated such uplift, alone or in combination: 

 upward pressure in the annulus that exceeded the weight of the production casing;5

 sustained flow of high-temperature 

hydrocarbons that caused the metal 

production casing to expand and lengthen;6 

 sufficiently forceful hydrocarbon flow; and 

 nitrogen gas that escaped from unstable 

foamed cement (explained in Chapter 4.4).7 

If the casing hanger lifted up as a result of net 

upward pressure in the annulus, the casing would 

have dropped back down once pressurized fluids 

escaped and the pressure equalized. That lifting and 

dropping motion would have occurred repeatedly, 

resulting in intermittent flow through the seal 

assembly. Repeated up-and-down movement could 

also dislodge the shoe track cement, creating an 

easier path for continuous flow. 

Flow up the Inside of the 

Production Casing 

Hydrocarbons could have traveled into and up 

through the production casing in two different ways. 

First, the cement in the shoe track could have failed, 

creating a path for hydrocarbons to flow into the 

open bottom end of the production casing. Those 

hydrocarbons would also have had to bypass two 

mechanical float valves (explained in Chapter 4.3). 

Second, hydrocarbons in the annulus could have 

flowed into the production casing through an 

opening in the casing. That opening could have 

been a breach in the 97⁄8-inch × 7-inch tapered 

crossover joint,8

 a leak in the threads of a casing 

joint,9

 or a hole in the casing wall, as illustrated in 

Figure 4.1.3. 

TrialGraphix
42 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Expert and Investigator Opinions on Flow Path Scenarios 

Each of the four general flow path scenarios described above are plausible during a blowout. 

Hydrocarbon flow up through the annulus is a more common problem10 that has ―long plagued 

the petroleum industry.‖11 But hydrocarbons have also been known to flow through shoe track 

cement and breaches of casing.12 

Experts involved in the Macondo containment operations initially speculated that flow had come 

up through the annulus and the seal assembly.13 But based on the evidence now available, expert

opinion has shifted to favor the scenario in which flow came up through the inside of the 

production casing.14 

BP internal investigators have concluded that hydrocarbons came up through the shoe track, 

based in large part on post-blowout well flow modeling.15 Transocean internal investigators have 

expressed agreement with this finding.

16

 Halliburton representatives, by contrast, continue to 

posit a theory in which seal assembly liftoff contributed to or caused annular flow.17 Halliburton 

has also speculated that there may have been a breach in the production casing.18 

The Chief Counsel‘s team finds that hydrocarbon flow came up through the production casing, 

most likely due to a failure of the shoe track cement.19

Forensic Evidence Suggests That 

Hydrocarbons Did Not Flow up the Annulus 

and Through the Seal Assembly

On September 5, 2010, BP removed the Deepwater Horizon‘s blowout preventer from the 

Macondo wellhead and replaced it with the blowout preventer from the Development Driller II, 

one of the rigs drilling the two relief wells. With a new blowout preventer and riser in place, the 

crew of the Development Driller II performed a series of forensic operations in and through the 

upper portions of the Macondo production casing.20

If hydrocarbons had flowed up the annulus and through the seal assembly, one would have 

expected to see at least the following two things: 

 hydrocarbons should have been present throughout the annular mud; and 

 the outside surfaces of the casing hanger and seal assembly should have been eroded by 

sustained high-volume flow through the flow passages.21 

If the casing hanger had lifted up, one would further expect the casing hanger not to have been

seated properly in the wellhead housing after the blowout. The evidence does not bear out 

these expectations. 
Chief Counsel’s Report — Chapter 4.1: Flow Path | 43

No Significant Presence of Hydrocarbons in the Annulus

Post-blowout operations analyzing the density of the fluid in the upper annular space suggest that 

the annular space contained insufficient hydrocarbons to support an annular flow path theory.

22

 

Perforation of the Production Casing

On October 7, BP perforated the 97⁄8-inch production casing midway down the well (from 9,176 to 

9,186 feet), creating a path from the inside of the production casing into the annulus.

23

 BP did 

this in order to determine the density of the fluids in the annular space. 

If the annulus had been filled with gaseous hydrocarbons (which are low in density, generally 

7 ppg or less24), high-density drilling mud (14.3 ppg25) inside the production casing would have 

flowed into the annulus until the densities in the annulus and production casing had equalized.26 

This would have led the crew of the Development Driller II to observe two signs: lost mud 

returns and a significant decrease in drill pipe pressure caused by the decrease in density of the 

fluid column in the production casing. 

Rig personnel did not observe either of those signs. Following perforation, they observed only a 

slight decrease in drill pipe pressure (from 250 to 143 psi27), indicating that the fluids in the 

annulus were similar in density to the mud in the production casing.28 (The bottomhole 

cementing procedure before the blowout left 14.17 ppg drilling mud in the annulus.29) After 

perforation, rig personnel monitored the well for 10 minutes and recorded no change in returns; 

the well was static.30 

Both of these observations suggested that the fluids present in the annulus after the blowout were 

the drilling fluids that BP and Halliburton had left in the annulus before the blowout.31 If 

hydrocarbons had flowed through the annulus, they would have flushed those drilling fluids out 

of the annulus during the course of the blowout.

Sampling of the Annular Fluid 

Subsequently, in mid-October, the Development Driller II’s crew cut the production casing 

midway down the well (at 9,150 feet),32 detached the production casing hanger from the 

wellhead,33 and lifted the cut portion of the casing up 15 feet.34 The crew then circulated the 

annular fluid up to the rig by pumping mud down into the production casing, around the corner 

of the cut portion, and up through the annulus into the riser, taking mud samples intermittently 

during the circulation.35 Those samples ranged from 13.0 to 14.3 ppg in density.36 Once again, 

those density measurements were consistent with the density of the drilling fluids that BP and 

Halliburton had left in the annulus at the end of the bottomhole cement job before the blowout.

37

 

This indicated again that hydrocarbons likely had not flowed through the annulus.38

No Erosion on the Outside of the Casing Hanger and 

Seal Assembly

A tremendous volume of oil and gas flowed out of the well at a tremendous rate during the course 

of the blowout.

39

 If that flow had traveled through the annulus, past the casing hanger, and 

through the seal assembly, it would have severely eroded the casing hanger and seal assembly.
44 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

On October 13, BP recovered the production casing hanger and seal assembly from the Macondo 

wellhead.40 Neither piece of equipment showed any signs of damage in locations where annular 

flow would have caused serious erosion. Instead, the relevant areas were totally undamaged.

Figure 4.1.4. Exterior of the Macondo production casing hanger and seal assembly.

 Figure 4.1.4. Exterior of the Macondo 

production casing hanger and seal assembly. 

The outside surfaces of the Macondo casing 

hanger and seal assembly show no damage 

(left). They have no erosion-induced 

channels. Instead, they resemble the 

condition of brand-new equipment (right). 

 The white square placed on the casing hanger 

before it was set remains. If hydrocarbons 

had flowed past that area, they almost 

certainly would have removed this mark.

41

 

 The 18 flow passages in the casing hanger 

show no signs of erosion.42 If hydrocarbons 

had flowed through those passages at the 

velocities estimated for this blowout, they 

likely would have eroded and enlarged the 

holes.43

 The rubber elastomeric element of the seal 

assembly (removed post-incident and 

circulated out into the shaker44) still retains 

its original shape, including a protrusion that 

one would expect to have been eroded away 

by annular hydrocarbon flow.

45

 

Dril-Quip
Chief Counsel’s Report — Chapter 4.1: Flow Path | 45

By contrast, the interior of the BOP46 (through which hydrocarbons definitely flowed) showed 

serious erosion, as did the interior of the casing hanger, seen in Figure 4.1.5.

47

Figure 4.1.5. Interior of the Macondo production casing hanger compared to 

new equipment.

This is strong evidence that hydrocarbons progressed up the inside of the production casing, not 

up the annulus past the casing hanger and through the seal assembly.

48

No Detachment of the Casing Hanger 

Post-blowout operations on the production casing hanger and seal assembly also suggest that the 

casing hanger and seal assembly remained in precisely the same place they had been set before 

the blowout. That observation is inconsistent with the theory that upward forces in the well lifted 

the casing hanger out of the wellhead. If the casing hanger had been lifted out of place, vented 

pressure, and then dropped back down, one would almost certainly expect the metal edges of the 

casing hanger and seal assembly to show damage and expect the casing hanger to have landed in a 

different position than the one in which it had originally been set. 

No Apparent Damage to Metal Edges

The casing hanger and seal assembly contain a series of circular metal lips (as shown in Figure 

4.1.6) that protrude and fit inside a corresponding profile on the inside of the wellhead housing. 

The parts fit together very precisely to create a metal-to-metal seal. If the casing hanger had lifted 

out of place, it would have caused significant damage to these metal lips. Post-blowout

photographs of the casing hanger and seal assembly show no such wear.49

 Dril-Quip

Macondo Equipment New Equipment
46 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Figure 4.1.6. Undamaged metal edges of the casing hanger and seal assembly.

Casing Hanger Properly Seated

In order to set a casing hanger, rig personnel normally lower the casing hanger into the wellhead. 

When in the correct position, a load transfer ring pops into place to support the load of the 

casing.50 The crew must lower the casing hanger slowly to avoid missing the correct landing spot. 

If the casing hanger had lifted up and dropped down during the blowout, it is highly likely that 

such movement would have been neither gentle nor slow. As a result, the load ring probably 

would have passed by its intended seat, and the casing hanger would not have reseated properly 

in its original position.51 

On September 9, the crew of the Development Driller II, along with representatives from 

Dril-Quip (the manufacturer of the casing hanger), ran a lead impression tool.

52 The tool 

indicated that the 97⁄8-inch casing hanger was ―seated properly‖ in the 183⁄4-inch high-pressure 

wellhead housing, where it had been placed prior to the blowout.53 Because none of the postblowout operations would have reconnected the casing hanger, this is strong evidence that it

never disconnected, and the casing hanger did not lift up during the blowout.54

Lead Impression Tool. A lead impression tool is a small block with soft metal (usually lead).

Rig personnel lower it into the wellhead and take an impression to identify the internal profile 

of the wellhead, including the elevation of the casing hanger.55

Passing Post-Blowout Positive Pressure Test

On September 10, the crew of the Development Driller II conducted a positive pressure test on 

the production casing and saw no significant change in pressure or flow.56 (Chapter 4.6 describes 

a positive pressure test in detail.) This is inconsistent with the casing hanger liftoff theory. A 

positive pressure test examines the pressure integrity of the casing hanger and seal assembly for a 

sustained period of time. If the casing hanger had lifted up or the seal assembly had leaked, the 

 Dril-Quip

Macondo Equipment New Equipment
Chief Counsel’s Report — Chapter 4.1: Flow Path | 47

crew of the Development Driller II likely would have observed a significant decrease in pressure 

or return flow from the well, or both.57

Successful Installation of the Lockdown Sleeve

Finally, on September 11, the crew of the Development Driller II successfully installed and 

pressure tested a lockdown sleeve in the Macondo wellhead.58 The fact that BP was able to install 

a lockdown sleeve after the blowout suggests that the casing hanger was properly seated in the 

wellhead.59 In order for the lockdown sleeve to properly set onto the casing hanger, the casing 

hanger itself must be properly seated in its high-pressure housing.60 

Circulation of Fluids During the Pre-Blowout Cement Job

Despite the evidence described above, Halliburton argues that ―hydrocarbons may have already 

been present in or even flowing into the annulus before the production casing cement job was 

complete.‖61 The company bases its hypothesis on the ―discernable drop in surface pressure at 

the conclusion of the cement job‖ that occurred on April 20 (illustrated in Figure 4.1.7).

62

 

Halliburton‘s argument is unpersuasive for several reasons. 

First, the observed fluctuation in surface pressure can be explained by the wellbore geometry at 

Macondo.63 Macondo had a tapered production casing string—97⁄8 inches from wellhead to 

12,488 feet below sea level, tapering to 7 inches from 12,488 feet below sea level to the bottom of 

the casing. In wells with a tapered production casing (and hence a tapered annulus), ―each 

discrete volume of fluid will grow in column height as it travels down the well [past the crossover

joint] and shrink as it comes up the well [past the crossover joint].‖

64 As a result, the hydrostatic 

pressure differential between the casing and the annulus will change over the course of the 

cement job (as it did at Macondo). 

Second, the drop in surface pressure did not appear particularly anomalous at the time. 

In fact, Halliburton‘s own pre-job cementing model predicted that pressure would decrease by 

some amount.65 The Chief Counsel‘s team has not identified any evidence to suggest that rig 

personnel monitoring the Macondo cement job thought that the pressures they were seeing

were abnormal.66 

Finally, the cement job pressure readings cannot alone support a theory of annular flow (a point 

that Halliburton concedes67), and the other evidence discussed above is inconsistent with 

annular flow.
48 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Figure 4.1.7. Halliburton post-cement-job report.

Hydrocarbons Appear to Have Flowed Into 

and up the Production Casing 

Post-blowout inspection of the production casing hanger and seal assembly retrieved from the 

Macondo well shows severe erosion on the inside of the casing hanger (shown in the left-side 

photo in Figure 4.1.8). Serrations near the top of the casing hanger—normally 1⁄8-inch deep—are 

almost completely abraded away.68 Threads that normally run around the inside of the casing 

hanger are flattened.69 The slot that normally interrupts the threads—1⁄4-inch deep when new—

appears as an almost nonexistent indentation.70 These observations all suggest that hydrocarbons 

came up through the production casing. 

Halliburton
Chief Counsel’s Report — Chapter 4.1: Flow Path | 49

Figure 4.1.8. Erosion of the inside of the casing hanger.

The remaining question is precisely how hydrocarbons entered the inside of the production 

casing. Currently available evidence leads the Chief Counsel‘s team to conclude that 

hydrocarbons almost certainly entered the production casing through the shoe track. At the same 

time, the Chief Counsel‘s team cannot rule out the possibility that hydrocarbons entered the 

production casing from the annulus through a breach in the side of the casing string.

Hydrocarbons Likely Entered the Production Casing Through 

the Shoe Track

Problems With the Primary Cement Job Could Have Compromised the 

Shoe Track Cement

The bottomhole cement job at Macondo involved an unusual number of risk factors. Some were 

inherent in the conditions at the well; others developed during the course of the design and 

execution of the bottomhole cement job. This includes a cement slurry that may have been 

unstable, uncertainties with regard to cement placement (because of doubts about float 

conversion and centralization), and concerns over cement contamination (as a result of limited 

pre-cementing circulation and low cement volume and flow rate). Chapter 4.3 discusses these 

risks in more detail.

The Float Valves Would Not Have Provided an Independent Barrier to 

Flow Through the Shoe Track

It is not clear whether the float valves in the Macondo well converted prior to the pumping of the 

bottomhole cement job. A failure to convert these two-way valves into one-way valves would have 

allowed the cement to flow back in the wrong direction and therefore could have compromised 

the bottomhole cement job. Even if they had converted, the float valves may not have closed fully 

due to malfunction or debris. In any case, float valves are not typically considered independent 

barriers to hydrocarbon flow. Chapter 4.3 discusses these issues in more detail.

Dril-Quip

Macondo Equipment New Equipment
50 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Evidence From the Static Kill Operation Suggests Flow Through the 

Shoe Track 

Data from the August 4 static kill operation on the Macondo well suggest that flow came up 

through the shoe track. In the static kill operation, BP planned to pump 13.2 ppg mud into the 

well, from the top of the wellbore to the bottom, monitoring pressures along the way.71 Before 

doing so, the company modeled expected pressures and volumes for several flow path scenarios, 

including flow up the annulus and flow up the production casing (with the drill pipe in different 

positions).72 Pressures observed during the operation more closely matched flow up the 

production casing.73

The static kill data analysis has several shortcomings. First, BP performed its analysis with 

imperfect knowledge of the wellbore geometry and without knowing whether there was debris or 

other obstructions in the well.74 Second, the observed pressures matched the modeled pressures 

only up to a certain point and then diverged.75 Third, it is unlikely that the pressure observations 

were sensitive enough to distinguish a casing breach near the bottom of the production casing 

(such as near the float collar).

76

 

Analysis of the static kill data is still ongoing and subject to future revision.

The Chief Counsel’s Team Cannot Rule Out the Possibility of 

Flow Through a Breach in the Production Casing

Hydrocarbons may have entered through a breach in the production casing, although the Chief 

Counsel‘s team considers this scenario unlikely.

A Breach Above the Top of Cement Is Unlikely

A breach in the 97⁄8-inch × 7-inch tapered crossover joint or anywhere above the top of 

the annular cement is unlikely. If hydrocarbons 

went from the formation into the annulus and then 

through such a breach, one would expect to observe 

hydrocarbons in the annular space. As explained 

above, there is no evidence of a significant 

hydrocarbon presence in the annulus. 

A Breach as a Result of External 

Pressure Is Unlikely

External pressure in the annulus (caused by 

hydrocarbon flow or nitrogen gas) could have 

caused a casing breach, but this is unlikely for at least two reasons.

First, if annular pressure had been sufficient to cause a breach in the production casing 

or threaded connections, that pressure should first have caused rupture disks in the 

16-inch casing, or the 16-inch casing itself, to burst (shown in Figure 4.1.9). The 

16-inch casing runs from 5,227 to 11,585 feet below sea level.77 BP installed three sets 

of rupture disks into the casing wall. The rupture disks were designed to fail before 

the production casing.78 Specifically, if pressure between the 16-inch casing and the 

production casing reached 7,500 psi, the rupture disks should have burst outward.79 

Figure 4.1.9. 16-inch 

casing and rupture 

disks.

TrialGraphix
Chief Counsel’s Report — Chapter 4.1: Flow Path | 51

This pressure is, by design, less than the 11,140 psi that the production casing and its threaded 

connections are designed to withstand.

80

 Even if the rupture disks did not function as designed, 

the 16-inch casing probably would have failed in some manner once pressures significantly 

exceeded 6,920 psi.81 But it appears that neither the rupture disks nor the 16-inch casing failed. 

Chapter 4.2 discusses this issue in more detail. 

Second, there is no evidence to date that the production casing was designed improperly, or that 

crew members improperly made up one or more casing joints before sending them downhole. A 

Weatherford representative was on the rig, monitoring the makeup of the casing, tracking torques 

and turns through a computer program, and verifying that all of the connections were up to 

standard.82 Furthermore, the Weatherford daily log and data from the computer program do not 

show any mishaps in casing makeup for most of the production casing.83 (The integrity of 

connections made up onshore—including the reamer shoe, centralizer subs, float collar, and 

crossover joint—remains unconfirmed.84) While members of the rig crew inadvertently dropped 

and damaged some pipe when making up the 7-inch portion of the casing,85 the evidence shows 

that they subsequently replaced the damaged joints before sending them downhole.86

A Breach Below the Top Wiper Plug as a Result of Internal Pressure 

Cannot Be Ruled Out

The Chief Counsel‘s team cannot completely rule out a casing breach below the top plug, though it 

is unlikely.87 If such a breach occurred prior to the cement job, it could have jeopardized the 

placement of the bottomhole cement. 

Testimonial evidence shows that in the day before the blowout BP personnel were concerned 

about a possible casing breach. (Chapter 4.3 discusses these facts in more detail.) On April 19, 

after attempting to convert the float equipment and establishing circulation, one witness recalls 

well site leader Bob Kaluza saying, ―I‘m afraid that we‘ve blown something higher up in the casing 

joint.‖88 Kaluza was presumably referring to the possibility that the unusually high 3,142 psi 

pressure that BP directed the rig crew to apply to convert the float valves created a breach in the 

production casing.89 BP and rig personnel subsequently observed lower-than-expected 

circulating pressures, which could be consistent with mud being circulated through a breach in 

the casing and back up to the rig through the upper part of the annulus, rather than out the 

bottom of the casing and up the entire annulus. Kaluza expressed his concern to BP drilling 

engineer Brian Morel, who was also on the rig.90 Morel relayed the concern to BP wells team 

leader John Guide, who was onshore.91 Meanwhile, Morel also emailed Weatherford sales 

representative Bryan Clawson, ―Yah we blew it at 3140, still not sure what we blew yet.‖92 

After discussing the issue, the BP Macondo team determined that if there were a casing breach,

they could not fix it at that point in the operations.93 They also concluded that they would detect 

any such breach in later well integrity pressure tests and could take remedial measures at that 

time.

94

 There is no evidence that anyone actually revisited the issue prior to the blowout. 

BP personnel may not have detected a casing breach near the float collar. After the cement job, 

rig personnel performed a positive pressure test on the well to test the integrity of the production 

casing. But a positive pressure test does not test the casing below the top wiper plug.95 
52 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

(Chapter 4.6 discusses positive pressure tests in more detail.)* After the blowout, BP conducted a 

static kill operation on the well and observed pressure data consistent with shoe track flow. But 

the modeled and observed pressure and volume data were not sensitive enough to distinguish a 

casing breach near the bottom of the production casing (such as near the float collar) from flow 

through the shoe track cement.

96

 And although a Weatherford log tracking the makeup of the 

production casing showed no mishaps, the log did not contain data on the integrity of connections 

made up onshore—including the float collar.97

Technical Findings

The Annular Cement Did Not Isolate the Hydrocarbon Zones 

The Chief Counsel‘s team finds that the cement in the annular space did not isolate the 

hydrocarbon zones. This finding calls into question the quality of the bottomhole cement job. 

Chapters 4.3 and 4.4 identify possible shortcomings in that cement job including mud 

contamination, improper cement placement, and cement slurry instability. 

Hydrocarbons Came to the Surface by Traveling Through the 

Production Casing

The Chief Counsel‘s team finds that hydrocarbons came to the surface through the inside of the 

production casing. This finding calls into question BP‘s temporary abandonment procedure and 

design. Chapter 4.5 discusses the risks attendant to the temporary abandonment. 

The Shoe Track Cement Probably Failed 

The Chief Counsel‘s team finds that flow almost certainly came up through the shoe track of the 

production casing. Cement in the shoe track should have blocked this flow. This finding again 

calls into question the quality of the bottomhole cement job. Chapter 4.3 discusses possible 

reasons for shoe track cement failure. 

 

* Rig personnel also performed a negative pressure test on the well. A negative pressure test does test the 

integrity of the casing down through the shoe track as well as the shoe track cement. But rig personnel 

misinterpreted the negative pressure test. Chapter 4.6 discusses this in more detail.
Chief Counsel’s Report — Chapter 4.2: Well Design | 53

Chapter 4.2|Well Design

BP’s engineering team made a number of important well 

design decisions that influenced events at Macondo. Among 

other things, the engineers (1) decided to use a long string 

production casing, (2) installed rupture disks in the well, 

and (3) decided to avoid creating trapped annular spaces by omitting a protective 

casing and leaving annular spaces open to the surrounding formation. The Chief 

Counsel’s team finds that these decisions complicated pre-blowout cementing 

operations and post-blowout containment efforts. 

Deepwater Well Design 

Wells are drilled for a reason: either to explore for 

oil and gas, appraise an earlier discovery, or create a 

development well in an existing oil field. By the time the 

well is designed, subsurface geologists and geophysicists 

will have identified subsurface objectives, usually using 

seismic reflection data. They will also have prepared—in 

as much detail as possible—a geologic prognosis describing 

lithology, pressure, and fluid content as a function of 

depth. If there are other wells nearby, the geologists and 

geophysicists will have used data from those wells to inform 

their prognosis. 

The design team that plans the well must determine how best 

to achieve the well’s objectives while managing potential drilling 

hazards. The hazards can include a variety of geologic features. 

For instance, porous gas-bearing intervals (“shallow gas”)—sand 

layers containing pressurized gas or water, or unstable formations—

may occur in the first few thousand feet below the seabed. Geologic 

faults and low-pressure hydrocarbon-bearing sands (depleted by 

nearby oil production) can also present hazards. Sudden variations in 

subsurface pore pressure can pose hazards as well. Operators must also 

consider man-made hazards such as nearby oil and gas development 

infrastructures (wells, platforms, pipelines) and ship traffic. 

In many cases the design team can identify drilling hazards in advance 

and avoid them. But some geologic hazards, such as high pore pressures 

and hydrocarbon deposits, are impossible to avoid. Indeed, they are closely 

associated with the drilling objectives—oil companies often target high-pressure 

hydrocarbon reservoirs. High pore pressures are a common feature of the deepwater 

Gulf of Mexico environment, and often signal the presence of oil and gas.

Drilling engineers must therefore keep several key issues in mind as they design a deepwater well. 

Artist’s rendering of 

the Macondo well 

from rig to rathole.

TrialGraphix

Figure 4.2.1
54 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Pore Pressure and Fracture Gradients

Drilling engineers must design wells to manage intrinsic risks. Specifically, they must develop 

drilling programs that will manage and reflect the pore pressure and fracture gradients at a given 

drilling location as shown in Figure 4.2.2. (Chapter 2 describes these concepts in more detail.) 

The design team must specify the kinds of drilling fluids that will be used and the number and 

type of casing strings that will extend from the seafloor to the total depth of the well. The drilling 

fluids and casing strings must work together to balance and contain pore pressures in the rock 

formation without fracturing the rock. 

Creating this plan can be difficult if engineers 

have limited information about subsurface 

geology and if actual pore pressures vary 

significantly from predictions.1

 This is often 

the case in exploration wells or in the first 

well in a new field. The problem frequently 

crops up in the Gulf of Mexico, which is prone 

to having a narrow window between the pore 

pressure and fracture gradients as well as 

zones of pore pressure repression (where the 

pore pressure gradient suddenly reverses and 

decreases with depth).2

 

Because drilling conditions often differ 

significantly from predictions, engineers 

often design and redesign a deepwater well 

as the well progresses. They work constantly 

to keep two factors within tolerable limits: 

equivalent static density (ESD) and equivalent circulating density (ECD). ESD refers to 

the pressure that a column of fluid in the wellbore exerts when it is static (that is, not circulating). 

ECD refers to the total pressure that the same fluid column exerts when it is circulating. When 

drillers circulate fluids through a well, ECD exceeds ESD because the force required to circulate 

the fluids exerts additional pressure on the wellbore. 

In planning the well, engineers will design a mud program to keep both ESD and ECD below the 

rock’s fracture gradient. Drillers monitor these parameters carefully as they work. 

Barriers to Flow

As discussed in Chapter 2, operators typically employ redundant barriers to prevent 

hydrocarbons from flowing out of the well before production operations. One important barrier 

in any well is the mud and drilling fluid system in the wellbore. When properly designed and 

operated, the drilling fluid system should balance the pressure of any hydrocarbons in the well 

formation. Engineers can also use other kinds of barriers during drilling and completion. Those 

barriers include cemented casing, mechanical and cement plugs, and the blowout preventer 

(BOP). Sound industry practice—and BP’s own policy—generally requires an operator to 

maintain two verified barriers along any potential flow path.3

 

Figure 4.2.2. Narrow drilling margins.

TrialGraphix

Pore Pressure Gradient

Mud Weight

Fracture Gradient
Chief Counsel’s Report — Chapter 4.2: Well Design | 55

Annular Pressure Buildup

If an operator plans to use a given well to produce 

oil in the future (rather than merely to learn about 

subsurface geology), its design team must consider 

the environmental and mechanical stresses that the 

well will experience over its lifetime. The casing and 

completion program must ensure that these stresses 

do not compromise well integrity over the life of the 

well, which could be as long as several decades.

In deepwater production wells, engineers pay 

special attention to a phenomenon called annular 

pressure buildup (APB). Figure 4.2.3 illustrates 

that during production activities, high-temperature 

hydrocarbons travel up from the pay sands through 

production tubing installed inside the production 

casing. The flow of hydrocarbons heats up the well. 

As a result, fluids and gases in the annular spaces of 

the well expand. If the well design creates annular 

spaces that are enclosed, the fluids and gases trapped 

within those spaces will exert increasing pressure on 

the well components as they heat up. In some cases, 

the pressure can become high enough to collapse 

casing strings in the well and to force the operator to 

abandon the well. 

Managing annular pressure buildup in a deepwater 

well requires careful planning and design. Engineers 

can use a number of design features to manage 

annular pressures or mitigate the risks of casing 

collapse. These include rupture disks, compressible 

fluids in the annular space, and insulated production 

tubing. Finally, they can design wells in ways that 

avoid creating trapped annular spaces at all. 

The Macondo Well Design 

Even before it began drilling Macondo, BP believed that the well might encounter a substantial 

hydrocarbon reservoir.4

 But BP also recognized that it might also encounter a number of hazards, 

including shallow gas sands, overpressures, and depleted reservoir zones, as well as the expected 

oil and gas in the mid-Miocene objective reservoir. BP chose the particular drilling location for 

Macondo to penetrate the objective section while avoiding shallow gas sands that it had identified. 

BP identified potential minor drilling hazards beneath 8,000 feet below sea level: thin 

gas-charged sands and depleted (low-pressure) zones.5

Using seismic imagery, BP had a high degree of confidence that the formation below contained 

a significant accumulation of oil and gas.6

 BP therefore planned the Macondo well as an 

exploration well that it could later complete and turn into a production well.7

 

During production 

activities, 

high-temperature 

hydrocarbons travel up 

from the pay sands 

through production tubing 

installed inside the 

production casing. The 

flow of hydrocarbons 

heats up the well, causing 

fluids and gases in the 

annular spaces of the well 

to exert pressure on 

their surroundings.

Pay Sands

Production 

Tubing

Production 

Casing

Figure 4.2.3. Annular pressure buildup (APB).

TrialGraphix
56 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

BP drilling engineer Brian Morel and senior engineer Mark Hafle 

had the primary responsibility for the Macondo well design work.8

 

They worked with a number of BP engineers and geoscientists to 

develop their plans.9

 Geologists and petrophysicists from BP’s 

Totally Integrated Geological and Engineering Resource (TIGER) 

team helped develop a pore pressure profile for the well based 

on other wells in the vicinity (“offset wells”) as shown in Figure 

4.2.4.10 A BP casing and tubular design team independently 

reviewed the well design.11 Fluid experts and rock strength experts 

checked the geomechanical aspects of the well.12 And because the 

well was being designed as a producer, BP completion engineers 

also provided input during the design process.13 The completion 

engineers recommended, among other things, an analysis of 

the well’s potential for annular pressure buildup and possible 

mitigation measures.14

In June 2009, the initial Macondo well design underwent peer 

review.15 The reviewers concluded that the Macondo design team 

“did a lot of good work,” that the initial design was “[r]obust” and 

“supported by good data and analysis,” and that “all major risk[s] 

[were] addressed and mitigations developed.”16 Over the course of 

the next year, the Macondo engineering team would update 

its drilling program several times. But three key design features 

never changed.

Rupture Disks

All of BP’s Macondo well designs included three sets of rupture 

disks in the 16-inch casing.17 The 16-inch casing was the longest 

piece of pipe outside of the production casing. The rupture disks

(or burst disks) would relieve annular pressure before that pressure 

could build up high enough to cause a collapse of the production 

casing or the 16-inch casing. 

The disks worked in two ways as shown in Figure 4.2.5. First, if pressure between the 16-inch 

casing and the production casing reached 7,500 pounds per square inch (psi), the rupture disks 

would burst outward and release that pressure.18 Because the production casing was rated to 

withstand 11,140 psi of pressure, this would prevent annular pressure from rising to the point at 

which it could collapse the production casing.19 Second, if pressure outside of the 16-inch casing 

(that is, between the 16-inch casing and the other larger casing strings outside it) exceeded 

1,600 psi, the rupture disks would collapse inward to release that pressure.20 Because the 16-inch 

casing was rated to withstand 2,340 psi of pressure, this would prevent pressure outside the 

16-inch casing from rising to the point at which it could collapse the 16-inch casing.21

Once ruptured, the disks would leave small holes in the 16-inch casing through which pressure 

could bleed into the surrounding rock formation.22

Figure 4.2.4. Offset wells and seismic data.

The green star indicates Macondo’s location.

BP
Chief Counsel’s Report — Chapter 4.2: Well Design | 57

Protective Casing

BP’s well design consistently and deliberately omitted 

a protective casing. A protective casing is an 

intermediate casing string outside the production 

casing that runs from deep in the well all the way 

back to the wellhead.23 A protective casing supplies a 

“continuous pressure rating” for the interval that it covers 

(as shown in Figure 4.2.6) and seals off potential leak paths 

at the tops of previous liner hangers.24 

It is common industry practice to use a protective casing 

whenever running a long string production casing.25 But the 

Macondo team never planned for a protective casing26 because 

installing such a casing would also have negated their efforts to 

mitigate annular pressure buildup.27 Specifically, it would have 

sealed off the rupture disks and the previously open annuli in the 

casing design.

The Macondo well 

design included three 

sets of rupture disks 

in the 16-inch casing. 

If pressure reached 

7,500 psi between 

the production casing 

and 16-inch casing, 

the rupture disks 

would burst outward. 

If pressure reached 

1,600 psi between 

the 16-inch casing 

and the larger casing 

string outside of it, 

the rupture 

disks would 

collapse inward.

Pay Sands

7,500 psi Production 

Casing

Larger 

Casing

Production 

Casing

Larger 

Casing

16" Casing

1,600 psi

16" Casing

Figure 4.2.5. Rupture disks.

Figure 4.2.6. Protective casing.

Protective casing 

(yellow) provides 

a “continuous 

pressure rating” 

for the casing 

interval that it 

covers (gray).

TrialGraphix

TrialGraphix
58 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Long String Production Casing

Third, BP’s Macondo well design called for a long string production casing, or long string, 

stretching from the bottom of the well all the way to the wellhead. This was true of the initial well 

design as well as the final well design.28 

As shown in Figure 4.2.7, the alternative to a long string production casing would have been a 

liner. A liner is a shorter string of casing hung from a casing hanger lower in the well. In order 

to connect the liner back to the wellhead, BP would eventually have had to install a tieback—a 

string of casing pipe stretching between the top of the liner on one end to the wellhead on the 

other end. Setting the tieback adds two annular flow barriers to the well design.

In the weeks just prior to the blowout, BP briefly considered using a liner instead of a long string 

at Macondo. There is no evidence that the Macondo team ever considered having the Deepwater 

Horizon crew install the tieback before temporarily abandoning the well.29 They presumably 

would have left that job for a completion rig. 

Drilling the Macondo Well 

BP encountered a series of complications while drilling the Macondo well. This included two 

previous kicks, a ballooning event, lost circulation events, and trouble determining pore pressures 

(as shown in Figure 4.2.8). Together, these issues made Macondo “a difficult well.”30 

Long String Liner Liner-Tieback

TrialGraphix

Figure 4.2.7. Casing options in deepwater drilling.
Chief Counsel’s Report — Chapter 4.2: Well Design | 59

Kicks and Ballooning

Twice prior to April 20, the Macondo well experienced 

an unwanted influx into the wellbore, or a “kick.” On 

October 26, 2009, the well kicked at 8,970 feet. The rig 

crew detected the kick and shut in the well. They were 

able to resolve the situation by raising the mud weight 

and circulating the kick out of the wellbore.31 On March 

8, 2010, the well kicked again, at 13,305 feet.32 The crew 

once again detected the kick and shut in the well.33 But 

this time, the pipe was stuck in the wellbore.34 BP severed 

the pipe and sidetracked the well.35 

On March 25 the Macondo well also had a ballooning, or 

“loss/gain,” event. The rig lost fluids into the formation. 

When the crew decreased the pressure of the mud in the 

wellbore, the rig then received an influx of fluids from 

the formation. 

Lost Circulation During Drilling

A major risk at Macondo was the loss of drilling fluid into 

the formation, called lost circulation or lost returns.

36 

At various points in February, March, and April, the 

pressure of drilling fluid exceeded the strength of the 

formation, and drilling fluid began flowing into the rock 

instead of returning to the rig.37 Lost circulation events 

are common in offshore drilling. The Horizon rig crew 

generally responded with a standard industry tactic: It 

pumped thick, viscous fluid known as lost circulation 

material into the well and thereby plugged the fractures 

in the formation. 

The Horizon crew successfully addressed repeated lost 

circulation events while drilling the Macondo well.38 The 

events occurred frequently and at various depths, and 

sometimes lasted several days: once in mid-February, 

four times in March, and three times in April.39 In total, 

BP lost approximately 16,000 barrels of mud while 

drilling the well, which cost the company more than 

$13 million in rig time and materials.40 

Uncertain Pore Pressures Affect the 

Well Design

The kicks, ballooning, and lost circulation events at 

Macondo occurred in part because Macondo was a “well 

with limited offset well information and preplanning 

pressure data [were] different than the expected case.”41 

Given BP’s initial uncertainty about the pore pressures 

October 6, 2009

Marianas spuds the well

October 26, 2009

Kick at 8,970 feet

TrialGraphix

Lost Returns

March 8, 2010

Kick at 13,305 feet

February 17-21, 2010

12,350 feet

March 21, 2010

13,150 feet

March 31, 2010

17,163 feet

April 4-7, 2010

18,260 feet

April 3, 2010

17,761 feet

March 2, 2010

11,587 feet

March 3-5, 2010

11,575 feet

April 9, 2010

18,193 feet

March 25, 2010

Ballooning at 15,113 feet

April 9, 2010

Total depth at 18,360 feet

November 9, 2009

Hurricane Ida damages 

Marianas at 9,090 feet

January 31, 2010

Deepwater Horizon arrives 

and resumes drilling on

February 10, 2010

7,937'

8,968'

11,585'

13,145'

15,103'

17,168'

18,360'

6,217'

5,067' below sea level

Figure 4.2.8. Timeline of drilling events.
60 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

of the rock, the company had to adjust its well design as it drilled the well and gained better pore 

pressure information. 

This was particularly true after the March 8 kick. According to contemporaneous 

communications among BP engineers, the “kick and change in pore pressure...completely 

changed” the forward design42 and did so “rapidly.”43 “Due to well pressure uncertainty, it [was] 

unknown how many more liners [BP would] need to set before getting to TD.”44 Accordingly, the 

Macondo team decided to proceed more conservatively and set casing strings shallower in the 

well.45 They installed an intermediate 117⁄8-inch liner (at 15,103 feet) that had been set aside as 

a contingency in the original plan.46 They then set an additional liner, 97⁄8 inches in diameter, 

above the reservoir (at 17,168 feet).47 And they planned for yet another smaller casing size in the 

final hole section.48

Rig Crew Calls Total Depth Early Due to Narrow Drilling Margin

The last of the lost circulation events occurred on April 9, after the rig had begun to penetrate the 

pay zone.49 At 18,193 feet below sea level, the drilling mud pressure exceeded the strength of the 

formation, and the rig crew observed lost returns. The point at which the formation gave way—

when ESD was approximately 14.5 pounds per gallon (ppg)—came as a surprise to the Macondo 

team.50 The crew had to stop drilling operations until they could seal the fracture and restore mud 

circulation. They pumped 172 barrels of lost circulation material down the drill string, hoping 

to plug the fracture.51 The approach worked, but BP’s onshore engineering team realized the 

situation had become delicate.52 In order to continue drilling, they had to maintain the weight 

of the mud at approximately 14.0 ppg in order to balance the pressure of hydrocarbons pushing 

out from the formation. But drilling deeper would exert even more pressure on the formation. 

Engineers calculated that drilling with 14.0 ppg mud would yield an ECD of nearly 14.5 ppg—

presenting the risk of once again fracturing the rock and losing returns.53 At that point, “it became 

a well integrity and safety issue.”54 The engineers had “run out of drilling margin.”55 The well 

would have to stop short of its original objective of 20,600 feet. 

Rig personnel were able to carefully drill ahead an additional 167 feet and called total depth at 

18,360 feet. In that sense, drilling was successful: BP reached the targeted reservoir zone and 

was able to run a comprehensive suite of evaluation tools.56 

ECD Concerns Influence Final Production Casing Design 

BP engineers then began preparing to install a production casing. BP had Halliburton run a series 

of computer models to help plan for cementing the production casing. 

March 23 Meeting Considers Both Long String and Liner Production Casing 

On March 23, Hafle, Morel, and in-house BP cementing expert Erick Cunningham met with 

Halliburton cementing engineer Jesse Gagliano to discuss ECD concerns in the modeling.57 The 

team was trying to decide what size production casing to install and cement at the bottom of 

the well.58 Earlier that month, the engineers had modeled both long string and liner production 

casing designs on two sizes of pipe—75⁄8-inch and 7-inch.59 They were concerned the 75⁄8-inch 

pipe would create a narrow annulus and increase friction to the point that the formation would 

break.60 According to Halliburton’s models, a smaller 7-inch pipe reduced ECD significantly.61 

Though no decision was made as to casing design or diameter, the group decided to find out 

how much 7-inch pipe was available should they decide to use that size production casing at the 

bottom of the well.62
Chief Counsel’s Report — Chapter 4.2: Well Design | 61

April Meetings Finalize Well Design 

BP and Halliburton continued to meet and review Halliburton’s computer models of the 

production casing. The team met on April 9 but decided Halliburton’s model was inaccurate 

because it predicted an ESD of 13.9 ppg, which was erroneously low because the weight of the 

mud in the wellbore was itself heavier than 13.9 ppg.63 Gagliano created a new model, but on 

April 12 BP drilling and completions operations manager David Sims determined the ESD in this 

model was now too high64 and requested that Cunningham review and lend his expertise to the 

well plan.65 

At that point, the team considered running a liner instead of a long string in the production 

interval. The Macondo team believed that ECD would be lower in running the liner.66 But BP 

engineering manager John Sprague raised additional technical concerns and requested a review 

of annular pressure buildup issues related to running a liner.67

The potential for a last-minute switch had BP engineers scrambling. Morel asked casing design 

specialist Rich Miller for a “quick response” on the annular pressure buildup review.68 “Sorry 

for the late notice,” he added, “this has been a nightmare well which has everyone all over the 

place.”69 Miller replied, “We have flipped design parameters around to the point that I got 

nervous,” but with respect to annular pressure buildup issues related to the liner he determined 

“[a]ll looks fine.”70

Although the onshore engineers had not yet decided the final casing parameters, the rig crew 

was still supposed to set the casing in a few days, so BP wells team leader John Guide instructed 

the BP well site leaders on the rig to ready the equipment necessary to run either a liner or a 

long string.71 BP had a number of boat and helicopter runs to the rig over the next several days, 

trying to coordinate the logistics of equipment and people necessary for the upcoming casing and 

cement jobs. Well site leader Don Vidrine complained to Guide about the last-minute changes. 

“[T]here [have] been so many last minute changes to the operation that the WSL’s have finally 

come to their wits end,” Guide recounted. “The quote is ‘flying by the seat of our pants.’”72 

Transocean also expressed concern to Guide about the long string/liner decision being made 

“very late in the day.”73 The contractor needed sufficient advance notice to verify logistics and, in 

particular, that the rig’s equipment was fit to handle the final casing string’s weight.74

Engineers Decide to Run Long String at April 14 Meeting

On April 14, Hafle, Morel, Cunningham, BP operations engineer Brett Cocales, and drilling 

engineering team leader Gregg Walz met to review Halliburton’s ECD modeling.75 The group 

identified another limitation of the model—they determined that its data inputs did not reflect 

the actual latest data acquired during the well logging process.76 After reassessing well conditions 

with Cunningham,77 the team decided they could successfully run and cement a long string.78 

Several factors appear to have motivated the decision to install and cement a long string 

production casing:79 a desire to stick with the original design basis of the well,80 a desire to 

mitigate future annular pressure buildup by avoiding a trapped annulus,81 a desire to eliminate an 

extra mechanical seal that could leak during production,82 and a desire to save $7 million to 

$10 million in future completion costs.83 

The team made the decision official in a management of change (MOC) document—part of 

BP’s process for documenting changes in well design.84 According to the MOC, the long string 

provided the best “well integrity case for future completion operations,” “the best economic 
62 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

case” for the well, and could be cemented successfully with careful cement job design.85 The 

document also discussed the risk that the primary bottomhole cement would not act as a barrier 

(as discussed in Chapter 4.3).86 Senior BP managers—including Sims, Walz, Guide, Sprague, and 

others—reviewed the management of change document and approved.87 

Technical Findings

Choosing a Long String Production Casing Made the Primary 

Cement Job at Macondo More Difficult

Operators in the Gulf of Mexico routinely use long string production casings in deepwater 

wells.88 But BP’s decision to use a long string at Macondo triggered a series of potential problems, 

particularly with the bottomhole cement job.

The lost circulation event at the pay zone in early April 

led the company’s engineers to carefully analyze whether 

they could circulate cement successfully around the 

production casing (or liner) without fracturing the 

already delicate formation. Because cementing a liner 

is typically easier than cementing a long string, the 

decision by BP engineers to stay with the long string 

design further complicated an already complex cement 

procedure in several ways.89

First, the use of a long string increased the risk of cement 

contamination. Cementing a long string instead of a 

liner required cement to travel through a larger surface 

area of casing before reaching its final destination, as 

shown in Figure 4.2.9. That increased surface area 

translates into increased exposure of cement to the film 

of mud and cuttings that adheres to the casing.90 That 

risk was exacerbated by the fact that the long string 

production casing was tapered, making it more difficult 

for wiper plugs to reliably wipe clean.91

Second, using a long string eliminated the possibility of 

rotating or otherwise moving the casing in place during 

the cement job. Rig personnel could have rotated a liner, 

which would have improved the likelihood of a quality 

cement job.92 But it is more difficult to rotate a long 

string than it is to rotate a liner, so choosing that design 

eliminated one option for mitigating cementing risks.

Third, cementing a long string typically requires higher cement pumping pressure (and higher 

ECD) than cementing a liner.93 To compensate for that pressure increase in a fragile wellbore 

like the one at Macondo, BP engineers made other adjustments to the cement job. As Chapter 

4.3 explains, some of the adjustments the engineers made to reduce ECD increased the risk of 

cementing failure. If BP engineers had chosen to use a liner, they not only could have obtained 

lower ECDs, but also may have been able to ignore ECD entirely. This is because the liner hanger 

includes a mechanical seal that serves as a barrier to annular flow.94 By relying on that seal, 

engineers can design a more robust primary cement job—they can, for instance, deliberately 

TrialGraphix

Figure 4.2.9. Cementing a long string vs.

cementing a liner.

Long String Liner
Chief Counsel’s Report — Chapter 4.2: Well Design | 63

exceed ECD limits, risk lost returns, and then plan to remediate cement problems later without 

having to rely on the cement as a barrier to flow.95

Fourth, it is harder to remediate a cement job at the bottom of a long string than it is to remediate 

one at the bottom of a liner. With a liner, rig personnel can remediate the cement job, before 

completing the setting of the liner, by lifting the stinger above the liner hanger and pumping 

additional cement over the top of the liner hanger.96 That method is more effective and less 

complex than remediating a long string.97 With a long string, rig personnel must perform a 

squeeze job (as defined in Chapter 4.3). A squeeze job is complicated and time-consuming—it 

can take several days.98 And BP classifies the time spent squeezing as nonproductive time,99 an 

undesired disruption that the company expects its employees to minimize.100

BP’s Design Efforts to Mitigate the Risk of Annular Pressure 

Buildup Compromised Containment Operations

BP’s decision to install rupture disks at Macondo and not to use a protective casing complicated 

its containment efforts and may have delayed the ultimate capping of the well. (Commission Staff 

Working Paper #6, titled “Stopping the Spill: the Five-Month Effort to Kill the Macondo Well,” 

discusses these issues in more detail.) Had BP’s design omitted the disks and included the casing, 

the company would have had increased confidence about the Macondo well’s integrity. This, in 

turn, may very well have allowed the company to shut in the well earlier. 

In BP’s early analyses of its failed late-May top kill attempt, the company concluded that the 

rupture disks in the 16-inch casing may have collapsed inward during the initial blowout.101 The 

disks could have collapsed if hydrocarbons had entered the annular space between the 16-inch 

casing and the production casing. Those hydrocarbons would have been much lighter than the 

heavy drilling mud that would have been in the annular space outside the 16-inch casing. That 

weight difference would have generated a pressure differential significant enough to collapse the 

rupture disks.102 

Based on this theory, as well as pressure readings and visual observations from the field,103 BP 

concluded that its top kill operation may have failed because the mud it pumped down the well 

had flowed out through the collapsed rupture disks rather than remaining within the well as 

intended.104 Although BP vice president of engineering Paul Tooms emphasized several months 

later that rupture disk collapse was just one of several theories that could have explained the top 

kill results,105 BP presented the theory to the government as the most likely scenario and changed 

its subsequent containment strategy to reflect it.106 Although the government remained skeptical 

of certain elements of BP’s analysis,107 it too believed the rupture disks may have collapsed and 

that emergency workers needed to consider that possibility when moving forward.108 

Before the top kill operations, BP had told Interior Secretary Ken Salazar and Energy Secretary 

Steven Chu that if the top kill failed, the company might try next to cut the riser, remove the lower 

marine riser package, and install a second blowout preventer on top of the existing one to shut 

in the well.109 But BP and others deemed this approach unwise after theorizing that the rupture 

disks had collapsed.110 If hydrocarbons had entered the annular space between the production 

casing and 16-inch casing and the rupture disks had collapsed, capping the well might divert 

hydrocarbon flow out the rupture disks and sideways into the rock formation around the well. 

This would have caused a “subsea blowout” in which hydrocarbons would have flowed up to the 

surface through the rocks below the seafloor. It would have been nearly impossible to contain 

that flow. To avoid this situation, BP and the government temporarily stopped trying to shut in 

the well. 
64 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

A few weeks after the top kill operation, in mid-June, BP and the government revisited the idea 

of shutting in the well, this time using a tight-fitted capping stack. Although BP was prepared 

to install the capping stack in early July,111 it appears that the government delayed installation 

for a few days to further analyze the stack’s impact on the risk of a subsea blowout.112 The 

government’s team insisted on monitoring for signs of a subsea blowout using several different 

methods. BP eventually used ships and remotely operated vehicles (ROVs) to gather visual, 

seismic, and sonar information about the area around the well. It also used wellhead sensors 

to monitor acoustic and pressure data. All of these efforts were aimed at determining whether 

the Macondo well lacked the integrity to prevent oil from flowing sideways into the rock.113 The 

government and BP were also concerned that closing the capping stack could increase pressures 

inside the well sufficiently to create new problems or burst the rupture disks (if they had not 

already collapsed).114 

Management Findings

BP Appears to Have Sought the Long-Term Benefits of a Long 

String Without Adequately Examining the Short-Term Risks 

BP engineers displayed a strong and perhaps unwarranted bias in favor of using a long string 

production casing. 

Industry experts have stated that successfully cementing a long string casing is a more difficult 

enterprise than cementing a liner. BP’s own engineers appear to have agreed—they considered 

using a liner as a means of mitigating the risks of losses during cementing. (Chapter 4.3 discusses 

this issue in more detail.) BP asked Halliburton to run numerous computer cementing models 

in an effort to find a way to make the long string casing a viable option. They appear to have 

approached the problem by trying to find a way to make a long string work instead of asking what 

design option would best address the cementing difficulties they faced. 

BP has argued that its team preferred to use a long string casing because a long string offers better 

long-term well integrity than a liner-tieback. This may be so. But because the Macondo team did 

not adequately appreciate the risks of a poor cement job (as described in Chapter 4.3), they could 

not adequately have compared the risks and benefits of using a long string casing at Macondo. BP 

engineers appear to have been reluctant to switch to a liner for other reasons as well. They had 

already obtained peer review and approval of the long string design. And the long string approach 

costs substantially less than the liner.

BP’s Special Emphasis on the Risk of Annular Pressure Buildup 

Overshadowed Its Identification and Mitigation of Other Risks

BP made several of the well design decisions discussed above in order to mitigate the risk of 

annular pressure buildup. Proper well design requires consideration of annular pressure buildup 

if the company plans to use the well for production.115 But BP was particularly sensitive to the 

issue because of its experience at the Marlin platform at the Atlantis field.116 BP attempted to 

mitigate the risk of annular pressure buildup in its Marlin wells by leaving the casing annuli 

open to the surrounding formation. But in late 1999, one of those wells nevertheless collapsed 

due to annular pressure buildup.117 Debris or sediments had apparently plugged the opening 

in the relevant annulus. The event was a major loss for BP because casing collapse essentially 

destroys a well.118 
Chief Counsel’s Report — Chapter 4.2: Well Design | 65

In the aftermath of the Marlin incident, BP made it a top priority to minimize the risk of annular 

pressure buildup in its wells.119 It created a dedicated group of design specialists who analyzed 

annular pressure buildup issues for every production well and recommended design features to 

mitigate those risks.120 BP also developed standard guidance instructing its engineers to leave 

annuli open as part of a deepwater well’s design.121 And it encouraged the use of rupture disks as 

a primary annular pressure buildup mitigation measure.122 

BP’s focus on and approach to annular pressure buildup concerns effectively de-emphasized other 

risks and discouraged certain well design approaches. Because the Macondo team planned the 

well as a producer, they made several design decisions to mitigate the risk of annular pressure 

buildup.123 These included adding rupture disks in the 16-inch casing, omitting a protective 

casing (which would have created a trapped annulus), leaving an open annulus below the 

97⁄8-inch liner, and using a long string production casing instead of a liner.124 As described above, 

those design features complicated the cement job as well as post-blowout containment efforts. 

While BP’s methods of mitigating annular pressure buildup created risks, there were alternatives. 

For example, BP could have used insulated production tubing to protect the well from the heat 

generated during production. This might have allowed the company to omit burst disks 

and include a protective casing. BP could also have pumped compressible fluids (such as 

nitrogen foamed spacer or syntactic foam) into any trapped annular spaces to mitigate the risk 

of annular pressure buildup rather than designing its well to eliminate such spaces. This 

approach would have allowed BP to use a liner-tieback without worrying that the tieback would 

create a trapped annulus.125 
66 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling
Chief Counsel’s Report — Chapter 4.3: Cement | 67

Chapter 4.3|Cement

Well Cementing

Cement performs several important functions in an oil well. 

It fills the annular space between the outside of the casing 

and the formation. In doing so, it structurally reinforces the 

casing, protects the casing against corrosion, and seals off 

the annular space, preventing gases or liquids from flowing up or down 

through that space. A cement job that properly seals the annular space 

around the casing is said to have achieved zonal isolation.

The cementing process is procedurally and technically complex. This chapter first 

describes the steps in the cementing process, the ways in which cement can be evaluated 

and remediated, and methods for laboratory cement slurry testing. It then describes the 

Macondo cementing operation in detail. Finally, it sets out the Chief Counsel’s team’s 

technical and management findings regarding the Macondo cementing process. The 

Chief Counsel’s team finds that the Macondo cement failed to achieve zonal isolation. 

While the Chief Counsel’s team cannot be sure why the cement failed, the team has 

identified several risk and other factors that may have contributed to cement failure, 

either alone or together.

The Cementing Process

The cementing process involves pumping cement down the inside of a casing string until 

it flows out the bottom and back up into the annular space around the casing string. 

Achieving zonal isolation requires several things. 

	First, the cement should fill the annular space in the zone to be isolated and also 

a specified space above and below that zone. 

	Second, cement flowing into the annular space should displace all of the drilling 

mud from that space so that no gaps or uncleared channels of mud remain 

behind. If mud channels remain after the cement is pumped, they can become a 

flow path for gases or liquids from the formation. Good mud removal is critical 

for a successful cement job.1

	Third, the cement should be formulated so that it sets properly under 

wellbore conditions. 

Although each cement job presents unique challenges, the principal steps involved in 

pumping cement at Macondo were the same as those for most deepwater wells. The 

following subsections describe the process in simplified form. These sections describe 

the process for running and cementing a production casing—the last casing string to 

be run in the well once a hydrocarbon-bearing zone has been penetrated. The process 

generally applies to running and cementing shallower casing strings and liners as well.

Zonal 

Isolation 

Above and 

Below 

Converted 

Float 

Equipment

Mud Displaced 

From Annulus 

by Cement

Mud Left in 

Rathole

Figure 4.3.1. Typical completed 

cement job.

TrialGraphix
68 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Primary Cementing. Primary cementing refers to an operator’s initial attempt to seal 

a casing with cement. By contrast, remedial cementing refers to subsequent cementing 

efforts undertaken if the primary cement does not achieve zonal isolation.

Logging and Mud Conditioning

After rig personnel finish drilling a well that will be completed as a production well, they 

typically condition the mud in the wellbore and then log the wellbore itself before lowering 

the final production casing and performing the final cement job.

During drilling operations, mud engineers manipulate the characteristics of drilling mud 

in the wellbore to optimize the removal of cuttings and to maintain hydrostatic pressure in 

the well. At the end of drilling operations, the mud is normally circulated to homogenize 

its properties and modify those properties as necessary to facilitate wellbore logging and 

eventual mud removal. That circulation process is called mud conditioning. Drillers 

normally circulate the mud in order to remove cuttings from the mud and ensure that 

it displays uniform and appropriate density and viscosity characteristics.2

 American 

Petroleum Institute (API) recommendations state:

Well preparation, particularly circulating and conditioning fluids in the wellbore, is 

essential for successful cementing. Many primary cementing failures are the result 

of fluids that are difficult to displace and/or of inadequate wellbore conditioning.3

Logging refers to the process of examining and recording the characteristics of the 

wellbore (first discussed in Chapter 2). Prior to running a production casing string, drillers 

typically examine the open section of the wellbore with an extensive suite of logging tools 

that use electric, sonic, and radiologic sensors to measure the physical characteristics of 

the formation and any fluids it might contain in order to learn as much as possible about 

the nature of the hydrocarbon-bearing formation.4

 One such tool, shown in Figure 4.3.2, 

is a caliper log, which measures the diameter of the wellbore. Because the wellbore 

diameter can vary significantly as a result of normal drilling variations, these data can be an 

important input in designing and modeling a primary cement job. 

Lowering the Production Casing String in Place 

With Centralizers

After logging is complete, rig personnel lower the production casing into 

place. During this process, they may install centralizers , shown in 

Figure 4.3.3, which serve an important role in the cementing process.

When the cementing crew pumps cement (or any other fluid) down the 

production casing and back up the annular space around it, the cement 

tends to flow preferentially through paths of least resistance. When the 

casing is not centered in the wellbore, the wider annular space becomes the 

path of least resistance,5

 shown in Figure 4.3.4. Cement tends to flow up 

through those spaces. This can seriously compromise mud removal and 

leave channels of mud behind in the narrower annular spaces. 6 Because of 

this problem, cementing experts consistently emphasize the importance of 

keeping the casing centered in the wellbore.7

 

Figure 4.3.2. Sample 

caliper log data showing 

open hole diameter 

by depth.

2800

0 0

020 0 20

per 150 20

mma Density

Resistence

Like something is written

Filler text to

Fill space not sure what to write

Just have to make it look like something

Density

Resistence

10

20

0 0

020 0 20

per 150 20

mma Density

Resistence

Density

Resistence

10

20

2900

3000

3100

3200

3300

3400

3500

3600

3700

3800

3900

4000

4100

4200

TrialGraphix

Figure 4.3.3. 

Centralizer.

TrialGraphix
Chief Counsel’s Report — Chapter 4.3: Cement | 69

Centralizers help keep the casing as close to the center as 

possible. They come in a variety of designs. Centralizer 

subs, shown in Figure 4.3.5, may be screwed between casing 

sections while bow spring centralizer slip-ons are attached to 

the outside of existing casing using collars. Sometimes stop 

collars (so named because they stop the centralizer from 

sliding up or down the casing) are separate pieces from the 

centralizer; sometimes they are integrated into the 

centralizer itself.8

 

Engineers measure the degree to which a pipe is centralized in 

a wellbore by calculating the “pipe standoff ratio.”9

 A perfectly 

centered casing has a standoff ratio of 100% while a casing that 

touches the walls of the wellbore has a standoff ratio of 0%. 

Although the industry rule of thumb is to achieve a standoff 

of 75%,10 cementing experts state that operators should 

achieve the highest possible standoff in order to facilitate 

mud displacement from the annular space.11 Engineers must 

calculate the standoff not only at each centralizer location, 

but also between the centralizers. Casing can bend and sag 

between centralizers, dramatically lowering the standoff in the 

intervals between them.12

Float Valves and Float Valve Conversion

Illustrated in Figure 4.3.6, float valves are one-way valves (also called check valves) 

installed at or near the interior bottom end of a casing string. Once operational, float 

valves permit fluid (such as mud or cement) to flow down through the inside of the casing 

while preventing fluids from flowing in the reverse direction back up the inside of the 

casing. By doing so, float valves prevent cement that is pumped down through the casing, 

into the shoe track, and up into the annular space from flowing back up through the 

valves once the cement is in place, an occurrence known as “reverse flow” or “u-tubing.”13 

Shoe and Shoe Track. The shoe refers to the bottom of the casing. The shoe track is the 

section of the casing between the shoe and the float valves above it.

A float check examines whether the float valves are working properly—that is, 

preventing cement from flowing back up through the valves due to u-tube pressure. 

U-tube pressure is created by the differential hydrostatic pressure between the fluid 

column inside the casing and the fluid column in the annulus. In cases where the cement 

density is close to drilling mud density, the u-tube pressure may be very small—too 

small to induce backflow or to be detected at the rig. The smaller the density differential 

between the cement and mud, the smaller the u-tube pressure and its expected effects.14

Float valves are important during the cementing process but can interfere with the process 

of lowering a casing string. As the casing string is lowered, it is generally preferable that mud be 

allowed to flow up the inside of the casing string. Otherwise, the casing will, as it descends, force 

mud down the well and back up through the annular space, greatly increasing the pressure that 

the casing string exerts on the formation as it is lowered.15 

Figure 4.3.4. Top view of off-centered casing.

TrialGraphix

Figure 4.3.5. 

Centralizer sub.

Weatherford

Cement in 

Annular Space

Casing

Drilling Mud

Drilling Mud 

Channel Left in 

Annular Space
70 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

To allow mud to flow into the casing string while it is being 

lowered, operators typically use an auto-fill tube. An auto-fill 

tube is a hollow tube that extends through and props open the 

two float valves, allowing mud to flow up through the casing 

while the casing is being run into the well. Once rig personnel 

finish lowering the casing, they convert the float valve 

assembly by pushing the auto-fill tube down and out of the float 

valves. This allows the float valves to close, converting them 

into one-way valves before cementing begins.

Wellbore Conditioning

After converting the float valves, rig personnel normally 

circulate mud through the newly installed casing and wellbore 

again. Like the earlier mud circulation process, this has at least 

two benefits. First, it cleans the casing, drill pipe, and wellbore 

of cuttings, gelled mud, and other debris that can interfere with 

good cement placement and performance.16 Second, the mud flow conditions the mud itself by 

breaking its gel strength, decreasing its viscosity, and increasing its mobility.17 

Figure 4.3.6. Float valve conversion.

TrialGraphix

Auto-Fill Tube

Float Valves

Figure 4.3.7. Full bottoms up.

Gelled 

Mud and 

Debris

Clean 

Drilling 

Mud

TrialGraphix

Mud

Spacer

Cement

Marker

Circulation Begins During Circulation Cementing Begins

Marker 

Reaches the 

Rig Before 

Cement Pour 

Begins

Marker

Mud Flow
Chief Counsel’s Report — Chapter 4.3: Cement | 71

Production 

Casing

Top Wiper Plug

Cement

Mud Wiped 

Into Cement

Mud Film

Under optimum conditions, operators prefer to circulate enough drilling mud through the casing 

after landing it to achieve what is known as a full bottoms up.

18 Circulating bottoms up means 

that the rig crew pumps enough mud down the well so that mud originally at the well bottom 

returns back to surface19 as shown in Figure 4.3.7. The extended circulation required to do this 

confers a third benefit in addition to the two described above: It allows rig crews to physically 

inspect mud from the bottom of the well for the presence of hydrocarbons before cementing. 

Pumping Cement

After completing the pre-cementing mud circulation, rig personnel pump cement down the well, 

then pump additional drilling mud behind the cement to push (or displace) the cement into the 

desired location at the bottom of the well. As they pump the cement, rig personnel must ensure 

that the oil-based drilling mud does not contaminate the water-based cement. The oil and gas 

industry has developed a variety of techniques to ensure that this does not occur. Rig personnel 

at Macondo used a common approach called the “two-plug method.”20 The two-plug method 

uses rubber darts and wiper plugs to separate the cement from the drilling mud as the cement 

travels down the well. 

Rig personnel begin the cement pumping process by pumping water-based spacer fluid down 

the drill pipe. They then drop a bottom dart into the drill pipe, followed by the cement, then 

a top dart and more spacer fluid. After pumping the final spacer fluid down the drill pipe, rig 

personnel resume pumping drilling mud to push the spacer-dart-cement-dart-spacer train down 

the drill pipe.

When the bottom dart reaches the end of the drill 

pipe, it fits into and launches a bottom 

wiper plug from the running tool that 

attaches the drill pipe to the production 

casing. The bottom plug then travels 

down inside of the production casing, 

separating the cement behind it from 

the spacer fluid and drilling mud 

ahead. Similarly, when the top dart 

reaches the end of the drill pipe, it 

launches a top wiper plug from the 

running tool. The top plug also travels 

down the inside of the production casing 

and separates the cement from spacer fluid 

and drilling mud behind. 

The rig crew continues to pump mud down the drill pipe to displace 

the cement into position. Eventually, spacer fluid reaches the float 

valves and flows through the valves. After the spacer flows through the float valves, 

the bottom plug lands on top of the float valves, where it stops. Circulating pressure 

causes the bottom plug to rupture, allowing cement to pass through the plug into the 

shoe track. After all of the cement flows through the ruptured bottom plug, the top plug 

lands on top of the float valves. Unlike the bottom plug, the top plug does not rupture. 

It instead blocks further flow of fluids down the well. When the top plug lands, the 

cement should be in place. Rig personnel stop pumping drilling mud and allow the 

cement to set in a process called waiting on cement. If the cementing process was 

Figure 4.3.8. Wiper plugs cause cement contamination.

TrialGraphix

Mud

Spacer

Cement
72 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

designed and executed properly, the cement should at this point fill the 

shoe track and should cover the hydrocarbon zone in the annular space 

outside the production casing. 

Even if rig personnel execute a two-plug cementing process precisely 

according to plan, cement can still be contaminated by drilling mud. As 

the wiper plugs travel down the casing, they wipe a film of mud away 

from the casing walls. The bottom plug removes most of the mud film 

but not all of it. The remaining mud film can contaminate the cement 

between the plugs as shown in Figure 4.3.8. The top plug also wipes the 

casing, but instead of wiping mud out of the way of the cement, it wipes 

that mud into the back portions of the cement flow. 

The casing shoe track is designed to provide room for contaminated 

cement at the tail end of the pumping process. Absent a shoe track, that 

contaminated cement would travel into the annular space, potentially 

compromising zonal isolation. 

Cement Evaluation

It is not easy for rig personnel to be sure about the progress or final 

result of a cement job at the bottom of a deepwater well. Cement does 

its work literally miles away from the rig floor, and there is no way to 

observe directly if the cement slurry arrives at its intended location, 

let alone whether it is contaminated or otherwise compromised. As a 

result, rig personnel cannot know whether the cement will isolate the 

well from the hydrocarbons in the reservoir as they pump the cement.

Because cementing is difficult to observe directly, the oil and gas 

industry has developed a number of methods for evaluating cement jobs 

indirectly. And because proper cementing is critical to well integrity, 

the API calls proper cement evaluation “indispensable.”21 But each of 

the various methods of cement evaluation has limitations, and the API 

standard on cement evaluation therefore notes: 

Anyone who wants to competently evaluate the quality of a 

cement job must thoroughly understand all the variables, 

assemble and comprehend the relevant pieces of information, 

and reach the proper judgment.22 

By understanding the full set of variables at play for a particular cement job, the right mix of tools 

can be employed to evaluate the cement. 

Volume and Pressure Indicators

While pumping a cement job, a cementing crew knows only how much cement and mud they have 

sent down the well and how hard the pumps have been working to push it. Using these volume 

and pressure readings, the rig crew looks for three general indicators of success during the job: 

full returns, lift pressure, and on-time plug landing.

A cementing crew gets full returns when the volume of mud returning from the well during a 

cement job equals the volume of fluids (spacer, cement, and mud) pumped down into the well. To 

determine whether they are getting full returns, the cementing crew monitors mud tank volumes. 

Figure 4.3.9. Lift pressure.

Mud

“Turning the 

Corner”

Cement

TrialGraphix

Pressure increases to lift cement in 

the annulus.
Chief Counsel’s Report — Chapter 4.3: Cement | 73

If the volume of fluid flow into the well equals 

the fluid flow out, the crew can infer that the well 

is behaving properly as a closed and leak-free 

container. If flow out is less than flow in, the 

crew has lost returns or lost circulation, and 

can infer that mud and/or cement has flowed 

into the formation.23 The crew cannot tell where

the rock fractured, however, and where the mud 

might have gone.24 

Lift pressure, shown in Figure 4.3.9, is a 

steady increase in pump pressure that begins 

when the cement flows out the bottom of the well 

casing and “turns the corner” to flow upward 

against gravity. The pressure increases because 

cement is generally heavier than drilling mud 

(and has a different viscosity). If the cementing 

crew observes a steady pressure increase at the 

appropriate time after pumping cement down 

into a well, they can infer that the increase is 

lift pressure and that cement has arrived at the 

bottom of the well and has begun flowing upward into the annular space. Seeing the expected lift 

pressure also allows the crew to infer that cement is not being lost into the formation.

Finally, the rig crew can also watch pressure gauges to infer whether the wiper plugs used to 

separate the cement from surrounding drilling mud have landed or bumped on time at the 

bottom of the well as shown in Figure 4.3.10. By calculating the volume of the inside of the well 

and the rate at which they are pumping fluids into it, cementing crews can predict when the 

bottom plug and top plug should land. They then watch the rig’s pressure gauges for telltale 

pressure spikes that indicate when the plugs actually land. If the pressure spikes show up when 

expected, the cementing crew can infer that the plugs landed properly, that cement arrived at the 

bottom of the well and flowed out of the shoe track into the annulus, and that substantial volumes 

of mud did not contaminate the cement as it moved down the well. If the pressure spikes do not 

appear on time, that suggests problems. For instance, large volumes of mud may have bypassed 

one or both of the wiper plugs. (Some volume of mud always bypasses the plugs; the plugs do not 

wipe the casing walls perfectly.) 25 

While pressure and volume indicators can suggest that a cement job has gone as planned, they do 

not give cementing crews any direct information about the location and quality of the cement at 

the bottom of the well. In particular, they do not indicate whether there has been channeling in 

the annulus or shoe track, or the location of the top of cement (TOC) in the annulus.26 These 

indicators also are not sensitive to all of the issues that can cause cement to fail. 

Cement Evaluation Logs

Because pressure and volume readings during the cement job are imperfect indicators of 

cementing success, the oil and gas industry has also developed tools for more directly examining 

a cement job after it is pumped. These cement evaluation tools generate data, or “logs,” known 

as cement evaluation logs. Technicians commonly lower cement evaluation tools down inside the 

well on a wire line.27 Once the tools reach an area that has been cemented, sensors in the tools 

probe the integrity of the new cement, measuring whether and to what extent the cement has 

Figure 4.3.10. Bumping the plugs.

TrialGraphix

Pressure 

Spike 

Detected by 

Monitoring 

Systems 

on Rig
74 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

filled the annular space between the cement and 

the formation.28

The most basic element in a cement evaluation system is the 

cement bond log tool.29 The cement bond log tool works 

by measuring the well casing’s response to acoustic signals. 

The tool includes an acoustic transmitter and receiver that 

are separated from each other by several feet of distance. The 

transmitters emit bursts of acoustic waves, and the receivers 

record the reverberations from those waves30 as illustrated 

in Figure 4.3.11. Because steel casing, set cement, and fluids 

all respond differently to the waves, a technician can use the 

recordings to evaluate the quality of the cement job, just as one 

can discern a muffled bell from a free-swinging bell by 

ringing it.31 

Modern cement evaluation systems combine the fairly 

straightforward cement bond log with variable-density logs,32

ultrasonic imaging tools, and flexural attenuation logs.33 By interpreting the combined data from 

these tools, a technician can assess the amount and quality of the cement in the annular space,34

including the TOC and the location and severity of channels in that cement.35 

Although modern cement evaluation logs have become increasingly sophisticated and reliable, 

they still have limits.36 First, they are not easy to read; it takes an experienced technician to 

properly interpret the data. Second, very low-density cement, such as cement produced with 

nitrogen foam technology, can be difficult to evaluate with these tools.37 (The density of the 

foamed cement at Macondo was not low enough to cause evaluation difficulties, however.38) 

Third, cement evaluation tools must be adjacent to annular cement in order to examine it. That 

means that the tools cannot evaluate cement in the shoe track or in the annular space below the 

float equipment. Float equipment and the shoe track cement block the tools from physically 

accessing those areas. Fourth and finally, cement evaluation logs work best after cement has 

completely hardened—a process that can take more than 48 hours.39 Consequently, operators 

typically do not run cement evaluation logs until completion operations.

Additional Methods

There are other methods to evaluate a cement job in addition to cement evaluation logs and 

pressure and volume indicators. In particular, a negative pressure test assesses whether a 

bottomhole cement job contains pressures outside the well and seals the well off from formation 

pressure. Chapter 4.6 of this report discusses negative pressure tests in detail. 

Remedial Cementing

If cement evaluation reveals problems with the primary cement job, rig personnel can remediate

the primary cement after pumping it. At a well like Macondo, the most common method for 

remediating the primary production casing cement is called squeeze cementing. 

Figure 4.3.12 illustrates that squeeze cementing first involves perforating the production casing 

to provide access to the annular space around it. Rig personnel perforate the casing by lowering a 

tool that uses shaped explosive charges to punch holes through the casing and into the formation. 

Rig personnel then pump, or “squeeze,” cement under pressure through the holes. In a properly 

Figure 4.3.11. Cement bond log tool.

TrialGraphix
Chief Counsel’s Report — Chapter 4.3: Cement | 75

executed squeeze job, the remedial cement then flows into the annular spaces where the primary 

cement has failed, filling in any channels and isolating zones as necessary.

Cement Slurry Testing

Cement hardens as a result of chemical reactions that depend on pressure and temperature. In 

the field, cement slurries are normally mixed at ambient temperature and pressure, then exposed 

to increasing temperatures and pressures as they are pumped down the well. These increasing 

temperatures and pressures can not only alter the chemical and physical properties of the liquid 

slurry and cured cement, but also can affect the cement curing process itself. Because every well 

presents a different combination of cementing conditions, it is critical for a cementing company to 

Figure 4.3.12. Remedial cementing—squeeze job.

TrialGraphix

From upper left: 1) Poor centralization has led to channeling; 2) a bridge plug is placed below the remediation area, and a packer is positioned 

above; 3) a perforation gun is lowered and fires shells through the casing and into the formation; 4) cement is pumped into the area, forced 

through the perforations, and into the formation, creating a seal.

Channeling

1

3

2

4
76 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

test a cement slurry design against expected conditions in the particular well before pumping it 

into that well. 

Cement slurries consist of a number of ingredients, including dry Portland cement (which 

itself is a combination of several chemical compounds), water, and various dry and liquid 

chemical additives. Cementing personnel adjust the concentrations of these ingredients to 

suit the particular needs of a given well. Cement slurry designs thus vary from well to well. To 

complicate matters further, many of the ingredients used in a cement slurry are made from 

naturally occurring materials, and their precise chemical composition depends on their source.40 

The liquid chemical additives may vary from batch to batch, and the mix water composition can 

vary depending on its source. This means that each batch of cement slurry is different. Finally, 

the constituents of a given cement slurry also may degrade in storage upon exposure to heat, 

humidity, and atmospheric gases such as carbon dioxide. To address this variability, cementing 

companies usually perform their pre-job testing with representative samples of the actual 

ingredients that will be pumped into the well. 

Pilot and Pre-Job Testing

A cementing company typically conducts at least two rounds of cement testing prior to pumping 

a challenging or uncertain cement job. First, it performs “pilot tests” substantially in advance 

of pumping the job in order to develop an appropriate cement slurry design (the recipe). At the 

time of the pilot tests, the operator gives the cementing company the best available information 

about the downhole conditions. That information may be incomplete, especially in the case of an 

exploratory well (such as Macondo). Sometime prior to pumping the cement, when the operator 

has learned the actual downhole job conditions, the cementing company typically performs 

pre-job tests using the actual cement ingredients that have been stored on the rig and will be 

pumped downhole. These pre-job tests are meant to confirm that the cement design will perform 

successfully during the upcoming job.

Laboratory Tests

To isolate hydrocarbons at the bottom of a well, the cement must display several attributes. First, 

as the cement is pumped into place at the bottom of the well, it must remain in a pumpable fluid 

state and not thicken prematurely. Second, once in place, it must set and develop strength within 

a reasonable time period. And third, the set cement must be sufficiently strong to provide casing 

support and zonal isolation. To check these things, cementing companies typically run a number 

of tests to evaluate a cement design during pilot and pre-job testing. The API has published 

recommended procedures for running these tests.41 

Cement Test. Cement tests examine various properties of the cement slurry and the set cement, 

and investigate the curing process. Thickening time tests determine how long the cement slurry 

will remain pumpable (before starting to set up) under the temperature and pressure conditions in 

the wellbore. Compressive strength tests determine the length of time required for the cement 

slurry to develop sufficient strength to provide casing support and zonal isolation. Rheology tests 

examine various cement slurry flow properties. The slurry viscosity and yield point affect the 

pumping pressure required for slurry placement and the displacement efficiency by which drilling 

fluid is removed from the annular space. The yield point also provides information concerning 

slurry stability—the ability of the slurry to keep solids in suspension and prevent fluid-phase 

separation. Static gel strength is a measure of the degree to which an unset cement slurry 

develops resistance to flow when at rest. Free-fluid tests directly examine slurry stability.
Chief Counsel’s Report — Chapter 4.3: Cement | 77

As cement slurry travels down a well, it encounters increasing heat and pressure. Laboratory 

technicians sometimes stir the slurry at elevated temperatures (and sometimes at elevated 

pressures) to simulate these conditions in order to better understand how the cement will behave 

when it reaches its intended location. This practice is known as cement conditioning (not to 

be confused with mud conditioning, described above).

Modeling the Cementing Process

Before pumping cement, engineers can also model the cementing process using computer 

simulation programs. Engineers run these simulations using data about wellbore and casing 

geometry, mud conditioning, the number and placement of centralizers, and the volume, 

pumping rate, and characteristics of the various fluids pumped down the well. The simulations, 

in turn, predict various things about the cementing process such as the pressure that will be 

required to pump cement.

Engineers routinely use cement simulations to model the complex process of mud displacement 

from the annular space. Predicting mud displacement is important for at least two reasons. First, 

if the cement flow does not displace mud and spacer from the annular space, those materials may 

create a flow path for hydrocarbons. Second, and relatedly, poor mud displacement increases 

the potential for gas to flow into the cement column as it sets.42 This gas flow can itself cause 

channeling and further compromise zonal isolation.

As the oil and gas industry develops deeper wells and more complicated well designs, engineers 

rely increasingly on computer modeling to predict mud removal. Operators and cementers 

can use these models to predict the impact of changing parameters such as cement flow rate 

and centralizer placement. By doing so, they can optimize these interrelated parameters for 

individual well conditions rather than relying on rules of thumb to guide their decisions. At the 

same time, the fluid mechanisms of mud displacement, gas flow, and other cementing phenomena 

are exceedingly complex. Computer simulations cannot model these phenomena precisely. In 

addition, even the best computer models depend entirely on their input data; if the input data are 

inaccurate, the modeling results will be inaccurate as well. 

Preparing for the Macondo Cement Job

Lost Returns at Macondo

BP and Halliburton designed crucial features of the Macondo cement job in response to the 

April 9 lost returns event (when drilling mud flowed out of the wellbore and into the formation) 

described in Chapter 4.2. Although BP engineers successfully restored mud circulation by 

pumping 172 barrels of heavy, viscous “lost circulation” fluids down the drill pipe,43 they also 

realized the situation had become delicate. Based on data from the lost circulation event, 

the engineers calculated that they had to maintain the weight of the mud in the wellbore at 

approximately 14.0 pounds per gallon (ppg) in order to maintain well control.44 Drilling ahead 

with that mud weight would exert even more pressure on the formation, raising the equivalent 

circulating density (ECD). BP engineers calculated that drilling with 14.0 ppg mud in the 

wellbore would yield an ECD of nearly 14.5 ppg—an increase that the engineers believed could 

induce lost returns again.

The engineers concluded they had “run out of drilling margin” and that they could no longer 

drill to their planned total depth of 20,600 feet below sea level.45 Instead, they cautiously drilled 

ahead from 18,193 to 18,360 feet in order to extend the wellbore beyond the pay zone. Optimally, 
78 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

engineers prefer to drill far enough beyond the pay zone to ensure that the float collar and shoe 

track will both be entirely below the pay zone. Among other things, this allows the operator 

eventually to use logging tools to evaluate all of the cement in the annular space in the pay zone. 

In March, before the April 9 lost circulation event, a BP engineer stated that BP planned an 

extended shoe track at Macondo.46

Wellbore Logging and Conditioning

After drilling, BP directed Schlumberger to run a series of logs to collect data from the well. 

Between April 10 and 15, 2010, Schlumberger technicians evaluated the formation to determine 

its porosity and permeability, and gathered fluid and core samples from the well. The logging 

data led BP to conclude that it had drilled into a hydrocarbon reservoir of sufficient size (at least 

50 million barrels47) and pressure that it was economically worthwhile to install a production 

casing. Schlumberger also ran a caliper log to determine the exact diameter of the wellbore.48 

On April 16, before running the final 97⁄8-inch × 7-inch long string production casing, the rig 

crew circulated the open wellbore bottoms up.49 They did not record any mud losses during this 

process.50 The crew inspected mud from the bottom of the well and found that it contained 

1,120 gas units on a 3,000-unit scale.51 This was not an unusual amount of gas because the 

mud at the bottom had been sitting in place in the well for about a week at that point.52 After 

circulating on April 16, gas eventually decreased to 20 to 30 units.53 

Designing the Macondo Cement Job 

BP’s cement planning focused heavily on reducing the risks of further lost returns. BP recognized 

that if the formation fractured again during cementing, it could compromise the cement job and 

force the rig crew to conduct remedial cementing operations. BP engineers focused particular 

attention on ensuring that the ECD during cementing would not exceed the threshold that they 

believed would induce further losses. In order to minimize the ECD during cementing, BP: 

(1) reduced the volume of cement that would be pumped, (2) reduced the rate at which the cement 

would be pumped, and (3) used nitrogen foamed cement for reduced density.54 

Cement Volume

Wellbore conditions are rarely optimal, and it is difficult to be sure precisely where cement 

has flowed during a cement job. Engineers can therefore improve the odds of achieving zonal 

isolation by increasing the volume of cement in the well design. Pumping more cement is a 

standard industry safeguard against uncertain cementing conditions. It reduces the risk of 

contamination by diluting the amount of contaminants in the cement. It also decreases the 

impact of errors in cement placement.

MMS Cement Volume Requirements

At the time of the Macondo blowout, MMS regulations included very few requirements that 

related to the cement design process at Macondo. One of those requirements concerned the 

volume of cement for a primary production casing cement job. According to 30 C.F.R. § 250.421: 

“As a minimum, you must cement the annular space at least 500 feet above the casing shoe and 

500 feet above the uppermost hydrocarbon-bearing zone.”

In other words, MMS required that the TOC in the annular space of the production casing be at 

least 500 feet above the “uppermost hydrocarbon-bearing zone.” 
Chief Counsel’s Report — Chapter 4.3: Cement | 79

BP’s Internal Guidelines

BP’s Engineering Technical Practice 10-60 (ETP 10-60), titled “Zonal Isolation Requirements 

during Drilling Operations and Well Abandonment and Suspension,” lists the company’s internal 

engineering design rules for cementing. ETP 10-60 states:

1.3 Zonal Isolation design criteria for cementing of primary casing strings to meet well 

integrity and future abandonment requirements, shall meet one of the following:

	30 m TVD [total vertical depth] (100 ft TVD) above the top of the distinct permeable 

zone where the top of cement (TOC) is to be determined by a proven cement 

evaluation technique (Section 5.3).

	300 m MD [measured depth] (1000 ft MD) above the distinct permeable zone where 

the hydraulic isolation is not proven except by estimates of TOC (Section 5.3). For 

each well the actual TOC shall be recorded along with the method used for this 

determination. Where the actual TOC is below the plan, the TOC shall be reviewed 

with stakeholders for its impact on future well integrity, operability, suspension and 

abandonment operations.55

Section 5.3 of ETP 10-60 distinguishes a “proven cement evaluation technique” from an 

“estimate” of TOC by stating that “to accurately assess TOC and zonal isolation cement sonic 

and ultrasonic logs should be used.” By contrast, the ETP states that temperature logs (which 

can detect the heat exuded by cement) and cement column backpressure measurements can be 

used to “estimate” TOC. This means that unless a BP engineering team plans to run sonic and 

ultrasonic logs, it should design the cement job so that there is 1,000 feet of cement above the 

highest distinct permeable zone in the well.

In addition to zonal isolation, BP also considers annular pressure buildup (APB) in planning 

TOC.56 The high temperatures caused by bringing hydrocarbons to the surface during later 

production can cause pressure buildup in the annular space. If trapped, the annular pressure will 

build up and can potentially collapse the inner casing string on itself and ruin the well. One way 

drillers avoid this is by allowing annular pressure to escape into the formation. By not cementing 

all the way up to the next liner—which necessarily means a lower TOC and lower volume of 

cement—the drillers allow a route for escape.57 It is likely that APB concerns were a factor in 

determining TOC and cement volume at Macondo.58

Macondo Cement Volume

After the early April lost returns events, the BP Macondo team decided to limit the height of the 

cement column in the annulus. They had little room to maneuver: A higher cement column in 

the annulus would have exerted more pressure on the fragile formation below, increasing the ECD 

of the cement job and risking further lost returns. 

Driven by ECD concerns, BP’s engineering team focused its attention on determining where TOC 

should be. While the main hydrocarbon reservoir zone at Macondo began at 18,100 feet,59 BP 

estimated that the “top HC [hydrocarbon] zone” began at 17,803 feet.60 BP engineers decided 

to pump only as much cement above that zone as MMS required.61 On or about April 14,62 they 

determined that TOC should be 17,300 feet below the ocean surface—503 feet above the top 

hydrocarbon zone and 830 feet above the main hydrocarbon zone.63 
80 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

On April 14, BP senior drilling engineer Mark Hafle initiated a formal management of change 

review of the plan to set the production casing.64 He marked the document as a high priority and 

asked that its approval be completed by the next day.65 Hafle incorporated the design decision 

regarding TOC in the management of change document. The document discussed the risk that 

the primary bottomhole cement would not act as a barrier: “If losses occur during the cement job, 

possible cement evaluation, remedial cement operations, dispensations and/or MMS approvals 

will be required prior to performing TA operations due to a lower than required Top of Cement 

in the annulus. Possible hydrocarbon zones could be left exposed in the annulus with only the 

casing hanger seal as the single barrier for the TA.”66 In the event that occurred, the document 

went on to note, “A perf[oration] and squeeze operation could be performed to add a second 

barrier in the annulus.”67 BP drilling and completions operations manager David Sims reviewed 

the management of change document and commented that the “[c]ontent looks fine.”68 BP 

drilling engineer team leader Gregg Walz, BP wells team leader John Guide, BP engineering 

manager John Sprague, and others also reviewed the document—all approved.69

Keeping TOC to a minimum necessarily reduced the total volume of cement that Halliburton 

pumped down the well. Several other features of the Macondo well also limited the total amount 

of cement that could be pumped:

	the relatively short distance the well had been drilled below the main pay sands;

	the relatively narrow annular space between the production casing and the formation; 

and

	BP’s decision not to pump any cement behind the top plug.70 

Halliburton calculated that it should pump approximately 51 barrels of cement (about 60 barrels 

after foaming) down the well in order to fill the shoe track and the annular space up to BP’s 

specified TOC.71 BP engineers recognized that this was a relatively small volume of cement that 

would provide little margin for error.72 

Cement Flow Rate

Just as increased mud flow rate improves wellbore conditioning, higher cement flow rates tend to 

increase the efficiency with which cement displaces mud from the annular space. Cement must 

be pumped fast enough so that it will scour mud from the side of the wellbore instead of merely 

flowing past. The API notes that “[h]igher pump rates introduce more energy into the system 

allowing more efficient removal of gelled drilling fluid.”73 However, increased pump pressure 

required to move the cement quickly would mean more pressure on the formation (ECD) and an 

increased risk of lost returns.74 

One way in which BP reduced the risk of lost returns at Macondo was by lowering the rate of 

cement flow. BP pumped cement down the well at the relatively low rate of four barrels or less 

per minute.75 This was a lower rate than called for in earlier drilling plans,76 but BP did 

inform Halliburton of the change and Halliburton’s computer models accounted for the 

reduced flow rate.

Use of Nitrogen Foamed Cement

One very direct way to reduce the amount of pressure that a column of cement exerts on 

the formation below is to use lightweight cement. While there are several ways to generate 

lightweight cement, BP and Halliburton chose to use nitrogen foamed cement. Cementing 

personnel create nitrogen foamed cement by injecting inert nitrogen gas into a base cement 
Chief Counsel’s Report — Chapter 4.3: Cement | 81

slurry. This produces a slurry that contains fine nitrogen bubbles. Because nitrogen gas weighs 

so little compared to cement, the nitrogen bubbles make the overall cement mixture less dense 

than the base cement slurry. 

BP and Halliburton jointly decided to use foamed cement technology at Macondo. (Chapter 4.4 

discusses the choice in more detail.) This would reduce the weight of the middle portion of the 

Macondo cement slurry from the base slurry density of 16.74 ppg down to a foamed slurry density 

of 14.50 ppg.77 

While using foamed cement slurry brought certain benefits, it brought risks as well. Chapter 

4.4 explains in more detail how an unstable foamed cement slurry can fail to provide zonal 

isolation. A BP cementing expert specifically advised one of the Macondo engineers in March that 

cementing the production casing using foamed cement would “present[] some significant stability 

challenges for foam, as the base oil in the mud destabilizes most foaming surfactants and will 

result in N2 [nitrogen] breakout if contamination occurs.”78 To guard against this possibility, the 

expert advised the team to pump non-foamed cement ahead of the foamed cement. This would 

create a “cap slurry” on top of the foamed slurry in the annular space that would mitigate the risk 

of foam instability.79

Planning for and Installing Centralizers 

at Macondo

BP procured only six centralizers for its production casing ahead of time, even though its 

plans had originally called for a greater number. Shortly before running the casing, however, 

Halliburton’s modeling revealed that BP would need more centralizers to prevent channeling. In 

response, BP decided at the last minute to purchase 15 more centralizers and send them out to the 

rig. But unlike the six centralizer subs that BP had purchased earlier, these additional centralizers 

were slip-on centralizers with separate stop collars. Once BP realized this, it reversed itself and 

decided not to use them, reasoning that the risks of using them outweighed the risks 

of channeling. 

API’s Centralization Guidance

While the API recognizes the importance of centralization, it has no recommended specific 

standoff ratio for casing. Rather, the API encourages drillers to determine the appropriate 

standoff ratio based on individual well conditions. Nor does the API have any recommendation or 

standard for how far above the pay zone casing should be centralized. 80 

BP’s Centralization Guidance

BP’s official technical guidance instructs engineers to design centralization programs to ensure 

there is at least 100 feet of “centrali[z]ed pipe” above the “permeable zone” in the event a cement 

bond log is not run.81 The technical guidance does not provide any further detail on the number 

or type of centralizers that should be used or the overall standoff that should result. BP in-house 

cementing expert Erick Cunningham explained that the guidance does not provide specific 

instruction on the number of centralizers that must be used to create a “centralized pipe.” A 

casing could have centralizers on every joint or every three joints; both could be considered 

“centralized pipe” depending on the particular well. Cunningham stated that the only way to 

predict the effect of centralizer placement on mud displacement is through computer modeling.82 
82 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Macondo Team’s Early Centralizer Plans

The Macondo team’s September 2009 well plan included enough centralizers to likely satisfy 

BP’s internal technical guidance. That plan’s formula would have required the team to install at 

least 16 production casing centralizers given the then-planned total depth of 20,200 feet.83 BP 

then produced another well plan in January 2010. Its formula would have called for at least 11 

centralizers on the production casing.84 Given the ambiguity of BP’s technical guidance, it is 

unclear whether the January 2010 plan would have satisfied BP’s internal requirements.85 Both of 

these plans were based on a deeper well depth and larger casing diameter than BP eventually used 

at Macondo.

The Macondo Team Procured Six Centralizers for the 

Production Casing

On March 31, BP drilling engineer Brian Morel emailed a Weatherford sales representative, Bryan 

Clawson, and asked for “7-10” centralizer subs.86 Clawson emailed Morel to say that Weatherford 

could only supply six centralizers immediately, explaining that it would take up to 10 days to 

manufacture more. Though it is common for Weatherford to manufacture centralizers to order, 

Morel did not ask Clawson to do so, even though Weatherford could at that point have made 

additional subs in time.87 Instead, the BP team decided that six centralizers would be sufficient.88 

These six centralizer subs that Morel ordered were ultimately the only centralizers that the 

Macondo team used. 

The Macondo Team Decided to Increase the Number of 

Centralizers to Address Potential Channeling Problem

During the long string decision-making process, Halliburton cementing engineer Jesse Gagliano 

had run a cementing model that predicted that the long string could be cemented successfully. 

Though Gagliano was a Halliburton employee, he worked at BP’s Houston campus, and his office 

was on the same floor as those of BP’s Macondo team.89 Gagliano’s April 14 model assumed 

proper centralization (by assuming a 70% standoff ratio) instead of calculating standoff based on 

centralizer placement plans.90 It also assumed optimal wellbore size and geometry because BP 

did not yet have caliper log data from the well.91 The April 14 model report did not predict 

significant channeling.92

On April 15, BP provided additional data to Gagliano from the Schlumberger logs, including 

caliper data, that could improve the accuracy of his cementing predictions. Based on the new 

data, Gagliano modeled the cementing process again, this time without assuming optimal 

centralization.93 His new model predicted that using only six centralizers would result in lower 

standoff ratios and that this would be inadequate to ensure good mud removal and avoid mud 

channeling.94 It also predicted that the mud channeling would increase the height of the cement 

column in the annulus (measured as TOC). That, in turn, would increase the effective pressure 

that the cement column would exert on the well formation below (ECD).95 

That afternoon, Gagliano alerted Walz and BP operations engineer Brett Cocales to his 

predictions. Although Guide was out of the office, BP’s engineering team acted on the 

information. The team was already concerned that the ECD during cementing operations could 

lead to lost returns during cementing and viewed lost returns as the biggest risk they faced 

during the cement job.96 Based on Gagliano’s predictions of increased ECD, Walz sought and 

obtained agreement from Guide’s superior, Sims, to procure more centralizers and fly them to 

the rig immediately.97 It appears that Walz and the BP team were concerned at this point about 
Chief Counsel’s Report — Chapter 4.3: Cement | 83

the impact that channeling might have on ECD and were not 

directly concerned about the impact channeling might have on 

zonal isolation. 98 

Gagliano ran and distributed two additional cementing models 

from the afternoon into the evening of April 15 to evaluate 

the impact of adding additional centralizers.99 His first model 

predicted that there would be reduced channeling with 

10 centralizers, but still a significant amount. He emailed the 

model to the team, writing what he had already warned them 

about in earlier conversation: “Updating [the model with 

caliper and other data] now shows the cement channeling and 

the ECD going up as a result of the channeling. I’m going to 

run a few scenarios to see if adding more centralizers will help 

us or not.”100 Morel, who was on the rig and unaware that the 

team had made the unusual decision to fly centralizers to the 

Deepwater Horizon, responded that it was “too late” to get any 

more centralizers to the rig.101 Gagliano’s second model showed 

even less channeling with 21 centralizers. Both models showed 

that increasing the number of centralizers at Macondo would 

reduce the potential for gas migration in the annular space, 

though the centralizers’ effect on gas flow was apparently of 

minor concern to the team compared with its effect on ECD.102 

Sitting in the Houston conference room with Gagliano, Cocales 

carried out Walz’s instructions to secure additional centralizers. 

Cocales called Clawson and ordered 15 additional Weatherford 

centralizers, the most that could be sent on a single helicopter.103 

BP also arranged for a Weatherford technician to accompany the 

centralizers and oversee the installation.104 These 15 centralizers 

were leftovers from another BP project called Thunder Horse. 

Unlike the six centralizer subs already on the Deepwater 

Horizon, however, the Thunder Horse centralizers were slip-on 

centralizers as shown in Figure 4.3.13. BP’s engineering team 

assumed that the Thunder Horse centralizers had integrated 

stop collars.105 But the centralizer schematics that Clawson sent 

to Cocales on April 15 (and that Cocales forwarded to the rest of 

the BP engineering team) showed that the stop collars would be 

separate from the centralizers.106 

Figure 4.3.13. 

Centralizer sub (top) 

and slip-on centralizer 

with stop collars 

(bottom).

Weatherford
84 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Figure 4.3.14. Gregg Walz April 16, 2010 email to John Guide about centralizers.

BP

Walz later explained his decision, as shown in Figure 4.3.14, to order the additional 15 centralizers to 

Guide in the following email, sent that night.107

Walz justified the decision to order additional centralizers because “we needed to be consistent with 

honoring the model.” That model had convinced the team that a long string could be successfully 

cemented, so long as ECDs were kept in a low, narrow range. That model had also assumed that the 

centralizers would achieve a 70% standoff ratio. 

The Macondo Team Decided Not to Install the 

Additional Centralizers

Sometime after 5 a.m. on April 16, a helicopter arrived at the Deepwater Horizon, carrying the 15 

additional centralizers and Weatherford service technician Daniel Oldfather.108 The helicopter did 

not, however, carry the stop collars and accessories that would be needed to secure the centralizers 

on the casing. Those had been shipped by boat and were scheduled to arrive by 4 p.m. (before the 

casing would be run).109 Oldfather explained this to the rig crew when he landed.110
Chief Counsel’s Report — Chapter 4.3: Cement | 85

Morel was still visiting the rig at the time the helicopter landed. He examined the centralizers 

when they arrived. Like the other BP engineers, he had expected that the centralizers would 

have integrated stop collars. He now recognized that this was not the case.111 Morel called Guide 

and told him that these were not the “one-piece” centralizers that he was expecting. Guide 

agreed they were not what he had planned on using either.112 Morel took digital pictures of the 

centralizers and emailed them to Guide, telling him that “the centralizers do not have the stop 

[collars] on them.”113 However, Morel also told Guide that the centralizers could still be used 

because the boat carrying the collars would arrive in “plenty of time before needing them.”114 

After learning that the new centralizers had separate stop collars, Guide reversed Walz’s decision 

to install them on the production casing in an email to him midday on April 16,115 shown here in 

Figure 4.3.16.

Guide’s email explained to Walz that the separate stop collars were prone to coming off the casing 

as it was being run into the well. Not only did this mean that the centralizers could slip away from 

their predetermined positions on the casing, but the centralizers could also get “hung up” against 

other parts of the well as the casing was being run. This could prevent the casing from being 

Figure 4.3.16. John Guide April 16, 2010 email to Gregg Walz about centralizers.

BP

Figure 4.3.15. Centralizers delivered to the Deepwater Horizon on April 16, 2010.

BP
86 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

lowered all the way to the bottom of the wellbore—a serious problem that would take significant 

time to fix.116 Guide also noted that installing this type of centralizer would alone take 10 hours.117 

In a phone call with Walz, Guide weighed the risks of losses that fewer centralizers presented 

against the risk of a “last minute” addition of unfamiliar centralizers. There was no discussion 

at that point of stopping the job in order to procure the “correct” style of centralizers.118 Instead, 

Guide told Walz and Sims he was reverting to the original plan. Sims agreed. Walz also accepted 

the reversal, saying, “I agree. This is not what I was envisioning,” and apologized to the rest of the 

drilling team for the “miss-step” of ordering centralizers.119 

During the same time period, Morel was attempting to position BP’s six centralizers where they 

would be most effective, rather than place them at fixed intervals. As early as April 14, he had 

emailed Gagliano his suggested placement.120 On April 15, when he mistakenly told Gagliano that 

it was “too late” to get more centralizers to the rig, he changed his recommendation, switching the 

position of two centralizers.121 The next afternoon, the day BP reverted to the six centralizer plan, 

Morel changed the position of two other centralizers on his own “casing tally.”122 Morel supposedly 

based his recommendation on the caliper data and a wellbore image, though it is unclear precisely 

how he used them.123 

Morel’s placement of the centralizer subs was different than Gagliano’s. Gagliano had assumed 

the centralizer subs would be evenly spaced apart while Morel placed them at irregular intervals.124 

It appeared that Morel expected Halliburton to run a new model based on his casing tally and 

centralizer placement. Morel’s discussion with Cocales regarding the placement concluded, “We 

can argue this one out after we get the actual vs model data and see how it reacts.”125 As it turned 

out, BP never requested a model that reflected the actual centralizer placement, and Halliburton 

never ran one. 

Neither Halliburton nor the BP engineering team appears to have considered that inadequate 

centralization might increase the chance of a blowout. Rather, they concluded that the 

worst-case result of using only six centralizers would be the need to conduct a remedial cement 

squeeze job.126 As Cocales emailed Morel, “I would rather have to squeeze than get stuck above 

the WH [wellhead]. So Guide is right on the risk/reward equation.”127 In other words, Cocales 

preferred the increased risk of having to perform a remedial squeeze job to the increased risk of 

one or more of the 15 slip-on centralizers getting stuck in the well while the crew was running the 

production casing.

The BP team did not explicitly communicate its decision to use only the six centralizer subs on the 

rig to Halliburton or Weatherford.128 When Gagliano eventually learned of the decision (from a 

Halliburton cementer aboard the rig), he asked BP to confirm it, and when he received no reply, 

he ran a new model on April 18.129 It predicted poor centralization, “SEVERE” gas flow potential, 

and mud channeling. When Gagliano emailed the latest cement job procedures to the BP team at 

9 p.m. that night, he attached this report.130 He spoke with Walz the next morning (April 19) about 

the potential for channeling.131 Walz in turn spoke with Guide about the issue.132 BP nevertheless 

proceeded with its plan to run only six centralizers. 

As BP has pointed out, Gagliano’s April 18 model was based on several imperfect inputs. Notably, 

Gagliano assumed that BP would use seven centralizers, not six, and again, that BP would space 

them evenly along the casing, not place them in sections of the borehole where they might be 

especially effective.133 Gagliano also utilized an incorrect pore pressure in the reservoir zone, 

which could influence the model’s prediction of gas flow into the cement column.134 It is unclear, 

however, whether eliminating these inaccuracies could have eliminated the channeling and gas 
Chief Counsel’s Report — Chapter 4.3: Cement | 87

flow predicted by the model. The use of fewer centralizers would decrease centralization, and 

the actual placement of two-thirds of the centralized joints was within 15 feet of the placement of 

the centralizers in the model.135 In any case, the April 18 model was the most accurate model of 

the cementing process that existed before the blowout,136 and it predicted that channeling would 

occur.137 (As of 10 months after the blowout, Halliburton had still not produced modeling results 

that more accurately reflect Macondo conditions.) 

BP began installing the casing at 3:30 a.m. on April 18 and finished at 1:30 p.m. on April 19.138 

Float Collar Installation and Conversion 

at Macondo

Once the production casing string had been run, the crew turned to converting the valves in the 

float collar. Until this time, the float valves had been propped open by an auto-fill tube. Rig 

personnel needed to push the auto-fill tube down and out of place, thereby converting the float 

valves and allowing them to close (Figure 4.3.1). Once closed, the float valves would become 

one-way valves that would permit drilling mud and cement to flow down through the inside of the 

casing but would prevent “reverse flow” or “u-tubing.”139 

Shoe Track Length and Placement

The shoe track is the space between the float collar and the reamer shoe at the bottom of the 

casing. (A reamer shoe is a bullet-nosed, perforated piece of equipment that guides the casing 

toward the center of the hole as it is lowered into the well). At the end of the cement job, this 

space is filled with the “tail” portion of the cement that was pumped down the well. That tail 

cement may be contaminated by mud scraped from the casing by the top wiper plug. Indeed, one 

purpose of the shoe track is to contain contaminated tail cement. 

A longer shoe track increases the volume for capturing contaminated tail cement, which in turn 

reduces the likelihood that such cement will flow into the annular space. A larger shoe track also 

dilutes the impact of any contamination in the tail cement. Morel suggested the shoe track at 

Macondo may not have been long enough but ultimately left the decision whether to extend the 

length up to the well site leaders on the rig.140 According to Guide, BP also wanted to set the shoe 

track deeper in the well so that it was entirely below the hydrocarbon-bearing zone.141 Ultimately, 

the shoe track was not below all of the hydrocarbon-bearing zones because the total depth of the 

well was shallower than planned due to problems of losing returns into the formation.142

Macondo Float Collar

The production casing at Macondo contained a Weatherford Flow-Activated Mid-Bore Auto-Fill 

Float Collar, which rig personnel had installed just above the 180-foot shoe track at the bottom of 

the casing string.143 

The Weatherford float collar held two aluminum float valves set approximately 6 inches apart and 

propped open by an approximately 14-inch-long auto-fill tube (made out of phenolic resin).144 As 

shown in Figure 4.3.17, the auto-fill tube allowed mud to flow up through the float valves while 

the casing string was run. Once the production casing had landed, however, the crew needed to 

push the tube out of the way to allow the float valves to close. 
88 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

The float collar’s auto-fill tube contains a 2-inch weighted ball, which is free to move within the 

tube but not out of it. At the top of the float assembly is a plastic cage that prevents the ball from 

escaping but allows mud to flow through. At the bottom is a phenolic resin collar that is less than 

2 inches in diameter, which also allows mud, but not the ball, to flow through. When casing is 

being run, mud flowing up through the tube pushes the ball against the inside of the cage. When 

the casing lands, the ball falls to and plugs the bottom of the tube, leaving two small holes on the 

side of the tube as the only path through the tube for mud circulated down through the well.145 

The crew converts the float valves by pumping mud down through the tube, against the ball, and 

out the two holes in the side. As rig personnel increase the flow rate of mud, the constricted flow 

path creates a differential pressure against the auto-fill tube. Once the flow rate exceeds a certain 

threshold, the differential pressure should break four shear pins that hold the auto-fill tube in 

position and force the tube downward and out of the float collar assembly. With the auto-fill tube 

removed, the float valves spring shut, “converting” the float collar into a one-way valve system.146

According to calculations based on Weatherford’s specifications, the Macondo float collar 

assembly would have converted at a flow rate of approximately 6 barrels per minute (bpm), which 

would have created a 500 to 700 pounds per square inch (psi) differential pressure across the 

auto-fill tube.147 Achieving the requisite flow rate through the two small holes is the only way 

to convert the collar. Significantly, increasing pump pressure above 500 to 700 psi would not 

push the auto-fill tube through and convert the valves unless the flow through the two side holes 

exceeds the flow rate recommended by Weatherford. 

Attempted Float Conversion at Macondo 

Rig personnel prepared to convert the float collar at approximately 2:30 p.m. on April 19.148 

The crew turned on the pumps and began pumping mud down the well in an effort to establish 

Figure 4.3.17. Auto-fill float collar.

TrialGraphix

Flow while casing is being lowered (left) and flow during conversion (right).
Chief Counsel’s Report — Chapter 4.3: Cement | 89

circulation to convert the float equipment. Morel and BP well site leader Bob Kaluza oversaw 

the operation.

The crew ran into a problem. They could not establish circulation (and hence had a zero flow 

rate), suggesting that the float collar or shoe track was somehow plugged. The crew increased 

pump pressure nine times before finally establishing mud circulation. They increased pump 

pressure to 1,800 psi, then to 1,900 psi, but could not establish circulation.149 Rig personnel then 

pressured up to 2,000 psi four times but still could not circulate. The crew then pressured up 

to 2,250 and then 2,500 psi and again failed to establish circulation.150 The crew then made a 

ninth attempt to establish circulation, pressuring up to 2,750 psi, then 3,000 psi. At 3,142 psi, 

the pressure finally dropped and mud began circulating down through the float collar assembly.151 

Significantly, however, the crew never thereafter achieved sustained flow rates of 6 bpm, 

which were required for conversion of the float valves based on calculations using 

Weatherford specifications. 

The rig crew sought advice from shore during these attempts to establish circulation. At 

3:28 p.m., Hafle emailed a representative from Allamon, another equipment supplier, and asked 

for the specifications of the auto-fill float equipment. The Allamon representative responded and 

suggested “rocking the casing in 1000 psi increments up to 5,000 psi.”152 Morel called Clawson 

at Weatherford, reported that they could not break circulation, and asked how much pressure 

could be applied.153 After checking with the Weatherford engineering department, Clawson 

called back Morel and told him they could increase pressure up to 6,800 psi.154 However, he also 

told Morel that at 1,300 psi the ball would pass through the bottom of the auto-fill tube without 

converting the floats.155 Morel called Guide onshore and received permission to increase pressure 

to 2,200 psi.156 The crew pressured up to 2,250 and then 2,500 psi but still failed to establish 

circulation.157 Guide later gave permission to increase pressure to 5,000 psi.158 

Questions remained after establishing circulation. At 5:30 p.m. on April 19, Clawson of 

Weatherford emailed BP’s Morel inquiring about progress.159 Morel responded, “[W]e blew it 

at 3140, still not sure what we blew yet,” indicating the rig crew did not know what they had 

dislodged with the amount of pressure applied.160 Kaluza said, “I’m afraid we’ve blown something 

higher up in the casing string.”161 Hafle said, “Shifted at 3140 psi. Or we hope so.”162 Despite 

these uncertainties, the rig crew proceeded onward.

Low Pressure After Circulation Established

After establishing circulation, BP observed another anomaly. The pump pressure required to 

circulate mud through the well was significantly lower than expected.163 As shown in 

Table 4.3.1, mud engineers from M-I SWACO had calculated that 370 psi would be required to 

circulate at 1 bpm and 570 psi at 4 bpm post-conversion. However, after the crew established 

circulation, it took only 137 psi to circulate at 1 bpm, which made Kaluza uncomfortable.164 The 

crew increased circulation to 4 bpm, which required only 340 psi of pressure—230 psi less than 

M-I SWACO had predicted. 

The low circulating pressure raised concern among personnel on the rig floor.165 Kaluza spoke 

to Morel, who was on the rig.166 Morel called Guide onshore, who agreed the pressures appeared 

low.167 Cocales asked M-I SWACO to rerun its model to confirm that the original calculations had 

not been mistaken; M-I SWACO’s models continued to predict substantially higher circulating 

pressures than actually observed.168 
90 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Guide and Kaluza instructed the crew to switch from pump 4 to pump 3 to see if changing 

pumps might change the circulation pressure.169 They observed a slightly higher circulation 

pressure (396 psi at 4 bpm) after switching pumps, but this was still significantly lower than the 

expected pressure.170 

Table 4.3.1. Low pressure observed after circulation established.

Circulation Rate 1 bpm 4 bpm

Pressures Observed 137 psi171 340 psi (on pump 4)172

396 psi (on pump 3)173

Pressures Modeled 370 psi174 570 psi175

At Guide’s suggestion, the crew checked whether the Allamon diverter in the drill pipe might be 

leaking. The diverter is a valve opened during casing installation to allow drilling fluid flowing up 

inside the casing to flow into the annulus and back to the surface. At Macondo, the diverter was 

located in the drill pipe, above the wellhead at a final depth of 4,424 feet.176 The test confirmed 

the diverter was closed.177 Morel and Kaluza considered the possibility of a breach somewhere

in the casing string.178 However, they determined that a leak in the casing could not be fixed at the 

moment and, if present, would be revealed by later pressure tests (such as the positive pressure 

test).179 

BP never resolved the low circulation pressure issue, concluding instead based on discussions 

with the rig crew that the pressure gauge was likely broken.180 Morel and others felt comfortable 

proceeding because of the fact that the cement would be pressure tested later.181 According to BP 

interview notes, Kaluza later described the low circulation pressure as an anomaly and said that 

after he had discussed it with Guide and well operations advisor Keith Daigle, Guide instructed 

Kaluza to begin pumping cement.182 

Pre-Cementing Wellbore Conditioning 

at Macondo

Circulation After Landing the Long String

After converting the float valves, BP circulated mud again to clean the inside of the production 

casing string, remove any debris and cuttings dislodged by the casing installation, and condition 

the mud in the wellbore for cementing. 

Planned Pre-Cement Circulation Volumes and Rates

An API recommendation from May 2010 was to circulate a minimum of 1.5 annular volumes or 

one casing volume after casing installation, whichever is greater.183 Had this recommendation 

been in place at Macondo, this would have meant circulating 4,140 barrels (bbl) of drilling fluid. 

Halliburton recommends performing at least one full bottoms up circulation on a well before 

pumping a cement job.184 This standard would have required BP to circulate 2,760 bbl of drilling 

fluid through the wellbore.185 
Chief Counsel’s Report — Chapter 4.3: Cement | 91

Early BP drilling plans discussed pre-cementing 

circulation but did not call for a full bottoms up 

circulation. Omitting a full bottoms up is not unusual 

at deepwater wells because of the large mud volumes 

involved—circulating bottoms up could have taken as 

long as 12 hours at Macondo.186 BP’s September 2009 

and January 2010 drilling programs called for circulating 

and conditioning 1.5 × pipe volume of drilling fluid 

“unless loss returns are experienced.”187 Although the 

plan did not specify which “pipe” volume it was referring 

to, circulation volumes are typically based on the volume 

of the casing used. The total long string casing and drill 

pipe volume at Macondo was 884 bbl, so it appears the 

plan called for the rig crew to circulate 1,326 bbl of mud 

before cementing.188 

BP changed its plans in response to the April 9 lost 

circulation event, decreasing both the pre-cementing 

circulation volume and rate in order to reduce ECD. BP’s 

April 12 plan thus called for circulating volume equal 

to one casing plus drill pipe capacity if hole conditions 

allowed, at a reduced rate of 8 bpm.189 In its subsequent 

April 15 plan, BP further lowered the pump rate to 

“reduced rates (3 bpm) based on MI-SWACO models to 

keep ECD below 14.5 ppg.”190 

Even after receiving full returns during circulation on 

April 16, BP engineers remained concerned about lost returns during pre-cementing circulation.191

They feared that circulating too extensively could damage the inside of the wellbore or instigate 

another lost returns event.192 Onshore, Walz discussed whether to circulate full bottoms up 

with Gagliano late in the morning on April 19.193 Afterward, Walz also spoke with Guide about 

circulation.194 Ultimately, Guide recommended against circulating bottoms up because of concern 

over lost returns and gave approval to begin cementing.195 On the rig, Halliburton cementing 

engineer Nathaniel Chaisson brought up the idea of circulating a full bottoms up but was told by 

a BP well site leader that a lower volume would be pumped.196 Halliburton’s April 18 cementing 

proposal lists reduced volumes, calling for 111 barrels at 1 bpm, followed by 150 barrels at 4 bpm 

for a total of 261 bbl.197 Chaisson noted in the April 18 plan that the volumes and pump rates listed 

were “as per co. man,”198 indicating that one of the BP well site leaders had provided it.

Pre-Cement Circulation Volumes and Rates

At approximately 4:18 p.m. on April 19, the rig crew re-established mud circulation after running 

the long string.199 The rig crew then circulated a total of approximately 350 barrels of mud at 

rates up to 4 bpm before beginning the cementing process.200 This figure exceeds the 261 bbl 

called for in the April 18 Halliburton cement job procedure201 but is significantly lower than the 

2,760 bbl required for a full bottoms up.202

Figure 4.3.18. BP’s pre-cementing mud circulation.

TrialGraphix

Estimated 

“Marker” 

Position With 

Cementing 

Completed

Estimated 

Bottoms Up 

“Marker” 

Position When 

Cementing 

Started
92 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Additional Circulation During Course of Cementing

BP has argued that the Chief Counsel’s team must also take into account the additional mud volume 

circulated up the annulus from the bottom during the cement job itself in determining the total 

volume of mud circulated prior to the conclusion of the cement job. During the cement job, rig 

personnel pumped approximately 1,020 bbl of base oil, spacer, cement, and mud down into the 

well, which would have displaced an equal volume of mud.203 

When combined with the pre-cementing circulation, this means that rig personnel pumped a 

total of 1,370 bbl of fluids (mud, spacer, and cement) down the well by the time cementing was 

complete.204 This would have brought the bottomhole mud up into the riser to a depth of 

4,250 feet below the ocean surface by the end of the cement job as shown in Figure 4.3.18. It would 

have taken a total of 2,760 bbl of circulation to bring the bottom mud all the way back to the rig.205 

Table 4.3.2. Plans reduce pre-cement circulation volumes and rates.

Plan Recommended Volume Volume in Barrels Recommended Circulation Rate

API RP 65, Part 2206

(First edition)

1.5 annular volumes 

or one casing volume, 

whichever is greater

4,140 bbl (1.5 

annular volumes)

Full Bottoms Up 2,760 bbl207

BP September 2009 Plan208

and January 2010 Plan209 1.5 x pipe volume 1,325.73 bbl210 —

BP April 12 Plan211

1 casing and drill 

pipe capacity, if hole 

conditions allow

883.82 bbl212 ~ 8 bpm

BP April 15 Plan213

1 casing and drill 

pipe capacity, if hole 

conditions allow

883.82 bbl214 3 bpm, based on M-I SWACO 

models to keep ECD below 

14.5 ppg

April 18 Halliburton 

Cement Proposal215 —

111 bbl

150 bbl per company 

man

1 bpm

4 bpm

April 19 Actual Circulation 350 bbl 1-4 bpm

Cementing Process at Macondo

Halliburton’s cementing team began pumping cement for the production casing on April 19.216 In 

all, they pumped the following fluids down the well:
Chief Counsel’s Report — Chapter 4.3: Cement | 93

Table 4.3.3. Cementing volumes.

Material Pumped Volume

Base oil 7 bbl217

Spacer fluid 72 bbl218

Unfoamed lead cement 5 bbl219

Foamed cement 39 bbl (Foamed to 48)220

Unfoamed tail cement 7 bbl221

Spacer 20 bbl222

After pumping these fluids, the cementing crew pumped mud into the drill pipe to push the 

cement down the well into position.223 

Over the next three-and-a-half hours, the cement traveled down the drill pipe and into the 

well. During that time, rig personnel watched pump pressures at the rig for signs of cementing 

progress. Morel saw small pressure spikes suggesting that the top and bottom plugs had passed 

through the crossover joint in the long string.224 Personnel on the rig agreed that the plugs 

bumped.225 At 12:38 a.m. on April 20, Chaisson marked in his tally book that the plugs bumped at 

a pressure of 1,175 psi.226 

Morel noted that the bottom plug landed 9 bbl ahead of plan.227 This meant that the rig crew had 

to pump 9 bbl less fluid down the well than they planned before the bottom plug reached the float 

collar, potentially suggesting that the bottom plug had bypassed mud on its way down the well, 

and that the bypassed mud had contaminated the cement. 

The top plug landed according to plan.228 Chaisson watched the Sperry-Sun data229 and estimated 

100 psi of lift pressure before the top plug bumped.230 Guide looked at the data from shore and 

thought it “easy” to see lift pressure.231 Throughout cementing, the rig crew saw “full returns.”232

BP and Halliburton declared the job a success based on the indirect indicators—lift pressure, 

bumping the plugs on time, and full returns. Chaisson sent an email to Gagliano at 5:45 a.m. 

saying, “We have completed the job and it went well.”233 He attached a detailed report stating that 

the job had been “pumped as planned” and that “full returns were observed throughout.”234 Just 

before leaving the rig, Morel emailed the rest of the BP team: “Just wanted to let everyone know 

the cement job went well. Pressures stayed low, but we had full returns the entire job, saw 80 psi 

lift pressure and landed out right on the calculated volume.... We should be coming out of the hole 

shortly.”235 Later, Morel followed up with an email saying “the Halliburton cement team...did a 

great job.”236 Sims congratulated Morel and the BP team, writing, “Great job guys!”237

The Float Check at Macondo

After cementing was complete, rig personnel conducted a float check to ensure the float 

valves had closed properly. Rig personnel began by pressuring up the system after bumping 

the top wiper plug.238 They then released the pressure and monitored the system for pressure 

differentials and flow back from the well.239 BP well site leader trainee Lee Lambert and 

Halliburton cementer Vincent Tabler opened a valve at the cementing unit to see how much mud 

flowed out of the well when they released the pressure. 240 (Some modest flow back is expected 

due to the compressibility of fluids during the pumping of the cement job.) Models had predicted 

5 or 6 bbl of flow back.241 The two men observed 5.5 bbl of flow, which tapered off to a “finger 
94 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

tip” trickle.242 Tabler testified they watched flow “until it 

was probably what we call a pencil stream,” which stopped, 

started up again, and then stopped altogether.243 The total 

flow at that point was close to the predicted flow,244 and the 

two men concluded the float valves were holding.245 

Cement Evaluation 

at Macondo

BP’s Decision Tree for 

Cement Evaluation

BP’s decision process for determining whether to run 

evaluation tools after the cement job focused on lost 

circulation concerns as shown in Figure 4.3.19. On April 15, 

Hafle developed a cementing decision tree that effectively 

reduced the decision process to a single question: “Losses 

while cementing long string?”246 If the cementing crew 

reported losses while pumping the cement job, the decision tree stated that BP engineers would 

“Calculate theoretical [top of cement] based on loss volume.” If that calculation estimated that 

TOC was below 17,970 feet that would mean that there was less than 100 feet of cement above 

the top of the pay zone—400 feet less than MMS requires.247 In that situation, the decision tree 

required a “log to confirm” the TOC. 

If the theoretical calculation predicted that TOC was above 17,970 feet, the decision tree stated 

that the Macondo team would discuss MMS requirements and consider seeking a dispensation. 

If unable to get dispensation or “obtain MMS approval,” then BP would “perforate” the casing 

and “squeeze” the annulus to remediate the cement job. An operator would not normally run a 

cement evaluation log and plan to remediate cement before temporary abandonment operations; 

the Macondo team’s explicit discussion of these contingencies illustrates how concerned they 

were about the possibility of cement losses.248

On April 15, Morel distributed a full plan for the temporary abandonment procedures at 

Macondo. The plan summarized the cement evaluation decision tree and provided further detail 

on the criteria for how to evaluate the cement job:249

1. If cement job is not successful: (no returns or lift pressure seen): set wear bushing / 

Run IBC-CBL log / Wait on decision to do remedial work (MMS and BP).

2. If cement job is successful (partial returns or lift pressure seen) or IBC-CBL log and 

required remedial work is completed.

The plan thus stated that the BP team would declare the cement job “successful” if it saw “partial 

returns” or “lift pressure.” It anticipated that the team might need to run cement evaluation tools 

(“IBC-CBL log”) but required doing so only if “no returns or lift pressure seen.” Steps one and two 

were the only steps in the BP plan that contemplated cement evaluation: In step three, the crew 

would move on to the temporary abandonment phase of the well and begin to displace mud in the 

wellbore with seawater. 

Figure 4.3.19. Decision tree.

Estimate TOC 

below 17,970'? 

(Top of pay = 

18,370')

Losses while 

cementing 

long string?

Yes

No

Discuss 

dispensation 

and MMS 

requirements

BP/TrialGraphix
Chief Counsel’s Report — Chapter 4.3: Cement | 95

BP Ordered Cement Evaluation Services From Schlumberger

On the same day that Morel distributed the temporary abandonment procedures, BP well site 

leader Ronnie Sepulvado placed an order with Schlumberger for cement evaluation services.250 

Sepulvado did so to ensure that a cement evaluation team would be available on the rig if the 

cement job did not go as planned. The order included a “full suite of logs,”251 including a cement 

bond log, isolation scanner, variable density log, and inclinometer survey.252 Schlumberger 

planned to evaluate the annular cement from the float collar to about 500 feet above the expected 

TOC.253 The total cost for the services would be about $128,000.254

On April 18 and 19, a team of technicians from Schlumberger flew out to the rig.255 BP told 

the team that the cement evaluation log would be run only if there were lost returns.256 The 

Schlumberger team waited for more than a day on the rig to see if BP needed their services.

BP Sent Schlumberger Home

At 7:30 a.m. on April 20, the Macondo team discussed the cement job during its daily morning 

phone call with its contractors. BP concluded during the call that the cement job had gone well 

enough that it could send home the Schlumberger technicians. According to Guide, “everyone 

involved with the job on the rig site was completely satisfied with the job.”257 Having seen lift 

pressure and no lost returns during the cement job, BP sent the Schlumberger team home and 

moved on to prepare the well for temporary abandonment. At approximately 11:15 a.m., the 

Schlumberger crew left the rig on a regularly scheduled BP helicopter flight.258 Not running the 

cement log probably saved BP about eight hours of rig time.259 

Technical Findings

The Primary Cement at Macondo Failed to Isolate Hydrocarbons

It is undisputed that the primary cement at Macondo failed to isolate hydrocarbons in the 

formation from the wellbore—that is, it did not accomplish zonal isolation.260 If the cement 

had set properly in its intended location, the cement would have prevented hydrocarbons from 

flowing out of the formation and into the well. The cement would have been a stand-alone barrier 

that would have prevented a blowout even in the absence of any other barriers (such as closed 

blowout preventer rams, drilling mud, and cement plugs). 

Although the Chief Counsel’s team is certain that the Macondo cement failed, data currently 

available do not allow the team to determine precisely why. It may never be possible to make 

such a determination. Government investigators recovered samples of debris from the blowout 

that may be cement, but they have not currently determined whether it came from the well and, 

if so, from where within the well.261 There are no plans to directly examine the annular cement 

currently remaining at Macondo for clues. Even if someone were to plan such an examination, 

the blowout and subsequent remedial efforts may have obscured or erased any clues that might 

otherwise have been discovered.

BP, Halliburton, and Transocean have each speculated about potential failure mechanisms. 

Based on information currently available, the Chief Counsel’s team can conclude that most (if 

not all) of the cement pumped at Macondo flowed through the float valves and that most of the 

cement that rig personnel intended to place in the annular space around the production casing 

did in fact reach that location. (Chapter 4.1 discusses the remote possibility of a casing breach 
96 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

that would have affected cement placement.) Several events may have contributed to cement 

failure, either alone or in combination: 

	cement in the annular space may have flowed back into the production casing due to 

u-tube pressure and failure to convert the float valves;

	drilling mud may have contaminated the cement in the shoe track and/or annular space 

badly enough to significantly slow cement setting time; 

	cement in the annular space may not have displaced mud from the annular space 

properly, leaving channels of mud behind;

	cement in the shoe track may have flowed down into the rathole (the open section of 

wellbore below the reamer shoe), “swapping” places with drilling mud and increasing the 

potential for flow through the shoe track;

	cement slurry characteristics (such as retarder concentration, base slurry stability/

rheology, or foam instability) may have compromised the sealing characteristics of the 

cement (discussed in Chapter 4.4); and

	severe foam instability may have allowed nitrogen bubbles to break out of the slurry, with 

unpredictable consequences (also discussed in Chapter 4.4).

Any theory regarding the precise mechanisms of the Macondo cement failure must account for 

several issues that the Chief Counsel’s team has identified. Most importantly, if our team is 

correct that hydrocarbon flow came through the shoe track and up the production casing, then 

the tail cement in the shoe track must have failed to block that flow. It would have taken only a 

relatively small amount of properly set cement in the shoe track to block that flow. This suggests 

one of three nonexclusive possibilities to the Chief Counsel’s team. 

Drilling mud contamination. The first is that enough drilling mud contaminated the shoe 

track to delay cement setting time so that the shoe track cement did not provide a competent 

flow barrier at the time of the blowout. This probably would have taken a significant amount of 

mud; testing by Chevron indicated that even with 25% mud contamination, the Macondo cement 

formulation would develop adequate compressive strength without serious delay.262 

The mud in question could have been entrained in the cement flow during cement placement by, 

for instance, the wiping action of the plugs. If the plugs landed off-schedule (as post-blowout 

statements by Morel suggest), that would support this theory. Cementing experts emphasize 

that the shoe track is designed to prevent cement contaminated by plug bypass from entering the 

annular space. Shoe track cement should therefore properly be treated as one part of the overall 

cement barrier system and may not bar hydrocarbon flow on its own. 

Drilling mud could also have “swapped” into the shoe track from the open hole section below 

the casing (sometimes called the rathole). The rathole volume was similar to the shoe track 

volume. Mud contamination could also have come from the annular space around the production 

casing if channeling or other phenomena caused contamination of that area and float equipment 

malfunctions allowed this material to flow back into the shoe track under u-tube pressure.

Gross nitrogen breakout. The second possibility is that the foamed middle section of the 

cement slurry was so unstable (as discussed in Chapter 4.4) that nitrogen gas bubbles in it “broke 

out” of suspension while the cement was flowing down the drill pipe and production casing. This 
Chief Counsel’s Report — Chapter 4.3: Cement | 97

could have left large gas-filled voids not only in the middle section of cement that was injected 

with nitrogen, but also in the tail cement (which became the shoe track cement). That tail cement 

should not otherwise have had nitrogen in it. A problem with this theory is that pumping data 

from the cement job do not show the sorts of gross anomalies that one would expect if cement and 

nitrogen flowed through the float collar separately. 

Nitrogen breakout could also have occurred after the cement arrived at the bottom of the 

well. This might not have produced anomalies in the pumping job data but still could have 

compromised the quality of the set cement. As described in Chapter 4.4, unstable nitrogen 

foamed cement can be excessively porous and permeable once set. Hydrocarbons can flow 

through such cement.

Gross cement slurry failure. A final possibility is that the Macondo cement slurry was 

unstable even before being foamed with nitrogen. As Chapter 4.4 explains in greater detail, 

pre-blowout testing shows that the Macondo slurry had a very low yield point, and post-blowout 

testing shows that a cement slurry produced using the Macondo recipe had a tendency to settle 

as it set. It is possible that these problems compromised the quality of the Macondo cement job 

so that cement in the shoe track could not have prevented hydrocarbon flow. A problem with this 

theory is that it appears, based on available information, that the cap cement in the annulus above 

the pay zone set up properly and created a barrier to flow up the annulus. 

Using Six Centralizers Increased the Risk of Cement Failure

Reduced pipe centralization increases the risk of poor mud displacement, the risk that mud 

channels will compromise zonal isolation, and the risk that hydrocarbons will migrate into and 

through the annular cement as it sets. Without a direct examination of the Macondo cement, the 

Chief Counsel’s team cannot determine whether any of these things occurred, let alone whether 

they caused or contributed to the blowout. The team can only conclude that BP’s engineering 

decision increased the risk of cementing failure. 

The Chief Counsel’s team cannot at this time accept Halliburton’s conclusory assertion that the 

limited number of centralizers at Macondo caused inadequate mud displacement, channeling, 

and cement failure.263 To support its view, Halliburton relies heavily on the results of the model 

that Gagliano produced on April 18.264 But Gagliano produced the April 18 report using several 

assumptions that did not match the eventual Macondo conditions. Halliburton points out that 

Gagliano received these assumed figures from BP, but that it is irrelevant; because the April 18 

modeling inputs were inaccurate, the modeling output was unreliable even if one were to assume 

that those models accurately predicted problems with a cement job.265 (Halliburton personnel 

have argued that their model would still have predicted channeling even with corrected inputs. 

However, Halliburton has yet to provide the results of a corrected model to the Chief Counsel’s 

team or the public. This leads the Chief Counsel’s team to infer that the results are not favorable 

to Halliburton.)

The Chief Counsel’s team also cannot accept BP’s equally conclusory assertion that the decision 

to use only six centralizers “likely did not contribute to the cement’s failure to isolate the main 

hydrocarbon zones....”266 Chapter 4.1 explains that the Chief Counsel’s team finds it likely that 

hydrocarbon flow came up the production casing through the shoe track. But even though 

insufficient centralization may not have directly affected the integrity of the cement in the 

shoe track, it very well could have damaged the integrity of the cement in the annular space 

around the pay zone. If that cement had worked properly, shoe track cement failure would have 

been irrelevant. 
98 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

BP’s technical guidance and early Macondo well plans called for more centralizers than were 

actually run and for centralizers to be used over a larger casing interval.267 If BP believed that its 

engineers could reliably reduce the number of centralizers (and hence cost) by scrutinizing caliper 

logs and pinpointing the placement of centralizers, one would expect its guidance documents 

and well plans to describe this practice. And while BP has repeatedly questioned the accuracy of 

the Macondo cementing models and the value of Halliburton’s model in general,268 it offers little 

affirmative technical analysis of its own to support its claim that centralization was not an issue at 

Macondo. Moreover, before the Macondo blowout, BP engineers thought the model’s predictions 

of channeling were sufficiently credible that they flew 15 more centralizers to the rig in response. 

Limited Pre-Cementing Mud Circulation Increased the Risk of 

Cement Failure

BP’s decision to circulate a limited volume of mud at a relatively low rate before cementing may 

have led to inadequate mud conditioning and wellbore preparation. BP’s decision was perhaps 

an understandable response to its concerns about formation integrity and lost returns, but it also 

increased the risks of cementing failure. 

BP has defended its decision not to circulate bottoms up before cementing. It has argued, among 

other things, that modern technologies can identify wellbore cleanliness problems without full 

mud circulation and that the Macondo team took other measures to prepare the wellbore for 

cementing. For instance, the team circulated bottoms up before running the production casing269 

and pumped additional spacer during the cementing process to remove debris from the well.270 

At the same time, BP cannot dispute that circulating bottoms up is a “best practice” specified by 

Halliburton and other cementing experts,271 and that its team did not do so. Although circulating 

less mud may have reduced the particular risk of lost returns, it nevertheless increased other 

aspects of the risk for cement failure, as compared to completing a full bottoms up.

Low Cement Volume Increased the Risk of Cement Failure

The limited volume of cement used at Macondo increased the risk of cement failure. BP pumped 

only about 60 barrels of cement (after nitrogen foaming) at Macondo. While BP may have 

thought it necessary to pump a small amount of cement to reduce the risk of lost returns, this 

approach magnified three other risks. 

First, it meant there would be less cement in the annular space above the hydrocarbon zones—less 

even than BP’s technical guidance recommends.272 Second, it increased the risk that placement 

errors would leave insufficient cement in the shoe track or in the annular space corresponding to 

the hydrocarbon zone. And third, it increased the detrimental effects of any mud contamination. 

Mud contamination may have been a particular problem at Macondo because the design called for 

a tapered long string casing. That casing design called for the top and bottom wiper plugs both to 

wipe mud from a relatively long length of casing and to wipe two different casing diameters.273 

Before the blowout, BP’s engineering team recognized that their design called for a low cement 

volume that would provide little room for error. 274 And since the blowout, BP has recognized that 

“small cement slurry volume” increased cementing difficulties at Macondo.275 

Cementing Pump Rate Increased the Risk of Cement Failure

In concert with Halliburton, BP chose to pump the primary cement at a relatively low rate.276 

This low rate would have decreased the efficiency with which the cement would have displaced 

mud from the annular space, especially given Halliburton’s predictions regarding the impact of 
Chief Counsel’s Report — Chapter 4.3: Cement | 99

a reduced number of centralizers.277 This, in turn, would have increased the risk of mud-related 

cementing failures such as channeling, contamination, and gas flow. 

Using a Reamer Shoe Instead of a Float Shoe May Have 

Increased the Risk of Cement Failure

BP could have decreased cementing risks using a float shoe. Like a reamer shoe, a float shoe 

is a rounded piece of equipment that attaches to the bottom of a casing string and helps to 

guide the string down. But unlike the reamer shoe, the float shoe includes a check valve that 

functions much like the valves in the float collar. That extra check valve serves as an extra line of 

defense against cement contamination and helps keep debris and contaminants away from the 

float collar’s valves. The existence of the extra check valve also helps to ensure proper cement 

placement by preventing cement from flowing back up the casing. Industry engineers often 

install float shoes where they are concerned about cement contamination.278 While cement 

contamination was (or should have been) a concern at Macondo, BP chose not to install a float 

shoe on its production casing.

Rathole Issues Could Potentially Have Increased the Risk of 

Cement Failure

BP chose not to take precautions against rathole swapping. The rathole, again, is the open 

section of wellbore below the end of the production casing. As described above, mud in this 

portion of the wellbore can swap places with cement in the shoe track if the mud is less dense 

than the tail cement. This can contaminate the cement in the shoe track or potentially create a 

flow path through the cement in the shoe track. 

One common precaution to guard against this phenomenon is to pump a small volume of dense 

mud into the rathole. If this mud is more dense than the cement, it will tend to stay in place 

rather than swap places with the cement. Although early BP plans called for this procedure,279 the 

engineers eventually chose not to do it because the volume was small and improper placement 

could cause ECD concerns.280 They reasoned that this created relatively small risks: the density 

differential between the mud and tail cement was not large, and the rathole volume was relatively 

low.281 Halliburton personnel admitted after the blowout that rathole swapping could create a 

problem, but they had not considered the issue before pumping the job.282

Rig Personnel May Not Have Converted the Float Valves

Although rig personnel and BP concluded that they successfully converted the float valves, the 

Chief Counsel’s team finds that the float valves at Macondo may not have actually converted.283 

Unconverted float valves could have compromised the bottomhole cement job at Macondo. 

Rig Personnel Never Pumped Mud at the Rates Weatherford Specified to 

Convert the Float Collar

Planning documents and pumping data show that rig personnel never pumped mud down the 

well at sustained rates high enough to ensure float valve conversion. While well plans specified 

mud circulation rates that would have converted the float valves, actual rates never exceeded 

4.3 bpm—significantly less than the 6 bpm required to convert the equipment:
100 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Table 4.3.4

Flow Rate Needed to Convert Differential Pressure Needed to Convert

BP September 2009 Plan284

and BP January 27, 2010 Final 

Drilling Program285

12 bpm maximum ~ 600 psi

BP April 12, 2010 Drilling Plan286 and 

BP April 15,2010 Drilling Plan287 8 bpm minimum ~ 500 to 700 psi per Weatherford 

recommendation

Weatherford Manufacturer 

Recommendation288 Adjusted for 

14.1 ppg Mud Weight289

6 bpm290 600 psi291

April 19 actual292 steady flow rate never exceeds 4.3 bpm,293 which would result 

in a differential pressure of approximately 328 psi294

BP contracted Stress Engineering Services, a third-party engineering firm, to conduct postblowout testing on float collars similar to those used at Macondo.295 On the basis of this testing, 

BP asserts that temporary surge flow rates caused by sudden pressure changes in the well would 

have converted the float equipment.296 BP contends that there were two potential surge-inducing 

events. The first was the sudden drop in pressure from 3,142 psi once mud circulation began.297 

The second was during the cement job when the bottom plug burst at 2,392 psi.298 

The Stress Engineering analysis shows that the Macondo float valves may have converted 

because of pressure-induced surge flows. But if this in fact happened, it was by happenstance, 

not design. More importantly, without having pumped mud consistently through the float collar 

at Weatherford-prescribed rates, BP personnel had no sound basis for concluding that the float 

valves had converted. And the later float check that they performed was not a reliable indicator 

that the float collar had sealed.299 BP’s own report agrees.300 

Although rig personnel deemed the Macondo float check to be a success, the check was actually 

inconclusive because of the small density differential between the cement and drilling mud in 

the well. Halliburton’s April 18 model predicted 38 psi of differential pressure.301 (The Chief 

Counsel’s team’s calculations based on actual volumes pumped indicate a u-tube pressure of 

about 56 psi—an inconsequential difference.302) A Weatherford representative confirmed that 

38 psi of differential pressure is “pretty tiny,”303 and other experts agree that it would be hard to 

detect.304 The small u-tube pressure would also have meant that any cement backflow may have 

been too small and gradual for rig personnel to detect in the time that they monitored for flow. 

The Drop From 3,142 psi May Have Been Due to a Clogged Reamer Shoe or 

a Failure of the Float Collar System

Rig personnel assumed that the sudden drop in pump pressure from 3,142 psi indicated that they 

had converted the float collar. If the float collar did not actually convert, then something else 

must have caused this pressure drop. The Chief Counsel’s team has identified two 

possible explanations. 

The Reamer Shoe May Have Been Clogged 

The first possibility is that the unexpected pressure increases and sudden pressure drop may 

have been caused by a clog in the reamer shoe that eventually cleared in response to elevated 

pump pressure. 

Drilling mud pumped down the Macondo production casing and through the float collar assembly 

had to exit the bottom of the casing through three 15⁄8-inch holes (“circulation ports”) at the 
Chief Counsel’s Report — Chapter 4.3: Cement | 101

bottom of the reamer shoe.305 Debris and/or cuttings may have plugged these holes during the 

course of casing installation as shown in Figure 4.3.20. This could explain why the rig crew 

was unable initially to establish mud circulation after landing the production casing. It could 

also explain why the pressure dropped suddenly from 3,142 psi—that pressure may have been 

sufficient to clear a clog in the reamer shoe to allow mud to flow again.

After the blowout, at least two BP personnel identified a clogged reamer shoe as a factor that 

may have complicated the float conversion process. Morel told BP investigators soon after the 

blowout that he believed the reamer shoe may have been plugged.306 Sepulvado, who was onshore 

at the time of the blowout, similarly told the Chief Counsel’s team that the only reason such 

high pressures would have been needed was because differential pressure was not getting to the 

ball,307 which may have been caused by a clogged reamer shoe.308 Besides interfering with float 

conversion, a clogged reamer shoe could have complicated cementing by altering cement flow out 

of the reamer shoe.

The Ball May Have Been Forced Through the Auto-Fill Tube

A second possibility, shown in Figure 4.3.21, is that the sudden pressure drop may have been 

caused when pump pressure forced the ball inside the auto-fill tube through the end of the autofill tube. The collar that would normally have retained the ball within the auto-fill tube was held 

in place with brass pins. It is possible those pins and the collar failed, allowing the ball to pass 

through.309 This would have left the auto-fill tube in place between the float valves and created a 

path for flow in either direction.

Figure 4.3.20. Clogged reamer shoe.

TrialGraphix

Figure 4.3.21. Ball

forced through tube.

TrialGraphix

Cuttings or 

Other Debris
102 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

If the ports in the bottom of the auto-fill tube were clogged, the rig pumps may have placed 

enough force on the collar to shear the brass pins instead of the pins holding the auto-fill tube in 

place. Clawson informed Morel on April 19 that it would only take 1,300 psi of pressure to force 

the ball through the collar without converting the float valves.310 It is not apparent whether Morel 

considered or informed others of this possibility.311

Unconverted Float Valves Would Have Increased the Risk of 

Cement Failure 

If rig personnel never converted the float valves at Macondo, it would have left an open flow path 

through the float collar assembly. That flow path may have allowed cement to flow back into the 

casing from the annular space outside the casing, which would in turn have left less cement in the 

annular space. This flow would also have: (1) increased the potential for contamination of the 

shoe track cement with mud; (2) brought foamed cement from the annulus into the shoe track 

(which should have contained only unfoamed tail cement); and (3) allowed any nitrogen that 

broke out of the foamed cement to compromise the shoe track cement. The open flow path would 

also have made it easier for any hydrocarbons that bypassed the cement to flow through the float 

collar assembly.312 

Properly Converted Float Equipment Is Not a Reliable Barrier to 

Hydrocarbon Flow

The Chief Counsel’s team does not believe that even properly converted float valves would have 

constituted a reliable physical barrier to hydrocarbon flow. While BP’s internal investigation 

report appears to state that float valves could be a barrier,313 several senior BP personnel 

disagreed with that statement.314 Weatherford does not consider float equipment a barrier to 

hydrocarbon flow and instead provides the equipment only to prevent backflow of cement.315 The 

API similarly states only that “float equipment is used to prevent the cement from flowing back 

into the casing when pumping is stopped”316 and does not include float equipment among its list 

of subsurface mechanical barriers.317 

Management Findings

BP’s Management Processes Did Not Force the Macondo Team 

to Identify and Evaluate All Cementing Risks and Then Consider 

Their Combined Impact

BP engineers failed to fully appreciate the cementing challenge they faced at Macondo. Every 

deepwater cement job presents a technical challenge, but the Macondo cement job involved an 

unusual number of risk factors. Several were inherent in the conditions at the well. BP and 

Halliburton created several others during the course of the design and execution of the primary 

cement job. The list includes:

	narrow pore pressure/fracture gradient;

	use of nitrogen foamed cement;

	use of long string casing design; 

	short shoe track;

	limited number of centralizers;

	uncertainty regarding float conversion;
Chief Counsel’s Report — Chapter 4.3: Cement | 103

	limited pre-cementing mud circulation;

	decision not to spot heavy mud in rathole;

	low cement volume;

	low cement flow rate;

	no cement evaluation log before temporary abandonment; and 

	temporary abandonment procedures that would severely underbalance the well and place 

greater stress than normal on the cement job.

BP engineers certainly recognized some of these risk factors and even tried to address some of 

them. For instance, the team asked Halliburton to use additional spacer during the cement job 

to compensate for the limited pre-cementing circulation.318 But it does not appear that any one 

person on BP’s team—whether in Houston or on the rig—ever identified all of the risk factors. 

Nor does it appear that BP ever communicated the above risks to its other contractors, primarily 

the Transocean rig crew. For instance, Transocean was never aware that Halliburton had 

recommended more than the six centralizers that were used.319 

More importantly, there is no indication that BP’s team ever reviewed the combined impact of 

these risk factors or tried to assess the overall likelihood that the cement job would succeed, 

either on their own or in consultation with Halliburton. Rather, BP appeared to treat risk factors 

as surmountable and then forgettable. For instance, after Guide had decided to use only six 

centralizers despite the risk of channeling, one BP engineer wrote to another team member, “But 

who cares, it’s done, end of story, [we] will probably be fine and we’ll get a good cement job.”320 

Reviewing the aggregate effect of risk factors may not even have led BP to change any of its design 

decisions. But if done properly, it may have led BP engineers to mitigate the overall risk in ways 

that could have prevented the blowout. Indeed, a major oil company representative stated that 

the risk factors at Macondo were so significant that his organization would not have counted 

the Macondo cement job as a barrier to annular flow outside the production casing even after a 

successful negative pressure test.321

A closely related issue is that once BP’s engineering team properly identified a risk, it often 

examined and addressed the risk without a full appreciation of other risks its response might 

create. For instance, BP’s team focused almost exclusively on the risk of lost returns in designing 

its cementing program. BP engineers may well have been right to view this as the largest 

individual risk they faced. But they failed to consider the secondary impacts of their numerous 

responses to that risk, which included reducing pre-cementing circulation, cement volume, and 

cement flow rate. Those responses may have increased the overall likelihood of cement failure 

even as they decreased the potential for lost returns.322

BP Did Not Properly Manage Design Changes and 

Procedural Modifications

Impact of Changes to Its Mud Circulation Plan

BP’s engineering team does not seem to have recognized that late-stage changes to mud 

circulation plans might impact float collar conversion. Before the early April lost circulation 

event, the team intended to circulate fluids at 8 bpm—a rate that would have converted the float 

valves. But the BP team later reduced the planned circulation rate to 4 bpm because of ECD 

concerns—a rate that would not have converted the float valves according to the manufacturer’s 

specifications. The April 15 drilling plan highlights the disjoint: It simultaneously calls for 
104 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

circulation rates of at least 8 bpm to convert the float equipment but recommends circulating 

mud at 3 bpm “to keep ECD below 14.5 ppg.”323 Circulating at 8 bpm would clearly exceed that 

ECD threshold, and an independent expert found this inconsistency irreconcilable.324

If BP had recognized that lowering planned circulation rates could impact float collar conversion, 

it could have solved the problem easily. Weatherford can readily produce float collars that 

convert at different flow rates—changing the conversion flow rate can be as simple as changing 

the number of shear pins or the size of the holes in the bottom of the auto-fill tube. BP could 

therefore have used a different float collar assembly that would have converted at the lower flow 

rates it planned. Its engineering team does not appear to have considered this possibility or the 

internal inconsistency in its drilling plan.

Centralizer Sub Procurement

By January 2010, BP’s well plan had called for at least 11 centralizers for its final production 

casing string. Weatherford, BP’s centralizer supplier, recommends that its clients notify it of 

equipment needs four to six weeks in advance.325 But BP engineers waited until the last day of 

March to begin the process of ordering centralizers, leaving themselves less than three weeks of 

lead time. If BP had ordered centralizers earlier, Weatherford personnel would have had ample 

lead time to manufacture more centralizer “subs” to meet BP’s request,326 and BP’s team would 

not have been forced to decide whether to use slip-on centralizers. 

When BP eventually ordered centralizers from Weatherford, the engineer who made the request 

only asked for a range of “7-10” centralizers rather than the 11 centralizers that BP’s 

January 2010 plan specified. It appears that BP engineers relied on their own estimates of 

centralizer needs given well conditions, but it is unclear why those conditions would have been 

any different than when the original well plan was designed.327 When Weatherford responded 

that it had only six centralizers in stock, BP’s team viewed this as sufficient even though it was 

less than the number the engineer requested and about half the number called for in the well 

plan. There is no indication that BP’s team even asked whether additional centralizer subs 

could be manufactured in time, nor is there any evidence that BP attempted to secure acceptable 

equipment from other suppliers besides Weatherford.328

Managing equipment procurement is a key part of safe and efficient offshore drilling. By failing 

to plan centralizer procurement properly, BP’s engineering team forced itself to choose between 

using only a few centralizer subs, adding slip-on centralizers that its team believed posed 

mechanical risks, or incurring costs by waiting for Weatherford to manufacture additional subs at 

the last minute. 

Decision Not to Run Additional Slip-On Centralizers

BP also mismanaged its engineering response to Halliburton’s advice to add centralizers. First, 

BP and Halliburton could have considered centralizer availability during the mid-April design 

review that led them to determine they could cement a long string without exceeding ECD 

thresholds. Instead, they simply assumed optimal centralization without examining whether they 

had the materials on hand to achieve it. 

Once Gagliano advised BP’s team that additional centralizers would be needed to avoid 

channeling, the team responded by procuring 15 additional centralizers immediately. The 

immediate response reflects appropriate levels of concern, but also highlights the problems 

with making complex design changes at the last minute. The engineering team believed that 
Chief Counsel’s Report — Chapter 4.3: Cement | 105

it was ordering slip-on centralizers with integrated stop collars even though a Weatherford 

representative sent the team specifications that showed otherwise. It appears that BP’s team 

did not review these specifications carefully, perhaps because of time pressure. Careful review 

here would have avoided last-minute decision making on April 16.329 The decision to send these 

additional centralizers prompted Guide to complain to his supervisor Sims the next day:

David, over the past four days there has been so many last minute changes to the 

operation that the WSL’s have finally come to their wits end. The quote is “flying by the 

seat of our pants.” More over we have made a special boat or helicopter run everyday. 

Everybody wants to do the right thing, but this huge level of paranoia from engineering 

leadership is driving chaos.... The operation is not going to succeed if we continue in 

this manner.330

After the centralizers were delivered, BP made its final decision not to use them without careful 

engineering review. After Guide found out the type of centralizers Weatherford had provided, he 

argued that they should not be used because of recent problems that BP had experienced with the 

design.331 (Guide mentioned time and cost concerns as well.) But Guide and the rest of the BP 

team appear to have been motivated by personal experience rather than any disciplined analysis. 

Notably, they did not consult the Weatherford centralizer technician that they had flown to the 

rig, who could have provided valuable input on the relative risks of centralizer hang-up.332 It is 

not even clear whether BP believes now that its Macondo team should or should not have used 

the centralizers; the Bly report states that the team “erroneously believed that they had received 

the wrong centralizers.”333 

BP also did not examine whether the mechanical risks of running additional centralizers 

outweighed the cementing risks of not using them. BP’s team could easily have asked Gagliano 

to run a new model to predict the impact of using only six centralizers and could have provided 

up-to-date wellbore and well design data to improve the accuracy of those predictions. The team 

also could have consulted its in-house cementing expert Cunningham.334 BP could have asked 

Halliburton to incorporate Morel’s irregular placement of centralizers into its model, rather than 

simply relying on Morel’s apparent ad hoc analysis to determine their placement. It did none of 

these things.335 BP’s engineering team may have been motivated by skepticism of Halliburton’s 

modeling,336 but this was the only analytical tool the team had at the time. 

Having made a last-minute decision to use fewer centralizers than planned, BP’s team should 

have recognized that decision would increase the risks, first, of lost returns (by increasing ECD), 

and second, of overall cementing failure. Instead, the team appears to have viewed its centralizer 

decision-making process as a “miss-step”337 that had little significance after it occurred. Had 

BP at least noted the risks of using fewer centralizers than it had planned, its rig personnel and 

contractors might have been better prepared for the events that followed.

Communication of Centralizer Decisions Hampered Risk 

Identification and Management

Once BP decided not to run the additional centralizers, it made no effort to inform its contractors 

of its decision. Weatherford’s technician only learned that the centralizers would not be used 

by asking about the issue hours after the installation should have occurred.338 When he did 

learn of it, the technician was concerned enough to call his supervisor—he had never been on 

an installation job that had been canceled.339 But neither he nor anyone else at Weatherford 

expressed concerns to BP. Instead, the technician’s supervisor instructed him to defer 

completely, stating: “Third party, we do what the company man requests.”340
106 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Gagliano only learned about the decision from Tabler, who in turn learned it from Chaisson, who 

in turn learned of the decision by happenstance.341 Gagliano stated that he was “frustrated,”342

and emailed BP’s team to confirm the decision and to ask if he should rerun his models, but 

nobody ever responded to him.343 Gagliano eventually updated the cement model on his own, 

but his model lacked up-to-date information from BP, and he sent it only after the casing run 

had begun. A prompt response from BP to Gagliano might have improved the Macondo team’s 

appreciation of the risks they faced.

Use and Management of Modeling Results

BP engineers mismanaged their use of Halliburton’s computer cementing models. 

It is unclear why BP did not review Halliburton’s modeling results more carefully and continually 

update Halliburton’s data after April 14. Industry experts say that it is not uncommon for 

operators to depart from cementing rules of thumb (such as full bottoms up) in reliance on 

favorable modeling predictions. But operators who do so should continually update such models 

to ensure that their departures do not cause cementing problems. At Macondo, BP appears to 

have done little after April 14 to ensure that Halliburton was using up-to-the-minute data. BP 

provided Halliburton a caliper log but not updated information about reservoir pressure and 

centralizer placement. Instead, it appears that BP’s engineering leadership paid little attention to 

refining the model once it produced results they found favorable. 

BP’s willingness to disregard Halliburton’s April 18 modeling predictions is especially 

questionable given the degree to which BP relied on the model’s earlier predictions. On April 14, 

BP relied almost exclusively on a Halliburton model to conclude that it could successfully cement 

a long string casing. At this time, BP engineers knew that the model was based on incomplete 

data. BP then disregarded the April 18 predictions even though the concerns it identified were 

similar to those that motivated more serious analysis on April 14. BP’s apparent skepticism of the 

value of the April 18 results is hard to square with its near-total reliance on the April 14 results.

BP Did Not Adequately Evaluate the Significance of Float 

Conversion Difficulties

BP’s management and review of the float collar conversion process were inadequate. As explained 

above, BP should have secured different float equipment once it modified its planned circulation 

rates. BP also mismanaged its evaluation of the float conversion process on the rig. BP rig 

personnel properly consulted their shore-based engineering team after encountering difficulties 

when converting the float collar. But after reinitiating circulation at much higher pressures than 

expected, BP’s team appears to have assumed the float valves converted. If the team had instead 

reviewed the data carefully, it would have recognized that it had not yet circulated mud in excess 

of 4.3 bpm and might have increased circulation to ensure conversion. 

Making matters worse, BP and Transocean personnel then tried to explain away concerns about 

lower-than-predicted circulation pressures by blaming a faulty pressure gauge. BP has since 

pointed out that the circulating pressures predicted by M-I SWACO were erroneous and that the 

circulation pressure observed was actually what should have been expected. But rig personnel 

believed at the time that M-I SWACO’s predictions were accurate, and yet there is no evidence 

that they took steps to confirm the gauge was actually faulty or tried to replace it.344 

If BP or Transocean had adequately considered the possibility that the float valves did not 

convert, they could have undertaken efforts to mitigate the potential risks. For instance, one 
Chief Counsel’s Report — Chapter 4.3: Cement | 107

standard industry tactic to address float valve failure is to add pressure inside the casing system 

after pumping cement and to thereby counterbalance any u-tube pressure that might otherwise 

induce flow back through open float valves.345 

BP Focused Excessively on Full Returns as an Indicator of 

Cementing Success

The Macondo team’s approach to cement evaluation at Macondo was flawed. Because the team 

focused its attention so heavily on the risk of lost returns, it overemphasized the significance of 

full returns as an indicator of cementing success. 

Receiving full returns showed that cement had not flowed into the weakened formation but 

provided little or no information about: (1) the precise location where the cement had ended 

up; (2) whether channeling had occurred; (3) whether the cement had been contaminated;346 

or (4) whether the foamed cement had remained stable. Similarly, reports of on-time top plug 

arrival indicated, at most, only one thing for certain: The cement flowed through the float 

collar. (Morel’s report that the bottom plug bumped early may suggest that mud contaminated 

the cement during job placement.) Accordingly, BP’s technical guidance documents do not list 

reports of full returns or on-time plug bumping as indicators of zonal isolation.347

BP engineers also considered lift pressure a positive indication. Company technical guidance 

documents state that lift pressure can provide a coarse indication of TOC (if not zonal isolation) 

but that it “is unlikely to provide a sufficiently accurate estimate” of TOC when “cement and 

mud weights are very similar,”348 as they were at Macondo. While one BP engineer stated that 

lift pressure was “easy” to see at Macondo,349 another admitted after the blowout that it was not 

a valid confirmation of good cement placement.350 Industry experts who reviewed the data after 

the fact were also skeptical. The Chief Counsel’s team spoke with several experts who agreed that 

the roughly 100 psi pressure increase that rig personnel observed at Macondo after the bottom 

plug landed was too low to be a reliable indication that cement had turned the corner and flowed 

up into the annulus.351 One described 100 psi of lift pressure as “nearly unreadable.”352 That 

relatively small pressure increase might have been caused by cement “turning the corner” into the 

annulus, but it might also have been caused by friction from cement flow.353 

Better management would have encouraged the BP team to question the overall value of its 

pressure and volume indicators. BP’s own report appears to agree. It states:

A formal risk assessment might have enabled the BP Macondo well team to identify 

further mitigation options to address risks such as the possibility of channeling; this may 

have included the running of a cement evaluation log.... Improved technical assurance, 

risk management and management of change by the BP Macondo well team could have 

raised awareness of the challenges of achieving zonal isolation and led to additional 

mitigation steps.354

Rather than aiding decision making, the Macondo team’s cementing decision tree reinforced 

the flaws in its analytic approach. Proper risk management in a complex engineering project 

requires a constant awareness of risks and potential risks. The decision tree instead encourages 

a simplified linear approach in which complex risks (such as the risk of failed cementing) can be 

forgotten or ignored on the basis of simple and incomplete indicators (such as partial returns or 

lift pressure). 
108 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Most Operators Would Not Have Run a Cement Evaluation Log 

in This Situation, but BP Should Have Run One Here, in Part 

Because of Its Chosen Temporary Abandonment Procedures

At least some personnel appear to have believed that the Macondo team was planning to run a 

cement bond log no matter what. On April 20, a BP completions engineer emailed Morel to ask 

for cement bond log data. When Morel responded “No CBL,” the completions engineer wrote 

“Can you explain why? I thought y’all were planning to run one.”355 

A cement evaluation log would have provided more direct and reliable information about the 

cement job than pressure and volume indicators on which BP relied. While most operators 

would not have run a cement evaluation log until the completion phase, BP should have run one 

here356 for at least two reasons. First, BP engineers recognized or should have recognized that 

this was a “finesse” cement job that presented higher-than-average risks.357 Full returns would 

not identify if channeling had occurred; a cement bond log could.358 Second, BP’s temporary 

abandonment procedures would force the rig crew to rely on this finesse cement job as the sole 

hydrocarbon barrier in the Macondo wellbore. Alternatively, BP should have sought other means 

for addressing the risk of unsuccessful cementing. 

Halliburton Did Not Adequately Inform BP of Cementing Risks or 

Suggest Design Alternatives

Halliburton did not provide BP the full benefit of its corporate cementing expertise. Since the 

blowout, senior Halliburton personnel have repeatedly and forcefully emphasized the complexity 

and difficulty of the Macondo cement job and the limitations of indicators such as full returns.359 

But Halliburton’s personnel did not raise all of these concerns before the blowout, let alone 

emphasize them with the same force.

It appears that Gagliano mentioned the possibility of cement channeling to individual BP 

engineers on April 15 and then again later on April 19.360 But he did not flag the concern in 

his emails or express serious reservations. Gagliano told Congressional investigators that he 

“recommended to BP that they use 21 centralizers” but admitted that he “did not think there 

would be a well control issue.”361

Gagliano also testified that he would have recommended that BP perform a cement bond log given 

the reduction in the number of centralizers but did not do so because “we do not recommend 

running a [cement] bond log”362 and, anyway, he “was never asked.”363 Although Gagliano was 

present when BP discussed criteria for the cement bond log, he never told anyone full returns 

alone could not identify channeling.364 Moreover, the only risk factor that Halliburton identified 

during the design process was the relatively low number of centralizers. Halliburton did not 

discuss any other risk factors or recommend other design changes that might have mitigated 

those risks. Halliburton personnel were aware that BP’s design called for a low cement volume 

and a low cement flow rate. They also knew of the decision not to circulate bottoms up, the float 

valve conversion difficulties, and the low post-conversion circulating pressures. 365 But they never 

raised concerns about these risk factors, let alone offered BP an independent assessment of the 

overall likelihood of success of the cement job. 

The format of Halliburton’s modeling reports exacerbated communication difficulties. After 

the blowout, Halliburton personnel argued that the reports included predictions of channeling 

and gas flow that BP engineers should have heeded.366 Halliburton could have highlighted these 

warnings—along with overall assessments of cementing success—in a simple summary early in 
Chief Counsel’s Report — Chapter 4.3: Cement | 109

the report. Instead, the reports presented information in an obscure and unnecessarily technical 

manner. (For instance, as shown in Figure 4.3.22, the reports present channeling predictions 

only as unexplained jagged lines in a well diagram).367 As a result, BP engineers reviewed the 

predictions in a cursory fashion, if at all.368

Halliburton missed another opportunity to communicate its concerns when it reported the overall 

success of its cement job. Chaisson expressed complete satisfaction with the cement job in his 

post-job report but later clarified that “[cementing] was successful on the surface. As far as being 

successful downhole, actually if it were successful at getting zonal isolation, I cannot be sure of 

that.”369 Halliburton explains the difference between its pre-blowout reports and its post-blowout 

skepticism by suggesting that it is BP’s responsibility as the operator to evaluate the significance 

of cementing indicators and BP’s responsibility to mitigate risks at the well. Whether that 

turns out to be true as a legal matter, Halliburton could have helped avoid the blowout if it had 

highlighted the risks of the cement job and the limitations of the few cementing indicators it 

had reviewed. 

Figure 4.3.22. Page 23 of Halliburton’s April 18, 2010 OptiCemTMreport.

 Halliburton

Halliburton personnel explained the green areas as predicted channeling.

Channeling

Chief Counsel’s Report — Chapter 4.4: Foamed Cement Stability | 111

Chapter 4.4|Foamed Cement Stability

and Halliburton chose to cement the final Macondo 

production casing into place using nitrogen foamed cement. 

That technology offered several advantages at Macondo, but it 

also posed a risk: An improperly designed or incorrectly 

pumped nitrogen foamed cement slurry can be unstable and lead to a failed 

primary cement job. Data from pre- and post-job laboratory testing lead the 

Chief Counsel‘s team to conclude that the foamed cement slurry pumped at 

Macondo was very likely unstable. The Chief Counsel‘s team finds that 

Halliburton failed to review properly the results of its own pre-job tests, and that 

a proper review would have led Halliburton to redesign the cement slurry system. 

The Chief Counsel‘s team also finds that BP inadequately supervised the cement 

design and testing process.

Foamed Cement

Cementing personnel create nitrogen foamed cement by injecting inert nitrogen gas into a 

base cement slurry. This produces a slurry that contains fine nitrogen bubbles. If the system is 

properly designed, the bubbles will remain evenly dispersed in the slurry as it cures, and the set 

cement will retain the bubbles in the same form.

Foamed cement offers two principal technical advantages. First, the nitrogen bubbles in the 

foamed cement slurry make the overall cement mixture less dense than the base cement slurry. 

Second, cementing personnel can adjust the density of the foamed cement slurry in response to 

well conditions by adjusting the rate at which they inject the nitrogen into the base cement slurry. 

Whereas a base cement slurry typically weighs about 15 pounds per gallon (ppg), foamed cement 

can weigh as little as 5 ppg.1 All other things being equal, a low-density column of cement in the 

annular space around a well casing will exert less hydrostatic pressure on the formation than a 

high-density column of cement. As a result, using a low-density foamed cement can reduce the 

risk of formation breakdown. Such a breakdown may result in the loss of cement into the 

formation, compromising zonal isolation and reducing the productivity of the well over the 

long term.2

Risks of Unstable Foamed Cement

A foamed cement system must exhibit good foam stability.

3 A stable nitrogen foamed cement 

slurry will retain the nitrogen bubbles internally and maintain its design density as the cement 

cures. The result is hardened set cement that has tiny, evenly dispersed, and unconnected 

nitrogen bubbles throughout. If the foam does not remain stable as the cement cures, the small 

nitrogen bubbles may coalesce into larger ones, potentially rendering the hardened cement 

porous and permeable to fluids and gases, including hydrocarbons.

4

 If the instability is 

BP
112 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Figures 4.4.2 and 4.4.3. Foam testing apparatus.

API RP 10b-4

Left: Graduated cylinder for unset foam test. 

Above: Curing mold for set cement tests.

particularly severe, the nitrogen can break out of the cement, with unpredictable consequences.5 

While technical authorities do not appear to have definitively determined the effects of pumping 

unstable foamed cement downhole, they uniformly agree that only stable foamed cement designs 

should be used.6

Foamed Cement Testing

When designing a nitrogen foamed cement system, it is critical to test the stability of the foamed 

slurry.

7 The American Petroleum Institute (API) has published recommended procedures for 

conducting foam stability tests.

8

 

The technician mixes a volume of 

base cement slurry with air (not 

nitrogen) in a sealed blender to 

generate a foamed slurry of the 

same density that will be used in the 

field (see Figure 4.4.1). The 

laboratory may then conduct 

foam stability tests using one 

of two methods. 

The first method involves pouring a 

sample of the foamed cement into a 

graduated cylinder (see 

Figure 4.4.2). After two hours, the 

technician visually examines the foamed slurry for signs of instability, such as large coalescing 

bubbles or cement density variations caused by nitrogen bubble migration or escape. 

The second method involves pouring the foamed cement into a plastic cylinder, sealing it, and 

then allowing it to cure and set (see Figure 4.4.3). The technician then removes the solid cement 

sample from the cylinder and measures the density of solid cement at the top, middle, and 

bottom of the sample. If there are density variations from top to bottom, or if the densities are 

equal to one another but significantly higher than the target density, the foamed cement is 

deemed unstable.

Figure 4.4.1. Foam testing apparatus.

Five-blade 

blender.

API RP 10b-4

Sambhav N. Sankar
Chief Counsel’s Report — Chapter 4.4: Foamed Cement Stability | 113

The API lists five signs of foamed slurry instability in the laboratory:9 

 more than a trace of free fluid;

 bubble breakout noted by large bubbles on the top of the sample;

 excessive gap at the top of the specimen;

 visual signs of density segregation as indicated by streaking or light to dark color change 

from top to bottom; and

 large variations in density from sample top to bottom.

None of these criteria is quantitative. All rely to some degree on the judgment of laboratory 

personnel or cementing experts.

Foamed Cement at Macondo

Decision to Use Foamed Cement

BP and Halliburton planned from the very beginning to use foamed cement technology for at least 

some of the cementing work at Macondo. It is common to use foamed cement on the first few 

casing strings in a deepwater well because shallow formations are often too weak to withstand the 

hydrostatic and dynamic pumping forces exerted by a heavier, normal-density cement slurry. 

(The Marianas crew and Halliburton cemented at least two of Macondo‘s early casing strings 

with foamed cement.)10 

Operators use foamed cement less frequently for deeper casing strings and in applications for 

which synthetic oil-based mud is being used as a drilling fluid. While at least one operator—

Shell—often uses foamed cement in deepwater Gulf of Mexico production casings, BP appears to 

have had relatively little experience with using the technology for this purpose.11

To cement the final long string production casing at Macondo, Halliburton and BP began 

planning as early as February 2010 to start with a base slurry having a density of 16.7 ppg and 

then to add enough nitrogen to reduce the density to 14.5 ppg. It appears that BP drilling 

engineer Brian Morel first raised the idea of using foamed cement technology for the production 

casing. He suggested the idea because using foamed cement might provide long-term strength 

benefits over the life of the well.12 Halliburton cementing engineer Jesse Gagliano agreed that 

foamed cement would be useful at Macondo.13 But an internal BP cementing expert cautioned 

Morel as early as March 8 that: 

Foaming cement after swapping to [oil-based drilling mud] presents some significant 

stability challenges for foam, as the base oil in the mud destabilizes most foaming 

surfactants and will result in N2 [nitrogen] breakout if contamination occurs. This drives 

the need for a lot of attention to the spacer programs and often results in non-foamed cap 

slurries being placed on top of the foamed slurry to mitigate breakout.14

The early April lost returns problems appear to have further solidified the decision to use nitrogen 

foamed cement. According to BP and Halliburton‘s calculations, using the lighter foamed cement 

would reduce the risk of fracturing the formation at the well and thereby reduce the risk of losing 

returns during the cementing process. 
114 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Pre-Blowout Cement Testing

When the Deepwater Horizon arrived at Macondo to replace the Marianas, it had on board a 

large quantity of cement dry blend that Halliburton had originally designed for use at Kodiak #2, 

the previous BP well the Horizon crew had drilled.15 Gagliano had designed the primary features 

of that blend in late 2009.16 

Dry Blend. The term dry blend refers to the combination of dry cement components that are 

blended together onshore for use on the rig. The Macondo dry blend included Portland cement, 

two different grades of silica powder, potassium chloride, a proprietary antisettling agent, and 

a proprietary flow-enhancing additive. The rig cementing team added water, two liquid 

chemical additives, and a glass fiber material to the dry blend to produce the base slurry.

On February 10, Gagliano instructed technicians in Halliburton‘s Broussard, Louisiana, 

laboratory to conduct pilot tests on a cement slurry recipe based on this dry blend. The slurry 

recipe specified the amount of water and the type and quantity of liquid chemical additives that 

should be mixed with the dry blend to produce the cement slurry. If the dry blend had been 

unsuitable—either because of its original design or because it had degraded during storage—then 

Halliburton could have delivered a new dry blend to the rig for use at Macondo. 

Foamed Cement Pilot Testing

Gagliano‘s February 10 pilot cement design listed the precise amount of liquid retarder, 

surfactant, and fresh water that the laboratory should add to the dry blend to produce a cement 

slurry for testing. The ―recipe‖ that Halliburton tested in February was identical to the recipe that 

it eventually used at Macondo, with one exception: The February recipe included roughly twice 

the amount of liquid chemical ―retarder‖ that Halliburton eventually used (0.20 gallons per sack 

(gal/sack) vs. the final 0.09 gal/sack) and correspondingly less water. (Adding retarder extends 

the setting time of cement.)17 The laboratory used the dry blend from the Deepwater Horizon

but used local tap water and stock liquid chemicals rather than water and liquid chemicals 

from the rig. 

The Broussard laboratory conducted several tests in February, including two separate foam 

stability tests.18 Both foam stability tests were ―set‖ slurry tests, in which personnel poured 

foamed cement into a cylinder, allowed it to cure for 48 hours, and then examined the density of 

the top and bottom of the set cement cylinder. 

Laboratory personnel appear to have conducted the first February foam stability test on or about 

February 13. The top and bottom of this sample weighed 16.8 ppg and 17.6 ppg, respectively. 

These measurements indicated serious instability because they differ significantly from each 

other, and they are both higher than the target density of 14.5 ppg. The test measurements 

showed either that: (1) The lab personnel were unable to generate a proper foamed slurry; 

(2) gas bubbles migrated within the foamed slurry; (3) gas escaped from the slurry before it 

could set; or (4) some combination of these things occurred.

Laboratory personnel appear to have conducted a second February foam stability test on or about 

February 17. The top and bottom of this sample weighed 15.9 ppg and 15.9 ppg, respectively. 
Chief Counsel’s Report — Chapter 4.4: Foamed Cement Stability | 115

While these two measurements were identical, the data still indicated serious instability because 

both measurements were significantly higher than the target density of 14.5 ppg. Again, nitrogen 

gas must have escaped from the tested slurry before it could cure, or the lab personnel had been 

unable to generate a proper foamed slurry.

These two February 2010 lab tests should have caused Halliburton technical personnel to 

conclude that the foamed cement Halliburton was planning to pump at Macondo was 

likely unstable.

Three other facts about the February tests are worth noting. First, laboratory personnel did not 

condition the cement before conducting the February 13 foam stability test but conditioned the 

cement for two hours before conducting the February 17 test. Second, rheology test results 

showed that the yield point of the base slurry was quite low. This can be an independent warning 

that the base slurry may be unstable and that a foamed slurry prepared from that base slurry may 

also be unstable.19 Third, time-lapse strength testing showed that the pilot cement recipe set 

extremely slowly, suggesting that the recipe included too much retarder. 

Halliburton did not report any of the February pilot testing data to BP until March 8.20 On that 

date, Gagliano attached an official data report of the February test results to an email in which he 

discussed his recommended plan for cementing one of the Macondo casing strings. 

The official data report included only the results of the February 17 foam stability test, in which 

the top and bottom portions of the set cement both weighed 15.9 ppg. (The official laboratory 

reports list the results in terms of specific gravity (SG) rather than pounds per gallon.) Because 

the top and bottom weights matched, the test did not demonstrate density segregation, but the 

test was still a clear failure because both weights were significantly higher than the target density. 

For some unexplained reason, Halliburton‘s official data report to BP incorrectly stated that 

laboratory personnel had not conditioned the cement prior to the February 17 foam stability test.

Apparently, Halliburton did no further testing of the proposed Macondo cement slurry until April 

2010, as the final production casing planning was under way.

April 13 Pre-Job Testing

On April 1, Morel sent an email to Gagliano, BP senior drilling engineer Mark Hafle, BP 

operations engineer Brett Cocales, and Quang Nguyen of Halliburton requesting that Halliburton 

begin testing cement for the final production casing cement job. Morel wrote, ―This is an 

important job and we need to have the data well in advance to make the correct decisions on this 

job.‖21 Gagliano responded on the same day with an email stating that he had already run the 

February pilot tests, and that he would run further tests ―[o]nce I get samples from the rig sent 

into the lab‖ and once he had the latest data on the downhole temperatures at the well.22 

Gagliano attached the same official laboratory report that he had sent on March 8.

Gagliano appears to have first ordered additional testing on April 12.23 This time, the laboratory 

tested samples of dry blend, additives, and water from the rig, and used a design recipe that was 

nearly identical to the one that Halliburton eventually pumped. (The tested recipe contained 

slightly less retarder than the pumped recipe—0.08 gal/sack instead of 0.09 gal/sack.) 

According to Gagliano, the main goal of this test was to determine how much retarder the 

recipe should use.24
116 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

It appears that the laboratory performed a foam stability test on this recipe on or about April 13 

and conditioned the cement slurry for 1.5 hours at 180 degrees before conducting the test.25 They 

finished the test on or about April 15. After curing, the top and bottom of the set cement sample 

weighed 15.7 ppg and 15.1 ppg, respectively. 

This April 13 test result, just a week before the blowout, indicated serious instability.26

On April 17, Gagliano sent an email to Morel, Cocales, and BP drilling engineer team leader Gregg 

Walz and attached two official laboratory reports.27 The data reports included results from 

various tests on cement slurry recipes with two slightly different retarder concentrations: 

0.08 gal/sack and 0.09 gal/sack. BP and Halliburton had discussed increasing the retarder 

concentration in order to compensate for the fact that they planned to pump the cement at a low 

rate. The slow pumping rate would translate to increased cement travel time, which would in 

turn raise the risk of premature cement thickening. 

Neither data report included the results of the April 13 foam stability test (or any other foam 

stability test). Gagliano did not otherwise alert BP to the foam stability test results. Gagliano‘s 

cover email discussed the data from recently completed thickening time tests, presumably 

because this measured the cement characteristic that would vary depending on retarder 

concentration. Gagliano also stated that he had not yet obtained compressive strength results for 

the final cement recipe that BP planned to use—which included slightly more retarder. 

Morel complained to Hafle that Gagliano had started the compressive strength tests later than he 

should have. Morel asked Hafle if Morel would be ―out of line‖ by sending the following message 

to BP wells team leader John Guide and Walz:

I need help next week dealing with Jesse. I asked for these lab tests to be completed 

multiple times early last week and Jesse still waited until the last minute as he has done 

throughout this well. This doesn‘t give us enough time to tweak the slurry to meet our 

needs.... As a team we requested that [Gagliano] run another test with 9 gals on 

Wednesday, I know the first [compressive strength] test had issues, but I do not 

understand what took so long to get it underway and why a new one wasn‘t put on right 

away. There is no excuse for this as the cement and chemicals we are running has been 

on location for weeks.28

Hafle agreed that Morel‘s concerns were reasonable and that BP should ask Halliburton to replace 

Gagliano soon (a request that BP appears to have made earlier as well).29 Morel and Hafle 

conveyed their concerns to Walz, Cocales, and Guide, and on April 18, Walz responded that he 

and Guide would be meeting soon with Halliburton.30 

Meanwhile, on April 17, Morel responded directly to Gagliano‘s email. Morel wrote:

I would prefer the extra pump time with the added risk of having issues with the nitrogen. 

What are your thoughts? There isn‘t a compressive strength development yet, so it‘s hard 

to ensure we will get what we need until it[‘]s done.31

Morel thus told Gagliano that he would prefer to alter the cement slurry recipe to include more 

retarder to increase the thickening time (or ―pump time‖) of the cement. In the same email, he 

appears to have recognized that adding more retarder would potentially increase the risk of 

nitrogen foam instability. 
Chief Counsel’s Report — Chapter 4.4: Foamed Cement Stability | 117

Laboratory personnel appear to have conducted a second April foam stability test on or about 

April 18. 32 They used the same amount of retarder (0.08 gal/sack) but conditioned the cement at 

180 degrees for three hours—the longest period yet. The top and bottom of the set cement sample 

weighed 15.0 ppg and 15.0 ppg, respectively. 

While these numbers are the same as each other, they are both 0.5 ppg higher than the target of 

14.5 ppg. This means one of two things. First, laboratory personnel may have generated a 

foamed cement slurry that initially weighed 15.0 ppg and retained that density throughout the 

test. If this was the case, however, the laboratory documents should at least have noted the 

difficulty; API standards state that if laboratory procedures generate a foamed slurry density that 

is above the design density, ―it will be difficult to obtain the proper foamed cement density in the 

field, and the slurry should be redesigned.‖ 33

Second, laboratory personnel may have generated a foamed slurry of 14.5 ppg, but some nitrogen 

gas may have escaped from the slurry as it set, making the slurry more dense. Because the change 

from 14.5 to 15.0 ppg is not indisputably ―large‖ within the meaning of API testing criteria, this 

might suggest that the foamed cement was stable. Halliburton appears to contend that this is 

what happened and argues that the April 18 test shows that its cement slurry was stable. 

Internal documents provided by Halliburton do not clarify which of these two things happened. 

Availability of April 18 Test Results

The documents also do not establish conclusively when Halliburton completed its April 18 foam 

stability testing. Handwritten notes in the documents suggest that laboratory personnel began 

the test at 2:15 a.m. on April 18,34 and Halliburton has confirmed this time in correspondence to 

the Chief Counsel.35 Halliburton at one point stated publicly that the test took 48 hours to 

complete.36 If that were true, the test results would not have been complete until at least 2:15 a.m.

on April 20, which would have been after the time Transocean‘s rig crew and Halliburton‘s 

cementing personnel finished pumping the primary cement job at 12:35 a.m. on April 20.37 

Six months after the blowout, and after the Chief Counsel‘s team publicly questioned the stability 

of the Macondo cement design and the timing of lab testing, Halliburton still had not determined 

whether its personnel had completed the April 18 foam stability test before pumping the Macondo 

job.38 Finally, eight months after the blowout, Halliburton informed the Chief Counsel that it had 

―learned more about the specific facts surrounding the cement lab testing,‖ including that ―the 

second April foam stability test was finished before the final cement job started.‖

39

 In the words 

of its counsel: 

Halliburton can now demonstrate that an email notification was sent to Jesse Gagliano 

on April 19, 2010, at approximately 4:14 pm indicating that all tests associated with the 

final cement job were then ―finished in lab,‖ more than three hours before the cement job 

commenced. Attached to this letter is a copy of a spreadsheet containing the ―web log‖ 

data referenced above and explained further in Halliburton‘s January 7th letter to you. 

This constitutes objective evidence...that the foam stability test was run in less than 

48 hours and that the test was completed prior to the final cement job.40

Halliburton contended that the ―finished‖ notification ―would not have been generated had the 

foam stability test failed or been incomplete.‖41 
118 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Figure 4.4.4. Halliburton evidence of test times. 

Halliburton

The Chief Counsel‘s team cannot accept or reject Halliburton‘s contentions based on these 

statements by its counsel. While Halliburton did provide a one-page spreadsheet that it views as 

―objective evidence‖ of the timing of its test, the Chief Counsel‘s team cannot decipher the 

document (displayed as Figure 4.4.4) without the aid of Halliburton personnel. 

Halliburton flatly refused to produce any witness who could explain this document (or any of 

the other timing and testing issues discussed above) in a transcribed interview. 

Significant problems remain even if the Chief Counsel‘s team accepts Halliburton‘s assertions 

about when the April 18 test had been completed. While Halliburton argues that its computer 

system generated a notice that the April 18 test results were available before its personnel 

pumped the cement job, it has carefully avoided saying that any of its engineers actually knew

that the results were available, let alone reviewed them, before pumping the job. Indeed, BP 

documents show that Halliburton first reported the April 18 result to BP on April 26, six days 

after the blowout.

42

 And while Halliburton contends that the ―finished‖ notification meant that 

the April 18 foam stability test did not fail by its standards, it refuses to identify those standards, 

let alone the person who actually applied them. 

Halliburton presumably would not deny this information to the Chief Counsel if it were favorable 

to the company.

Post-Blowout Cement Testing 

Testing by BP

BP‘s internal investigation raised several questions about Halliburton‘s cement slurry design and 

pre-job testing procedures.43 BP asserted that the final April 18 foam stability test ―indicated 

foam instability based on the foamed cement weight of 15 ppg.‖44 
Chief Counsel’s Report — Chapter 4.4: Foamed Cement Stability | 119

BP also commissioned third-party testing by CSI Laboratories, an independent cement consulting 

company.45 CSI could not conduct these tests on the actual materials that had been used at the 

Macondo well because those materials sank into the ocean with the rig. 

CSI also could not conduct these tests using the precise off-the-shelf ingredients specified by the 

cement slurry recipe because Halliburton refused to provide its proprietary additives to CSI. CSI 

therefore developed a model slurry to mimic the characteristics of the slurry used at Macondo. 

CSI prepared the model slurry by mixing commercially available cement and additives according 

to the final Macondo cement recipe. To replace proprietary Halliburton additives, CSI used 

third-party chemicals that served similar purposes (for example, using a commercially available 

third-party retarder instead of Halliburton‘s proprietary SCR-1000 retarder). Despite these 

differences, BP‘s investigation team asserted that the model slurry was ―sufficiently similar to 

support certain conclusions concerning the slurries actually used in the Macondo well.‖46 

CSI reported that foamed cement generated from the model slurry was unstable under several 

test conditions. Based in large part on this analysis, BP‘s investigation team concluded in its 

report that ―the nitrified foamed cement slurry used in the Macondo well probably experienced 

nitrogen breakout, nitrogen migration and incorrect cement density.‖47

Testing by Chevron and Chief Counsel’s Team

The Chief Counsel‘s team conducted its own independent tests of cement slurry stability on behalf 

of the Commission. 

The Chief Counsel‘s team worked with an independent expert and cement experts from Chevron 

to conduct these tests.48 Halliburton recognized that Chevron‘s laboratory personnel were highly 

qualified for this work; Chevron maintains a state-of-the-art cement testing facility in Houston, 

Texas, and employs a staff of cement experts to supervise cement design and testing for its oil 

wells. Halliburton also agreed to supply the Chief Counsel‘s team with off-the-shelf cement and 

additive materials of the same kind used at the Macondo well. Although these materials did not 

come from the specific batches used at the Macondo well, they are in all other ways identical in 

composition to the slurry pumped there. 

Halliburton refused to provide the Chief Counsel‘s team with full details of the methods and 

protocols that its laboratory used to conduct its February and April cement tests. Most notably, 

Halliburton refused to provide any information on whether and how its staff had conditioned 

the cement before conducting the foam stability tests. (At the time Chevron conducted its tests, 

Halliburton had not yet produced any internal laboratory documents to the Commission staff. 

Halliburton later provided some internal documents that disclosed conditioning times.) When 

the Chief Counsel‘s team sought input from BP and other parties regarding these and other issues, 

Halliburton demanded that the team refrain from doing so.49 The Chief Counsel‘s team agreed to 

honor Halliburton‘s request by working solely with Chevron experts and an independent expert to 

develop protocols for testing Halliburton‘s cement materials.

Chevron conducted numerous tests on the Commission‘s behalf. Chevron‘s laboratory report 

states that many of its results ―were in reasonable agreement‖ with results reported by 

Halliburton. However, Chevron‘s staff did not obtain foam stability test results that agreed with 

Halliburton‘s. Instead, Chevron‘s report stated that its staff was ―unable to generate stable foam 

with any of the tests‖ that they conducted to examine foam stability.50 Chevron‘s testing strongly 
120 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

suggests that the foamed cement slurry actually used at Macondo was unstable. Appendix D is 

Chevron‘s letter to the Chief Counsel‘s team that accompanied its report.

Technical Findings

The Foamed Cement Slurry Used at Macondo Was 

Very Likely Unstable

Of all the tests done so far to evaluate the stability of the Macondo foamed cement slurry design, 

only one (the April 18 Halliburton pre-job test) even arguably suggests that the design would 

be stable. 

Even the April 18 test result predicts only borderline stability. Industry experts believe that the 

three-hour high-temperature conditioning regimen for this test biased it in favor of success. 

Several have stated that cement laboratories should not condition a slurry sample at all before 

running foam stability tests, let alone at such elevated temperatures.51 They reason that during 

field cementing operations, crews do not usually mix or circulate the base slurry before foaming it 

with nitrogen. Halliburton explained that its laboratory personnel derived the conditioning time 

from pumping time,52 and then contended in writing that there is ―sound operational basis‖ for 

conditioning cement in a laboratory prior to foam stability testing.

53

 But when the Chief 

Counsel‘s team asked Halliburton to provide ―[a]ny scientific study or other document‖ 

supporting the latter statement,54 Halliburton cited only one thing: API Recommended Practice 

10b-2.

55 Section 15 of that document states, ―The cement slurry is conditioned to simulate 

dynamic placement in a wellbore.‖ But this document discusses methods for testing the static 

stability of unfoamed cement slurries. By contrast, API‘s practice recommendations for testing 

foamed cement do not mention pre-test conditioning at all.

Halliburton also declined to provide any information that would help the Chief Counsel‘s team 

determine whether lab personnel had difficulty generating a proper density foamed slurry sample 

on April 18, which might account for the 15.0 ppg density of that sample.

Indeed, Halliburton repeatedly flatly refused Chief Counsel‘s personal requests for documents or 

recorded testimony regarding many otherwise unsupported assertions from Halliburton‘s 

lawyers. For example, Halliburton‘s lawyers have consistently asserted that the April 18 foam 

stability test produced passing results. Commission staff requested ―any document specifying or 

prescribing the conditioning time...test duration, or success criteria‖ for this and other tests, and 

requested the opportunity to conduct and transcribe interviews with Gagliano, his supervisors, 

and any ―individual or individuals competent to testify regarding standard Halliburton laboratory 

practices.‖56 Halliburton produced no documents and provided no witnesses. It noted that it had 

allowed the Chief Counsel to interview Gagliano and a Halliburton cement expert early in the 

investigation—before the Chief Counsel had learned of the failed February and April tests and 

before the Chief Counsel‘s testing had identified concerns with the Macondo cement slurry recipe. 

Halliburton then stated: 

[H]alliburton is compelled to view these requested ―interviews‖ as being more in the 

nature of adversarial depositions designed to defend the [Chief Counsel‘s] preliminary 

conclusions as opposed to furthering an objective evaluation of what occurred. Given 

Staff‘s apparent shift in purpose, Halliburton respectfully declines to make such 

witnesses available.
Chief Counsel’s Report — Chapter 4.4: Foamed Cement Stability | 121

In contrast to the April 18 test, 12 other stability tests—three by Halliburton and nine by 

Chevron—clearly predict that the foamed cement slurry design would be unstable. One can 

debate the significance of these tests individually. For instance, the February Halliburton tests 

predicted severe instability but were performed with a recipe containing more retarder, which can 

potentially reduce slurry viscosity and make it more unstable.57 And one can also debate how well 

laboratory testing approximates field conditions.58 However, the sheer number of failed foam 

stability tests combined with other indicia of instability (discussed below) lead the Chief Counsel‘s 

team to conclude that the foamed cement slurry used at Macondo was very likely unstable. 

The Commission-sponsored tests further suggest that the Halliburton base slurry was unstable 

even before being foamed with nitrogen. Chevron‘s lab report notes that its personnel observed 

base slurry ―settling‖ in six of the nine tests it performed. The base slurry also consistently 

showed a very low yield point, which can be a warning that the slurry will be unstable before and 

after foaming. Base slurry instability also could have severely compromised the bottomhole 

cement job at Macondo.

The Chief Counsel‘s team notes that Halliburton‘s Broussard laboratory did retain a small sample 

(1.5 gallons) of dry blend material from the Deepwater Horizon. This material was left over from 

Halliburton‘s April pre-job testing process. At the time of this writing, the federal government 

had taken custody of the material and was holding it pending laboratory testing. Industry experts 

have informed the Chief Counsel‘s team, however, that the dry blend material has probably 

chemically degraded by now to the point where any laboratory testing results would be 

inconclusive. If this is the case, Halliburton‘s four pre-blowout tests and the Commission‘s nine 

post-blowout tests are the most probative information regarding the performance of the Macondo 

cement slurry.

Halliburton May Not Have Reviewed the April 18 Test Results 

Before Beginning the Cement Job

Currently available data lead the Chief Counsel‘s team to conclude that Halliburton did not fully 

review its April 18 foam stability tests before pumping the Macondo cement job. While 

Halliburton states that its personnel completed the test at approximately 4:14 p.m. on April 19, it 

has provided neither documentary nor testimonial evidence to show that its personnel actually 

reviewed that data before pumping the job or communicated it to anyone at BP. 

Once again, the Chief Counsel repeatedly offered Halliburton opportunities to produce witnesses

with relevant knowledge to be examined by the Chief Counsel. Halliburton consistently refused to 

support its lawyers‘ assertions with sworn testimony or additional documentation.

Even if Halliburton did review final test results before pumping the cement job, it did not 

transmit those results to BP until April 26—six days after the blowout.59 On that date, Jesse 

Gagliano sent BP an official laboratory data report containing the results of the second April foam 

stability test. Halliburton never sent BP the results of the April 13 foam stability test.

Halliburton Should Have Redesigned the Slurry Before 

Pumping It

Halliburton personnel should have redesigned the Macondo slurry before pumping it. Richard 

Vargo, a Halliburton cementing expert who testified at the Commission‘s hearings on November 
122 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

8, 2010, appears to agree. He testified: ―I don‘t think at this point I would choose to run 

this slurry.‖60

Table 4.4.1 summarizes Halliburton‘s internal laboratory data concerning the stability of the 

Macondo cement slurry. 

Table 4.4.1

Test ID

Apparent 

Date

Target 

Density 

in ppg

Top 

Density 

in ppg

Bottom 

Density 

in ppg

Retarder 

Concentration 

in gal/sack

Conditioning 

Time in Hours

Stable?

Available 

Before 

Job?

Sent to 

BP 

Before 

Job?

65112/1 Feb. 13 14.5 16.8 17.6 0.20 0:00 Unstable Yes No

65112/3 Feb. 17 14.5 15.9 15.9 0.20 2:00* Unstable Yes Yes

73909/1 Apr. 13 14.5 15.7 15.1 0.08 1:30 Unstable Yes No

73909/1 Apr. 18 14.5 15.0 15.0 0.09 3:00 Arguable Uncertain No

* Reported to BP as 0:00

Halliburton personnel should have redesigned the cement slurry design after receiving the 

February pilot test results. Both of the February foam stability tests clearly indicated that the 

pilot cement design was severely unstable. 

Halliburton has repeatedly argued that these pilot tests do not reliably predict the stability of the 

cement system used during the Macondo cement job. Specifically, Halliburton notes that the final 

cement design was different and that the final well conditions differed from BP and Halliburton‘s 

assumptions in February.61 

These facts are irrelevant to the question of whether Halliburton should have redesigned its 

slurry. The pilot test results showed that Halliburton‘s then-current design would be unstable 

under BP‘s then-available predictions of well conditions.62 This should have led Halliburton to 

inform BP of the problem and to redesign the slurry as necessary. Instead, the Chief Counsel‘s 

team has found nothing to suggest that Halliburton personnel seriously considered the issue.

Halliburton missed another clear warning in April. The April 13 foam stability test data should 

again have prompted Halliburton to inform BP of stability problems and to redesign the slurry 

immediately. Halliburton personnel have since testified that they would not use a slurry that 

generated such test results.63 

Halliburton contends that its laboratory personnel conducted the April 13 test improperly and 

that the results are therefore ―irrelevant.‖64 Halliburton cites a laboratory document to support 

this conclusion, but the Chief Counsel‘s team and an independent cementing expert were unable 

to confirm the conclusion merely by reviewing that document. The Chief Counsel asked 

Halliburton to provide witness testimony to support this assertion, but Halliburton declined.

Even if Halliburton personnel did conduct the April 13 test improperly, this is again irrelevant to 

the question of whether Halliburton should have redesigned the slurry. As of April 15, the only

data Halliburton had in hand predicted that the Macondo slurry design would be unstable, and 

Halliburton had very little time before it would have to pump the cement job. Under the 
Chief Counsel’s Report — Chapter 4.4: Foamed Cement Stability | 123

circumstances, Halliburton should have immediately redesigned the slurry and immediately 

retested the new design. It appears that some Halliburton personnel recognized the problem and 

responded by rerunning the test two days later with additional conditioning time, perhaps hoping 

for a more favorable result. But that response was wholly inadequate given how soon the job was 

to be pumped and the fact that the April 13 test results were consistent with the two earlier 

February test results. On April 15 or shortly thereafter, Halliburton should have immediately 

alerted BP to the stability problem and immediately begun redesigning the Macondo slurry. 

The Chief Counsel‘s team is not certain why Halliburton chose not to redesign its slurry. There 

are at least two possible explanations. One is that the Halliburton personnel who were 

responsible for approving or recommending the design were unaware of the foam stability test 

results or their importance. The other is that those personnel were aware of the results but did 

not consider them sufficiently problematic.65 

Management Findings

Halliburton Mismanaged Its Cement Design and 

Slurry Testing Process 

The number and magnitude of errors that Halliburton personnel made while developing the 

Macondo foamed cement slurry point to clear management problems at that company. 

In addition to the errors described above, the Chief Counsel‘s team believes that 

Halliburton personnel:

 began pumping the Macondo job without carefully reviewing laboratory foam stability 

data and without solid evidence that the foamed cement design would be stable; 

 reported foam stability data to BP selectively, choosing in February not to report the more 

unfavorable February 13 test, and choosing in April not to report the more unfavorable 

April 15 test result (although Halliburton contends these results were erroneous); 

 selected the pre-test conditioning time informally, choosing different conditioning times 

(ranging from no time to three hours) in each of the four foam stability tests without any 

stated explanation; 

 assumed, without apparent scientific basis, that conditioning the base slurry before 

foaming was scientifically equivalent to foaming the cement then pumping it down the 

well; and

 recommended a cement design without conducting any formal internal review of that 

design. Notably, the only design element that Halliburton manipulated between 

February and April was retarder concentration, even though BP‘s well design changed 

significantly during that period and even though bottomhole well conditions were 

unknown in February. Halliburton has provided no evidence that a supervisor or senior 

technical expert ever reviewed the final cement slurry design.
124 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

To date, Halliburton has not provided any documents or testimony to suggest that established 

company rules or guidelines prohibited its personnel from doing any of these things. And if such 

guidelines did exist, it appears that Halliburton failed to enforce them on the Macondo job. 

Halliburton’s Lab Report Format Complicated Data Evaluation

Halliburton‘s lab reports to BP were highly technical. As with its modeling runs, discussed in 

Chapter 4.3, Halliburton did not provide a summary of results, an overall assessment of slurry 

design, or even reference values for any of the laboratory data it provided to BP. Halliburton 

could have improved the value of the reports by, for instance, inserting its criteria for a successful 

foam stability test alongside the reported foam stability data. This would not only have helped BP 

personnel understand the significance of relatively obscure numerical data, but might also have 

helped Halliburton personnel do so as well. 

BP Did Not Adequately Supervise Halliburton’s Work

BP technical guidance documents for cementing emphasize the importance of timely cement 

testing,66 and BP Macondo team members themselves recognized that timely cement testing was 

important.

67 The team also expressed internal concern well before the blowout that Jesse 

Gagliano was not providing ―quality work‖68 and was not ―cutting it‖69 by waiting too long to start 

important tests. They had already asked Halliburton to reassign Gagliano, and Halliburton had 

apparently agreed to do so.70 But while BP engineers discussed ―how to handle Jesse‘s interim 

performance‖ by email on the very day of the blowout,71 they did not double-check his work or 

supervise him more closely pending his replacement. 

In particular, although BP personnel recognized the ―significant stability challenges‖ of using 

foamed cement for the Macondo production casing,72 and that changes to the retarder 

concentration in the cement design might increase the risks of foam instability,73 BP does not 

appear to have insisted that Halliburton complete its foam stability tests—let alone report the 

results to BP for review—before ordering primary cementing to begin.74 When asked why, a BP 

representative said, ―I think we didn't appreciate the importance of the foam stability tests.‖75

BP also did not adequately supervise the slurry design process or review earlier test results.76 BP 

documents show that its engineers questioned Gagliano‘s slurry recipes in other instances.77 But 

the Chief Counsel‘s team found nothing to suggest that BP questioned the Macondo slurry recipe, 

even after the slurry failed to perform properly during the cement job for the 16-inch casing 

string. (A BP engineer explained that Halliburton dismissed the failure as the result of cement 

contamination and noted that this is a typical response for any cementing contractor.)78 While 

the Macondo team consulted its in-house cementing expert on other issues, they did not ask him 

to review the foamed slurry recipe.79 The expert raised several concerns as soon as he reviewed 

the recipe after the incident—among other things, he expressed surprise that the slurry design did 

not include a fluid loss additive and did include a defoamer additive.80 

BP‘s failures are especially troubling because it had previously identified several relevant areas for 

concern during a 2007 audit of Halliburton‘s capabilities. In that year, BP hired Cemtech 

Consulting to review a Halliburton foamed cement job on the Na Kika project in the Gulf of 

Mexico.

81 Cemtech‘s report identified several issues that mirror problems at Macondo. For 

instance, Cemtech observed that Halliburton‘s initial foamed slurry design at Na Kika ―had 
Chief Counsel’s Report — Chapter 4.4: Foamed Cement Stability | 125

tendencies to stratify‖ (that is, was unstable) and required redesign. Cemtech also made broader 

observations such as:

 ―The HES [Halliburton] Fluids Center chemists and senior lab technicians do a very good 

job of testing cement slurries, but they do not have a lot of experience evaluating data or 

assisting the engineer on ways to improve the cementing program.‖

 ―COMMUNICATION and DATA TRANSFER/DOCUMENTATION could be improved to 

help avoid unnecessary delays or errors in the slurry design testing, data reporting, and 

evaluation of the cement program.‖

 ―Lab reports could be improved! They are difficult to evaluate; often incomplete; and are 

submitted WITHOUT supporting lab charts and DATA to validate the test results. LAB 

DATA SHOULD BE MANDATORY!‖

It does not appear that BP pressed Halliburton or its own Gulf of Mexico engineering teams to 

improve in these areas. 

Chief Counsel’s Report — Chapter 4.5: Temporary Abandonment | 127

Chapter 4.5|Temporary Abandonment

BP developed a temporary abandonment procedure for 

Macondo that unnecessarily introduced significant risks into 

the operation. BP disagrees with this finding and argues 

instead that the specific procedure it used at Macondo was 

necessary under the circumstances.1 The Chief Counsel’s team disagrees. BP 

could have avoided the additional risks created by the procedure by making a few 

simple changes. 

Temporary Abandonment 

Temporary abandonment refers to the procedures that a rig crew uses to secure a well so 

that a rig can safely remove its blowout preventer (BOP) and riser from the well and leave the 

well site. BP planned to have the Deepwater Horizon temporarily abandon the Macondo well 

after the rig finished its drilling operations so that another rig could later move to the Macondo 

site and complete the well construction process. (That rig would perforate the casing and install 

equipment to collect hydrocarbons.) 

Many operators divide operations in this way to save costs; deepwater drilling work requires a 

large and expensive rig like the Horizon, but completion work can be done by a smaller and less 

expensive rig.

There does not appear to be any standard industry procedure for temporary abandonment. 

Instead, different operators perform the process differently based on their internal technical 

guidance, the design preferences of individual engineers, the capabilities of individual rigs, and 

the needs of particular wells.

At the time of the Macondo incident, MMS regulations did impose some important requirements 

on operators that wished to temporarily abandon a well. The regulations specified that the 

operator must set “a retrievable or a permanent-type bridge plug or a cement plug at least 

100 feet long in the inner-most casing” and that the top of the plug must be “no more than 

1,000 feet below the mud line”2

 (as discussed in Chapter 6). Operators typically refer to this plug 

as a surface plug to distinguish it from other plugs that may be set deeper in the well. Despite 

the name, surface plugs are not set at the surface or even at the very top of the well. 
128 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Temporary 

Abandonment 

at Macondo

BP’s temporary abandonment procedure for the Macondo 

well had the following basic sequence:

	run the drill pipe into the well to 8,367 feet below 

sea level (3,300 feet below the mudline);

	displace 3,300 feet of mud in the well with 

seawater, lifting the mud above the BOP and into 

the riser;

	perform a negative pressure test to assess the 

integrity of the well (including the bottomhole 

cement) and ensure that outside fluids (such as 

hydrocarbons) are not leaking into the well; 

	displace the mud in the riser with seawater;

	set the surface cement plug at 8,367 feet below sea 

level; and 

	set the lockdown sleeve (LDS) in the wellhead to 

lock the production casing in place.

This procedure is notable in at least two respects. First, 

it called for rig personnel to set a surface plug deep in the 

well, 3,000 feet below the mudline. (BP requested and 

obtained authorization to depart from MMS regulations 

in order to do this.) Second, the procedure called for rig personnel to displace the wellbore and 

riser to seawater before setting the surface plug. 

After the incident, the BP Macondo team uniformly explained that it developed its particular 

temporary abandonment procedure in order to set a lockdown sleeve during temporary 

abandonment and to do so as the last step in the process.3

 The lockdown sleeve decision 

triggered a cascade of derivative decisions regarding the temporary abandonment procedure that 

are summarized here and described in greater detail below. 

	BP engineers decided to set the lockdown sleeve during temporary abandonment 

because the Deepwater Horizon could do that job more quickly and efficiently than a 

completion rig. 

	Having decided to set the lockdown sleeve during temporary abandonment, BP 

engineers wanted to ensure that other temporary abandonment operations would not 

damage the sleeve. To address this concern, they decided to set the sleeve last.4 

Figure 4.5.1. Planned configuration after 

temporary abandonment.

TrialGraphix

After finishing cementing the production casing (left), the 

rig crew began temporary abandonment procedures that 

would have allowed the Deepwater Horizon to remove its 

riser and BOP from the well and move on to another job 

(right). The blowout occurred before the rig crew set the 

cement plug and lockdown sleeve.

3,300' 

of Mud 

Removed

5,067' Below 

Sea Level

8,367'

Cement 

Plug

Lockdown Sleeve

(Simplified)

Mud
Chief Counsel’s Report — Chapter 4.5: Temporary Abandonment | 129

	Deciding to set the sleeve last then drove 

BP’s decision to set its “surface” cement plug 

unusually deep in the well. The process of 

setting the Macondo lockdown sleeve would 

require the rig crew to press (or pull) down on 

the sleeve with 100,000 pounds of force. The 

Macondo team chose to generate that force by 

hanging close to 3,000 feet of drill pipe below the 

lockdown sleeve.5 In order to leave room for that 

length of drill pipe, BP needed to set the surface 

cement plug even farther down, from 3,000 to 

3,300 feet below the mudline.6

	Deciding to set the cement plug deep in the well 

in turn led BP engineers to decide to remove a 

great deal of drilling mud from the well during 

temporary abandonment. The Macondo team 

believed that cement plugs set up better in 

seawater than in mud.7 To set the deep cement 

plug in seawater, the team instructed the rig 

crew to replace 3,300 feet of mud in the well 

with seawater before setting the plug.8 

Lockdown Sleeve. BP planned to set a lockdown sleeve during its temporary abandonment 

procedure at Macondo. A lockdown sleeve is a piece of equipment that is installed in 

the wellhead to guard against uplift forces that may be generated during the production 

of hydrocarbons at a well. The sleeve locks the production casing hanger and seal 

assembly to the high-pressure wellhead housing so that the forces generated during 

hydrocarbon production do not lift the casing hanger and seal assembly out of place.

Operators do not normally set lockdown sleeves during temporary abandonment.9

 They normally 

set lockdown sleeves later in the life of a well.10 BP decided to set the lockdown sleeve during 

temporary abandonment because it believed that a drilling rig, such as the Marianas or Deepwater 

Horizon, could do this job more quickly and at a lower cost than a completion rig.

This series of design decisions ultimately led BP to instruct the Deepwater Horizon crew to 

replace 8,367 feet of drilling mud from the riser and well with lighter seawater before setting any

additional mechanical barriers in the well, such as the surface cement plug. 

Decision to Set Lockdown Sleeve During 

Temporary Abandonment

Lockdown sleeves need not be set during temporary abandonment. Indeed, the Macondo team 

originally planned to leave the job for a completion rig.11 

Figure 4.5.2. Lockdown sleeve. 

TrialGraphix

BP’s desire to set a lockdown sleeve 

during temporary abandonment drove 

the development of its temporary 

abandonment procedure. The 

lockdown sleeve locks down the casing 

hanger and seal assembly.
130 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

BP decided to set the lockdown sleeve during temporary 

abandonment because it believed that a drilling rig 

could do this job more quickly and at lower cost than 

a completion rig. As Chapter 3 discusses, BP began 

drilling Macondo with Transocean’s Marianas rig. BP’s 

subsea wells team (Figure 4.5.3) accordingly developed 

a lockdown sleeve setting procedure in October 2009 

for the Marianas.

12 They reviewed the procedure on 

November 10, 2009, with Dril-Quip representative 

Barry Patterson.13 Two days later, BP subsea wells 

engineer Brad Tippetts sent a request to Patterson for 

the information necessary to develop a final lockdown 

sleeve setting procedure.14 Patterson included BP 

drilling engineer Brian Morel in this initial November 

conversation, but it does not appear that Morel 

participated or responded.15 

After BP decided that the Deepwater Horizon would 

replace the hurricane-damaged Marianas, BP engineers 

developed a revised drilling program. On December 31, 

BP subsea wells team leader Merrick Kelley checked in 

to ask if the Macondo engineering team still planned 

to install the lockdown sleeve as part of its new drilling 

program.16 Senior drilling engineer Mark Hafle said no: 

“We do not plan on installing lock down sleeve with 

the Horizon.”17 

Kelley responded by noting the time (and hence money) 

that BP could save by setting the lockdown sleeve with 

the Horizon. He explained that setting the lockdown 

sleeve during temporary abandonment “saves an incremental 5.5 days of rig time on the back 

side” and, with it, more than $2 million.18 (Doing the job with a completion rig would take seven 

days, whereas the Horizon could do the job in 1.5 days during temporary abandonment.19) Hafle 

discussed the issue with BP drilling and completions operations manager David Sims,20 and the 

Macondo team eventually decided to set the lockdown sleeve using the Horizon. 

The Macondo team also considered an open water lockdown sleeve installation, in which a boat 

would set the lockdown sleeve using ROVs.21 The open water installation process would save 

$120,000 in additional costs over having the Horizon do the installation.22 But it also presented a 

greater risk of damaging the lockdown sleeve.23 Kelley therefore recommended against it: 

“At the end of the day it boils down to the amount of risk we are willing to take to potentially save 

$120,000 by using a boat. To be honest and frank with you, performing this operation from the 

rig is the easiest and simplest way I know to install a[n] LDS.... For my money, it is just the right 

thing to do....”24 

Figure 4.5.3. BP subsea wells organization.

TrialGraphix

Merrick Kelley

Subsea Wells 

Team Leader

Subsea Wells Team

Shane Albers

Subsea Wells 

Engineer

Ross Skidmore

Subsea Wells Supervisor 

(Contractor)

Brad Tippetts

Subsea Wells Engineer
Chief Counsel’s Report — Chapter 4.5: Temporary Abandonment | 131

Ultimately, the Macondo team decided to set the lockdown sleeve with the Horizon during 

temporary abandonment.25 

Development of the Lockdown Sleeve Setting Procedure

Finalizing the procedure for setting the lockdown sleeve was a necessary first step in developing 

the overall temporary abandonment procedure. The Macondo team did not finalize its lockdown 

sleeve setting procedure until very late in the drilling process. Indeed, as late as mid-April, the 

Macondo team was still reconsidering its decision to have the Horizon set a lockdown sleeve 

at all. 

On April 8, 2010, Patterson again sent Morel the information about setting the lockdown sleeve 

that Morel had first received five months earlier.26 Morel reviewed the procedure later that day.27 

Four days later, on April 12, BP well site leader Murry Sepulvado asked Morel via email for the 

temporary abandonment procedures (among other things), saying that rig personnel were “in 

the dark and nearing the end of logging operations.”28 Morel emailed BP subsea wells engineers 

Shane Albers and Tippetts to ask for a lockdown sleeve running procedure: “I need a procedure 

this morning, do you have one available?”29 Tippetts responded five minutes later by attaching 

the detailed lockdown sleeve setting procedure that the subsea team had originally written for 

the Marianas. Tippetts said, “this should do for now,” but noted that Albers was modifying the 

procedure “slightly” for the Horizon and that Albers “will send out the updated version later 

today.”30 Morel told Sepulvado, “I will have you something this morning.”31 

Later in the afternoon of April 12, Morel asked Kelley via email when BP would be setting a 

lockdown sleeve at Isabela, another BP well.32 Morel knew that BP planned to set the Isabela 

lockdown sleeve using open water installation tools. Morel’s question therefore suggests that he 

(and perhaps the Macondo team) was still considering another option for setting the lockdown 

sleeve—namely, using the open water tools that BP would use at Isabela instead of using the 

Horizon. But late that night, Kelley advised Morel and Hafle against that approach. Kelley said 

that the subsea team would not make it a priority to “combine the Isabela and Macondo lock 

down sleeve jobs.” Kelley also warned that others in BP might challenge a decision to use open 

water tools to set the lockdown sleeve in order to save just 24 hours of rig time.33 

Morel did not send out a final updated procedure on April 12. Instead, after the close of business 

on April 13, Morel sent BP wells team leader John Guide the Marianas procedure, with the 

caveat that the subsea wells engineers “are updating for the Horizon, but mostly will remain 

the same.”34 A little less than an hour later, at 6:50 p.m. on April 13, Albers sent Morel the final 

updated procedure.35 

Numerous Last-Minute Changes During the Final Development 

of the Temporary Abandonment Procedure

In the nine days before BP began the temporary abandonment of the Macondo well, the company 

went through at least four different versions of temporary abandonment procedures.36 Each 

version switched the order of several key steps. 

April 12 Well Plan

In response to the April 12 prodding from Murry Sepulvado, Morel circulated a draft plan 

for upcoming operations at Macondo later that day.37 The draft plan included temporary 
132 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

abandonment procedures that instructed the rig crew to set the lockdown sleeve first and then to 

set a surface cement plug in seawater. The plug would be set just 933 feet below the mudline.38 

Morel’s draft did not include a negative pressure test. After reviewing it, well site leader Ronnie 

Sepulvado reminded Morel that he needed to include a negative pressure test.39

April 14 Morel Email

Two days later, Morel sent out a procedure that was different in several important respects.40 

First, the new procedure stated that BP would set the cement plug first and then set the 

lockdown sleeve. 

Second, Morel changed the depth of the cement plug in order to create the clearance necessary to 

set the lockdown sleeve. Morel moved the cement plug from 933 feet below the mudline to 

3,300 feet below the mudline. 

Third, Morel changed the procedure so that the rig crew would set the surface cement plug in 

drilling mud instead of seawater. 

Fourth, Morel included a negative pressure test. Morel’s procedure instructed the rig crew 

to perform the test “with base oil in kill/choke line to the wellhead.”41 Using base oil for a 

negative pressure test is a normal industry practice. Filling the choke or kill lines with base oil 

can simulate the pressure effects of displacing drilling mud in the riser and some portion of the 

wellbore with seawater without actually displacing any mud. This is because base oil is lighter 

than seawater. Morel presumably included this step to account for the new procedure to displace 

a large amount of mud from the wellbore before setting the surface cement plug. (Interestingly, 

Figure 4.5.4. Multiple last-minute revisions to the temporary abandonment procedure.

TrialGraphix
Chief Counsel’s Report — Chapter 4.5: Temporary Abandonment | 133

the procedure called for the negative pressure test to be done after the cement plug had been 

set,42 so that the test would examine the quality of the cement in the surface plug rather than the 

bottomhole cement.)

April 15 Well Plan and April 16 MMS-Approved Procedure

By April 15, with the approval of Guide and drilling engineering team leader Gregg Walz, Morel 

changed the plan again in at least two important respects.43 

First, Morel’s new plan required rig personnel to conduct a negative pressure test before setting 

the surface cement plug, so that the test would check the integrity of the bottomhole cement.44 

Second, the new plan called for the rig crew to displace the riser to seawater immediately after 

conducting the negative pressure test.45 Morel apparently made this change because one of the 

well site leaders had asked to set the cement plug in seawater.46 

The Macondo team clearly recognized that its plan called for an unusually deep cement plug. 

Morel included an alternative plan with a shallower plug in the event that MMS did not approve 

the deep plug.47

Morel and Hafle worked together to develop an application for an MMS permit allowing the team 

to use the “deep plug” option. As part of that application, filed on April 16, Morel listed BP’s 

planned temporary abandonment procedure and included a negative pressure test (even though 

MMS regulations did not require a negative pressure test, as discussed in Chapter 6). That test 

would now be conducted “with [the] kill line”—yet another change in the procedure.48 MMS 

approved the permit application—and with it, BP’s plan to use a deep plug—in less than 

90 minutes.49 

The language in BP’s April 16 permit application describing the negative pressure test and 

displacement procedure was unclear. Some have said that the language, like that in the April 15 

well plan, required BP to conduct its negative pressure test before displacing mud in the well with 

seawater.50 Others have said (after the blowout) that the only sensible time to do the negative 

pressure test would have been after the rig crew displaced the mud beneath the wellhead with 

seawater to the depth of the cement plug.51 This argument may be important; if the former 

interpretation is correct, the rig crew did not adhere to the approved MMS procedure.52 In any 

event, the debate highlights the lack of specificity in the permitted language.

After MMS approved the temporary abandonment procedure, Morel realized there was a problem. 

By planning to set its surface cement plug very deep in the well and set it in seawater, BP would be 

severely underbalancing the well during temporary abandonment. BP could not generate enough 

differential pressure to simulate those conditions merely by pumping base oil through the kill 

line down to the wellhead. Accordingly, the base oil negative pressure test procedure would not 

constitute a proper negative pressure test of the system.53 

The solution, as the drilling team saw it, was to conduct two negative pressure tests. The rig 

would conduct the first test as planned, with base oil to the wellhead before displacement to 

8,367 feet. They would conduct the second test after that displacement.54

April 20 “Rig Call” and Morel “Ops Note”

The Macondo team had still not resolved the negative pressure test procedures even during the 

7:30 a.m. “rig call” between the rig crew and shoreside personnel on April 20—the day of the 

blowout. The rig crew asked wells team leader Guide how they were supposed to run the negative 
134 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

pressure test. Guide responded that he would confer with the engineers onshore and get back

to them.55 

Guide decided that the crew would conduct only one negative pressure test. There would be no 

“first” test using base oil in the kill line. Instead, there would be a single test midway through the 

displacement at 8,367 feet. It is difficult to determine whether there was significant disagreement 

with this decision. Hafle stated that there was “some discussion but [that] John Guide [was] 

hard to argue with” and that “Walz was in discussion but didn’t argue with John.”56 Morel (who 

was visiting the rig) stated that the well site leaders did not have strong opinions either way.57 

According to Guide, however, there was never any plan to perform more than one negative 

pressure test.58 

Three hours after the rig call, Morel sent an “Ops Note” to the shoreside team and well site 

leaders. The Ops Note reflected the Macondo team’s final changes to the temporary abandonment 

procedure.59 The first time the rig crew saw the procedure was during the 11 a.m. pre-tour 

meeting on April 20.60 

Whereas BP’s April 16 submission to MMS may have stated that rig personnel would conduct the 

negative pressure test before displacement, the April 20 Ops Note directed the crew to conduct 

the negative pressure test midway through the displacement process.61 The rig crew would first 

displace mud with seawater from beneath the wellhead to 8,367 feet. The crew would then 

conduct the negative pressure test on the kill line. After the test, the crew would displace the mud 

remaining in the riser and then set the cement plug.62 Like the other procedures, the Ops Note 

lacked basic information about how the negative pressure test was to be conducted.63 

The Macondo team apparently recognized that conducting a negative pressure test midway 

through displacement (rather than before displacement) was different from the procedure 

MMS had approved. But BP decided not to notify MMS of the change or seek further MMS 

approval.64 According to members of the Macondo team, such notification and further approval 

were unnecessary because conducting the negative pressure test during displacement would be 

a more rigorous test than conducting it beforehand.65 This explanation is called into question by 

the fact that BP did seek MMS approval before making a similar change in a negative pressure test 

procedure during temporary abandonment operations in 2006.66

According to BP well site leader Bob Kaluza, Hafle called him on the afternoon of April 20 to 

discuss the Ops Note. Hafle had been away on vacation while the rest of the shoreside team had 

put together the procedures in the Ops Note. Reviewing it, Hafle was concerned that the Ops 

Note procedure was different than the procedure MMS had approved. Kaluza woke up Morel. 

Morel explained that the rest of the shoreside team had decided to “deviate” from the procedure 

in the MMS-approved permit, which called for conducting the negative pressure test before 

displacement. “The team in town wanted to do something different,” Kaluza later explained 

according to notes of BP’s post-blowout interviews. “They decided we could do the displacement 

and negative test together – don’t know why – maybe trying to save time.... Anytime you get 

behind, they try to speed up.”67

It is impossible to know whether the changes to the negative pressure test procedure (including 

elimination of a second negative pressure test at a different depth) contributed to the blowout. As 

Chapter 4.6 explains in detail, personnel on the Deepwater Horizon missed clear warning signals 

from the negative pressure test they did conduct. Conducting an earlier version of the test may 

have removed one of the factors confounding successful interpretation of the test and eliminated 

the crew’s erroneous explanation for the warning signals they observed.68 And conducting a 
Chief Counsel’s Report — Chapter 4.5: Temporary Abandonment | 135

second test at a different depth might have given the rig crew another opportunity to recognize 

those signals. 

Technical Findings

BP’s Temporary Abandonment Procedure Created 

Significant Risks

BP’s design decisions had significant consequences and increased the risks associated with the 

temporary abandonment at Macondo in several important ways. 

First, the procedures created a severe hydrostatic underbalance in the well. By requiring the rig 

crew to remove so much mud from the wellbore during temporary abandonment, BP’s procedures 

greatly reduced the balancing pressure that the mud column in the wellbore exerted on the 

hydrocarbons below. This increased stress on the bottomhole cement.69 While temporarily 

abandoning a deepwater well typically involves placing some amount of stress on the bottomhole 

cement, BP’s procedures stressed the cement more than usual70—to an extent never before seen 

by many in the industry.

71

Second, the procedures led the rig crew to conduct riser displacement operations with only one 

physical barrier in the well (the bottomhole cement) and only one backup barrier (the BOP).72 

That backup barrier, in turn, was highly dependent on well control monitoring. As a result, 

BP’s temporary abandonment procedure placed a high premium on kick detection and response 

during the displacement.

73 Unless the rig crew recognized a kick, they could not activate the BOP 

in time for it to function as a barrier.

Third, and as a result, the procedures placed a high premium on the integrity of the bottomhole 

cement and the negative pressure test that evaluated it.

74 Rig personnel could not rely on the 

bottomhole cement as a barrier until it had been verified, and the only procedure BP planned to 

use to verify the cement’s integrity was the negative pressure test. 

BP Did Not Need to Set a Lockdown Sleeve as the Last Step in 

Temporary Abandonment 

As explained above, BP made many of its procedural decisions regarding temporary abandonment 

based on its decision to set a lockdown sleeve during the temporary abandonment phase of the 

well. BP did not need to set a lockdown sleeve during the temporary abandonment phase. The 

fact that BP nevertheless chose to do so is not problematic in itself. Indeed, locking down the 

casing earlier rather than later can increase safety by mitigating against potential uplift forces 

during drilling and abandonment (explained in Chapter 4.1). But BP increased overall risks by 

deciding to set the lockdown sleeve last in the temporary abandonment sequence. 

A lockdown sleeve need not be set last in the temporary abandonment sequence. It can be set 

in mud prior to displacement and setting of the surface plug.75 This is commonly done in the 

industry,76 and BP engineers considered doing it this way at Macondo.77 
136 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Outer Lock Ring. Setting a lockdown sleeve before temporary abandonment can reduce the risk 

that underbalancing a well might lift the production casing out of place in the wellhead. Another 

mechanism for locking a production casing in place is an outer lock ring. Rig personnel can 

install an outer lock ring when they first set the casing in place. While this was not a common 

practice at the time of the Macondo incident,78 some industry experts have recommended that 

it become standard.79

Indeed, the Macondo team initially planned to set the lockdown sleeve in mud, before setting 

a shallow surface cement plug in seawater. In a March 3 email, Hafle stated that the team 

would “set the plug after [lockdown sleeve] installation”; with no plug in the way, they could 

easily “supply the correct weight for installation.”80 On April 8, Morel checked with Dril-Quip 

representative Barry Patterson to make sure the lockdown sleeve procedure was compatible with 

“100,000 lbs air weight in 14.0 ppg mud.”81 On April 12, Morel emailed Tippetts to confirm that 

the plan was “to still have mud in the riser and wellbore when we set the LDS.”82 Subsea well 

supervisor Ross Skidmore preferred to set the lockdown sleeve in mud because the hole would be 

in its cleanest state at that point.83 

As described above, by April 14, BP had changed its plan so that it would run the lockdown sleeve 

last, after setting a surface plug and displacing the riser to seawater.84 When Skidmore heard 

about the change, he approached one of the BP drilling engineers on the rig and expressed his 

preference to set the lockdown sleeve in mud; the engineer indicated the decision had come from 

personnel onshore and was final.85 

BP Did Not Need 3,000 Feet of Drill Pipe Below the 

Wellhead to Achieve the 100,000 Pounds Necessary 

to Set the Lockdown Sleeve

BP did not need to use 3,000 feet of drill pipe in order to generate the 100,000 pounds of 

downward force necessary to set the lockdown sleeve. Instead, BP could have instructed the rig 

crew to hang a much shorter length of pipe that included drill collars (a heavier type of drill 

pipe). Because drill collars are much heavier than other drill pipe, the crew could have used a 

much shorter length of them to generate the same downward force. BP could also have instructed 

the rig crew to generate some of the setting force using weight pushing down from above the 

running tool instead of hanging below it.86 Using these methods, BP could have set the lockdown 

sleeve in place without requiring 3,000 feet of clearance beneath the sleeve, as called for in its 

final plan.87 

BP engineers were well aware that they did not have to set the lockdown sleeve using 3,000 feet 

of hanging drill pipe. BP had previously set a lockdown sleeve with the same running procedures 

and weight requirement (100,000 pounds) at another well in the Gulf of Mexico, in Mississippi 

Canyon Block 129.88 BP used drill collars at that well to generate the required setting force89

and was thus able to set its surface plug only 1,600 feet below the mudline.90 Similarly, BP 

set a lockdown sleeve with an even greater force requirement (125,000 to 135,000 pounds) in 

Mississippi Canyon Block 777.91 There again, BP used drill collars to generate the required setting 

force and set a surface plug 1,500 feet below the mudline.92 Such depths were more typical for 

pre-lockdown sleeve plugs.93 

At one point, the Macondo lockdown sleeve was supposed to be set in much the same manner.94 

As far back as November 12, 2009, the Macondo team had planned to run drill collars beneath 
Chief Counsel’s Report — Chapter 4.5: Temporary Abandonment | 137

the lockdown sleeve in order to achieve the necessary setting weight.95 That was still the plan 

on February 3 when the lockdown sleeve setting procedure was submitted for inclusion in the 

Macondo well planning spreadsheet.96 But by March 2, Hafle had told Tippetts, “Here’s the final 

plan.... We will not be using any drill collars. The rig has 5-1/2'' [heavyweight drill pipe] and 

we will rent additional 5-1/2'' [heavyweight drill pipe] to have 100k buoyed weight below” the 

lockdown sleeve.97 

Despite Hafle’s email, BP obtained drill collars and had them on the rig by April 17.98 As late as 

April 12, Walz mentioned using drill collars to set the lockdown sleeve in an email to Morel,99 and 

Morel included them in the April 12 drilling program.100 The last final updated procedure that 

Albers sent to Morel on April 13 also included drill collars.101 But by the time drill collars arrived 

on the rig, Morel had changed the procedures to specify a deep surface plug, 3,000 feet below 

the mudline, which suggests that he had not envisioned using drill collars to set the lockdown 

sleeve.102 According to BP wells team leader Guide, the team changed the plan because the rig 

already had heavyweight drill pipe “racked back” and ready to run into the well.103 In order to use 

drill collars at that point, the rig would need to make up each piece of pipe individually, which 

would take time and add to the general risk of personal injury.104 

BP Could Have Set Its Surface Cement 

Plug in Mud Instead of Seawater

BP did not have to 

displace mud from the 

well and riser in order 

to set a cement plug; 

it could have set the 

cement plug in drilling 

mud instead. 

Surface cement plugs 

can be set in mud just 

as they can be set in 

seawater.105 Setting a cement plug in mud can present a risk 

of contamination and certain other chemical complexities.106 

But contamination issues can exist with cement plugs set 

in seawater as well,107 and the complexities can be managed 

with proper cement slurry design and the use of spacer.108 

In order to help ensure that cement plugs set in drilling mud 

are secure, engineers also use mechanical retainers or 

bridge plugs—metal and rubber devices that fit into the 

casing and hold the cement,109 as shown in Figure 4.5.5. The 

mechanical plug then serves as an additional barrier, apart 

from the cement it helps to set.110 

BP generally, and the Macondo team specifically, were 

familiar with these options.111 When an earlier surface 

cement plug at Macondo failed to set up, Morel and another 

BP engineer involved with the earlier plug discussed how 

“the biggest single factor for plug success is having a good 

base.”112 The engineers discussed how they could design that base by several means, including 

by contrasting fluid densities (lighter cement on heavier drilling fluid) and by using mechanical 

Figure 4.5.5. Bridge plug. 

TrialGraphix

BP could have used a 

mechanical plug in lieu of or 

in addition to a cement plug.

Cement 

Plug

Bridge 

Plug
138 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

devices (retainers and bridge plugs).113 Another engineer involved with the earlier plug 

commented, “We need to get better at setting plugs regardless of the method.”114 

BP representatives have acknowledged that surface cement plugs can be set in mud115 and that 

doing so is not a mistake.116 Indeed, BP has set surface cement plugs in mud before117 and 

apparently considered doing so at Macondo as late as April 14.118 BP has also frequently made use 

of mechanical devices for surface plugs, including both drillable and retrievable bridge plugs.119 

In fact, BP engineers affirmatively considered running a mechanical plug at Macondo—

specifically, a Baker Hughes model GT retrievable bridge plug.120 The GT plug was much more 

expensive than a cement plug, but Morel preferred it (at least initially) because of its greater 

reliability. In an email to Hafle and others, he noted: “If Baker’s GT plug wasn’t available, 

we would either set a cement plug in its place or a Halliburton Fast Drill plug. Both are much 

cheaper options, but leave us with potential issues during the completions. They could 

potentially cost us more as well, because extra rig time might be involved with removing these 

type of plugs.”121 

BP engineers planned at various points to use a GT plug at Macondo.122 The Macondo team would 

have rented that plug pursuant to a long-term GT plug rental contract that BP was arranging 

with Baker Hughes for several wells at the same time.123 Because the BP personnel arranging 

the contract believed there was a “high probability of a long term installation of this plug at 

Macondo,” they affirmatively committed to the rental.124 BP initiated rental of the Macondo plugs 

on April 6.125 The company paid $42,902 to Baker Hughes to make up, test, and keep a primary 

and backup GT plug on standby.126 

On April 9, a Baker Hughes representative emailed Morel and Hafle to ask for an update on 

whether BP had decided to use the standby plug or not.127 Morel responded with additional 

details but still no final decision: “If we need it, the rig will probably want to call it out next 

weekend or early the following week (18-19th of April). I will keep you informed.”128 Morel 

explained that the Macondo team would not commit to using the GT plug until it had decided if 

production casing was required.129 But by April 12, two days before finalizing the decision to run 

production casing, the Macondo team decided to use a plain cement surface plug.130 When the 

Baker Hughes representative emailed the two BP engineers again on April 19 to ask if they would 

need the plug he had kept on standby “since early April,”131 Hafle responded, “We will be setting a 

cement plug instead.”132 Baker Hughes stopped the rental.133 

It is not clear why the Macondo team chose to set a plain cement plug. Morel told one engineer 

that the reason was cost:134 “Plan is to set a cement plug instead of running the GT plug as 

it doesn’t cost us anything to leave it in the hole.”135 Morel told another set of engineers (the 

completion engineers) that the reason was risk: The “GT plug poses risks leaving it in the 

wellbore for an unknown amount of time.”136* 

BP Could Have Planned a Safer Temporary Abandonment 

Procedure Even Without Changing Its Design Assumptions 

Even assuming that BP truly had to set the lockdown sleeve last and set its surface cement plug 

*

 Some members of the Macondo team were concerned that leaving a mechanical plug in the well for an 

indefinite period of time might present complications during re-entry and completion. Retrievable plugs 

left in the wellbore for too long can corrode and become difficult to retrieve. Drillable plugs (like cement 

plugs) can produce debris when drilled out. Nevertheless, BP appears to have addressed or accepted these 

complications in other wells where the company set mechanical plugs. Indeed, a BP completion engineer 

reacted to Morel’s email with wonderment: “I am curious about what risks he speaks of with leaving GT 

plugs in place for long periods. We had them in place at Dorado for a couple of years without problems.”
Chief Counsel’s Report — Chapter 4.5: Temporary Abandonment | 139

deep in the well in seawater, BP could have taken at least three measures to mitigate the risk 

created by its unusual procedure. Each of these measures would have increased or improved the 

physical barriers in the wellbore during the displacement. While each would have taken some 

additional time,137 they would have ensured that the cement job at the bottom of the well was not 

the only barrier physically in place during the displacement.

BP Could Have Retained Hydrostatic Overbalance

BP still could have retained hydrostatic overbalance even with the removal of 3,300 feet of mud 

from the wellbore. To do so, they could have replaced the mud at the bottom of the wellbore with 

heavier “kill weight” mud.138 BP engineers should have been familiar with this concept,139 and it is 

a common industry practice.140 In doing so, they would have retained mud as a physical barrier in 

the wellbore during the displacement.141† 

BP Could Have Set Intermediate Plugs

BP could have set additional plugs between the bottomhole cement and the surface plug.142 BP 

engineers were familiar with this option, as the company had set multiple intermediate plugs 

(often including mechanical plugs) on previous wells.143 Indeed, some in the industry treat the 

setting of intermediate plugs as standard practice.144 But it appears that the Macondo team never 

considered it.145 Setting intermediate mechanical or cement plugs would have increased the 

number of physical barriers in the wellbore during the displacement.

BP Could Have Conducted the Displacement (of Both the Wellbore and 

the Riser) With the BOP Closed

BP could have closed an annular preventer (or variable bore ram) before beginning the 

displacement and, in various configurations, then displaced the casing and riser using the 

drill pipe and choke, kill, and boost lines.146 This would have been considered a particularly 

conservative approach in the industry, and unnecessary for most wells.147 But the unusually 

deep cement plug and the uncertain nature of the bottomhole cement job at Macondo warranted 

extra caution.148 Indeed, since the blowout, the industry appears to be moving in the direction 

of making this practice more prevalent.149 Closing the BOP before the displacement would have 

eliminated the BOP’s dependence on human monitoring and thereby converted it into a physical 

barrier in place during the displacement. The well would already have been shut in at the time of 

the kick, enabling the crew to more easily respond to and control the kick.

Management Findings 

BP Failed to Develop Its Temporary Abandonment Procedure in 

a Timely Manner

The moment an operator designs a production well, it can (and should) develop a temporary 

abandonment procedure.150 Even though BP planned Macondo as a production well from the 

start,151 it did not include temporary abandonment procedures in its initial drilling program.152 

†

 BP wells team leader John Guide suggested that for some wells underbalance is necessary because mud is 

simply not heavy enough to compensate for the loss of the riser. That was not true of the Macondo well. To 

be sure, if BP had insisted on using only one plug and setting that plug at 3,300 feet below the mudline, then 

replacing just the mud above that plug with kill weight mud would not have prevented underbalance. But 

BP could have set an intermediate plug deeper in the well (about 6,900 feet below the mudline), replaced 

the mud above that deeper plug with kill weight mud, and then set a surface plug higher up in the well. 

Therefore, BP could have left the Macondo well overbalanced by using a combination of kill weight mud and 

intermediate plugs. 
140 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

As early as January 2010, the Macondo team planned to use the Horizon to install a lockdown 

sleeve and then temporarily abandon the well. But the company’s January 2010 drilling program 

still did not include a temporary abandonment procedure.153 By April 9, the Macondo team knew 

the total depth of the well.154 At that point, they had enough information to design a temporary 

abandonment procedure specifically tailored to the final conditions at Macondo.155 But three days 

later, on April 12, the well site leader was forced to ask the shoreside team for procedures himself, 

saying, “we are in the dark and nearing the end of logging operations.”156 

The Macondo drilling team did not begin developing a procedure in earnest until after this 

request. Perhaps because of the delays, the Macondo team changed its procedures repeatedly 

at the last minute, even up until the day the procedure was to begin (the day of the blowout). As 

Walz acknowledged in another context, “planning [was] lagging behind the operations.”157

BP Changed Its Temporary Abandonment Procedure Repeatedly 

at the Last Minute Without Subjecting Those Changes to Any 

Formal Risk Assessment

BP’s temporary abandonment procedures for Macondo changed at least four times over the last 

nine days before the blowout. This was an unusual number of changes so close to the procedure’s 

execution.158 BP also changed its lockdown sleeve setting procedures over time. 

Several of BP’s decisions—not using drill collars, not using a mechanical plug, setting the plug in 

seawater, setting the lockdown sleeve last—may have made sense in isolation. But the decisions 

also created risks, individually and especially in combination with the rest of the temporary 

abandonment operation. For instance, BP originally planned to install the lockdown sleeve at the 

beginning of the temporary abandonment. BP’s decision to change plans and set the lockdown 

sleeve last triggered a cascade of other decisions that led it to severely underbalance the well 

while leaving the bottomhole cement as the lone physical barrier in place during displacement of 

the riser. 

There is no evidence that BP conducted any formal risk analysis before making these changes or 

even after the procedure as a whole.159 For example, on April 15, Morel (who was on the rig at the 

time) emailed the rest of the Macondo onshore engineers about setting a deep plug in seawater: 

“Recommendation out here is to displace to seawater at 8300' then set the cement plug. Does 

anyone have issues with this?”160 The response, from Hafle, was simply: “Seems ok to me.”161 

According to Guide, the team never discussed the risk of having such a deep surface plug.162 

Post-incident interviews with the Macondo team confirm that it made significant procedural 

changes in a relatively casual manner. Walz admitted that there was “no structured approval 

process” and that “changes [were] made with email and verbal discussion.”163 Cocales stated that 

there was “no formal process on communicating changes to [the] well plan.” Murry Sepulvado 

stated that it was not unusual to receive emails like the Ops Note containing procedural changes 

that had not been risk assessed through a formal process.164 And according to Guide, such Ops 

Notes would not even flag whether changes had been made to the well plan.165

BP Allowed Equipment Availability to Drive Design and 

Procedure Decisions

BP inverted the normal process of well design in determining the depth of the surface cement 

plug, and the type and length of pipe to use in setting the lockdown sleeve. 
Chief Counsel’s Report — Chapter 4.5: Temporary Abandonment | 141

Drilling engineers normally begin by considering their objective and the attendant risks and 

developing a well design and procedures that are efficient and safe. They then arrange for the 

equipment and materials necessary to execute the design.166 BP did the opposite at Macondo. BP 

made decisions about what type of drill pipe to use (ordinary, heavyweight, or drill collars), and 

hence where to set its surface cement plug, based on the type of pipe available on the rig.167 The 

Deepwater Horizon apparently already had heavyweight drill pipe “racked back” and ready to run 

into the well, which led the Macondo team to use that pipe instead of drill collars.168 

BP’s lockdown sleeve setting procedure underscored this logic: “To achieve 100,000 lbs of tail 

pipe weight drill collars & drill pipe will be used. The combination will depend on availability and 

will be determined while onsite.” The caveat was repeated in step seven of the procedure, which 

stated “the decision on the pipe size & length will be made on the rig.”169 

BP Failed to Provide Written Standardized Guidance for 

Temporary Abandonment Procedures 

BP had no consistent or standardized temporary abandonment procedure across its Gulf of 

Mexico operations.170 Formal written guidance was minimal: The Drilling and Well Operations 

Practice manual and relevant Engineering Technical Practice (GP 10-36) mandated that, in each 

flow path, there should be two independent mechanical barriers isolating flow from the reservoir 

to the surface and that those barriers should be independently tested.171 The documents did not 

specify the location of those barriers or the procedure by which they should be set. This left the 

Macondo engineers to determine such issues for themselves on an ad hoc basis. For example, 

when Hafle emailed the subsea engineers—“Can we set the plug after the LDS is in place?”—one 

subsea engineer wrote to another, “I do not know about setting the plug after the LDS. Do 

you? Could you ask someone around the office tomorrow about this to figure this out?”172 Such 

uncertainty existed even with something as basic as regulatory requirements.173 

Chief Counsel’s Report — Chapter 4.6: Negative Pressure Test | 143

Chapter 4.6|Negative Pressure Test

The negative pressure test performed at Macondo showed repeatedly over 

a three-hour period that the well lacked integrity and that the cement had 

failed to seal off the hydrocarbons in the pay zone. BP well site leaders, 

in consultation with Transocean rig personnel, nevertheless mistakenly 

concluded that the test had demonstrated well integrity and then proceeded to the 

next phase of temporary abandonment. 

The Chief Counsel’s team finds that the 

failure to properly conduct and interpret 

the negative pressure test was a major 

contributing factor to the blowout. 

Well Integrity Tests

After cementing the production casing, BP was 

nearly ready to complete the Macondo well and 

turn it into a producing well. (Completion refers to 

the process of preparing the well for production and 

installing equipment to collect oil from the well.) 

However, BP only planned to use Deepwater 

Horizon to drill the well, not to complete it. After 

installing the production casing, BP planned to 

have the Deepwater Horizon leave Macondo for 

a different drilling job elsewhere in the Gulf of 

Mexico. Another rig would perform the completion 

work at some undetermined time in the future. 

The well would be temporarily “abandoned” during 

the time between Deepwater Horizon’s departure and the completion rig’s arrival. The Deepwater 

Horizon crew’s last responsibility would be to secure the well to ensure that nothing could leak in or 

out—to confirm the well’s integrity—during that intervening time. It was during this temporary 

abandonment process, rather than during drilling, that the blowout occurred.

As part of the temporary abandonment procedure, the rig crew conducted tests to check the well’s 

integrity. If there were a leak in the system of cement, casing strings, and mechanical seals that 

comprised the well, these tests should have revealed it. The rig crew conducted three different tests: 

a seal assembly test, a positive pressure test, and a negative pressure test. The tests each checked 

different parts of the well’s integrity. 

Significantly, however, the negative pressure test was the only one that tested the integrity of 

the cement at the bottom of the well.

1

 That cement is what the rig crew would rely on to isolate 

hydrocarbons in the pay zone and keep them from coming up the well.

Testing this cement was thus critical to safety of everyone on the rig.

Figure 4.6.1. Well integrity tests.

TrialGraphix

The rig crew conducted three pressure tests as part of the temporary 

abandonment procedure to verify the integrity of the well. From left 

to right: the seal assembly test, the positive pressure test, and the 

negative pressure test. Test regions are shown in green.

Seal Assembly Test Positive Pressure Test Negative Pressure Test
144 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Figure 4.6.2 

TrialGraphix

The seal assembly test checked the 

integrity of the interface between the 

casing and the wellhead. After lowering 

a packer into the well, the rig crew 

closed a variable bore ram around the 

BOP, sealing the space above and below 

the seal assembly. The rig crew then 

pumped fluid into this space, increasing 

the pressure inside it. If fluid did 

not leak out of the seal assembly, the 

pressure would remain constant.

Seal Assembly Test

The seal assembly test, as its name 

implies, tests the casing hanger seal 

assembly. A long string production 

casing hangs from a casing hanger 

inside the wellhead. The casing 

hanger both supports the casing 

and seals off the annular space 

outside the top of the casing. After 

installing the casing, rig personnel 

conduct a test to determine that the 

casing hanger seal does not leak. To 

do so, the crew installs a plug, or 

packer, on the bottom of the drill 

pipe and lowers it beneath the seal 

assembly. The crew closes a variable 

bore ram of the blowout preventer 

(BOP) (above the seal assembly) 

around the drill pipe. This creates 

a small enclosed space inside the 

casing at the mudline. The rig crew 

then pumps additional fluid into 

this space, increasing the pressure. 

They then monitor the pressure for 

a predetermined time period. If the 

pressure remains constant, it means 

that the casing hanger seal is capable 

of containing high internal pressure. 

If the pressure drops, fluid is escaping 

through a leak. In the early morning 

hours of April 20, the rig crew 

performed two separate pressure 

tests on the seal assembly, both of 

which passed.2

 

WELL INTEGRITY TESTS

The casing hanger, as described in Chapter 4.1, has 

flow passages that facilitate the flow of fluids during 

normal drilling operations. The seal assembly (blue) 

is fitted atop the casing hanger to halt annular flow 

after the primary cement job is complete. Together, 

the two bind the casing to the wellhead.

Pay Sands

Variable 

Bore Ram

Drill Pipe

Packer

TrialGraphix

Seal 

Assembly

Seal Assembly Test

Mud

Cement
Chief Counsel’s Report — Chapter 4.6: Negative Pressure Test | 145

Figure 4.6.3

TrialGraphix

The positive pressure test checks 

the integrity of the well by testing 

whether the casing and wellhead seal 

assembly can contain higher pressure 

than surrounds them. The Deepwater 

Horizon crew increased the pressure in 

the production casing string by pumping 

fluid into it through the kill line. If fluid 

does not leak out of the casing, the 

pressure again remains constant.

Positive Pressure Test

Later that morning, the rig crew conducted a positive 

pressure test. A positive pressure test is like a 

seal assembly test, but over a larger area of the well. 

With the drill pipe pulled out of the well, the rig crew 

shuts the blind shear rams on the BOP to isolate the 

well from the riser. The crew then pumps additional 

fluid into the well below the BOP and monitors the 

pressure. If the pressure remains constant with the 

pumps shut off, that means that the casing, wellhead 

seal assembly, and BOP are containing internal 

pressure and are not leaking. Between 10:30 a.m. and 

noon, the crew conducted a positive pressure test to 

250 pounds per square inch (psi) for five minutes and 

then a second to 2,700 psi for 30 minutes. In both 

instances, pressure inside the well remained constant 

over the test period.3

 

Because the seal assembly and positive pressure 

tests at Macondo appear to have been performed and 

interpreted correctly, this report does not explore 

them further. 

Neither the seal assembly test nor the positive 

pressure test could check the integrity of the cement 

in the shoe track or in the annular space at the bottom 

of the production casing. The seal assembly test could 

not test anything below the packer. Similarly, the 

positive pressure test does not test anything below the 

wiper plug on top of the float collar. 

The only test that was capable of testing the 

bottomhole cement, which was essential to preventing 

a blowout, was the negative pressure test.4

 

Pressurizing the well 

during integrity testing 

requires the rig crew 

to seal the well at the 

BOP. Opening and 

closing valves, such as 

the kill line, allow the 

crew to manipulate 

pressures in the well 

from the rig.

Closed Valve

Open Valve

Riser

Pay Sands

Blind Shear 

Ram

Kill Line

Kill Line

Blind Shear Ram

TrialGraphix

Positive Pressure Test
146 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Negative Pressure Test

The negative pressure test is essentially the inverse of a positive 

pressure test. Rig personnel reduce the pressure inside the well below the 

pressure outside the well and then monitor the well to determine whether 

any hydrocarbons from the pay zones leak into the well from the formation 

outside it. 

Whereas rig personnel identify a failed positive pressure test by observing 

diminishing internal pressure, they identify a failed negative pressure test 

when they observe increasing internal pressure while the well is shut in or 

flow from the well while it is open. In a successful negative pressure test, 

there should be no pressure increase inside the well and no flow from the 

well for a sustained period of time.5

 Increased pressure during this period 

indicates that the primary cement job at the bottom of the well has failed and 

hydrocarbons from the pay zone are entering the well.

The negative pressure test simulates the conditions rig personnel will create 

inside the well once they remove drilling mud from the riser (and from some 

portion of the well below the mudline) in order to temporarily abandon the 

well. Removing that mud removes pressure from inside the well. 

Figure 4.6.5. End of cement to temporary abandonment.

TrialGraphix

After the final casing string was cemented, heavy drilling mud filled the 

riser and the well (left). After the temporary abandonment planned for 

Macondo, the riser and its drilling mud would be removed. The drilling 

mud in the final casing string would be replaced with lighter seawater to 

a depth of over 8,000 feet below sea level (right). The removal of the 

hydrostatic pressure this drilling mud applied to the bottom of the well 

would increase the stress on the casing, seals, and cement. The negative 

pressure test simulated the conditions of temporary abandonment to 

confirm the integrity of the well in a controlled environment (middle).

Bottomhole Cement

Lockdown Sleeve

Drill Pipe

Figure 4.6.4

TrialGraphix

By moving mud from the production 

casing into the riser (displacement), 

the rig personnel reduced the 

pressure inside the well below 

the pressure outside the well 

(underbalancing). If there was good 

well integrity, the pressure inside 

the well would remain constant 

during the negative pressure test. 

If there was a leak of hydrocarbons 

into the well, the pressure in the 

well would rise (if the drill pipe or 

lines to the rig were closed) or fluid 

in the wellbore would be forced up 

and flow out at the rig (if the lines 

were open).

Pay Sands

Drill Pipe

3,300' 

of Mud 

Removed

Annular

Preventer

Mud

Spacer

Seawater

Cement

Cement 

Plug

Annular 

Preventer
Chief Counsel’s Report — Chapter 4.6: Negative Pressure Test | 147

The purpose of the negative pressure test is to make sure that when that pressure is removed, the 

casing, cement, and mechanical seals in the well will prevent high-pressure hydrocarbons or other 

fluids in the pay zone outside the well from leaking in. The test thus evaluates the integrity of the 

wellhead assembly, the casing, and the mechanical and cement seals in the well—indeed, it is the 

only pressure test that checks the integrity of the primary cement (see Figure 4.6.4). 

For these reasons, both BP and Transocean have described the negative pressure test as 

critically important.6

Negative Pressure Test at Macondo

The negative pressure test at Macondo occurred in three separate phases over a five-hour period 

between approximately 3 and 8 p.m. on April 20. 

First, the crew prepared to conduct the negative pressure test. To replicate conditions after 

temporary abandonment, the crew needed to “remove” the column of mud to a depth of 8,367 feet 

below sea level. In its place, the crew would “substitute” a column of seawater (see Figure 4.6.5). 

The crew accomplished this by pumping seawater (preceded by a buffer fluid known as spacer to 

separate it from the mud) down through a drill pipe lowered to that depth, illustrated in 

Figure 4.6.6. As they exited the stinger at the end of 

the drill pipe, the spacer and seawater would force—or 

displace—the surrounding mud up through the casing and 

into the riser. Once the seawater had displaced the mud 

and spacer into the riser above the BOP stack, the crew 

would close an annular preventer on the BOP around the 

drill pipe. 

Closing the annular preventer would isolate the well below 

from the hydrostatic pressure exerted by the column of 

heavy drilling mud and spacer in the riser. At that point, 

the well would instead be subject to the lower 

hydrostatic pressure exerted by the lighter 8,367-foot 

column of seawater in the drill pipe. This would simulate 

the reduced hydrostatic pressure inside the well after 

temporary abandonment.

The next step was to conduct what became the first negative 

pressure test (the crew originally planned to conduct only 

one test). The crew would open a valve on the drill pipe at 

the rig and bleed off any pent-up pressure inside the drill 

pipe. In other words, the crew would allow fluids to flow 

out of the drill pipe until the flow stopped and the pressure 

in the pipe fell to 0 psi. The crew would then close—or shut 

in—the drill pipe and monitor the pressure inside it to see 

whether it remained at 0 psi or increased. This drill pipe 

pressure reflected the internal pressure of the well.

At Macondo, the crew had unexpected difficulty in bleeding 

the drill pipe pressure down to 0 psi. After each attempt, 

the crew would shut in the well, and the pressure would 

build back up. The rig crew attempted three times to bleed 

Figure 4.6.6. Preparations for the negative pressure test.

TrialGraphix

To prepare for the negative pressure test, the rig crew 

needed to displace the mud in the drill pipe and casing 

string from a depth of 8,367 feet to above the BOP. The 

crew did so by pumping spacer fluid (left) and then 

seawater (right) down the drill pipe until the mud was 

above the BOP.

8,367'

Negative Pressure Test

Mud

Spacer

Seawater

Cement
148 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

off the drill pipe pressure, but each 

time, the drill pipe pressure rose 

after being bled off. After the third 

attempt, drill pipe pressure rose 

from 0 to 1,400 psi as shown in 

Figure 4.6.7. 

All parties now agree that this 

1,400 psi pressure reading indicated 

that the well had failed the negative 

pressure test and that the cement 

job would not prevent hydrocarbons 

in the pay zones from entering the 

well.7

 The 1,400 psi pressure was the 

pressure of the hydrocarbon-bearing 

pay zone that was not properly sealed 

off by the primary cement.

The crew did not recognize that 

this first negative pressure test had 

identified a problem with the well—or 

if they did, they did not act upon 

that fact. Instead, they conducted a 

second test. 

BP had submitted a permit 

modification to MMS stating that it 

would conduct the negative pressure 

test on the kill line rather than the 

drill pipe.8

 At least in part for this 

reason, BP well site leaders decided 

to follow up their first test on the 

drill pipe with a second negative 

pressure test in which they monitored 

pressure and flow on the kill line.9

 

Rig personnel therefore opened the 

kill line, bled the pressure down to 0 

psi, and monitored the line for 

30 minutes. This time, there was no 

flow or pressure buildup in the kill 

line. The well site leaders and rig 

crew decided this was a successful 

negative pressure test and moved on to the next steps in the temporary 

abandonment procedure. But, as shown in Figure 4.6.8, although the pressure on the kill line may have stayed at 0 psi, 

drill pipe pressure remained at 1,400 psi. 

The well site leaders and rig crew never adequately accounted for that elevated pressure in the drill pipe.

The negative pressure test at Macondo “failed” in the sense that it did not show that the well had integrity. It was 

successful, however, in that it repeatedly and accurately identified a serious problem. All parties have since agreed that 

Figure 4.6.7. First test failure. 10005000

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2000

psi

1,400

TrialGraphix

During the first negative pressure 

test, the crew repeatedly bled the 

drill pipe pressure down to 

0 psi. However, more fluids bled 

than expected, and the drill pipe 

pressure repeatedly increased. 

After the last bleed, the drill pipe 

pressure rose from 0 to 1,400 psi, a 

clear failure.

Figure 4.6.8. Second test failure. 10005000

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2000

psi

1,400

1000

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3000

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2000

psi

0

TrialGraphix

During the second negative 

pressure test, the crew bled off the 

pressure in the kill line, rather than 

the drill pipe. The crew observed 

no excessive flow or pressure 

buildup on the kill line. The well 

site leaders and rig crew decided 

this was a successful test. But 

they had never accounted for the 

pressure on the drill pipe, which 

remained at 1,400 psi throughout 

the second test.

Mud

Spacer

Seawater

Cement
Chief Counsel’s Report — Chapter 4.6: Negative Pressure Test | 149

the 1,400 psi pressure reading on the drill pipe showed that hydrocarbons from the formation 

were entering the well from the pay zones and that the cement had failed to isolate or block off 

those pay zones. The larger question is why the men on the rig floor, who depended on this test to 

ensure well integrity, did not interpret the results of the negative pressure test correctly.

Answering this question is difficult because of the lack of consistent and detailed witness 

accounts. Some of the most valuable facts will never be known because many of the men involved 

in the test died in the rig explosion. The well site leaders involved in the test did survive but 

declined to speak to investigators about what happened (one citing his medical condition and the 

other invoking his Fifth Amendment rights). 

However, the Chief Counsel’s team did review notes taken by BP investigators who spoke with 

both well site leaders soon after the blowout. The Chief Counsel’s team also had access to data 

records showing the pressures that the rig crew observed as well as testimony from witnesses 

who observed certain events in the drill shack that evening. The Chief Counsel’s team based the 

following account on these information sources.

Preparations for the Negative Pressure Test

The rig crew began preparations for the negative pressure test at about 3 p.m. with a pre-job 

safety meeting. Because the crew would have to displace drilling mud to conduct the test, Leo 

Lindner, M-I SWACO’s mud engineer, led the meeting. Well site leader Bob Kaluza was 

present for the meeting, though he left soon after it ended.10 The meeting was held in or near the 

drill shack. 

Shortly after 3 p.m., Transocean driller Dewey Revette pumped water to displace mud from three 

pipes, or “lines,” that ran from the rig to the BOP stack: the boost, choke, and kill lines (see 

Figure 4.6.9). 

Figure 4.6.9. Negative pressure test progress, 3 p.m. on April 20, 2010.

TrialGraphix

To begin preparations for the negative pressure test, the rig crew displaced the boost, 

choke, and kill lines with seawater. Seawater was pumped into the lines on the rig, 

forcing mud into and up the riser (left). After the lines were displaced, the crew closed 

the valves connecting them to the riser and BOP (right).

Boost Line

Choke Line Kill Line
150 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Rig personnel could use these lines to pump fluids into the well without pumping fluids through the 

drill pipe.11 

The boost line was connected to the well immediately above the BOP. Rig personnel could pump 

fluids through it to accelerate the displacement of mud in the riser, literally “boosting” mud up 

toward the rig. The rig crew anticipated pumping seawater through the boost line later in the 

temporary abandonment process and prepared for doing so by displacing mud inside the line 

with seawater. 

The choke and kill lines were connected to the BOP at various points on the stack. Rig personnel 

could use these lines to pump fluids in and out of the well even while certain BOP elements were 

fully sealed. These lines were therefore crucial to controlling kicks during drilling operations: After 

shutting the well in with the BOP, rig personnel could use 

them to “kill” the well (that is, overbalance it) with heavy 

mud and then “choke it off” by circulating hydrocarbons 

out. The rig crew could also use these lines instead of the 

drill pipe to conduct the negative pressure test. The men on 

the Deepwater Horizon eventually did use the kill line for 

this purpose.12 

Just before 4 p.m., the crew took its next preparatory step. 

They pumped seawater down the drill pipe to displace 

the drilling mud in the pipe and then continued pumping 

seawater until they displaced mud in the casing above 

8,367 feet with seawater as shown in Figure 4.6.10.13 

Because mud is expensive and reusable, and because direct 

contact with seawater would contaminate it, the crew used 

spacer fluid as a buffer to separate the seawater from the 

mud. The crew’s goal was to displace the heavy mud and 

spacer fluid entirely above the BOP. 

Use of Lost Circulation Material as Spacer

Operators commonly choose to use a spacer during 

displacement. However, BP chose to use a somewhat 

unusual type of spacer fluid at Macondo. BP chose to use 

a fluid composed of leftover lost circulation materials

stored on the rig. As previously discussed, BP engineers 

had been concerned about the risk of further lost returns 

since the lost circulation event in early April. BP had asked 

M-I SWACO to make up at least two different batches, or 

“pills,” of lost circulation material for that contingency—one 

commercially known as Form-A-Set and the other as FormA-Squeeze. BP decided to combine these materials for use 

as a spacer during displacement. 

The combined spacer material that BP chose thus had two unusual characteristics. First, the 

material was denser than the drilling mud in the well and, at 16 pounds per gallon (ppg), much 

denser than 8.6 ppg seawater.14 While using such a dense spacer would arguably assist in displacing 

mud down and out of the drill pipe, it could prove problematic as well. BP’s plan called for the 

spacer to be pushed up through the wellbore and into the riser by the seawater flowing behind it. By 

Figure 4.6.10. 4 p.m.

TrialGraphix

The crew displaced the mud in the drill pipe and in the 

casing from 8,367 feet to above the BOP. The crew first 

pumped a spacer fluid down the drill pipe, which forced the 

mud out and up the casing and the riser (left). Following 

the spacer, the crew pumped seawater into the drill pipe. 

This forced the spacer and the mud up the casing. The 

crew’s intent was to pump enough seawater to displace the 

spacer and mud above the BOP (right).

8,367'

Mud

Spacer

Seawater

Cement
Chief Counsel’s Report — Chapter 4.6: Negative Pressure Test | 151

using a spacer that was so much denser than the seawater, BP increased the risk that the spacer 

would instead flow downward through the seawater, potentially ending up beneath the BOP and 

confounding the negative pressure test.15

Second, the lost circulation materials that BP combined to create its spacer created a risk of 

clogging flow paths that could be critical to proper negative pressure testing. Much as blood 

clots to stop a bleeding wound, viscous lost circulation materials are designed to plug fractured 

formations to prevent mud from leaking out of a well. M-I SWACO therefore warned BP before 

the negative pressure test that spacer composed of lost circulation material could “set up” or 

congeal in “small restrictions” in tools on the drill pipe.16 

The Chief Counsel’s team found no evidence that anyone in the industry had ever used (or even 

tested) this type of spacer before, much less that anyone at BP or on the rig had done so.17 There 

also appears to be no operational reason BP chose to use the lost circulation material as a spacer.18

Rather, according to internal BP emails and the testimony of various witnesses, BP chose to use 

the lost circulation pills as a spacer in order to avoid 

having to dispose of the material as hazardous waste 

pursuant to the Resource Conservation and 

Recovery Act (RCRA).19 

RCRA regulations would normally have required BP to 

treat and dispose of the two pills as hazardous waste. 

But BP and M-I SWACO reasoned that once the two pills 

had been circulated down through the well as a spacer 

they could be dumped overboard pursuant to RCRA’s 

exemption for water-based drilling fluids.20 This is 

what prompted BP to direct M-I SWACO to use the lost 

circulation material as a spacer.21 This decision would 

save BP the cost of shipping the materials back to shore 

and disposing of them as hazardous waste.22 

These disposal concerns also led BP to use an unusually 

large volume of spacer material at Macondo. Typically, 

200 barrels of spacer are enough to provide an 

adequate buffer between mud and seawater.23 BP chose to 

pump 454 barrels of its unusual combined spacer fluid

at Macondo.24 

Unlikely Displacement of All Spacer Above the BOP

After pumping 352 barrels of seawater behind the spacer, the crew closed the upper annular 

preventer, believing that they had displaced all of the spacer above the BOP.25 BP’s post-incident 

report calculates that the crew was correct, albeit by a slim margin of just 12 feet.26 But that 

calculation is optimistic. It assumes that none of the heavy spacer fell back down through the 

much lighter seawater that was pushing it upward through the wellbore. Given the substantial 

density differential between the spacer and seawater and the substantial amount of time it took 

to displace 454 barrels of spacer, it is likely that at least some of the spacer fell backward through, 

or mixed with, the seawater on its way up the casing into the riser. Even putting aside that 

complication, Transocean and at least one independent expert have calculated that the tail end of 

the spacer did not end up above the BOP.27

Figure 4.6.11. 4:53 p.m.1000

5000

3000

4000

2000

psi

2,325

TrialGraphix

The crew closed the annular preventer around the drill 

pipe. The drill pipe pressure was approximately 700 psi 

higher than should have been expected, a sign that some 

spacer may have remained beneath the BOP.

Annular Preventer
152 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Because the BOP and wellhead were a mile beneath the rig, the crew had no way of observing 

directly whether they had displaced all of the spacer above the annular preventer. But pressure 

readings on the drill pipe should have alerted them that something was amiss. When the crew 

first closed the annular preventer around the drill pipe (see Figure 4.6.11), the pressure on the 

drill pipe was approximately 700 psi higher than it should have been.28 That anomaly should have 

merited further investigation because it could have indicated that spacer remained below the 

BOP. But it does not appear that anyone in the drill shack had ever calculated what the drill pipe 

pressure should have been.29 

This higher-than-expected pressure was the first of many unrecognized and unheeded anomalous 

readings during the negative pressure test. 

The rig crew next bled the drill pipe to 1,250 psi, in an effort to equalize pressure on the drill pipe 

with pressure on the kill line (which was 1,250 psi at the time, as shown in Figure 4.6.12).30 Once 

the crew had bled the drill pipe pressure down to 1,250 psi, it opened a valve on the kill line at 

the BOP so that both the drill pipe and kill line were open to the well. At this point, the drill pipe 

and kill line should have behaved like two straws in the same glass of water: The pressure in both 

should have been a steady 1,250 psi. Instead, when rig personnel opened the valve, the drill pipe 

pressure jumped, and the kill line pressure dropped.31 

Figure 4.6.12. 4:55 p.m.

1000

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psi

1,250

1000

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2000

psi

1,250

1000

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3000

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psi

1,250

1000

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4000

2000

psi

1,400

1000

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3000

4000

2000

psi

645

1000

5000

3000

4000

2000

psi

2,325

TrialGraphix

After the annular preventer was closed (left) the crew bled down the pressure in the drill pipe to equalize its 

pressure with the pressure in the kill line. Because both the drill pipe and the kill line go to the same vessel, 

when the valve connecting the kill line to the BOP is opened, the pressures should remain equal (middle). 

Instead, when the valve was opened, the pressures diverged (right).

Annular 

Preventer 

Mud

Spacer

Seawater

Cement
Chief Counsel’s Report — Chapter 4.6: Negative Pressure Test | 153

This should have been another indication that spacer might have ended up beneath the BOP 

or that something else was amiss.32 There is some evidence that the crew or well site leaders 

may have recognized a concern, but nobody appears to have acted upon it. 33 In what became 

a pattern, individuals on the rig did not take a simple precaution: They could have opened up 

the annular preventer, pumped more seawater into the well to ensure that all spacer had been 

displaced above the BOP, and begun the negative pressure test anew.34 This would have taken 

time but also would have ensured that misplaced spacer did not confound the test results. 

The First Negative Pressure Test

Just before 5 p.m., the crew opened a valve at the top of the drill pipe on the rig and attempted 

to bleed the drill pipe pressure down to 0 psi, as shown in Figure 4.6.13. The crew was unable to 

do so and could only reduce pressure to 260 psi.35 It is not clear how many barrels of fluid the 

crew bled off at this point. Three witnesses have testified that 23 to 25 barrels were bled off; other 

accounts suggest it may have been more or less.36 

The uncertainty over how much fluid flowed from the well during the bleed-off suggests that the 

well site leaders and crew failed to monitor the bleed-off volumes with requisite rigor. It does not 

appear that anyone had calculated ahead of time how many barrels should have flowed from the 

Figure 4.6.13. 4:58 p.m.

1000

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psi

1,262

1000

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3000

4000

2000

psi

260

1000

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3000

4000

2000

psi

1,400

TrialGraphix

The crew began the negative pressure test by attempting to bleed the drill pipe pressure to 0 psi (left). 

However, the crew was unable to reduce pressure to below 260 psi (middle). This bleed returned an unknown 

amount of water to the rig. The crew shut in the drill pipe, and the pressure built up to 1,262 psi (right). In a 

successful negative pressure test, pressure does not build up.
154 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

well during the bleed, even though such calculations would have been relatively straightforward.37 

After failing to bleed the pressure down to 0 psi, the crew closed the valve on the drill pipe, and 

the pressure built back up to 1,262 psi.38 

These events indicated that the well was not behaving as a closed system. Something was entering 

the well, although the source of the material entering the well was indeterminate. If the well had 

been a closed system, the crew would have had no difficulty bleeding the drill pipe pressure down 

to 0 psi, and the well would have returned far less than 23 barrels of fluid during the bleed-off.39 

Also, the drill pipe pressure would not have increased. 

As one independent expert has pointed out, this series of events actually constituted a failed 

negative pressure test, although the crew did not recognize that fact.40 

At 5:10 p.m., the rig crew apparently noticed that the level of fluid in the riser was falling.41 Spacer 

in the riser was leaking down through the annular preventer and into the well below the BOP.42 

Unlike many other indications, the crew could observe the fluid levels in the riser with their own 

eyes. When one rig crew member arrived on the rig floor, he saw others standing around the 

rotary table and using a flashlight to peer down into the riser to see how much fluid was missing.43 

Around this time, the night crew began to gather at the drill shack in anticipation of the 6 p.m. 

Figure 4.6.14. 5:10 p.m. 

TrialGraphix

The rig crew noticed that the fluid level in the riser was falling. Because the annular preventer was 

not sufficiently tight around the drill pipe, spacer fell beneath the BOP (left). In response, the rig crew 

tightened the seal of the annular preventer and refilled the riser (right), but did not circulate the spacer 

back above the BOP.

Spacer material 

below the annular 

preventer

Annular Preventer. The 

annular preventer is a 

hard rubber donut that 

surrounds the drill pipe; 

when activated it expands 

and fills the space around 

the drill pipe, sealing 

the well below (see also 

Figure 2.9).

TrialGraphix

Mud

Spacer

Seawater

Cement
Chief Counsel’s Report — Chapter 4.6: Negative Pressure Test | 155

shift change. The night crew would include Transocean 

toolpusher Jason Anderson and M-I SWACO mud 

engineer Gordon Jones. 

A group of visiting BP and Transocean executives also 

entered the drill shack as a part of a rig tour. They were 

escorted by Transocean offshore installation manager 

Jimmy Harrell and senior toolpusher Randy Ezell. The 

drill shack was so crowded with the shift relief and tour 

group that it was “standing room only,”44 Transocean 

executive Daun Winslow recognized that the drilling 

team was confused about something. When the tour 

group left the drill shack, Winslow asked Harrell and 

Ezell to remain behind to assist.45

In response to the dropping levels of fluid in the riser, 

Harrell instructed the rig crew to tighten the seal of 

the annular preventer against the drill pipe as shown 

in Figure 4.6.14. Wyman Wheeler, the Transocean 

toolpusher on duty at the time, then topped off the riser 

with 20 to 25 barrels of mud, and the fluid level in the 

riser stayed steady.46 The crew had thus identified and 

eliminated a leak in the well system that could have 

explained the anomalous pressure readings they had seen 

and their inability to bleed the drill pipe pressure to 

0 psi.47 By this time Kaluza returned to the rig floor.48 

Despite clear evidence that spacer had probably leaked 

below the BOP, rig personnel again did nothing to ensure 

that they had fully displaced the spacer above the BOP 

and instead proceeded with the test.49

Having tightened the annular preventer, the crew once 

again tried to bleed the pressure in the drill pipe to 0 psi as shown in Figure 4.6.15. This time 

they were successful. According to witness accounts, 15 barrels of fluid were bled off from the 

drill pipe in the process.50 Again, nobody had done any calculations to predict the returns. Those 

calculations would have predicted only three to five barrels of returns; the bleed-off process had 

produced more fluids than it should have.51 

The crew shut in the drill pipe, but the pressure again built back up.52 In this case, the pressure 

reached 773 psi and most likely would have gone higher had the crew not begun immediately 

bleeding it off.53 

This second series of bleed-offs, excessive flows, and pressure buildups constituted another failed 

“negative pressure test” that the crew again did not recognize as such. With the annular preventer 

fully closed and sealed, the only explanation for the excessive returns and pressure increase 

would be that the primary cement job had failed to seal off the pay zone. Hydrocarbons were 

leaking from the formation into the well. Individuals involved in the test at this point should have 

recognized that the well lacked integrity. 

According to at least one witness, shortly before 6 p.m. Kaluza directed the crew to bleed down 

Figure 4.6.15. 5:26 p.m.

1000

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psi

773

1000

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psi

0

TrialGraphix

The rig crew attempted again, this time successfully, to 

bleed the drill pipe pressure down to 0 psi. Fifteen barrels 

of seawater were returned during this bleed (left). The 

drill pipe was shut in, but the drill pipe pressure rose to 

773 psi. Fifteen barrels is a higher return than should have 

been expected, and the drill pipe pressure should not have 

built back up.
156 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

the drill pipe pressure by opening the kill 

line rather than the drill pipe. Because 

the kill line and drill pipe both led to the 

same place (again, like two straws in the 

same glass of water), bleeding pressure 

from the kill line would also cause drill 

pipe pressure to drop to 0 psi. It is not 

clear why Kaluza directed the crew to 

bleed down the drill pipe pressure by 

opening the kill line. The switch may 

be significant, however, as it suggests 

uncertainty about the pressure readings 

and flow observations. “Let’s open the 

kill line and see what happens,” Kaluza 

reportedly said.54 Shortly afterward, 

Kaluza left the rig floor to speak with the 

Don Vidrine, the other BP well site leader 

whose shift was about to begin.55

Witnesses have provided differing 

estimates of the amount of seawater the 

crew bled from the kill line, ranging from 

three to 15 barrels.56 Flows in the upper 

end of this range would have been more 

than expected—but once again, nobody 

calculated ahead of time what flows to 

expect. As the pressure on the drill pipe 

dropped almost to 0 psi,57 the kill line 

continued to flow and spurt water until 

the crew closed the line’s upper valve on 

the rig.58 Over the next 30 to 40 minutes, 

the drill pipe pressure rose to 1,400 psi as 

shown in Figure 4.6.16.59

This was the clearest indication yet that 

the well lacked integrity. The 

1,400 psi pressure buildup can only have been caused by hydrocarbons leaking into the well from 

the reservoir formation. 

One expert described this test result as a “conclusive failure.”60 Later analysis has shown that 

1,400 psi is approximately the reading that one would have expected reservoir hydrocarbon 

pressure to produce at the surface if there had been no cement at the bottom of the well during 

the negative pressure test.61 

Kaluza returned to the rig floor with Vidrine, who would soon be relieving him.62 While personnel 

at the rig had not treated earlier pressure readings and flow observations as problematic 

indications, the two well site leaders and other rig personnel did recognize that the rise in drill 

pipe pressure to 1,400 psi was a cause for concern.63 According to witness accounts, Kaluza and 

Vidrine discussed the test in the drill shack together with Anderson, Revette, assistant driller 

Steve Curtis, and BP well site leader trainee Lee Lambert.64 Because Kaluza’s and Vidrine’s 

Figure 4.6.16. 5:53 p.m. 10005000

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0

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1400

TrialGraphix

The rig crew bled drill pipe pressure down for a third time, 

this time through the kill line. Witnesses reported that 

three to 15 barrels were returned as the drill pipe reached 

0 psi (left). When the drill pipe was shut, the drill pipe 

pressure rose to 1,400 psi. According to BP witnesses, 

the Transocean rig crew attributed this rise to a “bladder 

effect.” A 15-barrel return would have been excessive, 

and the rise of drill pipe pressure to 1,400 psi was a clear 

sign that the negative pressure test had failed (right).

Mud

Spacer

Seawater

Cement
Chief Counsel’s Report — Chapter 4.6: Negative Pressure Test | 157

Bladder Effect. This figure 

represents the Chief Counsel’s 

team’s understanding of the 

“bladder effect” theory that 

supposedly explained the 

elevated pressure on the drill 

pipe. The “bladder effect” 

explanation contends that 

heavy fluids (mud and spacer) 

displaced to the riser were 

exerting force on the annular 

preventer from above, 

which in turn communicated 

pressure into the well. The 

Chief Counsel’s team found 

no evidence to support 

this theory.

Figure 4.6.17

accounts are only known through BP internal investigation notes, and the 

Transocean personnel principally involved did not survive (Ezell has stated that 

he did not take part in any such conversation and that he left the drill shack before 

the drill pipe pressure reached 1,400 psi), the details of the discussion are unclear. 

Transocean has challenged the accounts of the three BP witnesses, but those three 

accounts are consistent with each other, and at this point the Chief Counsel’s team 

has no testimonial or documentary evidence that conflicts with them.

According to notes from BP’s post-incident interviews of Kaluza and Vidrine, as 

well as testimony from Lambert, Anderson explained that the 1,400 psi pressure on 

the drill pipe was being caused by a “bladder effect” or “annular compressibility.”65 

According to Lambert, Anderson explained that “heavier mud in the riser would 

push against the annular and transmit pressure into the wellbore, which in turn you 

would expect to see up the drill pipe,” as illustrated in Figure 4.6.17.66 

The Chief Counsel’s team found no evidence to support this theory. Indeed, every 

industry expert that the Chief Counsel’s team spoke with agreed that no such 

phenomenon exists. Even if it did exist, any pressure caused by this “bladder effect” 

would have disappeared after the rig crew bled off the drill pipe and kill line.67 

Any “bladder effect” could not explain the 1,400 psi on the drill pipe.

Although there was a long discussion about the drill pipe pressure, it does not 

appear as though anyone in the discussion seriously challenged the bladder effect. 

According to BP witness accounts, Anderson explained that the pressure buildup 

after bleeding was not unusual. He told the well site leaders, “Bob and Don, this 

happens all the time.”68 Revette, the driller, apparently agreed that he had seen the 

bladder effect before.69 Lambert testified that he asked about the phenomenon but 

accepted Anderson’s explanation. On later reflection after the blowout, however, 

Lambert agreed that the explanation did not make sense.70 

The conversation apparently turned to conducting another negative pressure test, 

this time on the kill line instead of the drill pipe. According to witness accounts, 

Vidrine insisted that the crew perform a new negative pressure test on the kill line 

because the latest permit that BP had submitted to MMS stated that BP would 

conduct the test on the kill line.71 But it is unlikely that Vidrine made this decision 

solely because of the permit language; the rig crew had conducted the first test on 

the drill pipe without regard to the permit. Moreover, the BP team had already 

consciously deviated from the permit when it instructed the crew to conduct a 

combined displacement and negative pressure test–the permitted procedure did 

not specify such a step.72 It appears instead that Vidrine insisted on a kill line test 

at least in part out of concern over the results of the negative pressure test on the drill pipe.73 

But again, neither Vidrine, Kaluza, nor the rig crew treated the test on the drill pipe as a failure. 

Instead, they chose to disregard it in favor of a new test on the kill line. 

TrialGraphix
158 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

The Second Negative Pressure Test

Sometime after 6:40 p.m. on 

April 20, while the group in 

the drill shack continued 

to discuss the test, the 

crew moved the negative 

pressure test to the kill 

line at Vidrine’s behest. 

The crew pumped a small 

amount of fluid into the kill 

line from the rig to ensure 

the kill line was full. They 

plumbed the kill line so that 

fluids could be bled off into 

the “mini trip tank” near the 

drill shack and then bled 

the pressure on the kill line 

down to 0 psi as shown in 

Figure 4.6.18. According 

to witness accounts, less 

than one barrel of seawater 

flowed from the kill line, an 

insignificant amount. Once 

that flow stopped, beginning 

at about 7:15 p.m., the crew 

monitored the kill line

for 30 minutes and observed 

no additional flow or 

pressure buildup.74 

The lack of pressure or 

flow on the kill line, on its 

own, would have meant a 

successful negative pressure test. But the 1,400 psi on the drill pipe had never disappeared. 

The well site leaders and rig crew carried on their discussion about the test and whether the 

1,400 psi on the drill pipe was acceptable. Vidrine later told BP interviewers that he continued 

talking about the 1,400 psi reading for so long that the rig crew found it “humorous.”75 Anderson 

and Revette apparently continued to explain the pressure as a “bladder effect.” Kaluza’s 

statements to BP investigators suggest that he was present for the discussion as well and that 

he too accepted the Transocean explanation. He justified his acceptance to the investigators by 

saying that if Anderson had seen this phenomenon so many times before it must be real.76 In an 

email written after the blowout, Kaluza explained to BP management: 

Please consider this suggestion in the analysis about how this happened. I believe 

there is a bladder effect on the mud below an annular preventer as we discussed.... Due 

to a bladder effect, pressure can and will build below the annular bladder due to the 

differential pressure but can not flow – the bladder prevents flow, but we see differential 

pressure on the other side of the bladder.77

Figure 4.6.18. 6:40 p.m. 

1000

5000

3000

4000

2000

psi

0

1000

5000

3000

4000

2000

psi

1,400

1000

5000

3000

4000

2000

psi

0

TrialGraphix

The rig crew conducted a negative pressure test on the kill 

line. The rig crew reduced the pressure on the kill line to 

0 psi, bleeding an insignificant amount of water (left). No 

flow or pressure buildup was observed on the kill line, which 

on its own would have been a successful negative pressure 

test. However, the 1,400 psi on the drill pipe remained and 

was never properly accounted for (right).

Mud

Spacer

Seawater

Cement
Chief Counsel’s Report — Chapter 4.6: Negative Pressure Test | 159

In the end, everyone apparently accepted that the negative pressure test on the kill line 

established that the primary cement job had successfully sealed off hydrocarbons in the 

pay zone.78

Transocean and BP have each contested their relative involvement in the negative pressure 

test and their relative legal responsibilities for interpreting it. The determination of legal 

responsibility is beyond the scope of this Report. However, experts and witnesses alike agree that 

industry practice requires the well site leader to make the final decision regarding whether the 

test has passed or failed.79 There is also widespread agreement that the rig crew plays some role 

in interpreting tests, given their experience in running them and their authority to stop work if 

they recognize a safety concern.80 

The Chief Counsel’s team believes that the group of personnel involved in the Macondo negative 

pressure test—including Transocean drilling personnel and the two BP well site leaders—decided 

as a group that the test had succeeded.81 It appears that the highly experienced Transocean crew82

affirmatively advocated the view that the first and second negative pressure tests were acceptable 

once the “bladder effect” was considered, and the well site leaders eventually agreed. The long 

time spent conducting and discussing the tests shows a desire for consensus. It is possible, even 

likely, that this desire obscured the parties’ responsibilities. 

It does not at this time appear that either the BP well site leaders or the Transocean drilling 

crew ever sought guidance from others on the rig or onshore. For instance, based on available 

evidence, it does not appear that the BP well site leaders ever called the shoreside BP engineering 

team to ask for advice on interpreting or conducting the negative pressure test (Ezell also stated 

that nobody spoke with him regarding the test results).83 BP did not require its well site leaders 

to obtain shoreside approval before directing the rig crew to begin temporary abandonment 

operations.84 But the shoreside team had valuable expertise and experience. They could 

have answered questions about the test results, just as they often did regarding other drilling 

operations.85 John Guide, BP’s Houston-based wells team leader, later stated that given the 

pressure readings, he would have expected a call from the rig.86 

Instead, Vidrine apparently deemed the test successful. No one disagreed,87 and the rig crew 

moved on to begin displacing the remaining mud from the riser. Vidrine did speak to BP senior 

drilling engineer Mark Hafle by telephone shortly before 9 p.m., roughly an hour after the 

negative pressure test was finished. Hafle had called from Houston to see how operations were 

proceeding. Hafle had the transmitted Macondo drilling data up on 

his monitor. Vidrine told Hafle that there had been issues with the 

negative pressure test. He may specifically have told Hafle about the 

1,400 psi seen on the drill pipe, and Hafle would have been able to see 

on his computer the recorded pressures from the test. But Vidrine 

explained that the test issues had been resolved.88 The Chief Counsel’s 

team has not seen any evidence of any further discussion of the test 

with BP personnel onshore.89

The second negative pressure test showed again that the well lacked 

integrity. The 1,400 psi reading from the drill pipe indicated that 

hydrocarbons were leaking into the well. The fact that the kill line 

pressure was 0 psi at this time suggests that something may have been 

blocking fluids from flowing through the kill line and transmitting 

pressure to the gauges on the rig. One possibility, alluded to earlier, 

is that the spacer below the BOP had migrated into the 31

⁄16-inch 

Figure 4.6.19. Spacer migration. 

Leftover lost 

circulation 

material 

used as 

spacer for 

the negative 

pressure test 

could have 

migrated 

into the kill 

line during 

bleeds.

TrialGraphix
160 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

diameter kill line and clogged it.90 It is also possible that rig crews accidentally closed a valve that 

should have been open. The kill line could also have been clogged by undisplaced mud in the kill 

line or by gas hydrates that solidified during the test (the same type of hydrates that complicated 

containment operations).91 The exact reason may never be known. 

Technical Findings

The Negative Pressure Test Showed That the Cement Failed

The pressure readings and flow indications during the negative pressure test were not ambiguous. 

In retrospect, BP, Transocean, independent experts, and other investigations all agree that this 

critical test showed that the cement had failed and there was a leak in the well.92 

There were three instances in which pressure built up after being bled off, including the buildup 

experts have deemed a “conclusive failure” wherein pressure inside the drill pipe rose from 

0 to 1,400 psi.93 On at least one occasion, bleed-off procedures produced more flow than should 

have been expected. And while the rig crew observed no flow from the kill line during the second 

negative pressure test, the drill pipe pressure remained at 1,400 psi. 

The test failure should have been clear even though the well site leaders and rig crew had 

complicated matters by using an untested spacer and by allowing the spacer to leak below the 

BOP during the test. The well site leaders and rig crew never should have accepted the test as a 

success or continued with displacement operations.

BP’s Spacer Choice Complicated the Negative Pressure Test 

BP’s decision to use 454 barrels of a highly viscous spacer may have confounded the negative 

pressure test. All parties agree that at some point during the negative pressure test the spacer 

had leaked beneath the BOP and that the rig crew never circulated it out. That spacer may have 

migrated into and clogged the open kill line. If there had been a clear path through the kill line 

down to the wellhead, the rig crew would have observed the same 1,400 psi pressure inside the 

kill line that they saw on the drill pipe.94 If that had happened, the crew might have recognized 

that the second negative pressure test had failed. 

The Chief Counsel’s team did not examine the legal significance of BP’s decision to use lost 

circulation materials as spacer and then discharge them directly into the Gulf of Mexico. But the 

Chief Counsel’s team does conclude that greater care should have been taken first in testing and 

then in monitoring the placement of this unusual spacer. 

BP’s own investigative report states that its team used the spacer because of a “perceived 

expediency.”95 Although BP had never used this material as a spacer before or tested it for such 

use, and although BP used twice as much spacer at Macondo as it had used at other similar jobs, 

the company did not undertake a risk analysis to consider the consequences of its decision. 

BP thus did not consider the risk that a dense spacer made of lost circulation materials could be 

left beneath the BOP, potentially clogging crucial piping paths. 

Rig Personnel Should Have Displaced All Spacer Above the BOP

Personnel involved in the test may have further confounded the negative pressure test by failing 

to set up the test as intended. They knew for at least two reasons that heavy spacer fluid had 

leaked beneath the BOP where it could potentially confuse test results. First, they observed 
Chief Counsel’s Report — Chapter 4.6: Negative Pressure Test | 161

that the pressure inside the drill pipe was 2,325 psi when the annular was closed at 5 p.m. 

Second, when they opened the kill line, they observed a drop in pressure on the kill line and a 

simultaneous jump in pressure on the drill pipe. 

Despite these indicators, the individuals conducting the test did not try to correct the problem 

even after they decided to run a second negative pressure test. They could easily have circulated 

the spacer out of the wellbore to ensure that the test was set up as planned. They should have 

done so.96

Management Findings

Given the risk factors attending the bottomhole cement, individuals on the rig should have 

been particularly attentive to anomalous pressure readings. Instead, it appears they began with 

the assumption that the cement job had been successful and kept running tests and proposing 

explanations until they convinced themselves that their assumption was correct. The fact that 

experienced well site leaders and members of the rig crew believed that the Macondo negative 

pressure test established well integrity demonstrates serious management failures. 

There Were No Established Procedures or Training for 

Conducting or Interpreting the Negative Pressure Test

Lack of Standard Procedures

Neither BP nor Transocean had pre-established standard procedures for conducting a negative 

pressure test.97 While BP required negative pressure tests under certain conditions, one of its 

employees admitted that the tests “could be different on every single rig depending on what the 

[well] team agreed to.”98 Transocean likewise required negative pressure tests but did not have 

set procedures.99 For example, the crew of the Marianas had done the immediately preceding 

negative pressure test at Macondo in a different way than the Deepwater Horizon crew did the 

April 20 test.100 Partly because Transocean rigs conducted tests differently (in part because 

different rigs have different equipment), Kaluza and BP drilling engineer Brian Morel both 

spoke with an M-I SWACO engineer on April 20 to ask how the rig had previously conducted the 

negative pressure test.101 

Unfortunately, the lack of standard test procedures is unsurprising. In April 2010, MMS 

regulators did not require operators even to conduct negative pressure tests, let alone spell out 

how such tests were to be performed.102 (The Chief Counsel’s team notes that some wells need not 

be negative tested.103) Nor had the oil and gas industry developed standard practices for negative 

pressure tests.104 An independent expert admitted that he had to consult an academic text to find 

a description of a negative pressure test procedure.105

The recent regulatory proposal to require negative pressure test information in permit 

applications to MMS may trigger companies and the industry to establish standard negative 

pressure test procedures106 (discussed further in Chapter 6). A negative pressure test procedure 

ought to include the depth of mud displacement, the volumes of fluids to be pumped into the 

well, the pressures and fluid returns to be expected during the test, and criteria for determining 

whether the negative pressure test passes or fails. The procedure should also include explicit 

instructions for diagnosing and addressing problematic or anomalous test readings. 
162 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Lack of Training at Macondo

BP well site leaders displayed troubling unfamiliarities with negative pressure test theory and 

practice. Neither Kaluza nor Vidrine calculated expected pressures or volumes before running the 

negative pressure test even though other BP well site leaders routinely do so.107 Vidrine, Kaluza, 

and Morel all described the criteria for a successful test in terms of “flow or no-flow,” which 

ignores the importance of monitoring pressures in the well.108 Both well site leaders apparently 

accepted the “bladder effect” explanation, and Kaluza continued defending the theory and 

describing the Macondo test results as “rock solid” a week after the blowout.109 These are clear 

signs that BP needs to train its personnel better. 

Transocean has acknowledged that it does not train its personnel in the conduct or interpretation 

of negative pressure tests and that its Well Control Handbook does not describe a negative 

pressure test. Instead, Transocean states that its rig crews learn how to conduct a negative 

pressure test through general work experience.110 

Partly because of this, Transocean has been unable to conclude whether its Deepwater Horizon

rig crew had enough experience to conduct and interpret the negative pressure test on April 20.111 

Transocean is not unique in omitting training for the negative pressure test. Experts have 

stated that academic training on the negative pressure test may only be included in coursework as 

time allows.112

Transocean has argued that the members of its rig crew were tradesmen, not engineers, and could 

not have been expected to interpret the complex results of the Macondo negative pressure test. 

Transocean’s training approach certainly supports that view. 

However, a negative pressure test essentially consists of underbalancing a well and then 

watching to see if a hydrocarbon kick enters the well as a result. Transocean expected its rig 

crew to recognize signs of a kick during complex drilling operations. It appears inconsistent for 

Transocean to claim that its crew is trained in and skilled in recognizing kick indicators during 

drilling but is unable to recognize the same kick indicators during controlled testing.

Inadequate Procedures for Macondo

The most conspicuous problem with the negative pressure test procedures at Macondo is that 

there were almost no written procedures at all. As described in Chapter 4.5, although BP 

eventually developed temporary abandonment procedures that included a negative pressure 

test, the procedures stated only when the test would be done in relation to other operations. BP 

did not explain to the crew or its well site leaders how they should perform or interpret the test. 

The final M-I SWACO procedure, for instance, said simply, “[c]onduct negative test.” After the 

incident, BP engineering managers opined that the Transocean crew knew how to conduct a 

negative test, and that these limited instructions should have been adequate.113 Whether justified 

or not, the events of April 20 prove that BP’s expectation was incorrect. 

BP’s early plans for abandonment repeatedly failed to mention a negative pressure test at all.114 

On April 12, Morel circulated a draft temporary abandonment plan that did not include a negative 

pressure test.115 Morel’s omission may have been a mere oversight, but it may also have signaled 

his unfamiliarity with the test. 

Ronnie Sepulvado, one of BP’s Deepwater Horizon well site leaders who was not on the rig for the 

negative pressure test, needed to tell Morel that he should include one.116 Similarly, Kaluza’s 

pre-tour briefing to the rig crew described temporary abandonment procedures that did not 
Chief Counsel’s Report — Chapter 4.6: Negative Pressure Test | 163

include a negative pressure test. This prompted Harrell to state that Kaluza needed to add a 

negative pressure test.117 Kaluza’s omission, like Morel’s, may have signaled unfamiliarity with 

the test and its importance.

Although Morel and other BP engineers continually refined their temporary abandonment 

procedures, they never expanded their negative pressure test procedures to explain what 

pressures or flow volumes the crew should expect to see.118 Even more importantly, they did 

not add criteria for determining if the test had passed, nor contingency procedures in case the 

test failed. Kaluza admitted “[w]e didn’t talk about what if the negative test fails.”119 Moreover, 

several of the BP Macondo team’s early descriptions of the negative pressure test (including the 

one approved by MMS) were written so imprecisely that team members disagree even today 

about what they mean (as described in Chapter 4.5). Nor were the later descriptions passed along 

in “Ops Notes” or telephone calls necessarily better. When Hafle called Kaluza to discuss the test 

on the afternoon of April 20, he “had [the] impression that Kaluza wasn’t really clear on neg[ative 

pressure] test procedure.”120 Unfortunately, neither Hafle nor Kaluza seemed to think this 

uncertainty was a problem, because they appear to have ended the call without resolving it.

Lindner eventually wrote a displacement procedure for BP that contained the most detailed 

procedure for running the negative pressure test. Lindner’s document spelled out how much 

spacer and seawater the rig crew should pump into the well before conducting the test. His 

was the first procedure that reflected BP’s decision to use a large combined spacer fluid to help 

displace mud from the well.121 But it told rig personnel nothing about expected bleed-off volumes, 

how to interpret the negative pressure test, or what to do about anomalous pressure readings. 

It may also have included errors. For example, Lindner’s calculations directed rig personnel 

to pump a volume of seawater that may have been too small to fully displace spacer above the 

blowout preventer. In retrospect, it is inexcusable that the most detailed written procedures 

for the negative pressure test were written by a mud engineer in the course of specifying fluid 

volumes to be displaced prior to the test. 

Finally, the men on the rig did not always follow the few clearly written procedures that they had. 

Beginning April 14, the procedures directed that the negative pressure test would be conducted 

on the kill line. But rig personnel did not follow this instruction during the first negative pressure 

test. Instead, they conducted the initial negative pressure test on the drill pipe. This may suggest 

that in addition to creating better test procedures, BP and Transocean need to ensure that those 

procedures are followed. 

BP Failed to Recognize and Alert Rig Personnel to the Exclusive 

Reliance on the Negative Pressure Test at Macondo

Both the Macondo well plan and the challenges surrounding the Macondo cement job put a 

premium on the negative pressure test. BP’s temporary abandonment procedures required the 

crew to severely underbalance the well and to rely solely on the high-risk bottomhole cement as 

the exclusive barrier in the wellbore to flow while they displaced mud from the riser. 

Despite these facts, BP never emphasized to rig personnel the particular importance of the 

Macondo negative pressure test. BP personnel forgot even to mention the test during relevant 

communications on at least two occasions. (See “Inadequate Procedures for Macondo” section, 

above). Had BP properly emphasized the importance of the test and the need for special scrutiny 

of its results, BP and Transocean personnel on the rig may have reacted more appropriately to the 

anomalous pressure readings and flows they observed.
164 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Leadership and Communication

Even in the absence of detailed procedures, BP well site leaders should have exercised better 

judgment and initiative. When they confronted a 1,400 psi pressure reading from the drill pipe 

and a 0 psi reading from kill line, they should have insisted on probing and fully resolving the 

issue. Instead, interview notes suggest that they deferred to a toolpusher’s explanation without 

fully understanding, questioning, or testing it. 

Kaluza was not on the rig floor during most of the preparations for the test and may have missed 

the first part of the attempted negative pressure test on the drill pipe. He was in the well site 

leader’s office doing calculations for the planned cement plug.122 Had he been on the rig floor and 

participating in the test the entire time, Kaluza would have been in a better position to observe 

several anomalies, including:

	the excessive pressure (2,325 psi) at the end of the pre-test fluid displacement; 

	the pressure changes in the drill pipe and kill line when the rig crew opened the kill line 

valve at the BOP; 

	the rig crew’s inability to bleed the drill pipe below 260 psi and the abnormally large 

volume of fluid flow during that bleed; and

	the drop in the fluid level in the riser.123 

One BP well site leader who was not on the rig on April 20 stated that his practice during negative 

pressure tests is to remain on the rig floor from the beginning of preparations until he signs off on 

the test.124 Independent experts have stated that well site leaders should certainly be 

present as seawater is pumped out of the drill pipe during displacement and before the crew 

begins any bleeds.125 

Kaluza also apparently never personally analyzed the unusual spacer that the rig crew used during 

his shift.126 And notes of his statements to BP investigators suggest that he did not recognize that 

such a spacer could confound the negative pressure test.127 One independent expert has stated 

that it would have been standard industry practice for the well site leader to “personally confirm[] 

the properties of the final blend.”128 

Most significantly, it appears that neither the BP well site leaders nor the Transocean drilling 

team ever called shore-based personnel to ask for assistance, to report the anomalous pressure 

readings, or to check the “bladder effect” explanation. Neither company had specific policies in 

place that required their personnel to report the results of the test to shore.129 But both BP and 

Transocean expected rig personnel to call if they needed help or were uncomfortable.130 Indeed, 

BP personnel called to shore on April 19 to discuss the problems the rig crew was experiencing 

while trying to convert the float collar.131 Instead, the well site leaders and drilling team 

relied solely on their own limited experience and training to wrongly interpret the test results 

as a success.
Chief Counsel’s Report — Chapter 4.7: Kick Detection | 165

Chapter 4.7|Kick Detection

he Chief Counsel‘s team finds that rig personnel missed signs of a kick 

during displacement of the riser with seawater. If noticed, those signs 

would have allowed the rig crew to shut in the well before 

hydrocarbons entered the riser and thereby prevent the blowout. 

Management on the rig allowed numerous activities to proceed without ensuring 

that those operations would not confound well monitoring. Those simultaneous 

activities did confound well monitoring and masked certain data. 

Despite the masking effect, the data that came through still showed clear anomalies.1 The crew 

either did not detect those anomalies or did not treat them as kick indicators.

Well Monitoring and Kick Detection 

A kick is an unwanted influx of fluid or gas into the wellbore. The influx enters the wellbore 

because a barrier, such as cement or mud, has failed to control fluid pressure in the formation. In 

order to control the kick, personnel on the rig must first detect it, then stop it from progressing by 

adding one or more barriers.2 The crew must then circulate the influx out of the wellbore. If the 

crew does not react properly, fluids will continue to enter the wellbore. This will eventually 

escalate into uncontrolled flow from the well—in other words, a blowout.3 

In order to detect a kick, rig personnel examine various indicators of surface and downhole 

conditions. These indicators include pit gain, flow-out versus flow-in, drill pipe pressure, and gas 

content in the mud.4

Pit Gain (Volumetric Comparison)

Pit gain is the difference between the volume of fluid pumped into the well and the volume of 

fluid pumped out of the well. If the well is stable (that is, there are no gains or losses) the two 

should be equal. 

The easiest way to monitor pit gain is to pump fluids into the well from a single pit and route 

returns from the well into the same pit. This is called single-pit monitoring. However, when 

dealing with several different fluids (mud, spacer, seawater), the crew must use several different 

pits to prevent the fluids from mixing. In order to monitor multiple pits, the crew can use the 

active pit system. 

Active Pit System. The active pit system refers to a computer setting that allows the driller 

(and others) to select several pits and aggregate their volumes into one “active pit volume” 

reading. Even though there are several different pits involved, the rig’s computer system 

displays them as a single pit for volume monitoring purposes.5

T
166 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Sperry-Sun data/TrialGraphix

In a closed-loop system, active pit volume will remain constant so long as the well is 

stable. An increase in active pit volume strongly indicates that a kick is under way.

There are several ways to configure the active pit system. In a closed-loop system, the fluids going 

into the well are taken from the active pit system, and the fluids coming out of the well are 

returned to the active pit system. Because volume-in should equal volume-out, the active pit 

volume will stay constant when the well is stable. If the active pit volume increases, that strongly 

indicates that a kick is under way.6 A volume increase should be easily detectable by a positive 

slope in the trend line (seen in Figure 4.7.1) or an uptick in the numerical data. 

Figure 4.7.1. Active pit volume in a closed-loop system.

Monitoring pit gain in a non-closed-loop system is more complex. In a non-closed-loop system, 

fluids are either taken from or returned to places other than the pits on the rig. For instance, 

when rig crews use seawater to displace mud from a well, the rig may pump the seawater in from 

the ocean (and bypass the pits) but still direct mud returns back to the pits.7 In that case, active 

pit volume will increase over time because the returns are filling up the pits (seen in Figure 4.7.2).

To monitor pit gain in a non-closed-loop system, rig personnel must manually calculate the 

volume of seawater pumped into the well (pump strokes × volume per pump stroke) and compare 

it to the volume of mud returning from the well (measured by changes in pit volume).8 

Certain kinds of operations can make it impossible to use pit gain as a kick indicator. For 

example, this happens when return flow from the well goes overboard instead of into a pit. Rig 

personnel generally cannot measure the volume of flow overboard, so they cannot make a 

volume-in/volume-out comparison during such operations.
Chief Counsel’s Report — Chapter 4.7: Kick Detection | 167

Figure 4.7.2. Active pit volume in a non-closed-loop system.

Flow-Out (Rate Comparison)

Flow-in is a calculation of the rate at which fluid is being pumped into the well (pump rate × 

volume per pump stroke). Because it is calculated from known and reliable values, flow-in has a 

small margin of error. It is a trusted value. 

Flow-out is a measurement of the rate at which fluid returns from the well. It is typically 

measured by a sensor in the flow line coming out of the well. As a result, the accuracy of the 

flow-out measurement depends on the quality of the sensor. It is a less reliable value than 

flow-in.9 

If the well is stable, flow-in and flow-out should be equal.

10

 An unexplained increase in flow-out 

is a kick indicator. For example, if the pump rate is constant but flow-out increases, the 

additional flow is likely caused by fluid or gas coming into the wellbore from the formation.11 

The simplest application of this principle occurs when the rig is not pumping fluids into the well

at all. At this point, flow-in is zero, so flow-out should also be zero. Rig personnel can confirm 

that flow-out is zero in two ways: by reading the data from the flow-out meter and by visually 

inspecting the return flow line (performing a flow check). If rig personnel see flow from the well 

at a time when the pumps are off, that is an anomalous observation. While such flow can indicate 

thermal expansion of the drilling fluid, rig heave, or ballooning, it can also indicate that a kick is 

under way.12 In any case, further investigation is warranted. 

When the rig crew first shuts pumps down, it generally takes some period of time for flow-out to 

drop to zero. This reflects the time it takes for the pumps to drain and for circulation to come to a 

stop. During this time period, there continues to be some residual flow.

13

 

Each rig has its own residual flow-out signature—a pattern wherein flow-out dissipates and 

levels off over the course of several minutes.14 It is important that rig personnel identify that 

signature and monitor flow-out for a sustained period of time afterward to confirm that there is 

indeed no flow after the pumps have been shut down.15 

Sperry-Sun data/TrialGraphix

In a non-closed-loop system, active pit volume will increase continuously regardless of 

the well’s stability.
168 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Flow checks constitute an important safeguard and ―double-check‖ ensuring that the well is 

secure. It is therefore a common practice to assign one member of the rig crew to always visually 

confirm that flow has stopped whenever the pumps have been shut down, and announce it to the 

rest of the rig‘s personnel.

Drill Pipe Pressure

Drill pipe pressure is a measurement of the pressure exerted by fluids inside the drill pipe.16 

When the rig pumps are off, drill pipe pressure should remain constant.17 When the density of 

fluids in the well outside the drill pipe is higher than the density of fluids inside the drill pipe, drill 

pipe pressure will be positive. This is because the heavier fluid outside the drill pipe exerts a

u-tube pressure on the fluids inside the drill pipe. 

When the rig crew turns pumps on, drill pipe pressure will fluctuate depending on the relative 

densities of fluids inside and outside of the drill pipe and the circulating friction generated by 

moving those fluids.18 When the pumps are pushing lighter fluid down the drill pipe to displace 

heavier fluid outside it, drill pipe pressure should steadily decrease as the lighter fluid displaces 

the heavier one. 

Drill pipe pressure can be a difficult kick indicator to interpret because so many different factors 

can affect that pressure. For instance, drill pipe pressure might change because of a washout in 

the drill pipe or wear-out of the pump discharge valves.19 But such causes should still prompt the 

driller to stop and check that the rig and well are all right.20 

In a situation where there are changing fluid densities, changing pump rates, and changing 

wellbore geometry, close monitoring of drill pipe pressure can be facilitated by advance planning 

and charts describing what pressures to expect.21 Unexplained fluctuations in drill pipe pressure 

can indicate a kick. 

Some kicks exhibit an increase in drill pipe pressure,22 although an increase can also indicate a 

clog in the pipe or that the crew is pumping the wrong fluids into the well.23 More commonly, it is 

a decrease in drill pipe pressure that indicates a kick; lighter oil and gas flow into the annulus 

around the drill pipe and thereby lower the drill pipe pressure.24 But a decrease in drill pipe 

pressure can also indicate a hole in the drill pipe.25 In any case, unexplained fluctuations in drill 

pipe pressure are a cause for concern and warrant further investigation.26 

Gas Content

Gas content refers to the amount of gas dissolved or contained in a fluid. Fluid returns from a 

well can contain gas for several reasons. Some amount of gas is often present in a well during 

normal operations, depending on the mud type and the location of the well. And ―trip gas‖ 

appears when tripping out of the hole and conducting a bottoms up circulation after a trip. 

An increase in the gas content of fluid returns over time can indicate an increase in pore 

pressure,27 penetration of a hydrocarbon-bearing zone, or a change in wellbore dynamics allowing 

more effective cuttings removal.28 But unexplained increases in gas content are always a cause for 

concern. They can indicate either that a kick is occurring or that wellbore conditions are 

becoming conducive for a kick.29
Chief Counsel’s Report — Chapter 4.7: Kick Detection | 169

Figure 4.7.3. Hitec data display. Figure 4.7.4. Sperry-Sun data display.

Fred H. Bartlit, Jr. 

Photos taken on Transocean’s Deepwater Nautilus.

Sensors and Displays

Rig personnel rely on data that are recorded and displayed by proprietary sensors, hardware, and 

software. For the Deepwater Horizon, Transocean hired National Oilwell Varco (NOV) to 

provide Hitec-brand sensors, driller‘s chairs, and displays for the rig.30 BP contracted 

Sperry Drilling, a Halliburton subsidiary, to conduct additional independent mud logging and 

well monitoring services.31

NOV placed a comprehensive set of sensors on the rig that measured various drilling parameters 

and surface data, including flow-in, flow-out, pit volume, drill pipe pressure, block position, and 

hook load.32 The Hitec system recorded and displayed only the data from the Hitec sensors. 

Sperry Drilling‘s Sperry-Sun system collected data from many of the Hitec sensors,33 including 

the sensors for pit volumes, flow-in, drill pipe pressure, and kill line pressure.34 It also collected 

data from separate Sperry-Sun sensors, including Sperry-Sun sensors for flow-out and 

gas content.35 

Sperry Drilling and NOV both provided BP and Transocean with proprietary displays consisting 

of real-time numerical data, historical trend lines, and other features like tables and charts.36 

Each of the systems allowed users to manually set (and constantly adjust) audible and visual 

alarms for various data parameters, including pit gain, flow-out, and drill pipe pressure.37 The 

alarms could be set to trigger whenever incoming data crossed preselected high and low 

thresholds, and could also be shut off.

38

While the Hitec and Sperry-Sun data systems displayed similar data, they did so using 

significantly different visual design (seen in Figures 4.7.3 and 4.7.4).

Because the two systems in many cases used the same underlying sensors, most of the numerical 

values should have been close if not identical.39 Where they displayed data from different sensors, 

the differences were usually predictable and could generally be dealt with through calibration.40 

Hitec and Sperry-Sun each had its own flow-out sensor in the return flow line. These flow-out 

sensors differed in type, location, and format. Hitec had a paddle-type flow-out sensor.41 As fluid 

Sambhav N. Sankar
170 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

rushed past, it pushed and lifted the paddle. The Hitec system inferred the rate of flow from the 

degree of paddle elevation. Sperry-Sun, by contrast, used a sonic-type sensor.42 The sensor 

emitted a beam to ascertain the height of the fluid. The Sperry-Sun system inferred the rate of 

flow from the fluid level.43 

The Hitec flow-out sensor was located in the return flow line before the line forked to either send 

returns to the pits or send them overboard.44 The Sperry-Sun sensor was located after the fork, 

capturing flow-out only when returns from the well were routed to the pits.45 (Positioning of both 

sensors is illustrated in Figure 4.7.5.) This means that the Hitec flow-out sensor could register 

returns going overboard, but the Sperry-Sun sensor could not.46 

In addition to the data display systems, the rig also had video cameras that monitored key areas 

and components, including the rig floor and the flow line. The flow line camera (also illustrated 

in Figure 4.7.5) simply pointed at the flow line. Like the Sperry-Sun flow-out sensor, this camera 

was located after the fork; rig personnel could use it to observe flow returning to the pits but not 

flow that had been routed overboard.47 When returns were sent overboard, rig personnel could 

still visually inspect for flow but could not do so using the video camera. They had to physically 

look behind the gumbo box (which was located before the fork).48

Figure 4.7.5. Flow-out sensors and flow line camera.

TrialGraphix

The Sperry-Sun flow-out sensor and the rig’s flow line camera could not register returns 

going overboard. The Hitec flow-out sensor could, but data from the Hitec flow-out sensor 

sank with the rig.
Chief Counsel’s Report — Chapter 4.7: Kick Detection | 171

Figure 4.7.6. Transocean’s Deepwater Horizon Emergency Response Manual.

The rig‘s sensors and display equipment appear to have been working properly at the time of the 

blowout. There is no evidence that the Sperry-Sun system malfunctioned. It continued recording 

and transmitting data up until the first explosion. The Hitec system was also ―in satisfactory 

condition,‖ as an April 12 rig condition assessment recorded in some detail.49 

The crew had expressed some complaints about the driller‘s and assistant driller‘s control chairs, 

known as the ―A-chair‖ and ―B-chair‖ respectively.50 The computer system powering the chairs‘ 

controls and displays had ―locked up‖ or crashed on several occasions.51 When this happened to 

the A-chair, the driller‘s screens would either freeze or revert to a blank blue screen, disabling 

real-time data display on the screen and requiring the driller to move to the adjacent B-chair.52 

In response, Transocean replaced the chairs‘ hard drives.53 This appears to have corrected the 

problem.54 The April 12 assessment found that the software on all of the chairs ―was stable and 

had not shown (excessive) crashes.‖55 There is no evidence that the chairs malfunctioned on 

April 20.56 

Personnel and Places 

On the Rig

Rig data are available in various forms to personnel on the rig and onshore. The Hitec data, 

Sperry-Sun data, and video feeds were all available to personnel on the rig, in real time, anywhere 

there was a television.57 Certain individuals had more extensive data displays depending on their 

level of well monitoring responsibility.

On the Deepwater Horizon, the Transocean driller and assistant driller, and the Sperry Drilling

mudlogger, were directly responsible for well monitoring. 

The driller was responsible for monitoring well conditions at all times, interpreting and 

responding to downhole conditions, and securing the well in a well control situation (see 

Figure 4.7.6).

58

 The driller sat in the A-chair in the drill shack. He normally monitored three 

screens: two screens in front of him that displayed Hitec data and a screen to the side with 

Transocean
172 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Sperry-Sun data.59 He also had a screen with live video feeds and a window straight ahead 

with a direct view of the rig floor.60 The driller was supposed to actively look at his data screens 

during well operations.61 He contemporaneously recorded rig activities for each day‘s daily 

drilling report.62 

The driller was the central point of contact for all well control concerns: Anyone with ―an 

understanding of something that may have indicated a well control event, would have called back 

to the driller, most likely, and informed him.‖ 63 He was the one who had the most information 

about current operations on the rig and the ability to react to them.64 

The assistant driller was also responsible for monitoring the well and taking well control actions. 

He served as a crucial backup and assist to the driller. The assistant driller was expected to have 

―a comprehensive understanding of well control‖ and ―be able to recognize the signs of a well kick 

or blowout before it develops into an emergency condition.‖65 He assisted the driller in 

monitoring the drilling instrumentation and recognizing and controlling well conditions.66 As 

part of that assistance, he monitored the pit volumes and from time to time would go to the pits 

and check in with the derrickhand to make sure all was well.67

There were two assistant drillers on duty at any one time. One sat in the B-chair, adjacent to the 

driller in the drill shack.68 He had access to the same screens as the driller. If there was activity 

on the deck—like pipe handling—another assistant driller would sit in the ―C-chair‖ in the 

auxiliary driller‘s shack.69 Although the assistant drillers had many responsibilities, at least one 

should have been monitoring the well at any given time.70

The Sperry Drilling mudlogger also monitored the well, serving as a second set of eyes for the 

Transocean crew.71 BP specifically contracted the mudloggers for this purpose.72 It was the 

mudloggers‘ duty to continuously monitor operations and provide well and drilling data upon 

request. They watched the data but did not have any control over rig operations and could not 

respond directly themselves. If the mudloggers identified problems, they would notify the driller 

(or drill crew).73 

The mudlogger sat in the mudlogger‘s shack, one flight of stairs away from the drill shack.74 He 

had 12 monitoring screens arranged in two rows of six. These screens displayed both Hitec and 

Sperry-Sun data.75 Among the screens, the mudlogger had a display to the left showing all of the 

rig‘s pit volume levels. Below that, the mudlogger had a graphical log and a digital readout of the 

Hitec numbers.76 He also had a screen with live video feed from the rig‘s cameras—he could 

switch between channels showing the flow line, the rig floor, and other areas.77 In addition to 

monitoring the well, the mudlogger performed formation analysis when the rig was drilling and 

provided data printouts and reports.78 

Several individuals supervised well monitoring work by the driller, assistant driller, 

and mudlogger. 

The BP well site leader had responsibility for overseeing all operations on the well. That 

responsibility involved delegating duties like minute-by-minute monitoring of data.79 Some well 

site leaders did monitor the well during critical operations.80 To facilitate such monitoring, the 

well site leaders‘ office had screens that constantly displayed the Hitec data, Sperry-Sun data, and 

live video feeds.81 The Sperry Drilling mudloggers reported to the BP well site leader. 
Chief Counsel’s Report — Chapter 4.7: Kick Detection | 173

The Transocean toolpusher supervised the driller and ensured that all drilling operations were 

carried out safely, efficiently, and in accordance with the well program.82 That included 

confirming that all well control requirements were in place, performing all well control 

calculations, and assisting in killing the well in emergency situations.83 The toolpusher was 

generally on the rig floor at all times, had access to the driller‘s and assistant driller‘s monitors, 

and had a small office inside the drill shack.84 

The toolpusher reported to the senior toolpusher. The senior toolpusher had a similar job 

description as the toolpusher but was one level higher in the hierarchy.

85

 Although he had no

continuous role in operations and was not generally on the rig floor, the senior toolpusher was 

supposed to be consulted when there were anomalies or emergencies. In a well control event, the 

senior toolpusher organized response actions and acted as a liaison to the well site leader.86 The 

senior toolpusher reported to the offshore installation manager. 

The offshore installation manager (OIM) was the senior-most Transocean drilling manager 

on the rig and oversaw the entire Transocean crew. He assisted with abnormal or emergency 

situations.87 Both the senior toolpusher and OIM had separate offices away from the rig floor, 

near their living quarters, that included data displays.88

Onshore

Onshore, only the Sperry-Sun data were available in real time.89 The Hitec data and video feeds 

did not go to shore.90 

BP personnel could view the Sperry-Sun data in their Houston offices and in an operations room 

for the Deepwater Horizon that had dedicated data displays.91 They could also view the data over 

a secure Internet connection.92 Personnel at Anadarko and MOEX could access the Sperry-Sun

data onshore as well.

93

 BP, Anadarko, and MOEX appeared to have used real-time data to 

examine geological and geophysical issues.94 

Sperry Drilling personnel could access the Sperry-Sun data in their Houston real-time center and 

Lafayette operations office.95 They appeared to have used their access to provide customer 

support and quality control.96 

None of the entities receiving the Sperry-Sun data onshore appears to have monitored the data for 

well control purposes.97 (Transocean did not receive data onshore.98) 

Table 4.7.1. Personnel and places with access to the rig’s Sperry-Sun data.

Rig: Responsible for 

Monitoring Data

Rig: Accountable for Operations Onshore: Could Access Data 

in Real Time

 Transocean driller

 Transocean assistant driller

 Sperry-Sun mudlogger

 BP well site leader

 Transocean OIM

 Transocean senior toolpusher

 Transocean toolpusher

 BP

 Anadarko

 MOEX

 Sperry-Sun

 
174 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Figure 4.7.7. Rig personnel on duty 

during the final displacement.

TrialGraphix

Well Monitoring at Macondo 

It is difficult to know exactly what data screens rig personnel were looking at during their final 

hours on the Horizon.

99

 There were multiple screens, with multiple data types, and each was 

highly customizable.100 This Report relies on the Sperry-Sun historical log for its data analysis 

because that log is the only surviving dataset and display from the rig.101 

The Sperry-Sun data log is valuable. This log (or something very close to it) was ―the actual log 

that they were watching on the Horizon‖102—it was displayed on one of the several screens in front 

of the driller, assistant driller, mudlogger, and company man. The drill 

pipe pressure presented on the Sperry-Sun screen was collected from

Transocean‘s Hitec data sensors. Accordingly, the data values shown on 

the available Sperry-Sun screen formats would also have been shown on 

the Hitec screens. 

Witness accounts suggest that the driller, assistant driller, and 

mudloggers all watched the Sperry-Sun data log.

103

 The numerical values 

reflected in the data log would have been available on other screens as 

well.104 And one can reasonably expect that rig personnel monitoring the 

well would have had (or should have had) pit volumes, flow-out, flow-in, 

and drill pipe pressure reflected in the log somewhere on their screens—

no matter the format.105 

At the same time, the Sperry-Sun data have significant limitations. The 

log is not fully inclusive: It does not contain data from the Hitec flow-out 

sensor. And scrutinizing the complete log carefully in retrospect is 

significantly different from monitoring it in real time, while the trend 

lines are developing.106 

The First Hour

After cementing the production casing and conducting pressure tests that 

had been deemed successful, the crew moved on to the remainder of the 

temporary abandonment procedure. The crew would displace mud and 

spacer from the riser with seawater. There were several stages in the 

planned displacement. First, rig personnel would pump seawater down 

the drill pipe to displace mud from the riser until the spacer fluid behind 

the mud reached the rig floor. They would then shut down the pumps 

and conduct a ―sheen test.‖ That test would confirm that the crew had 

displaced all of the oil-based mud from the riser. The crew would then 

change the lineup of valves to send further returns from the well (spacer) 

overboard rather than to the mud pits. They would then resume the 

displacement until all of the spacer was out of the wellbore and the riser 

was full of nothing but seawater.107 

At the start of the displacement process, Transocean driller Dewey 

Revette was in the drill shack‘s A-chair, monitoring the well. Transocean 

assistant driller Stephen Curtis was likely in the drill shack‘s B-chair, also 

monitoring the well.108 BP well site leader Don Vidrine was in the drill 
Chief Counsel’s Report — Chapter 4.7: Kick Detection | 175

Figure 4.7.8. Erratic vs. normal flow-out.

Sperry-Sun data/TrialGraphix 

Flow-out readings appear to have been more erratic 

than normal during the final displacement, perhaps 

because crane operations were causing the rig to sway.

shack to oversee the initiation of the displacement.

109

 Donald Clark, the other Transocean 

assistant driller, was at the bucking unit (a machine for making up pipe) on the port aft deck, 

working with personnel from Transocean, Weatherford, and Dril-Quip to prepare for setting the 

lockdown sleeve.110 Sperry Drilling mudlogger Joseph Keith was in the mudlogger‘s shack, 

monitoring the well.111 

At 8:02 p.m., the crew began displacing the mud and spacer in the riser with seawater.112 The 

pumps were not lined up in a closed-loop system. Instead, the crew was pumping seawater from 

the ocean through the sea chest and into the well. This bypassed the pits. Returns from the well 

were flowing into the active pits (in this case, pits 9 and 10).113 As a result, individuals monitoring 

the well could not rely on the ―pit volume change‖ display.114 To monitor pit gain, rig personnel 

would have had to perform volumetric calculations comparing the increase in pit volume 

(reflecting returns) against the volume of seawater pumped into the well (pump strokes × volume 

per stroke).115 There is no evidence, one way or the other, as to whether the crew performed such 

volumetric calculations. 

This setup should not have impaired rig personnel‘s ability to monitor flow-out versus flow-in. 

However, the flow-out readings appear to have been more erratic than readings captured the 

previous day (seen in Figure 4.7.8). This may be because cranes were moving on the rig‘s deck, 

causing the rig to sway and thus affecting the level of fluids in the flow line.116 Otherwise, 

flow-out appeared normal.117

This setup also should not have 

impaired rig personnel‘s ability to 

monitor drill pipe pressure. The 

drill pipe pressure appears to have 

behaved as expected. It rose 

initially as the pumps turned on 

and then decreased gradually as 

lighter seawater replaced the 

heavier mud and spacer in the

riser. At 8:10 p.m., mud engineer 

Leo Lindner looked at the drilling 

screen and ―thought everything 

was fine.‖118 At 8:16 p.m., the data 

showed an increase in gas units—

not atypical at the start of 

circulation.119 The gas readings 

then tapered off as the last of the 

mud left the wellbore.120
176 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

From 8:28 to 8:34 p.m., the crew emptied the trip tank (pit 17), with the fluid going into the flow 

line and pits with the rest of the returns. This complicated the monitoring of both the pits and 

flow-out. To accurately monitor either parameter, 

the crew had to perform calculations to subtract the 

effect of emptying the trip tank from the pit volume 

and flow-out readings that appeared on-screen. It is 

unknown whether the crew did so. 

At 8:34 p.m., the crew did three things 

simultaneously. They (1) directed returns away from 

the active pits (pits 9 and 10) and into a reserve pit 

(pit 7); (2) emptied the sand traps into the active pits 

(pits 9 and 10); and (3) began filling the trip tank 

(pit 17).121 Each of these actions further complicated 

pit monitoring for well control purposes. The active 

pit system was eliminated as a well monitoring tool. 

In order to know the volume coming out of the well, 

the crew had to perform calculations taking into 

account that returns were going to two different 

places—the reserve pit (pit 7) and the trip tank (pit 

17). In addition, routing returns to the trip tank 

bypassed the flow-out meter, so the flow-out reading 

appeared artificially low and had to be added to the 

rate of entry of fluids into the trip tank to ascertain actual flow-out.122 Again, it is unknown 

whether the crew was performing any such calculations. In addition, communication between the 

rig crew and mudlogger may have broken down at this time: The drill crew did not inform Keith 

about the switch in pits.123 Keith did notice a slow gain in the active pits and called M-I SWACO 

mud engineer Leo Lindner to inquire; Lindner said they were moving the mud out of the sand 

traps and into the active pits.124

At 8:49 p.m., the crew again rerouted returns, this time from one reserve pit (pit 7) to another 

(pit 6). At about this time, the displacement process had underbalanced the well. The combined 

hydrostatic pressure at the bottom of the well (generated by the mud and spacer still in the riser, 

the seawater in the riser and the well, and the mud remaining in the well beneath 8,367 feet below 

sea level) dropped below the reservoir pressure. 

Transocean‘s post-explosion analysis estimates that the well became underbalanced at 

8:50 p.m.125 BP‘s post-explosion modeling estimates that the time was 8:52 p.m.126 Given the 

failed bottomhole cement job, hydrocarbons would have begun flowing into the well at this time.

At 8:52 p.m., Vidrine called BP‘s shoreside senior drilling engineer Mark Hafle to ask about the 

procedure for testing the upcoming surface cement plug. Hafle asked Vidrine if everything was 

OK. Hafle had the Sperry-Sun real-time data up on-screen in front of him. It does not appear 

that the two discussed the rig crew‘s handling of the displacement or rig activities complicating 

well control monitoring.127 

In retrospect, it does not appear there were (or would have been) any signs of a kick prior to about 

9 p.m. Nevertheless, between 8 and 9 p.m., rig personnel did not adequately account for whether 

Trip Tank. A trip tank is a small 

tank. Its primary purpose is to hold 

fluid that the drill crew may need to 

rapidly send into the well, for 

example, to compensate for the 

volume removed when pulling out the 

drill pipe (known as tripping the 

pipe). The drill crew also uses the 

trip tank to monitor the well. The 

trip tank is situated between the well 

and the mud pits. When emptied, 

fluid from the trip tank goes into the 

return flow line, past the flow-out 

meters, and into the same pits as the 

returns from the well. The Horizon 

had two trip tanks.
Chief Counsel’s Report — Chapter 4.7: Kick Detection | 177

and to what extent certain simultaneous operations, such as emptying the trip tanks, may have 

confounded their ability to monitor the well.

Indications of an Anomaly as Early as 9:01 p.m.

Just before 9 p.m., Keith left the mudlogger‘s shack to take a short break.128 He notified the drill 

crew (by calling Curtis) and then stepped out.129 He went downstairs, used the restroom, got a 

cup of coffee, and smoked half a cigarette.130 He was apparently gone for about 10 minutes before 

returning to his post.131 

At 8:59 p.m., the crew simultaneously decreased the pump rate on all three pumps and began 

emptying the trip tanks.132 The decrease in the pump rate should have caused a decrease in the 

flow-out, but because emptying the trip tanks sent additional fluid flowing past the flow-out 

meter, the flow-out reading actually increased. That increase potentially masked any sign of a 

kick from the flow-out reading.133

At 9:01 p.m., drill pipe pressure changed direction. Instead of continuing to steadily decline, it 

began to increase. This change in direction was a significant anomaly. If lighter seawater were 

replacing the heavier mud and spacer in the riser as should have been the case, drill pipe pressure 

should have continued to drop, as it had done for at least the previous 40 minutes.134 In 

retrospect, this change in drill pipe pressure likely indicated that hydrocarbons were pushing 

heavier mud up from the bottom of the well against and around the drill pipe.

By 9:08 p.m., with the pump rates constant, drill pipe pressure had increased by approximately 

100 pounds per square inch (psi). The magnitude of the increase would have appeared subtle on 

the Sperry-Sun screen showing only trend lines, but it likely would not have been subtle on the 

numerical displays.135 

The change in direction was by now clear and clearly anomalous. An individual who saw the drill 

pipe pressure increase should have been seriously concerned and should have investigated 

further.136 But Keith, who would have returned from his break by that time, reviewed the logs for 

the period he was absent and did not notice any indication of a problem: ―I went back over it and 

looked, and to my recollection, I didn‘t see nothing wrong.‖137 

At 9:08 p.m., after the top of the spacer column reached the rig, the crew shut down the pumps 

and switched the lineup to route returns overboard.138 Keith looked at the video feed from the 

flow line camera and visually confirmed that there was no flow.139 He likely communicated this to 

the rig floor.140 According to Vidrine, who was on the rig floor, everything looked fine.141 

Everything was not fine. For about a minute after the pumps stopped, flow-out continued beyond 

the Horizon‘s typical flow-out signature.142 This was a kick indicator (Figure 4.7.9 depicts a 

typical flow-out signature at 4:52 p.m. and the 9:08 p.m. spike). A driller, assistant driller, or 

mudlogger watching the screen could have seen it.143 Instead, they thought they had visual 

confirmation of no flow, based at least on Keith‘s observations.144 
178 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Sperry-Sun data/TrialGraphix

For about a minute after the pumps stopped at 9:08 p.m., flow-out continued beyond the 

Horizon’s typical flow-out signature.

Figure 4.7.9. Typical flow-out signature vs. spike at 9:08 p.m.

There are several possible explanations for this contradiction: (1) Keith may have seen some flow 

but attributed it to residual flow; (2) Keith may not have looked at the camera for long enough to 

realize that it was not residual flow;

145 (3) the flow may have been too modest to detect from the 

video feed;146 or (4) the flow may already have been rerouted overboard before Keith performed 

his flow check.147 Rig personnel could have performed a secondary flow check by sending 

someone to physically look behind the gumbo box, but apparently they did not do so. On many 

rigs (including the Horizon148), this would have been a common practice, especially if rig 

personnel had noted anomalies.149 

By 9:10 p.m., the crew had rerouted returns overboard. Doing so bypassed the pits, the 

Sperry-Sun flow-out meter, and the gas sensors.150 That equipment could no longer be used to 

monitor the well. The flow did not bypass the Hitec flow-out meter, but for some reason—

perhaps malfunction, perhaps neglect—data from that meter never alerted the crew to the kick. 

At about the same time that they rerouted returns overboard, the crew also transferred mud from 

the active pits (pits 9 and 10) to the reserve pit that had been taking returns from the well (pit 6). 
Chief Counsel’s Report — Chapter 4.7: Kick Detection | 179

Sperry-Sun data/TrialGraphix

At 9:01 p.m., drill pipe pressure changed direction. By 9:08 p.m., with the pump rates 

constant, drill pipe pressure had increased by approximately 100 psi. From 9:08 to 

9:14 p.m., while the pumps were shut down, drill pipe pressure increased by 

approximately 250 psi. Each of these changes in drill pipe pressure was an anomaly 

that should have prompted rig personnel to stop and investigate, but the signs apparently 

went unnoticed. 

The crew probably made this pit transfer to prepare for cleaning out the active pits (pits 9 and 

10).151 The immediacy of the transfer suggests that the crew did not take the time to compare the 

volume of fluid pumped into the well with the volume of fluid returned from the well. 

Meanwhile, the mud engineers conducted the sheen test and communicated to the drill shack that 

it passed. Vidrine directed the crew to get in place to start sending returns overboard and ordered 

the displacement to begin again. He then returned to his office and did paperwork. 

During the course of these activities, drill pipe pressure gradually increased. From 9:08 to 

9:14 p.m., while the pumps were shut down, drill pipe pressure increased by approximately 

250 psi (see Figure 4.7.10). This was a significant anomaly.152 By 9:14 p.m., the increase would 

have been noticeable and a cause for concern.153 The driller apparently missed this increase, 

perhaps because ―having looked and seen 60 seconds of constant pressure...he may have then 

turned to do the next step in the process which was line up another mud pump to pump down the 

kill lines.‖154 It is unclear why the assistant driller and the mudlogger also missed the increase.155

Figure 4.7.10. Drill pipe pressure anomalies from 9:01 to 9:14 p.m.

At 9:14 p.m., the drill crew turned the pumps back on: first, pumps 3 and 4 at 9:14 p.m., then 

pump 1 at 9:16 p.m. Keith called Curtis and asked why the drill crew was turning the pumps on 

gradually and not at full rate. Curtis replied, ―That‘s the way we‘re going to do it this time.‖156 

Shortly after 9:17 p.m., the crew also turned on pump 2 to pump down the kill lines. Within 

seconds of turning on pump 2, the pressure relief valve (PRV) on pump 2 blew.157 The PRV 

probably blew because the crew had inadvertently started the pump against a closed kill line valve 

(a rare but not unheard-of mistake).158 

After the PRV blew, at 9:18 p.m., the crew shut down the primary pumps (pumps 3 and 4). They 

left the riser boost pump (pump 1) on. The driller organized a group of individuals including 

Clark to go to the pump room and fix the PRV on pump 2.159 In addition, the driller ordered 

someone to open up the closed kill line valve that had caused the PRV to blow.160 

At 9:20 p.m., the drill crew restarted the primary pumps (pumps 3 and 4). Transocean senior 

toolpusher Randy Ezell called the drill shack and spoke with toolpusher Jason Anderson. He 
180 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Sperry-Sun data/TrialGraphix

At 9:27 p.m., kill line pressure reached approximately 800 psi. From 9:30 to 9:35 p.m., 

while the pumps were shut down, drill pipe pressure increased by approximately 550 psi. 

After the crew attempted to bleed it down, drill pipe pressure again shot up, at 9:38 p.m., 

by approximately 600 psi. Each of these anomalies was a sign that fluids were moving in 

the well. Despite observing those signs, the crew did not yet shut in the well.

asked how the displacement was going. Anderson said, ―It‘s going fine. It won‘t be much 

longer...I‘ve got this.‖161 From 9:14 to 9:27 p.m., the data did not clearly reflect any anomalies. 

The return flow bypassed the pits, Sperry-Sun flow-out meter, and gas sensors. Drill pipe 

pressure appeared to be behaving roughly as expected—increasing as the pumps ramped up and 

then decreasing as seawater replaced the last of the spacer.162

Drill Crew Notices Anomaly but Does Not Treat It as a Kick

By 9:27 p.m., an obvious anomaly appeared. The pressure on the kill line—now discernable

because the drill crew had just opened up the previously closed kill line valve—rose to 

approximately 800 psi.163 This kill line pressure was anomalous.164 The crew noticed a

―differential pressure‖ between the kill line (approximately 800 psi) and the drill pipe 

(approximately 2,500 psi).165 At 9:30 p.m., they shut down the pumps to investigate.166 

Around that time, Transocean chief mate David Young went to the drill shack to speak with 

Anderson and Revette about the timing of the surface plug cement job.167 Revette, sitting in the 

driller‘s A-chair, and Anderson, standing next to him, were speaking to each other.168 At times, 

they looked at the driller‘s screens.169 Revette noted that they were ―seeing a differential.‖170 The 

two men appeared concerned but calm. According to Young, ―It was quiet...there was no panic or 

anything like that.‖171 

From 9:30 to 9:35 p.m., drill pipe pressure increased by approximately 550 psi (see Figure 4.7.11). 

This was another significant anomaly: With the pumps shut off, there should have been no 

movement in the well.172 (The increase might have reflected mud continuing to travel up the 

wellbore with oil and gas below.)173 Revette and Anderson were intently watching the screens, but 

they did not shut in the well. Instead, Revette ordered Transocean floorhand Caleb Holloway to 

bleed off the drill pipe pressure174—apparently to eliminate the differential pressure. At 

9:36 p.m., Holloway cranked open a valve on the stand pipe manifold to bleed down the 

pressure.175 But it was taking longer than usual to bleed off.176 Revette told Holloway, ―Okay, 

close it back.‖177

Figure 4.7.11. Drill pipe pressure and kill line pressure anomalies from 

9:27 to 9:40 p.m.
Chief Counsel’s Report — Chapter 4.7: Kick Detection | 181

Once he did, at 9:38 p.m., the drill pipe pressure shot back up. It increased by approximately 

600 psi. Again, the increase was a serious anomaly. 

By this point, rig personnel had observed several serious anomalies. Each was ―a sign that fluids 

are moving‖ in the well.178 Those anomalies should have ―caused alarm.‖179 But there appears to 

have been no hint of alarm. 

The crew actively investigated the anomalies and performed diagnostic interventions. But it 

appears that the crew did not perform the most basic kick detection intervention—a flow check. 

If they had done so, they would have directly seen flow coming out of the well and should have 

shut in the well.180 The fact that the crew apparently did not perform a flow check suggests that 

Revette and Anderson either did not consider or had already ruled out the possibility of a kick. 

Anderson thought ―it would be a little bit longer‖ before they figured out the differential pressure 

and told Young that they probably wouldn‘t need him for the cement job meeting for another 

couple of hours.181 According to Young, Anderson ―wasn‘t sure if they were going to need to 

circulate.‖182 Anderson then left to go to the pump room.183 Young also left at about the same 

time.184 He ran into Holloway, who was coming down from the stand pipe manifold; they spoke 

for a couple of minutes and joked.185 There was no sign of concern or hurry.186 

Not long afterward, Holloway was leaving the rig floor and ran into Curtis. Curtis was on his way 

to the drill shack. He was in no rush. Curtis and Holloway spoke for a few minutes.187

Throughout this period of investigation, the drill crew did not communicate with the mudlogger 

about the anomaly.188 Nor did they contact the senior toolpusher, OIM, or well site leader to ask 

for their help or to notify them that something was amiss.

Mud Overflow and Recognition of the Anomaly as a Kick 

Sometime between 9:40 and 9:43 p.m., mud overflowed onto the rig floor, shot up to the top of 

the derrick, and poured down onto the main deck.189 By about that time, drill pipe pressure had 

decreased by approximately 1,000 psi. At 9:41 p.m., the trip tank (pit 18) abruptly gained about 

12 barrels in volume. The crew likely routed flow back to the trip tank intentionally to help 

diagnose whether the riser was static.190 The gain showed that there was still flow from the well 

up the riser. 

At about the same time, Anderson returned to the drill shack. At 9:41 p.m., he activated the 

blowout preventer‘s (BOP‘s) annular preventer.191 Drill pipe pressure began to increase (as it 

should when a well is shut in). By now, gas would already have been in the riser, expanding 

rapidly on its way to the surface. This may have made it more difficult to successfully activate the 

blowout preventer. In any case, even if the crew had successfully shut in the well, they should 

have expected flow from the well to continue at least until all of the gas in the riser had escaped.

Interviews and testimony after the blowout recount what happened next. Anderson called 

Vidrine to say the crew was getting mud back and had diverted flow to the mud gas separator and 

closed the annular.192 Curtis called Ezell and said: ―We have a situation. The well is blown out. 

We have mud going to the crown.... [Anderson] is shutting it in now.‖193 Someone, perhaps 

Revette, called Andrea Fleytas on the bridge, said ―We have a well control situation,‖ and hung 

up.194 Vidrine started for the rig floor.195 Ezell did the same.196 Fleytas turned to Yancy Keplinger 

and yelled, ―We‘re in a well control situation.‖197 Keplinger radioed the Damon Bankston, 
182 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

alongside the rig,198 and told the vessel to disconnect and move off 500 meters: The Horizon was 

in a well control situation.199

Although Anderson had activated the annular preventer, that action had not fully shut in the well. 

Instead of reaching the expected shut-in pressure (approximately 6,000 psi), drill pipe pressure 

plateaued at about 1,200 psi.200 In response, the drill crew either tightened the annular to create a 

seal or activated a variable bore ram.201 At 9:47 p.m., drill pipe pressure increased dramatically. 

At this point, the well may have been shut in.202 

At 9:48 p.m., pit 20 abruptly gained 12 barrels in volume. The data also show an increase in 

active pit volume (pits 9 and 10) and several upward spikes in flow-out. Flow from gas already in 

the riser might have been jostling the rig or otherwise overwhelming the rig‘s systems.203

The first explosion happened at 9:49 p.m. At the time, Anderson, Revette, and Curtis were in the 

drill shack, trying to get the well under control. Vidrine had been on his way to the drill shack 

but, seeing mud blowing everywhere,204 turned back toward the bridge.205 Ezell was at the 

doorway of his office, on his way to the rig floor. Clark and three others were in the pump room; 

they had just finished fixing the PRV.206 Keith was in the mudlogger‘s shack, apparently surprised 

that anything went wrong.207 Transocean OIM Jimmy Harrell was in the shower, with no 

knowledge that there had been a well control situation.208 

Technical Findings

The data available to rig personnel showed clear indications of a kick.209 The change in direction 

of drill pipe pressure (9:01 p.m.) and its subsequent steady increases (9:01 to 9:08 p.m., 9:08 to 

9:14 p.m.) should have been a cause for concern but apparently went unnoticed. Even after the 

drill crew noticed an anomaly (9:30 p.m.), they do not appear to have seriously considered the 

possibility that a kick was occurring. 

The anomaly the rig crew noticed at 9:30 p.m. and discussed occurred before hydrocarbons had 

entered the riser and 10 to 13 minutes before mud appeared on the rig floor. If the rig crew 

had at all considered that a kick might be occurring, they had plenty of time to activate the 

blowout preventer. 

Rig Activities Potentially Confounded Kick Detection

The crew on the Deepwater Horizon engaged in a number of concurrent activities during 

displacement of the riser. Each could have interfered with the data.210 

First, rig personnel were pumping seawater directly into the well from the sea chest. The crew 

had to pump water in from the sea chest for the displacement. But pumping it in directly from 

the sea chest to the rig pumps, thereby bypassing the pits, made it harder for the crew to monitor 

the pits. It created a non-closed-loop system that made it impossible to detect a kick by visually 

monitoring pit gain. Instead, pit monitoring required volumetric calculations. The crew could 

have, and should have, performed those calculations211—it was the rig crew‘s regular practice to 

do so212—but there is no evidence that they did so here. They also could have routed the seawater 

through the active pit system before sending it down the well.213 That approach would have 

preserved visual monitoring of pit gain.
Chief Counsel’s Report — Chapter 4.7: Kick Detection | 183

Second, rig personnel sent returns overboard during the latter part of the displacement. Sending 

returns overboard was an inherent part of the displacement. But pumping it directly from the 

well overboard—bypassing the pits, Sperry-Sun flow-out meter, and both gas meters—eliminated 

the crew‘s ability to monitor the pits and the Sperry-Sun flow-out meter for kick indicators.214 

The crew could still monitor the well by using the Hitec flow-out meter and by physically checking 

the overboard line whenever the pumps were stopped. But there is no evidence that they did so. 

The crew could also have lined up the displacement so that it did not confound well monitoring by 

taking returns to the pits first and then channeling it overboard. 

Third, rig personnel were using the cranes. From early in the displacement (about 8:20 p.m.) 

until the explosion, rig personnel were operating one or both of the cranes.215 Crane movement 

can cause the rig to sway,216 affecting the flow-out levels and pit volumes,217 and ―complicat[ing] 

kick recognition.‖218 Rig personnel can still detect kicks when there is rig sway, but the movement 

increases the level of background noise in the data and thereby reduces the minimum detectable 

kick sensitivity with respect to flow-out and pit volumes.219 The crane movement was not 

necessary for the displacement. Rig personnel could have waited until the displacement was 

complete to engage in crane activity. 

Fourth, rig personnel appear to have begun emptying the mud pits without first checking for pit 

gain. During the sheen test, the rig crew began emptying the active pits into reserve pit 6. Until 

that point, returns from the well had been flowing to pit 6. The problem is, the crew does not 

appear to have measured the volume in pit 6 before emptying the active pits into it. This suggests 

that the crew was not mathematically comparing the actual volume of returns to the expected 

volume of returns to verify that there had been no gain. The apparent reason that rig personnel 

emptied the active pits was to prepare for cleaning them.220 It was unnecessary to clean the active 

pits, or even empty them in preparation for cleaning, during the displacement. 

Fifth, rig personnel were emptying the sand traps into the pits.221 Sand traps separate sand from 

mud. After a while, they fill up with clean mud. When that happens, the crew empties the mud 

from the sand traps into the pits. Emptying the sand traps was not problematic by itself. The 

problem was that the crew emptied them into the active pit system and thereby complicated pit 

monitoring. The crew could have simplified pit monitoring by using the active pit system to 

monitor the volume of fluid returning from the well and routing mud from the sand traps to a 

reserve pit instead.

Sixth, rig personnel were emptying the trip tanks during the displacement. It appears that the 

crew had to do so at this point in the displacement process.222 It also appears that the rig‘s 

plumbing forced the crew to route flow-out from the trip tank past the flow-out meter.223 This 

flow added to pit gain and flow-out, making both figures higher than they would have been 

otherwise. The crew could nevertheless have preserved pit monitoring and flow-out monitoring if 

they calculated the effect of emptying the trip tank in this manner, but there is no evidence that 

they did so. Alternatively, the crew could have stopped displacing the riser while they emptied the 

trip tanks. 

Kick Detection Instrumentation Was Mediocre and Highly 

Dependent on Human Factors 

The data sensors on the rig had several shortcomings. First, the system did not have adequate 

coverage. For example, there was no camera installed to monitor returns sent overboard and no 
184 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

sensor to indicate whether the valve sending returns overboard was open or closed. Therefore, 

while video monitoring of flow was possible when returns went to the pits, it was not possible 

when returns went overboard. 

Second, some of the sensors were not particularly accurate. For example, electronic sensors for 

pit volumes can be unreliable, so much so that the crew would sometimes revert to using a string 

with a nut to measure pit volume change.224 

Third, the sensors often lacked precision and responded to movement unrelated to the state of the 

well. For example, a fluctuation in flow-out might result from crane activity on the rig.225 These 

shortcomings can result in rig personnel not receiving quality data and, furthermore, discounting 

the value of the data they do receive. 

The data display systems also had notable limitations. There were no automated alarms built into 

the displays. Rather, the system depended on the right person being in the right place at the right 

time looking at the right information and drawing the right conclusions.226 Although the systems 

did contain audible and visual alarms, the driller was required to set them manually.227 He could 

also shut them off. Manually setting and resetting alarm thresholds is a tedious task and not 

always done. For example, there is typically no alarm set for flow-in and flow-out because the 

pumps stop and start so often that the alarms would trigger too frequently.228 

There was also no automation of simple well monitoring calculations. For example, if the 

displacement is set up as a non-closed-loop system, and rig personnel want to keep track of 

volumes, they must perform the calculation by hand (return volume – (pump strokes × volume 

per pump stroke)). If the rig is emptying its trip tank while taking returns, and rig personnel want 

to disaggregate the two activities, they must perform the subtraction by hand. Each of those 

calculations could easily be automated and displayed for enhanced real-time monitoring. 

There was also no advance planning or real-time modeling of expected pressures, volumes, and 

flow rates for the displacement. Although well flow modeling has been employed in 

post-explosion analysis,229 there was no comparable modeling technology in place for 

real-time analysis.230 

Finally, the displays themselves sometimes made fluctuations in data hard to see.231 Indeed, in 

post-explosion reports and presentations, BP has consistently chosen to rotate the vertical 

Sperry-Sun log and enlarge it so that viewers can understand the data from April 20.

These limitations made well control monitoring unnecessarily dependent on human beings‘ 

attentions and abilities. 

Management Findings

One of the most important questions about the Macondo blowout is why the rig crew and 

mudlogger failed to recognize signs of a kick and did not diagnose the kick even when they shut 

operations down to investigate a well anomaly. The Chief Counsel‘s team finds that a number of 

management failures, alone or in combination, may explain those errors.

232
Chief Counsel’s Report — Chapter 4.7: Kick Detection | 185

BP, Transocean, and Sperry Drilling Rig Personnel Exhibited a 

Lack of Vigilance During the Final Displacement

The evidence suggests that BP, Transocean, and Sperry-Sun personnel on the rig were not 

sufficiently alert to the possibility that a loss of well control might occur during the final 

displacement. There are several reasons why this might have been the case. First, kicks are not 

commonly associated with the temporary abandonment phase of well operations. In a 2001 study 

of 48 deepwater kicks in the Gulf of Mexico, the vast ―majority of kicks occurred during 

drilling operations.‖233 By contrast, only one kick ―occurred in association with a well 

abandon[ment] operation.‖234 

Second, confidence in barriers, particularly tested barriers, can make rig personnel overconfident 

in the well‘s overall security. A satisfactory negative pressure test generally confirms that the well 

is secure and that hydrocarbons will not flow into the well during riser displacement operations. 

Once rig personnel deemed the Macondo negative pressure test a success, they may have believed 

that a kick was no longer a realistic hazard.235 Investigations of a 2009 North Sea blowout and a 

2009 Timor Sea blowout found that rig personnel were ―blinkered‖ by a successful negative 

pressure test or drew an ―unwarranted level of comfort‖ from the presence of a barrier.236 Both 

attitudes ―reflected and influenced a lax approach to well control.‖237 

Third, end-of-well activities tend to be marked by a hasty mindset and loss of focus.238 This can 

result simply from a desire to finish and move on, particularly when a well has been difficult to 

drill (like Macondo).239 Rig personnel have noted in post-blowout interviews that ―[a]t the end of 

the well sometimes they think about speeding up.‖240 This may be because ―everybody goes to the 

mindset that we‘re through, this job is done...everything‘s going to be okay.‖241 

Together, these factors appear to have contributed to reduced well monitoring vigilance, 

diminished sensitivity to anomalous data, delayed reactions, a failure to undertake routine well 

monitoring measures (like flow checks and volumetric calculations), and a willingness to perform 

rig operations in a manner that complicated well monitoring.

Such a lack of vigilance was particularly surprising at this well. Given the risk of a poor 

bottomhole cement job and the fact that the final displacement would severely underbalance the 

well, rig management—and the well site leader in particular—should have treated the 

displacement as a critical operation and personally monitored the data.242

Transocean Personnel Lacked Sufficient Training to Recognize

That Certain Data Anomalies Indicated a Kick243

Several times during the evening of April 20, data anomalies indicated that hydrocarbons were 

flowing into the well.244 Despite noticing the anomalies—and taking time to discuss them—the rig 

crew did not recognize that a kick was under way. 

Earlier in the evening, during the negative pressure test, hydrocarbons flowed into the well. 

Pressure anomalies signaled the kick. But rig personnel did not heed those signals. 

During the final displacement, the pressure anomalies reappeared. Although some went 

unnoticed, the rig crew did recognize an anomaly at 9:30 p.m. and shut the pumps down to 

investigate. Over the next 10 minutes or so, the crew watched the drill pipe pressure visibly 
186 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

increase—steadily at first (9:30 to 9:35 p.m.) and then, after they attempted to bleed it off, rapidly 

(9:38 p.m.)—even though the pumps were off. They also saw an anomalous kill line pressure. 

Each indicator was ―a sign that fluids are moving‖ in the well—in other words, a sign of a kick.245

To a skilled observer, those anomalies ―would have caused alarm.‖246 But there appears to have 

been no hint of alarm. Instead, the rig crew spent at least 10 minutes ―discussing‖ the ―anomaly,‖ 

―scratching their heads to figure what was happening.‖247 Even in retrospect, Transocean‘s 

internal investigator asserts that it was ―a very strange trend,‖ ―a confusing signal,‖ explained only 

after ―months of work.‖248 

Transocean leaves open the possibility that its rig crew ―did not have the experience‖ or training 

to interpret pressure anomalies during the negative pressure test.249 If true, then the crew likely 

did not have sufficient training or ability to interpret the recurrence of those anomalies during the 

final displacement. 

Transocean further states that its crew relied on the operator (BP) to make a final assessment of 

anomalies during the negative pressure test.250 But when those anomalies reappeared during the 

displacement, the rig crew did not notify BP rig personnel and ask for their help in interpreting 

the data.251 

BP and Transocean Allowed Rig Operations to Proceed in a Way 

That Inhibited Well Monitoring 

BP and Transocean management on the rig allowed simultaneous operations without adequately 

ensuring that those operations would not complicate or confound well monitoring.252

Simultaneous activities can interfere with well monitoring in several ways. First, they can 

influence data that are used to monitor for kicks (for example, by altering fluid levels) and thereby 

obscure signals of a kick.253 Second, they can make it more difficult to interpret data because rig 

personnel may attribute data anomalies to rig activities instead of a kick. Third, even when 

simultaneous operations are necessary, such as when changing the lineup of pipes and valves or 

fixing a mud pump, they can distract rig personnel who would otherwise be monitoring the 

well.254 Rig personnel can reduce these difficulties by identifying relevant rig activities, 

calculating or otherwise predicting their probable effect, and communicating any expected effects 

to well monitoring personnel. Rig management should ensure that someone is watching the 

screens at all times, despite ongoing activities. 

BP, Transocean, and Sperry Drilling Rig Personnel Did Not 

Properly Communicate Information 

Insufficient communication, both prior to and during the final displacement, affected risk 

awareness and well monitoring on the Deepwater Horizon.

BP did not adequately inform Transocean about the risks at the Macondo well, particularly the 

risks of a poor bottomhole cement job.

255

 Transocean argues that if BP had done so, its crew 

might have demonstrated ―heightened awareness.‖256 But it is unlikely that this particular 

communication failure compromised kick detection; the crew would probably have dismissed 

warnings about cement risks anyhow after the successful negative pressure test.
Chief Counsel’s Report — Chapter 4.7: Kick Detection | 187

BP and Transocean did not do enough to ensure that rig personnel were aware of the objectives, 

procedures, and hazards of the riser displacement operation.257 The individuals conducting the 

pre-job meetings should have emphasized that BP‘s temporary abandonment procedures would 

leave only a single barrier in the well besides the BOP and would produce an unusually 

underbalanced well.258 They should have warned against complacency stemming from the 

negative pressure test and emphasized that tested barriers can fail. 

The pre-job meetings should also have informed well monitoring personnel that certain kick 

indicators such as pit gain and flow-out would be compromised or unavailable during the planned 

operations. Well monitoring personnel should have been told that, as a result, they would need to 

perform volumetric calculations to keep track of pit gain, pay special attention to other 

parameters (such as drill pipe pressure), and conduct visual flow checks whenever the pumps 

were stopped.259 In addition, to facilitate well monitoring, those personnel should have been 

given a pump schedule for the different phases of the displacement, along with guidance 

regarding how much deviation from that schedule should be considered anomalous.260 

Transocean and Sperry Drilling personnel did not communicate effectively about the 

displacement operation.261 And the BP well site leader did not play a sufficiently active role in 

ensuring such communication.262 Communication broke down between the drill crew and the 

mudloggers on several occasions. For example, when rig personnel announced early on April 20 

that they would be pumping mud to a supply boat, Cathleenia Willis (the mudlogger on shift) told 

Clark she was concerned that this would limit her ability to monitor pit gain.263 Clark said he 

would address the matter but never got back to Willis.264 Keith reported after the explosion that 

he was concerned that simultaneous activities would complicate monitoring but never expressed 

those concerns to others.265 The drill crew repeatedly failed to inform Keith of various activities 

that influenced well monitoring data.266

Even after the Transocean crew shut down the pumps to investigate an anomaly, they did not 

inform the Sperry Drilling mudlogger, senior Transocean personnel, or the BP well site leader of 

the anomaly or ask for their help in resolving it.267 

The Chief Counsel‘s team cannot conclude that any one of these problems contributed to the 

failure to detect the kick. But together they suggest a communication breakdown that made kick 

detection more difficult. Knowledge of ongoing rig activity ―is essential to accurate interpretation

of the data.‖268 Absent that knowledge, it is difficult to ascertain whether anomalous data are 

benign or problematic.269 

While BP and Transocean Management Were Taking Steps to 

Improve Well Monitoring, These Steps Had Not (Yet) Improved 

Kick Detection on the Deepwater Horizon

BP

BP recognized that well control was critically important to its operations. In a 2009 Major 

Hazard Risk Assessment, the company identified ―Loss of Well Control‖ as first among the two 

―major accident risks‖ in drilling and completions operations.270 

BP specifically gave the Deepwater Horizon a mid-range risk rating for loss of well control271 and 

acknowledged the potentially severe consequences of a well control failure: ―Catastrophic 
188 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

health/safety incident‖ with the ―potential for 10 or more fatalities,‖ ―extensive‖ and ―widespread‖ 

damage to sensitive environments, ―$1 billion - $5 billion‖ in financial impact, ―severe 

enforcement action,‖ government intervention, and ―[p]ublic and investor outrage.‖272 

To address this risk, BP checked to ensure that all drilling and completions workers had well 

control training and certification, developed tools to further assess the risk (―BowTie diagrams,‖ 

―Risk Mitigation Plans,‖ ―Asset-specific‖ risk assessments, a ―Barrier Assessment Tool‖), and 

emphasized that risk management in this area would be ―under continual review.‖273 The 

company also planned to evaluate the effectiveness of barriers with each rig‘s team and train 

personnel in the new well control response guide.274

BP understood the risks presented by less severe well control events too. An April 14, 2010 

presentation to the drilling and completions Extended Leadership Team noted that half of all 

nonproductive time in the company‘s offshore drilling sector was the result of ―downhole 

problems (wellbore instability, losses, gains, tight hole) and stuck pipe.‖275 The presentation 

continued: ―Post analysis of the...incidents clearly indicates that in most cases[,]...events could 

have been prevented or decisions influenced if the drilling data that is already generally available 

had been appropriately presented and analysed.‖ That is, ―early warning indicators were usually 

present albeit invisible in the mountain of data.‖276 Therefore, as Macondo senior manager David 

Sims stated, downhole problems were ―low hanging fruit‖ for decreasing nonproductive time.277 

Reviews conducted in late 2007 and early 2008 similarly showed that ―the quality of monitoring, 

detection and reaction to downhole hazards during drilling operations‖ was ―variable.‖278 In 

response, BP planned to develop a program to facilitate Efficient Reservoir Access, the ―ERA 

Advisor.‖ This ambitious program would monitor data in real time onshore, generate expert and 

automated advice in response to that data, and use new software and sensors to track and 

diagnose the data.279 The program‘s goal was to ―ensure the right information is in the right 

place at the right time.‖

280

 It would focus, however, on monitoring data during the drilling of the 

well (not end-of-well activities).281 BP‘s Extended Leadership Team developed and endorsed the 

ERA in 2009; initial pilot testing of the first stage of the system was to begin in the fourth quarter 

of 2010.282

Even before planning its ERA program, BP contracted Sperry-Sun to relay rig data to its Houston 

offices. But despite recognizing the risks associated with poor well monitoring and the usefulness 

of onshore assistance, BP did not monitor this data for well control purposes. Even though each 

of its working rigs had an operations room with dedicated Sperry-Sun data displays,283 BP 

typically used these rooms only for meetings and the data were ―not ever monitored.‖284 Thus, 

before BP implemented its ERA Advisor system, it failed to take the interim step of ensuring that 

someone onshore was monitoring the data systems it already had in place. 

This is surprising in light of the fact that BP was particularly concerned about well monitoring at 

Macondo. Less than two months before the blowout, on March 8, 2010, the Macondo well took a 

kick.285 The kick occurred while the rig was drilling.286 The ―well kicked for 30 minutes before the 

trends were obvious enough.‖287 The Transocean drill crew and Sperry Drilling mudlogger—

indeed, the very same Revette, Curtis, Clark, and Keith—observed a gain in flow-out, a slow gain 

in the pits, a decrease in equivalent circulating density (ECD), and an increase in gas content.288 

The drill crew stopped the pumps, performed a flow check, and shut in the well.289 The situation 

soon went ―from bad to worse.‖290 There were ―[m]ajor problems on the well‖:291 The pipe was 

stuck. BP ultimately had to sever the pipe and sidetrack the well.292
Chief Counsel’s Report — Chapter 4.7: Kick Detection | 189

After the event, BP involved its in-house Totally Integrated Geological and Engineering Resource 

team (the ―TIGER team‖), to conduct an engineering analysis, and (on March 18) distributed a 

―lessons learned‖ document to its Gulf of Mexico drilling and completions personnel.293 BP 

recommended that its personnel ―evaluate the entire suite of drilling parameters that may be 

indicative of a shift in pore-pressure‖ (including gas, flow-out, and flow checks), ―ensure that we 

are monitoring all relevant [pore pressure] trend data,‖ ―have [pore pressure] conversations as 

soon as ANY indicator shows a change,‖ ―no matter how subtle,‖ and ―be prepared to have some 

false alarms and not be afraid of it.‖

294

 The ―lessons learned‖ document also specified that 

―[b]etter lines of communication, both amongst the rig subsurface and drilling personnel, and 

with Houston office needs to be reestablished. Preceding each well control event, subtle 

indicators of pore pressure increase were either not recognized, or not discussed amongst the 

greater group.‖295 

In addition, BP wells team leader John Guide initiated several conversations to address the rig‘s 

response to the kick, which he thought was ―slow and needed improvement.‖296 Guide specifically 

instructed the BP well site leaders to ―up their game.‖297 He spoke with Transocean and Sperry 

Drilling personnel about ―tighten[ing] up wellbore monitoring.‖ 

The goal of Guide‘s conversations and of the TIGER team‘s involvement was to maintain 

heightened attentiveness ―for the remainder of the Macondo well,‖298 up to the point 

when the Horizon unlatched its BOP and left.299 Evidently, the team fell short of that goal. As 

Guide conceded after the incident, the Macondo team‘s heightened attentiveness to well 

monitoring lasted all the way up until, apparently, the negative pressure test.300 This is likely 

because BP‘s focus, once again, was on monitoring data during the drilling of the well (not 

end-of-well activities).301

Transocean 

Transocean also recognized the importance of well control. In a 2004 Major Accident Hazard 

Risk Assessment, the company gave Deepwater Horizon a 5B risk rating for reservoir blowout,302

meaning that there was a ―Low‖ likelihood of a blowout occurring, but if one did occur, the event 

would have ―Extremely Severe‖ consequences:303 ―Multiple personnel injuries and/or fatalities,‖ 

―Major environmental impact,‖ and ―Major structural damage and possible loss of vessel.‖304 As 

prevention and mitigation measures, Transocean listed (among other things) well control 

procedures, training of drill crew, and instrumentation indicating well status.305 

As discussed in greater detail in Chapter 5, despite those concerns, Transocean did not inform the 

Deepwater Horizon‘s crew of lessons learned from an earlier well control event on another rig. 

On December 23, 2009, Transocean barely averted a blowout during completion activities on a rig 

in the North Sea. Rig personnel were in the process of displacing the wellbore from mud to 

seawater.306 They had just completed a successful negative pressure test, and they had lined up 

the displacement in a way that inhibited pit monitoring. 307 During the displacement, a critical 

tested barrier failed, and hydrocarbons came up the wellbore, onto the drill floor, and into 

the sea.308

The incident differed from Macondo in some respects: It occurred during the completion phase 

of the well, not drilling or temporary abandonment, and the failed barrier was a mechanical valve, 

not cement.309 But the incident was identical to Macondo in crucial respects:

 the rig crew underbalanced the well while displacing mud to seawater; 
190 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

 a successful negative pressure test ―blinkered‖ the crew and produced an improper 

―change in mindset‖; 

 the crew conducted displacement operations in ways that inhibited pit monitoring; and 

 the crew discounted kick indicators by attributing them to other occurrences on the rig.310 

Transocean nevertheless failed to effectively share and enforce the lessons learned from that 

event with all relevant personnel. The company held two conference calls and distributed an 

advisory for its North Sea personnel only. It also posted a shorter advisory about the event on its 

electronic documents platform—accessible fleetwide—but it did not alert crews of the advisory‘s 

existence. Indeed, there is no evidence that anyone on or affiliated with the Deepwater Horizon

knew of the North Sea incident or read any of its lessons prior to the Macondo blowout.
Chief Counsel’s Report — Chapter 4.7: Kick Detection | 191 Saritha Komatireddy Tice

Figure 4.7.12. Last two hours of Sperry-Sun data.

Chief Counsel’s Report — Chapter 4.8: Kick Response | 193

Chapter 4.8|Kick Response

n the event of an unwanted influx of fluid or gas into the wellbore

(a ―kick‖), the safety of a drilling rig turns on split-second responses 

by the rig crew.

The Deepwater Horizon‘s crew did not respond to the April 20 kick before hydrocarbons had 

entered the riser, and perhaps not until mud began spewing from the rig floor. If the rig crew had 

recognized the influx earlier, they might have been able to shut in the well. But the crew still had 

response options even at the point that they eventually did recognize the kick. If the crew had 

diverted the flow overboard immediately, they might have delayed the ignition and explosion of 

the gas flowing out of the well. Instead, the crew sent the flow to the mud gas separator.1 The 

mud gas separator was not designed to handle this flow volume and was overwhelmed. Sending 

flow to the mud gas separator, rather than overboard, therefore increased the risk that gas from 

the well would explode on the rig.

The crew appears to have followed standard Transocean procedures for dealing with hydrocarbon 

kicks. But those procedures were written to guide the crew‘s response to routine hydrocarbon 

kicks. They did not address extreme emergencies like the one the Deepwater Horizon crew faced 

on the evening of April 20. In the future, Transocean and other companies must provide better 

training and drills to ensure that their crews are prepared to respond quickly to low-frequency, 

high-risk events like the Macondo blowout.

Well Control Equipment

Blowout Preventer and Emergency Disconnect System

The last piece of equipment that can prevent hydrocarbons from flowing into the riser above the 

wellhead is the blowout preventer (BOP). As Chapter 4.9 explains in more detail, the 

Deepwater Horizon‘s BOP had several annular preventers, pipe rams, and shear rams that the rig 

crew could use to control flow coming from the well from going up the riser. 

Most of the barriers in the wellbore, such as drilling mud and cement, block hydrocarbon flow 

without active supervision by the rig crew. By contrast, BOP elements are typically open during 

well operations. The BOP does not block flow unless the rig crew spots an influx and closes a BOP 

element, or an automated backup system activates the blind shear ram. Chapter 4.9 explains the 

BOP‘s automated backup systems in detail. 

In addition to directly activating the BOP rams, the rig crew can activate the blowout preventer‘s

blind shear ram and disconnect the rig from the well using an emergency disconnect 

system (EDS).

2

 In accord with Transocean policy, the rig crew had tested the Deepwater 

Horizon‘s EDS at surface prior to deploying the blowout preventer at the Macondo well.3 

I
194 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Emergency Disconnect System. The crew can activate the emergency disconnect system (EDS) 

from either the driller’s control panel, the toolpusher’s control panel, or the bridge.4Power 

and communication signals are sent from the rig to the BOP through multiplex (MUX) cables.5

The signals initiate a sequence in which pod receptacles de-energize and retract, choke and kill 

line connectors unlatch, the blind shear ram closes, and the lower marine riser package 

unlatches from the BOP stack,6separating the rig and riser from the well. Once initiated, this 

sequence typically takes about a minute.7Emergency disconnect is not generally considered a 

well control response. Rather, it is used in emergency dynamic positioning scenarios to 

separate the rig from the well. The rig may begin to “drift off” from its station if the rig loses 

power, or the rig may “drive off” if the dynamic positioning system mistakenly directs the rig 

to move away. The riser would likely be damaged if the rig drifted or drove off, potentially 

resulting in an uncontrolled release of hydrocarbons into the water. 

Once gaseous hydrocarbons move past the blowout preventer, they expand exponentially with 

decreasing depth8and reach the rig within minutes.9 Timely BOP activation is therefore crucial to 

drilling safety.10 If the BOP is activated quickly, little or no gas will enter the riser and travel to 

the rig. Transocean advises its personnel: ―If the volume of gas above the BOP stack is kept small 

by detection equipment and shut-in, then the gas can be safely handled at [the] surface.‖11 If this 

is not done, the consequences can be severe. On March 14, BP well site leader Jimmy Adams 

cautioned BP senior drilling engineer Mark Hafle: ―Rigs have been burn[ed] down and people 

killed from gas in the riser.‖12 

Diverter and Mud Gas Separator

Transocean‘s Well Control Handbook warns that ―[l]arge amounts of gas above the BOP stack can 

rise rapidly and carry a large volume of mud out of the riser at high rates.‖13 In those situations, 

the rig‘s diverter becomes the last line of defense. The diverter on the Deepwater Horizon sat 

directly beneath the rig floor.14 It could prevent gas from flowing uncontrollably onto the drilling 

rig,15 in order to ―keep combustible gases safely away from sources of ignition.‖16 

As Chapter 4.7 explains, mud coming out of the well normally flows up the riser, through the mud 

cleaning system and into the mud pits. When the rig crew activates the diverter, an annular 

packer in the diverter closes around the drill pipe (or closes the open hole if no drill pipe is in the 

hole) and prevents flow up the riser and onto the drill floor. The Deepwater Horizon’s diverter 

packer had a 500 pounds per square inch (psi) working pressure rating,17 meaning that it could 

safely withstand 500 psi of pressure exerted by fluids flowing up the riser. Although the diverter 

is designed to handle worst-case scenarios,18 pressures above the pressure rating could cause it to 

fail and allow an influx to continue up the riser.

When closed, the packer forced flow to one of two 14-inch diameter overboard lines—one going 

to the port side of the rig, the other to starboard (see Figure 4.8.1).19 The rig crew could select the 

direction of overboard flow in order to discharge gas on the downwind side of the rig. The 

starboard-side overboard line was also connected to another pipe that led to the mud gas 

separator. The rig crew could close a valve in the starboard line in order to route flow from that 

line to the mud gas separator.20
Chief Counsel’s Report — Chapter 4.8: Kick Response | 195

Figure 4.8.1. Diverter system.

A mud gas separator consists of a series of pipes, valves, and a tank. When gas-bearing mud flows 

into the tank, the mud falls to the bottom of the tank while the gas rises. The mud flows out 

through a pipe in the tank bottom to the rig‘s mud pits. The gas flows out through a separate 

pipe. On the Deepwater Horizon, that pipe ran to a vent high atop the derrick where gas could 

discharge into the open air. 

When using the diverter system, the crew‘s most important decision is whether to send the fluid 

influx overboard or to send it to the mud gas separator.

21

 The choice depends on the size of 

the hydrocarbon influx in the riser.22 The mud gas separator is the right choice for small 

quantities of mud and hydrocarbons. By separating mud from gas, it allows the crew to collect 

and reuse the mud rather than discharge it overboard and pollute the sea. Moreover, it vents gas 

out of a gooseneck pipe on the derrick at the center of the rig. But sending a large influx to the 

mud gas separator can create a large flammable cloud of gas over the rig.23 If a sufficiently large 

and sustained influx of gas from the riser goes to the mud gas separator, ignition becomes more 

likely, with the potential for explosion.24 As a result, it is inappropriate to send large flows 

through the mud gas separator.25 In the event of a large hydrocarbon influx into the riser, the 

crew should send flow overboard through the downwind line.26 

Kick Response at Macondo

On April 20, gas moved through the Deepwater Horizon’s open blowout preventer and shot up 

the riser. As it rose, the gas expanded, pushing the mud and gas faster and faster toward the rig.27 

Sometime between 9:40 and 9:43 p.m.,28 mud spewed from the rotary table,29 sprayed onto the 

rig floor,30 and shot up and out the crown of the derrick31 about 200 feet above the rig floor. 

TrialGraphix

On April 20, the rig crew diverted the influx to the mud gas separator rather than sending 

it overboard. That caused mud and gas to spray onto the rig from the derrick. 
196 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

A Transocean representative likened the force of the gas to ―a 550-ton freight train hitting the rig 

floor,‖32 followed by a ―jet engine‘s worth of gas coming out of the rotary.‖33

The Rig Crew Sends the Influx to the Mud Gas Separator

After drilling mud began spraying out from the rig floor, the crew activated the diverter system.34 

Transocean toolpusher Jason Anderson was in the drill shack. He called BP well site leader Don 

Vidrine to say that the crew was taking action in response to mud coming back from the well.35 It 

appears that rig personnel had previously set the valves on the diverter system to route diverted 

flow through the mud gas separator rather than overboard.

36

 The crew may have done this to 

avoid inadvertently discharging oil-based drilling mud or other pollution into the Gulf of Mexico 

in violation of environmental regulations. Whatever the reason, it appears that the rig crew did 

not change the valve settings to route the flow overboard in response to the sudden mud influx. 

Diverting flow to the mud gas separator stopped the flow of mud onto the rig floor within seconds. 

Micah Sandell, a Transocean gantry crane operator, testified: ―I seen mud shooting all the way up 

to the derrick...then it just quit...I took a deep breath thinking,  ̳Oh, they got it under control.‘‖ 37 

Any relief was temporary. Given the size of the influx, routing the influx to the mud gas separator 

rather than overboard made ignition all but inevitable. The capacity of a mud gas separator 

depends on the size of the outlet lines,38 and these lines are generally not large enough to handle 

very high flow rates.39 The Macondo blowout therefore quickly overwhelmed the Deepwater 

Horizon‘s mud gas separator.40 Sandell observed: ―Then all the sudden the...mud started coming 

out of the degasser...so strong and so loud that it just filled up the whole back deck with a gassy 

smoke...loud enough...it‘s like taking an air hose and sticking it to your ear.‖41 

A Weatherford specialist on the rig watched mud come out of the gas vent lines of the mud gas 

separator.42 Gas likely entered the line to the mud system, which would have sent gas to the 

pump room, the mud pit room, and the shaker room.43 Components of the mud gas separator 

may have failed at that time as well.44 There was little wind on April 20,45 creating ―worst-case‖ 

conditions for gas dispersion.46 A flammable gas cloud started accumulating on the rig.

The Rig Crew Activates the Blowout Preventer 

In addition to activating the diverter, the crew also attempted to shut in the well with the BOP‘s 

annular preventer.47 (Though there is evidence that the rig crew activated the lower annular 

preventer at 9:41 p.m., Transocean has recently contended the rig crew activated the upper 

annular, not the lower annular.)48 At about the same time, Transocean assistant driller Stephen 

Curtis called Transocean senior toolpusher Randy Ezell to tell him that the well was blowing out, 

that mud was shooting through the crown on top of the derrick, and that Anderson was shutting 

the well in.49 Pressure data indicate the crew activated a variable bore ram—or tightened the 

annular preventer—on the BOP at about 9:46 p.m.

50

 

Activating the annular preventer and variable bore rams are ―normal and appropriate‖ responses 

to a typical kick.51 But this was not a typical kick. By the time the Deepwater Horizon’s rig crew 

attempted to activate the BOP, substantial volumes of hydrocarbons probably had already 

entered the riser, where they would have been rapidly expanding upward toward the rig.52 The 

flow rate of mud and hydrocarbons may have been high enough to prevent the annular preventer

from sealing.

53

 
Chief Counsel’s Report — Chapter 4.8: Kick Response | 197

BP 

The blind shear ram can be activated from 

the BOP’s control panels on the rig floor 

and bridge.

In addition to activating the annular preventers or pipe rams, the crew 

could have activated the blind shear ram to cut the drill pipe and shut in 

the well.54 The blind shear ram can be activated directly by the rig crew 

from the control panels, seen in Figures 4.8.2 and 4.8.3.

55

 There is no 

evidence the rig crew attempted to activate the blind shear ram prior to 

the explosion.56

The rig crew‘s response generally followed the procedures that 

Transocean‘s Well Control Handbook specified ―upon taking a kick.‖57 

The ―shut-in‖ procedure in the handbook that applied to the April 20 

situation specifies that the rig crew should first close the ―annular‖ and 

then close ―pre-determined rams‖ later if necessary.58 The handbook‘s

shut-in procedures do not offer any specific guidance on the use of the 

blind shear ram. (The handbook elsewhere advises that the blind shear 

rams may be used ―only in exceptional circumstances.‖59) By closing the 

annular preventer and then a variable bore ram, the rig crew thus appears 

to have followed Transocean procedures. 

Gas Ignites Minutes After Mud Reaches 

the Rig Floor

The first explosion occurred at about 9:49 p.m.60 Ezell was on his way to 

the rig floor when the explosion ―threw [him] against the wall in the 

toolpusher‘s office.‖61 ―Debris‖ covered him.62 Transocean performance 

division manager Daun Winslow was smoking in the coffee room when he 

felt the walls suck in and the roof panels collapse on top of him.63 The 

explosion injured several of the rig crew64 and likely killed the men on the 

rig floor instantly.

The precise source of ignition may never be known. Most of the 

equipment on a drilling rig is not classified to protect against ignition.65 

One of the engines likely exploded first—or at least shortly after an initial 

explosion. Transocean motor operator William Stoner testified that he 

heard gas hissing and Engine 3 starting to overspeed before the first 

explosion.66 The engine revved higher than Mike Williams, Transocean‘s 

electronics technician, had ever heard before.67 Engine 6 was also on and 

began to rev.68 Transocean chief mechanic Douglas Brown testified that 

the first explosion came from the direction of Engine 3.69 After the 

explosion, the exhaust stacks, wall, handrail, and walkways around Engine 

3 were all missing.70 Seconds after the first explosion, another explosion occurred.71 Parts of the 

rig were in flames.72 Fewer than 10 minutes, and perhaps as few as six minutes, had elapsed since 

mud first hit the rig floor. 

The Rig Crew Attempts to Activate the 

Emergency Disconnect System

After the explosions, crew members elsewhere on the rig attempted to activate the emergency 

disconnect system. Transocean subsea supervisor Chris Pleasant rushed to the bridge and 

informed Transocean Captain Curt Kuchta that he was activating the emergency disconnect. 

Figures 4.8.2 and 4.8.3. 

BOP control panels on the rig floor 

and bridge.
198 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Captain Kuchta replied, ―[c]alm down, we‘re not EDSing.‖73 Nevertheless, with the backing of 

Vidrine and Transocean offshore installation manager (OIM) Jimmy Harrell, Pleasant initiated 

the emergency disconnect at approximately 9:56 p.m.

74

 It appears that the panel‘s electronic 

signals responded, but there was no indication of hydraulic flow closing the blind shear ram.75 

The low accumulator alarm was sounding, indicating a loss of surface hydraulic power.76 

The Chief Counsel‘s team believes that by this time the explosion had already damaged the MUX 

cables connecting the rig and the blowout preventer, preventing the command from reaching the

stack.77 Pushing the EDS button does not appear to have activated the blind shear ram or the 

remainder of the emergency disconnect system. This left the rig attached to the riser. Gas 

continued to flow up the riser, fueling the fires on the rig.78

Technical Findings

If the Rig Crew Had Recognized the Kick Earlier, They Could 

Have Shut in the Well Before Gas Entered the Riser

The crew would have been able to prevent gas from reaching the rig if they had recognized the 

influx before gas entered the riser and responded by shutting in the well. At that point, closing 

the annular preventer or the variable bore ram should have controlled the kick and stopped flow. 

By the time the Deepwater Horizon crew actually did recognize the influx and activate the 

blowout preventer, hydrocarbons had almost certainly entered the riser and begun expanding 

rapidly upward toward the rig.

The Deepwater Horizon crew recognized that there was an anomaly, but they did not identify that 

anomaly as a kick. If rig personnel suspect a kick, they perform a flow check and shut in the 

well.79 The same cannot be said for responses to anomalies. The Horizon crew suspected that

something was amiss when they shut down the pumps at 9:30 p.m. Over the next 10 minutes or 

so, they conducted diagnostics and discussed the anomalous pressures they were seeing. Only 

after hydrocarbons had entered the riser, and about when mud started emerging from the rotary, 

did the crew act to shut in the well. Apparently, the crew did not suspect a kick until 10 minutes 

after they detected the anomaly. A more conservative initial approach to the anomaly—of 

shutting in first and investigating afterward—would have resulted in rig personnel shutting in the 

well while hydrocarbons were still confined to the wellbore and thereby preventing the blowout. 

By the time the crew activated the annular preventer, mud and hydrocarbons may have been

flowing through the BOP at a high enough rate to prevent it from sealing.80 Data on drill pipe 

pressure indicate that the annular preventer did not achieve shut-in pressure. Only 1,200 psi 

registered,81 well below what would have been required.82 Later, the drill pipe pressure climbed 

above 5,500 psi.83 That appears to have been due either to tightening of the annular or to 

activation of the variable bore ram.84 Though the well may have been shut in by 9:49 p.m.,85 it 

appears that there was already a substantial volume of gas above the BOP at this time because this 

is when the first explosion took place. 

Previous modifications to the BOP may have compromised the ability of the lower annular 

preventer to seal the well. (As noted above, Transocean has recently contended the rig crew 

activated the upper annular and not the lower annular. If true, modifications to the lower annular 

would not have affected the BOP‘s performance during the blowout.) As discussed further in 

Chapter 4.9, BP asked Transocean in 2006 to modify the lower annular to a ―stripping‖ annular. 
Chief Counsel’s Report — Chapter 4.8: Kick Response | 199

This change reduced the rated working pressure from 10,000 to 5,000 psi,

86 and allowed the rig 

crew to raise or lower pipe through the BOP while the annular was closed. The 10,000-psi-rated 

annular body was not replaced.87 While the stripping annular would still be able to close in 

pressures above 5,000 psi, it is not clear whether it would completely seal at these 

higher pressures.

88

Diverting Overboard Might Have Delayed the Explosion

The rig crew should have diverted the flow overboard when mud started spewing from the rig 

floor.89 The flow of mud at this point was tremendous—it shot 200 feet up to the crown of the 

derrick. That should have prompted the crew to take immediate emergency measures.

Transocean‘s Well Control Handbook advises that ―at any time, if there is a rapid expansion of gas 

in the riser, the diverter must be closed (if not already closed) and the flow diverted overboard.‖90

The handbook also provides: ―[I]f large volumes of gas have entered the riser, it will flow rapidly 

on its own and there will be no way to control it by adjusting the circulation rate. Then, the 

surface gas and liquid rates become very high, especially as the gas bubble reaches surface and the 

flow must be diverted overboard.‖

91

 

Although mud flow at the rig floor does not always mean that gas is in the riser, the Deepwater 

Horizon‘s crew should have assumed that this was the case for two reasons. First, the fact that 

mud was spewing from the rig floor after the crew had displaced the well with seawater down to 

8,367 feet below sea level should have indicated that hydrocarbon flow had already proceeded a 

substantial distance up the well. Second, and more significantly, the high mud flow rate and 

volume should have warned the crew that the kick was severe and prompted them to send the 

influx overboard.

While the Chief Counsel‘s team finds that the rig crew should have sent the influx overboard 

immediately, doing so may not have prevented an explosion. Two factors determine whether 

diverting flow overboard would have prevented an explosion: (1) the ability of the diverter 

packer, overboard lines, and other equipment to handle the flow rate and volume, and (2) the way 

in which gas dispersed away from the rig.92

With regard to equipment capabilities, currently available information leads the Chief Counsel‘s 

team to conclude that the diverter packer probably would have been able to handle the flow rate 

and volume during the blowout, though it is not certain. The diverter packer on the Deepwater 

Horizon was rated to withstand 500 psi of pressure. Two post-blowout computer models 

commissioned by BP for its internal investigation offer perspective on the forces that may have 

been exerted on the diverter packer during the blowout; the Chief Counsel‘s team is not aware of 

any other modeling that has been performed at this time. One model predicts that the maximum 

pressure exerted on the diverter packer during the blowout was 145 psi,93 not even close to the 

packer‘s limit. Another model indicates that the pressures may have been much higher, peaking 

at 500 psi.94 But even under that scenario, the diverter packer probably would not have failed. 

That model only predicted that the packer would have been subject to 500 psi for an instant,95

and this type of equipment can generally handle pressures beyond rated capacity for a short 

period of time. Moreover, if the rig crew had sent the influx overboard, the pressure on the 

diverter element likely would have been even lower.96 The Chief Counsel‘s team therefore 

believes that the diverter packer probably would not have failed if the rig crew had sent the 

influx overboard.97 
200 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Though the diverter packer probably could have withstood the blowout flow rate and pressure, 

the slip joint could have failed. The slip joint sat below the diverter packer, permitting the rig to 

heave vertically while maintaining the riser connection to the sea floor. It had two modes: a 

low-pressure mode with a 100 psi working pressure98 and a high-pressure mode with a 500 psi 

working pressure.99 If the slip joint had been in low-pressure mode, it would have been 

vulnerable to failure.100 That would have allowed gas to escape into the moon pool area of the rig. 

Additionally, because the diverter packer does not seal off the riser, there is a possibility that gas 

could have also traveled up the drill pipe and onto the rig.

With regard to gas dispersion, the calm wind conditions on April 20 would have limited the rate 

at which gas dispersed away from the rig. The wind speed was low, about 2 to 4 knots.101 The 

wind also appears to have been blowing from starboard to port,102 though the precise direction is 

difficult to ascertain.103 Because of this, gas flowing out of the starboard overboard line would 

have stayed close to the rig and perhaps even blown back onto the rig rather than drifting away.104 

Nevertheless, diverting overboard would have substantially reduced the risk of ignition of the 

rising gas and given the rig crew more time to respond.105 An MMS study of offshore blowouts 

between 1992 and 2006 found that the ―success rate for diverter systems was very high...16 of the 

20 diverter uses were considered successful because the desired venting of gas was sustained until 

the well bridged.‖106 

The Chief Counsel‘s team concludes that diverting flow overboard likely would have sent a 

substantial amount of gas off the rig.107 This may not ultimately have prevented an explosion but 

probably would have given the rig crew more time to respond to the blowout. BP has concluded 

that ―diversion of fluids overboard, rather than to the MGS, may have given the rig crew more 

time to respond and may have reduced the consequences of the accident.‖108 Transocean agrees 

that ―diverting overboard might have delayed the explosion....‖109 

Management Findings

Transocean Should Have Trained Its Employees Better on How 

to Respond to Low-Frequency, High-Risk Events

There are at least three explanations for why the crew did not immediately divert the 

flow overboard.

 First, the crew may not have recognized the severity of the situation, though that seems 

unlikely given the amount of mud that spewed from the rig floor.

 Second, they did not have much time to act. At most, the drill crew had six to nine 

minutes after mud emerged from the rig floor before the first explosion. 

 Finally, and perhaps most significantly, the rig crew had not been trained adequately

regarding how to respond to such an emergency situation. It appears that the crew 

followed the procedures for dealing with a kick set forth in Transocean‘s Well Control 

Handbook. Those procedures were inadequate given the circumstances.110

Transocean has highlighted to the Chief Counsel‘s team the ―extensive curriculum of courses‖ 

available to its rig crew, including courses on well control.111 Transocean contends that the 
Chief Counsel’s Report — Chapter 4.8: Kick Response | 201

Transocean

Protocol from Transocean’s Well Control Handbook. 

―initial response...was the appropriate first normal response‖112 and that the ―crew utilized the 

proper sequencing.‖113 The Chief Counsel‘s team recognizes that the rig crew may simply have 

done what it had been trained to do. But that assertion indicates the inadequacy of the crew‘s 

training and guidance in the first place. 

Though Transocean‘s protocols provide that a severe influx should be sent overboard, the 

sequence of ―procedures for handling gas in the riser‖114 (Transocean document shown in Figure 

4.8.4) specifically recommends the overboard line—instead of the mud gas separator—only in the 

ninth step after actions such as monitoring for flow and circulating the riser. Here, there was no 

time to get to the ninth step.115 In the future, well control training should include simulations and 

drills for low-probability, high-consequence emergency events and well-control protocols should 

specifically address such emergencies.116

Figure 4.8.4. Transocean’s “procedures for handling gas in the riser.”

Chief Counsel’s Report — Chapter 4.9: The Blowout Preventer | 203

Figure 4.9.1. Transporting the Deepwater Horizon BOP.

U.S. Coast Guard photo/Petty Officer 3rd Class Stephen Lehmann

The Deepwater Horizon’s blowout preventer on the Mississippi River in transit to 

Michoud, Louisiana, to undergo forensic testing, September 11, 2010. 

Chapter 4.9|The Blowout Preventer 

he blowout preventer (BOP) is a routine drilling tool. It is also 

designed to shut in a well in case of a kick, thereby ―preventing‖ a 

blowout. As described in Chapter 4.8, the rig crew attempted to close 

elements of the BOP and to activate the emergency disconnect system 

(EDS) in response to the Macondo blowout. Automatic and emergency activation 

systems should have also closed the BOP‘s blind shear ram and shut in the well. 

Though preliminary evidence suggests one of these systems may have activated 

and closed the blind shear ram, the blind shear ram never sealed the well. 

The federal government has recovered the BOP from the blowout site, and forensic testing is 

ongoing. Until that testing is complete, a full examination of blowout preventer failure is 

impossible. In the meantime, the Chief Counsel‘s team has made preliminary findings and 

identified certain technical faults that may have prevented the BOP system from activating and 

shutting in the well. 

T
204 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

U.S. Coast Guard photo/ TrialGraphix

Petty Officer 1st Class Thomas M. Blue

Left: Photo of the recovered Deepwater Horizon BOP. 

Right: 3-D model of the Deepwater Horizon BOP.

Figure 4.9.4. Blind shear ram.

Figures 4.9.2 and 4.9.3. The Deepwater Horizon blowout 

preventer stack.

TrialGraphix

Blind shear ram open, about to cut drill pipe, and immediately 

after cutting drill pipe.

Blind Shear Rams 

Federal regulations required the Deepwater 

Horizon to have a BOP that included a blind 

shear ram (BSR).1 The blind shear ram is 

designed to cut drill pipe in the well (as shown in 

Figure 4.9.4) and shut in the well in an emergency 

well control situation.* But even if properly 

activated, the blind shear ram may fail to seal the 

well because of known mechanical and design 

limitations. In order for a blind shear ram to shut 

in a well where drill pipe is across the BOP, it must 

be capable of shearing the drill pipe.2 And blind 

shear rams are not always able to perform this 

critical function, even in controlled situations. 

Blind Shear Rams Cannot Cut 

Tool Joints or Multiple Pieces 

of Drill Pipe 

Blind shear rams are not designed to cut through 

multiple pieces of drill pipe or tool joints

connecting two sections of drill pipe.3 It is thus 

critically important to ensure that there is a piece 

of pipe, and not a joint, across the blind shear ram 

before it is activated.4 This fact prompted a 2001 

MMS study to recommend every BOP to have two 

sets of blind shear rams such that if a tool joint 

prevented one ram from closing, another adjacent 

ram would close on drill pipe and would be able to 

shear the pipe and shut in the well.5

 MMS never 

adopted the recommendation. 

The Horizon‘s blowout preventer had only one 

blind shear ram. Sections of drill pipe are joined 

by a tool joint at each interval and are often about 

30 feet in length, though some of the drill pipe 

used on the Horizon varied in length.6 If one of 

those joints was in the path of the blind shear ram 

at the time of attempted activation, as portrayed in 

Figure 4.9.5, the ram would have been unable to 

shear the pipe and shut in the well. 

 

*

 Although not separately depicted in Figures 4.9.3 and 

4.9.4, there are hydraulic, power, and communications 

lines (cables), as well as the choke, kill, and boost lines 

(pipes) running from the rig to the blowout preventer. 

TrialGraphix 
Chief Counsel’s Report — Chapter 4.9: The Blowout Preventer | 205

Figure 4.9.5. Tool joint in the blind shear ram.

Blind shear 

rams cannot 

cut tool joints.

Even if a tool 

joint did not prevent 

the blind shear rams 

from shutting in the 

Macondo well, the 

inability to shear tool 

joints is a recognized 

and significant 

limitation. The Chief 

Counsel‘s team agrees 

with the MMS study 

that installing a 

second blind shear 

ram would mitigate 

this risk and increase 

the probability of 

success in shutting in 

a well.7

 

Study Finds Deepwater Exacerbates Limitations 

A 2002 MMS study conducted by West Engineering Services, a drilling consulting firm, presented 

―a grim picture of the probability of success when utilizing [shear rams] in securing a well after a 

well control event.‖

8

 The study found that only three of six tested rams successfully sheared drill 

pipe under operational conditions.9 It also found that ―operators often do not know how their 

shear rams would perform in a high pressure environment.‖10 These problems worsen in 

deepwater because, among other things, deepwater operators often use stronger drill pipes that 

are more difficult to cut.11 Increased hydrostatic and dynamic pressures in deepwater wells also 

increase the difficulty of shearing.12

 

Although the study found that these factors were ―generally ignored,‖13 it is not certain whether 

these factors affected the blind shear ram at Macondo. 

Deepwater Horizon Blind Shear 

Ram Testing 

Earlier Tests Establish Shearing Ability 

The shearing ability of the Deepwater Horizon‘s blind shear ram was demonstrated on at least 

two occasions. During the rig‘s commissioning, the rams sheared a 5.5-inch, 21.9-pound pipe at a 

shear pressure of 2,900 pounds per square inch (psi).14 According to pipe inventory records, this 

was the same thickness and weight of the drill pipe retrieved from the Macondo well.15

 The ram 

also successfully sheared drill pipe during a 2003 EDS function.16 

The Rig Crew Regularly Tested the Deepwater Horizon’s Blind Shear Ram, 

but Often at Reduced Pressures 

Regulations require frequent monitoring and testing of the BOP blind shear ram both on surface 

and subsea. This includes testing the blind shear ram on the surface prior to installation17 and 

TrialGraphix 
206 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

subsea pressure testing after installation.18 The BOP stack was inspected almost daily by remotely 

operated vehicle (ROV).19 Like the positive pressure test, other pressure tests of the blind shear 

ram established that the ram was able to close and seal in pressure.20 The rig crew also regularly 

function tested the blind shear ram, which tested the ability of the ram to close but did not test 

its ability to withhold pressure.21 Subsea pressure and function tests do not demonstrate the 

ability of the blind shear ram to shear pipe.22 

MMS regulations include, among other things, requirements regarding the amount of pressure a 

BOP must be able to contain during testing. MMS regulations normally require rams to be tested 

to their rated working pressure or maximum anticipated surface pressure, plus 500 psi.23 

However, BP applied and received MMS approval to downgrade test pressures for several of the 

Deepwater Horizon‘s BOP elements. The departure that MMS granted allowed BP to test the 

Deepwater Horizon‘s blind shear ram at the same pressures at which it tested casing.24 Though 

the rig crew tested the blind shear ram to 15,000 psi prior to launch (showing that it would 

contain 15,000 psi of pressure), subsequent tests were at pressures as low as 914 psi.25 The rig 

crew also tested the annular preventers at reduced pressures. MMS regulations require that 

high-pressure tests for annular preventers equal 70% of the rated working pressure of the 

equipment or a pressure approved by MMS.26 BP‘s internal guidelines similarly call for annular 

preventers to be tested to a maximum of 70% of rated working pressure ―if not otherwise 

specified.‖27 In May 2009, BP filed an application to reduce annular tests to 5,000 psi.28 In 

January 2010, BP filed another application to further reduce testing pressures for both annular 

preventers to 3,500 psi.29 It is likely BP sought to test equipment at lower pressures in order to 

reduce equipment wear.30 

BP‘s lowered pressure testing regime was both approved by MMS and consistent with industry 

practice. BOP elements are designed to withstand and should be able to withstand higher 

pressures even if tested to lower pressures.31 Nonetheless, low-pressure testing only 

demonstrates that equipment will contain low pressures. At Macondo, many tests did not prove 

the blowout preventer‘s ability to contain pressures in a worst-case blowout scenario.32

 

Blind Shear Ram Activated and Sealed During April 20 

Positive Pressure Test 

On the day of the blowout, the rig crew used the blind shear ram to conduct a positive pressure 

test.33

 As discussed in Chapter 4.6, the blind shear rams closed and sealed as expected during the 

test. This fact suggests that the rams were capable of sealing the well when the blowout occurred. 

But the evidence on its own is inconclusive that the rams could have functioned in an emergency; 

during the positive pressure test the crew closed the blind shear rams using a low-pressure 

hydraulic system, rather than the high-pressure hydraulic system that would have activated the 

rams in the event of a blowout. 

Blind Shear Ram Activation at Macondo 

There are five ways the blind shear ram on the Deepwater Horizon blowout preventer could have 

been activated: 

 direct activation of the ram by pressing a button on a control panel on the rig; 

 activation of the EDS by rig personnel; 

 direct subsea activation of the ram by an ROV ―hot stab‖ intervention;34
Chief Counsel’s Report — Chapter 4.9: The Blowout Preventer | 207

 activation by the automatic mode function (AMF) or ―deadman‖ system due to emergency 

conditions or initiation by ROV; and 

 activation by the ―autoshear function‖ if the rig moves off location without initiating the 

proper disconnect sequence or if initiated by ROV. 

Preliminary information from the recovered blowout preventer suggests the blind shear ram may 

have been closed and indicates erosion in the BOP on either side of the ram as pictured in Figure 

4.9.6.35 This suggests one of these mechanisms may have successfully activated the blind shear 

ram but failed to seal the flowing well because high-pressure hydrocarbons may have simply 

flowed around the closed ram.

Figure 4.9.6. Deepwater Horizon blowout preventer’s closed blind shear ram 

(top view). 

As discussed in Chapter 4.8, there is no evidence that rig personnel attempted to directly activate 

the blind shear ram from the rig‘s control panels. Rig personnel did attempt to activate the EDS 

system after the explosions, but those attempts did not activate the blind shear ram. Emergency 

personnel in the days following the blowout were unable to shut in the well by directly activating 

the blind shear ram using an ROV. At various points in time, the deadman function should have 

closed the ram. Though Transocean has suggested that this system activated the blind shear 

ram, faults discovered post-explosion may have prevented the deadman from functioning. 

BP has suggested that post-explosion ROV initiation of the autoshear system activated the blind 

shear ram. 

It is clear that some of these mechanisms failed to activate; forensic testing will likely confirm 

which, if any, of these triggering mechanisms successfully activated. Even if activated, none of 

these mechanisms shut in the flowing well. 

TrialGraphix, BP photo
208 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

ROV Hot Stab Activation at Macondo 

Rig personnel can also close the blind shear ram by using an ROV to pump hydraulic fluid into a 

hot stab port on the exterior of the BOP. The hot stab port is connected to the blind shear ram 

hydraulic system; fluid flowing into the port actuates the ram directly, bypassing the BOP‘s 

control systems. 

In theory, this function should close the blind shear ram when other methods fail. But an MMS 

study by West Engineering found ROVs may be unable to close rams during a well control event 

due to lack of hydraulic power.36 The study also found that a flowing well may cause rams to 

erode or become unstable in the time it takes for an ROV to travel from the surface to the BOP on 

the seafloor.37 

ROVs deployed at Macondo at about 6 p.m. on April 21.38 ROV hot stab attempts to shut in the 

well on April 21 and 22 with the pipe rams and the blind shear ram failed.39

 As discussed below, 

on April 22 ROVs may have successfully activated the blind shear ram through the 

AMF/deadman system or autoshear system.40

 But despite these efforts, the blind shear ram did 

not shut in the well.41 Efforts to shut in the BOP through an ROV hot stab continued without 

success until May 5.42

 By May 7, BP had concluded that ―[t]he possibility of closing the BOP has 

now been essentially exhausted.‖43

Efforts to close the BOP stack were frustrated by organizational and engineering problems. In 

December 2004, Transocean had converted the lower variable bore ram on the BOP into a test 

ram44 at BP‘s request.45 Because of an oversight that likely occurred during the modification, a 

hot stab port on the BOP exterior that should have been connected to a pipe ram was actually 

connected to the test ram, which could not shut in the well.46

 Unaware of this fact, response 

teams tried to use that hot stab port to shut in the well.47

 For two days, they tried to close a pipe 

ram but were actually activating the test ram instead.48 This error frustrated response efforts49

until crews discovered the mistake on May 3.50 After discovering the mistake, response crews 

attempted on May 5 to activate the BOP‘s pipe rams again, with no success.51

 

None of the attempted hot stab activations prevented the flow of hydrocarbons from the well. The 

rig crew had tested the hot stab function before installing the Deepwater Horizon BOP, in accord 

with Transocean‘s Well Control Handbook.52 

There are a number of possible reasons why ROVs were unable to activate the rams using hot 

stabs. First, the ram may have activated, but the presence of a tool joint or more than one piece of 

pipe prevented the ram from shearing the pipe and sealing the well. Second, ROV pumps failed 

during early intervention efforts.53

 Third, ROVs were incapable of pumping fast enough and as a 

result were not able to build pressure against a leak in the BOP hydraulic system.54

 

Automatic Blind Shear Ram Activation at 

Macondo

Transocean and BP both claim an automated backup system activated the blind shear ram. 

According to Transocean, the automatic mode function activated.55

 According to BP, the 

autoshear system activated.56 If activated, neither system sealed the well. 
Chief Counsel’s Report — Chapter 4.9: The Blowout Preventer | 209

Automatic Mode Function (AMF)/Deadman 

The AMF or deadman system is designed to close the blind shear ram under certain emergency 

conditions. The system should activate when all three of the following conditions are met: 

 loss of electrical power between the rig and BOP;57 

 loss of communication between the rig and the BOP;58 and 

 loss of hydraulic pressure from the rig to the BOP.59 

Catastrophic events on a rig can create these conditions, or emergency workers can trigger them 

by using an ROV to cut power, communication, and hydraulic lines to the BOP (these components 

are labeled in Figure 4.9.7.).60 The AMF will not operate unless rig personnel ―arm‖ it at a surface 

control panel.61 Notes from response crews and post-explosion analysis of the BOP control 

pods indicate the AMF system on the Deepwater Horizon BOP was likely armed.62

Figure 4.9.7. AMF system. 

Based on available information, it appears likely that the explosion on April 20 created the 

conditions necessary to activate the deadman system. The multiplex (MUX) cables, which carried 

the power and communication lines, were located near a primary explosion site in the rig‘s moon 

pool and would probably have been severed by the explosion.63

 The hydraulic conduit line was 

made of steel64 and less vulnerable to explosion damage.65 However, the BOP would have likely 

lost hydraulic power at least by April 22 when the rig sank, and the deadman should thus have 

activated by that date.66 Response crew personnel also tried to activate the deadman on April 22 

by cutting electrical wires using an ROV.67 According to Transocean, the AMF activated the blind 

shear ram.68

TrialGraphix

The AMF, or deadman, system is activated in emergency conditions.
210 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Unclear Whether AMF Activated 

It is currently not clear whether the AMF activated the blind shear ram. However, the Chief 

Counsel‘s team has identified issues that may have affected the AMF. 

First, the universe of available test records may be limited because Transocean destroyed test 

records at the end of each well.69 Second, the deadman system was not regularly tested.70 

Although Transocean‘s Well Control Handbook calls for surface testing the deadman system,71

based on available evidence the AMF was not tested prior to deployment.72 

Third, the deadman system relied upon at least one of the BOP‘s two redundant control pods 

(yellow or blue) to function. If both pods were inoperable, the system would not have functioned. 

The rig crew function tested and powered both pods at the surface in February 2010 prior to 

splashing the BOP.73 But post-explosion examination revealed low battery charges in one BOP 

control pod and a faulty solenoid valve in another. If these faults were present at the time of the 

incident, they would have prevented the deadman and autoshear functions from closing the blind 

shear ram. 

Low Battery Charge in the Blue Pod 

In the event that electric power from the rig to the BOP is cut off, the BOP‘s control systems are 

powered by a 27-volt and two 9-volt battery packs contained in each pod.74

 These batteries power 

a series of relays that cause the pod to close the blind shear ram if there is a loss of power, 

communication, and hydraulic pressure from the rig.75

 BP tests suggest that it takes at least 

14 volts of electricity to power the relays,76 and a Transocean subsea superintendent has stated 

that the activation sequence may require as many as 20 volts.77 

Tests on the blue pod conducted by Cameron after the blowout on July 3 to 5, revealed that 

battery charge levels may have been too low to power the sequence to shut the blind shear ram. 

The 27-volt battery was found to have only a 7.61-volt charge.78 One of the 9-volt batteries was 

found to have 0.142 volts, and the other 9-volt battery had 8.78 volts.79

 If these battery levels 

existed at the time the deadman signaled the pods to close the blind shear ram, the low battery 

levels very likely would have prevented the blue pod from responding properly.80 Transocean 

disputes whether the batteries were depleted at the time of the explosion. Transocean has 

suggested battery levels were adequate to power the AMF but, due to a software error, may have 

been left activated and discharged after the explosion.81 The Chief Counsel‘s team has not 

received evidence in support of this assertion but anticipates ongoing forensic testing of the pods 

will evaluate expected battery levels at the time of the incident.

Available records suggest that Transocean did not adequately maintain and replace its BOP pod 

batteries.82

 Cameron recommends replacing pod batteries at least annually, and recommends 

yearly battery inspection.83

 Transocean itself recommends yearly inspection of batteries.84 

An April 2010 Transocean ModuSpec rig condition assessment stated that all three pods had new 

batteries installed.85

 But internal Transocean records suggest that the crew had not replaced the 

batteries on one pod for two-and-a-half years prior to the Macondo blowout and had not replaced 

the batteries in another pod for a year.86

 This appears to have been a pattern: Company records 

show that rig personnel found all of the batteries in one Deepwater Horizon BOP pod dead in 

November 2007.87

 
Chief Counsel’s Report — Chapter 4.9: The Blowout Preventer | 211

Table 4.9.1. Control pod battery replacements (based on available records).88

Pod Battery

Replacement Dates

Time Between Battery 

Replacements

Time Between Replacement and 

Blowout

Pod 1* January 26, 2006; 

April 25, 2009 3 years 1 year

Pod 2

May 28, 2004;

December 29, 2005; 

October 13, 2009

1-3 years 6 months

Pod 3 March 26, 2004; 

November 4, 2007 3 years 2.5 years

*The Deepwater Horizon had three pods for its BOP; at any given time, 

one was the ―blue‖ pod, one was the ―yellow‖ pod, and one remained on the surface.

Solenoid Valve Problems in the Yellow Pod 

Control pods also rely on functioning solenoid valves (diagrammed in Figure 4.9.8). The solenoid 

valves open and close in response to electrical signals and thereby send hydraulic pilot signals 

from the pods to the BOP elements.89

 The pilot signals in turn open hydraulic valves, which then 

deliver pressurized hydraulic fluid into BOP rams to close them.90 Each solenoid activates when 

electric signals energize one of two redundant coils in the solenoid.91 

Figure 4.9.8. BOP’s electrical schematic. 

According to maintenance records, the yellow pod‘s solenoids were changed on January 31, 

2010.92 However, tests on the yellow pod conducted by Cameron after the blowout on May 5 

to 793 revealed that a key solenoid valve used to close the blind shear ram was inoperable.94 

TrialGraphix

Tests on the Deepwater Horizon’s yellow pod revealed that the solenoid valve used to 

close the blind shear ram was inoperable.
212 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

BP

Erosion above the blind shear ram on the 

BOP’s kill side.

Figure 4.9.9. Erosion in the BOP.

If this fault existed prior to the blowout, an alarm on the rig‘s control system should have notified 

the rig crew and triggered a record entry by the rig‘s event logger.95 According to witness 

testimony, the rig crew believed the solenoid valve in the yellow pod was functioning as of 

April 20.96

 

Autoshear System May Have Activated but Failed 

to Shut in Flowing Well 

Like the emergency disconnect system (EDS), the autoshear function is designed to close the 

blind shear ram in the event that the rig moves off position. The autoshear is activated when a 

rod linking the lower marine riser package (LMRP) and BOP stack is severed. The rod can be 

severed by rig movements; if the rig moves off position, it will pull the LMRP out of place and 

sever the rod. Rig personnel can also sever the rod directly by cutting it with an ROV.97

 Like the 

deadman, the rig crew must arm the autoshear system at the driller‘s or toolpusher‘s control 

panel.98 According to BP‘s internal investigation, the autoshear function was armed at the time of 

the incident.99 Transocean policy required its personnel to surface test the autoshear system 

before deploying the BOP, and the Deepwater Horizon rig crew conducted a test on 

January 31, 2010.100

Response crews used an ROV to activate the autoshear function directly by cutting the rod on 

April 22 at approximately 7:30 a.m.101 According to BP, response crews reported movement on 

the stack, which may have been the accumulators discharging pressure and activating the blind 

shear ram.102 Even if the autoshear did activate and close the blind shear ram, the blind shear 

ram did not stop the flow of oil and gas from the well. 

Potential Reasons the Blind Shear Ram 

Failed to Seal 

Flow Conditions Inside the Blowout Preventer 

Even if the blind shear ram activated, it failed to seal the well. One possible 

explanation is that the high flow rate of hydrocarbons may have prevented 

the ram from sealing. Initial photos from the recovered BOP show erosion 

in the side of the blowout preventer around the ram, which was a possible 

flow path for hydrocarbons, as seen in Figure 4.9.9.103

 Therefore even if 

the ram closed, the hydrocarbons may have simply flowed around the 

closed ram. 
Chief Counsel’s Report — Chapter 4.9: The Blowout Preventer | 213

Presence of Nonshearable Tool Joint or Multiple Pieces 

of Drill Pipe 

As discussed above, the ram may not have closed because of the presence of a tool joint across the 

blind shear ram. If a tool joint or more than one piece of drill pipe was across the blind shear ram 

when it was activated, the ram would not have been able to shear and seal the well. Though 

preliminary evidence suggests these factors may not have impacted the blind shear ram‘s ability 

to close, the Chief Counsel‘s team cannot rule out the possibility of such interference.104 

Accumulators Must Have Sufficient Hydraulic Power 

The Deepwater Horizon blowout preventer had subsea accumulator bottles that provided 

pressurized hydraulic fluid used to operate different BOP elements. If the hydraulic line between 

the rig and BOP is severed, these accumulators must have a sufficient charge to power the blind 

shear ram. 

The lower marine riser package had four 60-gallon accumulator bottles were on.105 On the BOP 

stack, eight 80-gallon accumulator bottles capable of delivering 4,000 psi of pressure provided 

hydraulic fluid for the deadman, autoshear, and EDS systems.106 These tanks were continuously 

charged through a hydraulic rigid conduit line running from the rig to the blowout preventer.107 

Should the hydraulic line disconnect, the tanks contained compressed gas that could energize 

hydraulic fluid to activate the blind shear ram. The rig crew checked the amount of pre-charge 

pressure in the accumulators prior to deploying the BOP in February.108 However, the available 

amount of usable hydraulic fluid in the accumulators at the time of autoshear and AMF activation 

is unknown. If the charge levels were too low, the accumulators would not have been able to 

successfully power the blind shear ram.109 

BP‘s internal investigation suggests accumulator pressure levels may have been low based on fluid 

levels discovered post-explosion.110 Responders discovered 54 gallons of hydraulic fluid were 

needed to recharge accumulators to 5,000 psi.111

 BP‘s investigation suggests a leak in the 

accumulator hydraulic system may have depleted available pressure levels but not to levels that 

would have prevented activation of the blind shear ram.112

 Response crews observed additional 

leaks from accumulators during post-explosion ROV intervention.113

 

Leaks 

It is relatively common for BOP control systems to develop hydraulic fluid leaks on the many 

hoses, valves, and other hydraulic conduits in the control system. Not all control system leaks 

affect the ability of the BOP to function: Because BOP elements are designed to close quickly, a 

minor leak may slow, but not likely prevent, the closing of the BOP.114

 

Even if a leak is minor, rig personnel must first identify the cause of a leak to ensure that more 

severe system failures do not occur.115 Constant maintenance, inspections, and testing are 

required to prevent and detect such leaks.116 Leaks discovered during surface testing should be 

repaired before deployment.117

 If rig personnel discover a leak after deployment, they must 

decide whether the leak merits immediate repair. Raising and lowering a BOP stack is a 

complicated operation with risks of its own; taking this action to repair a minor control system 

leak may actually increase rather than reduce overall risk.118

 
214 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Leaks May Have Been Unidentified Prior to Incident 

According to Transocean senior subsea supervisor Mark Hay, the Deepwater Horizon‘s BOP had 

no leaks at the time it was deployed at Macondo.119 Even if no leaks existed when the BOP was 

deployed, rig personnel identified at least three leaks in the months before the blowout after the 

BOP was in service.120

 And rig personnel identified several more leaks during response efforts 

that according to independent experts were not likely created during the explosion.121

 It is 

possible leaks developed during the response effort. But it is also possible leaks already existed 

and the rig crew had not identified or analyzed the impact of the leak. 

A leak on the ST lock close hydraulic circuit (leak 3 in Table 4.9.2) may have prevented ROVs 

from pumping enough pressure to fully close the blind shear ram.122 Both BP and Transocean 

have suggested that a leak on the ram lock circuit (leak 4 in the table) may be proof that the blind 

shear ram in fact closed.123 Ongoing forensic testing will likely determine if leaks on the BOP 

control system otherwise affected the BOP‘s functionality, though it is unlikely these leaks 

prevented the BOP from sealing. 

 Table 4.9.2. Leaks on the Deepwater Horizon blowout preventer (partial list). 

Leak Time of Identification

1

Test ram, pilot leak on yellow pod open circuit 

shuttle valve124 Pre-explosion (February 23, 2010125)

2

Upper annular preventer, blue pod leak on the 

hose fitting connecting the surge bottle to 

operating piston126 Pre-explosion (February 19, 2010127)

3

ST lock close hydraulic circuit leak (this is in the 

same hydraulic circuit as the blind shear ram)128 Post-explosion (April 25, 2010129)

4 Blind shear ram ST lock circuit leak130 Post-explosion (April 26,2010131)

5 Lower annular preventer open circuit132 Pre-explosion (date not available133)

Identified Leaks Not Reported to MMS 

Even if forensic testing concludes leaks on the BOP control system did not impact functionality, it 

is not clear BP and Transocean adequately responded to known leaks. According to Transocean 

senior subsea supervisor Owen McWhorter, ―the only thing I‘d swear to is the fact that leaks 

discovered by me, on my hitch, were brought to my supervisor‘s attention and the Company 

man‘s attention.‖134

 

Under 30 C.F.R. § 350.466(f), drilling records must contain complete information on ―any 

significant malfunction or problem.‖135 This provision may require control system leaks or other 

anomalies to be recorded in daily drilling reports and thus subject to review by MMS 

inspectors.136

 At least two of the leaks identified pre-explosion were not listed in daily drilling 

reports. A pilot leak on the test ram open circuit shuttle valve (leak 1 in the table) was not 
Chief Counsel’s Report — Chapter 4.9: The Blowout Preventer | 215

mentioned in the daily drilling report for February 23.137 However, the leak was reported in BP‘s 

internal daily operations report from February 23 until March 13.138 BP wells team leader John 

Guide and BP regulatory advisor Scherie Douglas made the decision not to report the leak to 

MMS, a failure which Guide admits was ―a mistake in hindsight.‖139

 BP well site leader Ronnie 

Sepulvado also admits this leak should have been noted in the daily drilling report but stated that 

it was not reported because the leak did not affect the ability to control the well since it was on a 

test ram and the test ram was still operable.140 

The rig crew failed to include at least one other known leak in the daily drilling reports. Although 

the rig crew discovered a leak on an upper annular preventer hose fitting (leak 2 in the table) on 

February 19,141 the leak was not listed on the daily drilling report.142 Although subsea personnel 

in the past had been required to produce documentation on the leak so that the leak could be 

explained to MMS, McWhorter was not asked to produce documentation for this leak.143 A failure 

to report these leaks potentially violated MMS reporting regulations.144

Inconsistent Response to Identified Leaks 

There is little industry guidance as to what constitutes an appropriate response to minor leaks.145 

It appears the rig crew was able to identify the cause and impact of some leaks but not others. 

Evidence indicates both BP and Transocean personnel assessed the leak on the test ram shuttle 

valve (leak 1 in the table) and determined the ram would still function properly.146 Records 

appear to indicate the rig crew planned to further evaluate this leak when the rig moved from 

Macondo to the next well.147 

In response to a leak on an upper annular hose fitting (leak 2 in the table), the rig crew appears to 

have isolated and monitored hydraulic pressure.148 The crew eventually measured this leak at 

0.1 gallons per minute.149

 Sepulvado noted the leak on his office white board.150 Although the 

leak was later erased from the board, Transocean crew questioned whether the leak was resolved 

and a similar leak was still present during post-explosion ROV intervention.151 According to 

witness testimony, the rig crew never determined the source of a leak on the lower annular (leak 5 

in the table).152 

BOP Recertification 

Recertification of a blowout preventer involves complete disassembly and inspection of the 

equipment.153 This process is important because it allows individual components to be examined 

for wear and corrosion. Any wear or corrosion identified can then be checked against the 

manufacturer‘s wear limits.154

 Because this process requires complete disassembly of the BOP at 

the surface, it can take 90 days or longer155 and generally requires time in dry dock.156 Industry 

papers suggest that ―the best time to perform major maintenance on a complicated BOP control 

system [is] during a shipyard time of a mobile offshore drilling unit (MODU) during its five-year 

interval inspection period.‖157

 The Deepwater Horizon had not undergone shipyard time since 

its commission.158

 

MMS regulations require that BOPs be inspected in accordance with American Petroleum 

Institute (API) Recommended Practice 53 Section 18.10.159 This practice requires disassembly 

and inspection of the BOP stack, choke manifold, and diverter components every three to five 

years.160 This periodic inspection is in accord with Cameron‘s manufacturer guidelines, and 

Cameron would have certified inspections upon completion.161

 
216 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

The Deepwater Horizon Blowout Preventer Was Not Recertified 

It was well known by the rig crew and BP shore-based leadership that the Deepwater Horizon 

blowout preventer was not in compliance with certification requirements.162 BP‘s September 

2009 audit of the rig found that the test ram, upper pipe ram, and middle pipe ram bonnets 

were original and had not been recertified within the past five years.163

 According to an April 

2010 assessment, BOP bodies and bonnets were last certified December 13, 2000, almost 

10 years earlier.164 

Although the September 2009 audit recommended expediting the overhaul of the bonnets by the 

end of 2009 and emails between BP leadership discussed the issue,165 the rams had not been 

recertified as of April 2010.166 A Transocean rig condition assessment also found the BOP‘s 

diverter assembly had not been certified since July 5, 2000.167 Failure to recertify the 

BOP stack and diverter components within three to five years may have violated the MMS 

inspection requirements.168 An April 1, 2010 MMS inspection of the rig found no incidents of 

noncompliance and did not identify any problems justifying stopping work.169

 The inspection did 

not identify the fact that the Deepwater Horizon‘s BOP had not been certified in accordance with 

MMS regulations.170 

“Condition-Based Maintenance” 

Transocean did not recertify the BOP because it instead applied ―condition-based 

maintenance.‖171

 According to Transocean‘s Subsea Maintenance Philosophy, ―[t]he condition of 

the equipment shall define the necessary repair work, if any.‖172

 Condition-based maintenance 

does not include disassembling and inspecting the BOP on three- to five-year intervals,173 a 

process Transocean subsea superintendent William Stringfellow described as unnecessary.174 

According to Stringfellow, the rig crew instead tracks the condition of the BOP in the Rig 

Management System and ―if we feel that the equipment is—is beginning to wear, then we 

make...the changes that are needed.‖175 Transocean uses condition-based monitoring to inspect 

all of its BOP stacks in the Gulf of Mexico.176

 According to Transocean witnesses, its system of 

condition-based monitoring is superior to the manufacturer‘s recommended procedures and can 

result in identifying problems earlier than would occur under time-based intervals.177

 

The Chief Counsel‘s team disagrees. Condition-based maintenance was misguided insofar as it 

second-guessed manufacturer recommendations, API recommendations, and MMS regulations. 

Moreover, the decision to forego regular disassembly and inspection may have resulted in 

necessary maintenance not being performed on critically important equipment. As discussed in 

Chapter 4.10, the Rig Management System used to monitor the BOP was problematic and may 

have resulted in the rig crew not being fully aware of the equipment‘s condition. Given the critical 

importance of the blowout preventer in maintaining well control, the Chief Counsel‘s team 

questions any maintenance regime that could undermine the mechanical integrity of the BOP. 

Technical Findings 

As discussed above, this report does not make any conclusive findings regarding whether and to 

what extent the Deepwater Horizon‘s BOP may have failed to operate properly because forensic 

testing is still ongoing. At this point, the Chief Counsel‘s team can only identify possible reasons 

why the BOP‘s emergency systems failed to activate. 
Chief Counsel’s Report — Chapter 4.9: The Blowout Preventer | 217

The possibilities include:

 explosions on the rig may have damaged connections to the BOP and thereby prevented 

the rig crew from using the emergency disconnect system to successfully activate the 

blind shear ram; 

 ROV hot stab activation may have been ineffective because ROVs could not pump at a fast 

enough rate to generate the pressure needed to activate the relevant rams; and 

 BOP control pods may have been unable to activate the blind shear ram after power, 

communication, and hydraulic lines were severed; low battery levels in the blue control 

pod and solenoid faults in the yellow control pod may have prevented pod function. 

Even if activated, the blind shear ram did not seal in the well on April 20 or in subsequent 

response efforts. Possible reasons for failing to seal include: 

 the high flow rate of hydrocarbons may have eroded the BOP and created a flow path 

around the ram; 

 the BOP‘s blind shear ram may have been mechanically unable to shear drill pipe and 

shut in the well because it was not designed to operate under conditions that existed at 

the time. For instance, the ram may have been blocked by tool joints or other material 

that it was not designed to cut; 

 subsea accumulators may have had insufficient hydraulic power; and 

 leaks in BOP control systems may have delayed closing the BOP, though it is unlikely that 

they prevented the BOP from sealing. Leaks may have existed on the BOP control system 

but not been identified. Identified leaks were not reported to MMS and may have been 

inconsistently monitored. 

Management Findings 

Whether or not BOP failures contributed to or prolonged the blowout, the Chief Counsel‘s team 

has identified several major shortcomings in the overall program for managing proper 

functioning of the BOP stack. 

 MMS regulations require only one blind shear ram on a BOP stack. But blind shear rams 

cannot cut the joints that connect pieces of drill pipe, which comprise a significant 

amount of pipe in a well. The Chief Counsel‘s team agrees with a 2001 MMS study that 

two blind shear rams would mitigate this risk. 

 MMS approved the testing of the Deepwater Horizon blowout preventer at lower 

pressures than required by regulation. Though testing at lower pressures is in accord 

with industry practice, most tests of the blind shear ram did not establish the ability of 

the equipment to perform during blowout conditions with large volumes of gas moving at 

high speed through the BOP into the riser. 
218 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

 Transocean‘s practice of destroying test records at the end of each well creates 

unnecessary information gaps that may undermine BOP maintenance. 

 Critical BOP equipment on the Deepwater Horizon may have been improperly 

maintained. The BOP ram bonnets, bodies, and diverter assembly had not been certified 

since 2000, despite MMS regulations, API recommendations, and manufacturer 

recommendations requiring comprehensive inspection every three to five years. 

Transocean and BP‘s willingness to disregard regulatory obligations on a vital piece of rig 

machinery is deeply troubling. 

Table 4.9.3. Modifications to the Deepwater Horizon blowout preventer. 

Date Modification

November 2001 Control pod subsea plate mounted valves changed from 1-inch to 0.75-inch valves.178

October 2002 Increased power supply to control pod subsea electronic modules (SEMs) to higher amp. rating.179

December 2002 ST locks modified.180

January 2003

Three high-shock flow meters were installed in BOP control pods, replacing 

ultrasonic flow meters.181

January 1, 2003

Changed retrievable control pods to nonretrievable control pods.182

This required the LMRP to be retrieved to surface in order to perform maintenance 

on control pods.183

November 2003 New high-interflow shuttle valve replaced on LMRP and BOP stack.184

May 2004 Control pod regulators modified.185

June 2004 Control pod subsea electronic modules (SEMs) software upgraded by Cameron.186

July/August 2004 New rigid conduit manifold installed and riser-mounted junction boxes removed.187

August 2004 Cameron conduit valve package replaced with ATAG conduit valve package.188

This isolates LMRP accumulators if pod hydraulic power is lost.189

August 2004 Fail-safe panels on choke and kill valves removed from LMRP and BOP stack.190

Valves will close only by spring force.

191

November 2004 “Add a second pod select solenoid functioned by an existing pod select switch—to add double 

redundancy to each control pod.”192

December 2004

AMF/deadman accumulators: “[T]he pre-charge required on the subsea accumulators is 6800 psi 

while the maximum working gas pressure for subsea bottles is 6000 psi. This will mean different 

fluid volumes than are normal on the BOP control system.”193

The deadman accumulators “have now become part of the subsea accumulators since 

the deadman system has been modified.... There will be little appreciable differences 

in the system operability but it is important to know how the reduced pre-charge

and extra accumulators work on the system.”194

December 2004

Lower variable bore ram converted to test ram.195

A test ram holds pressure from above, instead of below. 196 Possibly overlooked relabeling 

ROV hot stab connections, resulting in ROVs activating test ram during post-explosion

efforts to close the BOP.197

February 2005 Control pod modified: “[R]eplace all unused functions on pod with blind flanges. Possible failure 

points resulting in stack pull.”198

September 2005

Control system pilot regulator: “[R]eplace pilot regulator with a better designed, 

more reliable regulator leaks. (Gilmore is a larger unit and will require a bracket 

to be fabricated for mounting.)”199

February 2006

Control panel: “Modification to Cameron control software to sound an alarm 

should be a button stay pushed for more than 15 [seconds]. If a button is stuck 

and not detected it will lock up panel.”200
Chief Counsel’s Report — Chapter 4.9: The Blowout Preventer | 219

Table 4.9.3 (continued) 

Date Modification

June 26, 2006

Installed new repair kit in autoshear valve. New repair kit came with new rod and the rod 

was too long, had to use old rod.201

July 2006 (proposal for 

modification approved) At BP’s request, the lower annular preventer was changed to a stripping annular.

202

January 2007

AMF/deadman—Cameron will remove the SEM from the MUX section to replace the pipe 

connectors (customer provided) and to install the AMF/deadman modification kit.203

September 2008 Riser flex joint replaced.204

June 10, 2009

Software changes made to allow all functions that were previously locked out from any of 

the BOP’s control panels to become unlocked whenever the EDS command was issued 

from any control panel.205

August 3, 2009 Autoshear valve replaced with new Cameron autoshear valve.206

2010

Combined the following ROV hot stab functions:207

blind shear ram close;

ST lock close; and choke and kill fail-safe valves.

Chief Counsel’s Report — Chapter 4.10: Maintenance | 221

Chapter 4.10|Maintenance

deepwater drilling rig like the Deepwater Horizon has literally 

thousands of pieces of equipment that need routine monitoring and 

repair.1 The Deepwater Horizon‘s crew performed more than 

550 preventative maintenance jobs each month on the Deepwater 

Horizon and had spent more than 30,000 work hours on maintenance in the 

10 months prior to the explosion.2 

In some respects the Horizon appeared to be operating quite well. The rig received several safety 

awards3and a place inside Transocean‘s ―excellence box,‖ which compares rigs based on safety 

performance and equipment downtime.4 BP wells team leader John Guide described the rig as 

BP‘s most successful in terms of performance,5and one reason leaders from BP and Transocean 

were visiting the rig on the day of the blowout was to recognize the rig‘s high performance.6 

It is nevertheless possible that poor maintenance contributed to technical failures. According to 

pre-explosion BP emails, the rig was ―getting old and maintenance has not been good enough.‖7

Most notably, Chapter 4.9 of this report explains that certification of blowout preventer (BOP) 

equipment was overdue and that if blowout preventer maintenance was inadequate, it could have 

affected the ability to shut in the well. Other issues may have affected maintenance but, based on 

available information, likely did not contribute to the blowout. 

Transocean’s Rig Management System

Transocean had in place comprehensive procedures and systems for scheduling, implementing, 

and monitoring maintenance.8 Like all Transocean rigs, the Deepwater Horizon used the 

computerized ―Rig Management System II‖ (RMS), which Transocean had implemented as a 

result of its merger with Global Santa Fe.9 Transocean personnel used RMS to schedule 

maintenance work based on information including equipment data, maintenance records,10

information on certification and surveys,

11 and risk assessments.12

 Based on these materials, the 

automated system generated preventative maintenance13 items for the rig.14 The rig crew would 

perform these tasks and then record their completion in the system.15 Transocean‘s goal in using 

the system was to ensure consistency, consolidate information, and facilitate personnel 

movement from rig to rig.16 

While the Chief Counsel‘s team interviewed Deepwater Horizon crew members who found the 

RMS useful (despite the fact that it ―definitely had some bugs in it‖) and who used it daily,17 the 

team also found evidence to suggest that the system had problems. Transocean installed the RMS 

on the Horizon in September 2009,18 but according one witness it was ―still a work in progress‖ at 

the time of the blowout.19 For instance, while the system produced thousands of preventative 

maintenance orders for Transocean‘s fleet,20 many orders were disorganized, erroneous, or 

irrelevant to individual rig crews. The Deepwater Horizon‘s rig crew was forced to actively search

the system for the Deepwater Horizon‘s maintenance items and to continually submit requests to 

remove duplicate maintenance orders or orders meant for another rig.21 The system also 

A
222 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

generated work orders for equipment that had already been repaired, leaving the rig crew to 

determine if work orders generated by the system actually needed to be performed.22 According 

to chief engineer Stephen Bertone, the rig crew ―went through them as much as [they] could just 

poking through the system, but...there were still issues with it.‖23 According to assistant driller 

Allen Seraile, the system was chaos at one time.24 Chief electronics technician Mike Williams 

described the system as ―overwhelming.‖25

The crew expressed confusion regarding the new system and concerns about its implementation. 

In a March 2010 Lloyd‘s Register survey, crew members stated that system changes to the RMS 

and other rig systems were ineffectively implemented.26 They thought that new systems were 

introduced too frequently and before the previous system was understood.27 The rig crew also 

thought there was insufficient support to implement changes and that system changes required a 

level of technical capability not typically available throughout the rig.28 An April 2010 Transocean 

assessment also found that the maintenance system was not understood by the crew.29 

Competing Interests Between Drilling 

and Maintenance

The rig services contract between BP and Transocean specifies that shutting down the rig to 

perform certain types of maintenance will trigger financial consequences. BP paid Transocean a 

daily operating rate of $533,495 for the Deepwater Horizon, but under the contract BP was not 

obligated to pay for time in excess of 24 hours each month spent on certain equipment repairs.30

The Chief Counsel‘s team cannot be certain whether these provisions or other financial pressures 

influenced maintenance decisions. However, some of the rig crew raised concerns that drilling 

priorities took precedence over planned maintenance.31 The Deepwater Horizon had never been 

to dry dock for shore-based repairs in the nine years since it had been built.32 BP and Transocean 

appear to disagree as to whether financial considerations influenced this decision. While Guide 

suggested the Horizon did not go to dry dock because Transocean insisted on being paid its daily 

rate during repairs,33 Transocean operations manager Daun Winslow testified that any necessary 

repairs would have been made regardless of financial constraints.34 

Lack of Onshore Maintenance

Some maintenance can only be performed when a rig is moving between well sites or when the rig 

is brought into shore.35 But the Horizon had never been to dry dock since it was built in 2001.

Transocean instead conducted ―Underwater Inspection in Lieu of Dry-docking‖ (UWILD) and 

other at-sea inspections.36 In the March 2010 Lloyd‘s Register survey some of the rig crew 

expressed concern that the lack of dry dock time could generally undermine equipment 

reliability.37 According to the survey, the maintenance department was looking forward to a 

scheduled dry dock visit in 2011 ―to carry out evasive [preventative maintenance] routines 

that they normally could not do.‖38 Lack of time in dry dock may have resulted in a lapse in 

BOP certification.39

Following company policy,40 Transocean commissioned an inspection in April 2010 to assess 

equipment and prepare for the rig‘s scheduled 2011 shipyard maintenance.41 The inspection 

found that some problems identified in September 2009 remained unaddressed and identified 
Chief Counsel’s Report — Chapter 4.10: Maintenance | 223

several new maintenance issues.42 As of April 2010, Transocean documents listed 35 critical 

items of equipment that either were in bad condition, had shown excessive downtime, had passed 

manufacturer wear limits, or that the manufacturer no longer supported.

43

 As discussed in 

Chapter 4.9, the list included BOP elements that had passed their certification date.44 According 

to witness testimony, Transocean had decided to extend the Horizon‘s anticipated time in dry 

dock because of the number of repairs necessary.45 The Chief Counsel‘s team requested but was 

not able to obtain a list of repairs scheduled for the Horizon‘s 2011 dry dock visit.

Maintenance Audits and Inspections

The Horizon was subject to audits and inspections by various government and private entities, 

including BP,46 Transocean,47 MMS,48 the Coast Guard,49 the American Bureau of Shipping,50 and 

the Marshall Islands (the ship‘s flag state in 2010).51 These audits varied in scope and duration. 

Both BP and Transocean had a vested interest in keeping the Horizon in working order. Witness 

testimony describing the response to a fall 2009 audit indicates collaboration by both companies 

to ensure necessary repairs were made. 

Transocean Resolved Many Maintenance Issues Identified in the 

September 2009 BP Audit

In September 2009 BP audited the Deepwater Horizon‘s drilling equipment and the vessel 

itself.52 The audit found 390 maintenance jobs overdue and identified some of those as 

high-priority items.53 BP estimated that the work would require 3,545 man-hours of labor.54 

The audit may have overestimated the sheer number of jobs that were overdue because of errors 

and duplicates in the RMS system, which Transocean had recently installed.55 BP asked 

Transocean to undertake certain repairs before allowing the Horizon to resume operations.56 

A few days later, BP determined that the rig was operational,57 and the rig resumed operations 

on September 22, 2009, five days after the audit ended.58 

BP and Transocean increased communication and coordination to monitor implementation of 

outstanding audit recommendations.59 For example, auditors communicated conditions to the rig 

crew during the audit itself in order to ensure that certain repairs were made promptly.60 BP and 

Transocean held weekly meetings to track progress,61 and Guide or well site leaders signed off on 

corrective actions taken in response to the audit.62 By March 30, 2010, 63 of 70 had been 

completed, progress BP described as ―commendable.‖63 Twenty-six other outstanding items were 

in progress and deemed not safety-critical.64 

BP and Transocean Believed the Rig Was in Safe Working Order

At the time of the blowout, both BP and Transocean believed the Deepwater Horizon was in safe 

operating condition.65 Well site leader Ronnie Sepulvado did not believe there were serious 

outstanding safety issues,66 and neither he nor the other well site leaders indicated that the vessel 

was unsafe to operate.67 Guide recognized that the rig was operating safely and making very good 

progress on addressing audit items.68

An April 1, 2010 MMS inspection of the rig found no incidents of noncompliance and did not 

identify any problems justifying stopping work.69 But, as discussed in Chapter 6, the inspection 

did not identify that the Deepwater Horizon‘s BOP had not been certified.70
224 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Maintenance Findings

Inspections, audit programs, and statements by rig- and shore-based leadership indicate that BP, 

Transocean, and government regulators believed the Deepwater Horizon was in safe operating 

order at the time of the blowout. With the exception of potential BOP maintenance issues, the 

Chief Counsel‘s team found no reason to believe that maintenance problems may have 

contributed to the blowout. However, the Chief Counsel‘s team believes the following issues may 

have compromised the rig‘s maintenance regime: 

 Transocean‘s RMS system may have complicated routine maintenance and monitoring. 

The rig crew appears to have been confused about the system, and the system issued 

duplicate and erroneous maintenance instructions; and 

 the fact that the Deepwater Horizon had never been in dry dock may have delayed or 

prevented certain repairs that could only have been done onshore.
Chief Counsel’s Report — Chapter 5: Overarching Failures of Management | 225

Chapter 5|Overarching Failures 

of Management

he Macondo disaster was not, as some have suggested, the result of a

coincidental alignment of disparate technical failures.

1

 While many 

technical failures contributed to the blowout, the Chief Counsel‘s team 

traces each of them back to an overarching failure of management. 

Better management would have identified the risks at Macondo and prevented the technical 

failures that led to the blowout. In Chapter 4, the Chief Counsel‘s team identified particular 

management failures associated with each technical failure. This chapter synthesizes those 

findings into higher-level observations about the management system in place at Macondo. 

The management breakdown at Macondo affected many of the operational aspects of designing 

and drilling the well. The Chief Counsel‘s team observed at least the following management 

failures: (1) ineffective leadership at critical times; (2) ineffective communication and siloing of 

information; (3) failure to provide timely procedures; (4) poor training and supervision of 

employees; (5) ineffective management and oversight of contractors; (6) inadequate use of 

technology; and (7) failure to appropriately analyze and appreciate risk. Ultimately, the 

companies placed undue reliance on timely intervention and human judgment in light of their 

failure to provide individuals with the information, tools, and training necessary to be effective.

BP‘s and Transocean‘s corporate guidance documents, in place before the blowout, show that they 

recognize how important each of these management areas is to safe and effective oil and gas 

exploration.2 (Halliburton declined to provide management documents to the team.) The fact 

that failures in these areas led to the Macondo blowout reinforces the companies‘ conclusions 

about their importance. It also underscores the importance of management follow-through to 

ensure that policies affect cultures and day-to-day routines.

This chapter discusses each of these various failures in turn. The management observations in 

this chapter are limited to the Macondo well, which has been the focus of the Chief Counsel‘s 

investigation. The failures at Macondo were not inevitable, and the Chief Counsel‘s team sets 

them out here in the hope that they will not be repeated.

Leadership 

The first principle of BP‘s operating management system (OMS) is leadership. OMS calls for 

―operating leaders [who] are competent, exhibit visible, purposeful and systematic leadership and 

are respected by the organizations they lead.‖3 BP further expects that ―operating leaders create 

and support clear delegation and accountability.‖4 Often this did not happen at Macondo. The 

Chief Counsel‘s team observed conflict between managers and confusion about who was 

accountable for critical decisions.5 The team responsible for key decisions at Macondo did not 

always appear to be acting with a consistent and shared purpose.

T
226 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Figure 5.1. BP internal presentation slide.

In March, for example, operations to control the well after a kick led to disagreements between 

BP‘s managers on the Macondo team. BP engineering team leader David Sims wrote BP wells 

team leader John Guide: ―We cannot fight about every decision.... I will hand this well over to 

you in the morning and then you will be able to do whatever you want.‖6 Sims later explained this 

and other comments as ―coaching‖ and stated that Guide‘s performance was atypical during this 

time period.7 Guide himself appears to have acknowledged the concern and responded that he 

would ―consult the team and make well thought out decisions.‖8 Nonetheless, the comments 

suggest management friction during a critical operation, and leadership problems on the 

Macondo team did not end in March.

At the beginning of April, BP conducted a major reorganization of its exploration business unit, 

including the BP Macondo team, creating separate reporting structures for engineering and 

operations. Prior to the reorganization, the unit had been organized by project—all of the 

engineers and operations personnel for a given well reported to the same manager. Thus, Guide 

(representing operations) and Sims (representing engineering) both reported to the same person, 

BP wells manager Ian Little. BP senior drilling engineer Mark Hafle and drilling engineer Brian 

Morel reported to Sims; the well site leaders reported to Guide.9 

The reorganization separated engineering and operations into distinct functional groups within

the business unit. As of April, the wells team leader reported to a wells operation manager, and 

the engineering team leader reported to a separate engineering manager. BP also moved key 

personnel. BP promoted Sims from engineering team leader to wells operation manager. Instead 

of being Guide‘s peer, he was now Guide‘s supervisor. Gregg Walz, who had no prior experience 

with the Macondo well before March 

2010, took over for Sims as 

engineering team leader. Walz now 

reported to new engineering manager 

John Sprague.10

The reorganization caused delays and 

distractions. Shortly before the 

reorganization, BP vice president of 

drilling and completions Pat O‘Bryan 

questioned Gulf of Mexico managers 

about recent subpar performance, 

asking, ―What‘s getting in the 

way...reorg uncertainty?‖11 Sims later 

shared that there were ―challenges‖ 

associated with the reorganization 

and that ―it may have taken a little 

more time to ensure that there was 

alignment between Ops and 

Engineering teams.‖12 In an 

interview with Commission staff, 

Sims acknowledged that Walz may 

have been taking longer than usual to 

make engineering decisions as he 

came up to speed in his new role.13 

BP
Chief Counsel’s Report — Chapter 5: Overarching Failures of Management | 227

Guide agreed. He told BP investigators that it was ―easier‖ and ―faster‖ to make decisions under 

the old structure.14

The reorganization also led to questions about authority and accountability, and apparent friction 

between team leaders Guide and Walz. Hafle noted that ―no one argues with John Guide,‖ but 

after the reorganization, Guide expressed confusion about his own authority to Sims and to 

Sprague.15 In an April 17 email to Sims, Guide asked, ―Everybody wants to do the right thing, but, 

this huge level of paranoia from engineering leadership [i.e. Walz] is driving chaos.... What is 

my authority? With the separation of engineering and operations I do not know what I can and 

can‘t do.‖16 

Sims responded, ―I don‘t think anything has changed with respect to engineering and operations,‖ 

but went on to note, ―If you don‘t agree with something engineering related, and you and [Walz] 

can‘t come to any agreement, [Sprague] or me gets involved.‖ Guide later observed that the 

resolution of an issue by Sprague or Sims was precisely his concern.17 While Little had previously 

been responsible for engineering and operations on his own, now there were two separate leaders 

for each team, each of whom had a different supervisor of their own. To find an individual who 

had responsibility for both engineering and operations, the Macondo team had to go all the way 

up to O‘Bryan, the head of drilling and completions for the Gulf of Mexico. 

The Chief Counsel‘s team does not presume to know whether the reorganization improved BP‘s 

previous management structure, but it is clear that the way BP handled authority and 

accountability created confusion during the Macondo project. For example, the BP team did not 

know who was accountable for important practices associated with safety. After the blowout, 

Hafle told BP investigators that he had no idea who was accountable for ensuring compliance with 

BP‘s standards on drilling safety.18 Sims told BP investigators, ―this accountability is not well 

documented‖ and ―it is more like  ̳we are all accountable.‘‖19 

Saying that everyone is accountable can be beneficial in certain instances, such as with respect to 

personal safety and ―stop-job‖ authority, but can lead to a diffusion of personal responsibility for 

process safety. For example, BP has admitted that its internal engineering standards required the 

Macondo team to conduct a formal risk assessment of the annulus cement barriers in the well, 

and that such an assessment might have led the team to run a cement evaluation log.20 Yet 

nobody on the team appears to have brought up the relevant Engineering Technical Practice 

(ETP) on zonal isolation.21 There also appears to have been confusion about who was accountable 

for ensuring the adequacy of the cement slurry design, determining the risks attendant to changes 

in operations, and assessing the competence of personnel assigned to perform the negative 

pressure test.22

Though it is understandable that no one would wish to take ownership of the well after the 

blowout, the Chief Counsel‘s team found many instances in which nobody was taking ownership 

before the blowout. 

Communication

Inadequate communication and excessive compartmentalization of information contributed to 

the Macondo blowout. Individuals making decisions regarding one aspect of the well, such as

onshore engineers, did not always communicate critical information to others, such as the well 

site leaders, who were making related decisions on other aspects of the well. When faced with 
228 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

anomalous data, decision makers often failed to seek counsel from others with expertise and 

instead made decisions based on incomplete information. BP and Transocean also failed to 

communicate lessons learned from other wells that could have assisted the decision makers at 

Macondo. Below are a few examples.

Information Compartmentalization

Information about drilling at Macondo was compartmentalized both within and between 

companies. In several instances, the BP onshore engineering team was aware of risks with the 

Macondo job but failed to communicate those risks to its own employees on the rig or the 

contractor personnel who might have helped mitigate those risks. The cementing and temporary 

abandonment processes provide key examples. 

Cement jobs inevitably involve some uncertainty, but this job was particularly tricky. Due to 

equivalent circulating density (ECD) concerns, BP did not perform a full bottoms up prior to the 

cement job, it used foam cement, it pumped a smaller volume of cement than normal, it circulated 

the cement at lower flow rates than normal, and it used an overall slurry having a density 

approaching the density of the drilling mud in the annulus. BP pumped the job knowing that it 

had had difficulty converting the float equipment and that post-conversion circulating pressures 

had been unexpectedly low. And BP used fewer centralizers than called for by Halliburton‘s 

model. BP also decided to rely heavily on its difficult cement job soon after pumping it, by using 

temporary abandonment procedures that forced rig personnel to rely on the cement as the only 

constant barrier during riser displacement.

Despite knowing all of these cementing-related risks, BP‘s onshore team did not emphasize them 

to the individuals conducting the negative pressure test (including its own well site leaders). It 

also did not emphasize these risks to the individuals who were monitoring the well for kicks 

during riser displacement (Transocean and Sperry Drilling personnel), much less involve those 

individuals in discussions about how to mitigate the risks of cement failure.23 

While rig personnel should always assume for well monitoring purposes that the bottomhole 

cement (or any other barrier) might fail, BP‘s onshore team should have, and easily could have, 

alerted the well site leaders and rig crew that cement failure at Macondo might be more likely 

than normal and instructed them to be extra vigilant regarding any odd pressure readings. 

Chapter 4 is replete with similar examples.

Experts

BP did not always use its internal technical experts effectively.

For example, BP asked an in-house cement expert to help redesign the cement job to address ECD 

worries and thereby allow BP to use the long string production casing rather than a liner. During 

that process, the Macondo team asked the expert only for his general opinions about the 

suitability of foamed cement. Though Guide believed that the expert had ―vetted‖ the cement 

program,24 nobody on the Macondo team consulted the expert after April 14, and he never saw 

any laboratory testing data for the cement until after the blowout.

The Macondo team similarly did not consult completion engineers before reaching a decision on 

whether to run a long string or a liner. On April 15, one of the completion engineers wrote Morel: 
Chief Counsel’s Report — Chapter 5: Overarching Failures of Management | 229

―Yeah, well no one told us what the actual decision was, so we thought y‘all were going with the 

liner....‖

25

 BP is now developing standards on how to consult internal experts and hiring more 

cementing experts. 

Calling Shore

BP did not provide adequate guidance on when staff on the rig should consult onshore personnel. 

BP had a communications plan that described instances when rig personnel should call shore.26 

The plan did not address the negative pressure test specifically, and its general criteria for calls to 

shore did not apply clearly (if at all) to the negative pressure test on April 20.27 After the incident, 

Hafle said that the communications plan ―was not well written.‖28 Another BP employee poked 

fun at its ―weird drawings with boxes & arrows.‖29 

It does not appear that the well site leaders ever contacted BP onshore personnel to discuss their 

inability to bleed off drill pipe pressure during the negative pressure test. They did not seek a 

second opinion from Sims or O‘Bryan, both of whom are engineers and were on the rig during the 

negative pressure test as part of the VIP visit. Instead, according to their own accounts, the well 

site leaders accepted an explanation from a Transocean toolpusher who had no more training on 

test procedures than they had. 

Less than one week after the blowout, BP well site leader Bob Kaluza wrote the following email to 

Guide and a colleague explaining how the ―bladder effect‖ could account for the 1,400 pounds per 

square inch (psi) on the drill pipe:

I believe there is a bladder effect on the mud below an annular preventer as we discussed. 

As we know the pressure differential was approximately 1400-1500 psi across an 18 3⁄4′′

rubber annular preventer, 14.0 SOBM plus 16.0 ppg [pounds per gallon] Spacer in the 

riser, seawater and SOBM below the annular bladder. Due to a bladder effect, pressure 

can and will build below the annular bladder due to the differential pressure but can not 

flow – the bladder prevents flow, but we see differential pressure on the other side of 

the bladder.

Now consider this. The bladder effect is pushing 1400-1500 psi against all of the mud 

below, we have displaced to seawater from 8,367' to just below the annular bladder where 

we expect to have a 2,350 psi negative pressure differential pressure due to a bladder 

effect we may only have a 850-950 psi negative pressure until we lighten the load in 

the riser.

When we displaced the riser to seawater, then we truly had a 2,350 psi differential and 

negative pressure.30

O‘Bryan responded to the forwarded email as follows: 

Mike,

??????????????????????????????????????????????????????????????????????????????????

??????????????????????????????????????????????????????????????????????????????????

??????????????????????????????????????????????????????????????????????????????????

??????????????????????????????????????????????????????????????????????????????????

?????????????????????????????????????????????????????????????
230 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Regards,

Pat

It thus appears that, had Kaluza brought the ―bladder effect‖ explanation to O’Bryan’s attention 

on April 20, events likely would have turned out differently. Guide, Walz, Sims, and BP 

operations engineer Brett Cocales have each told the Chief Counsel‘s team that the ―bladder 

effect‖ does not exist, that it would not account for the pressure readings seen that night in any 

event, and that they would have insisted on further testing before declaring the test a success had 

the well site leaders called to shore.31 While these statements are self-serving, they are believable 

in this instance—everyone who has testified before the Joint Investigation Panel or spoken with 

the Chief Counsel‘s team has agreed the ―bladder effect‖ does not exist and would not explain the 

pressure readings observed that night.

While O‘Bryan appears to have been incredulous at Kaluza‘s explanation of the ―bladder effect,‖ 

BP management itself is to blame for failing to make clear to its well site leaders that they must 

call back to shore when confronted with unexpected results on a critical test.

32

 After the fact, BP 

and Macondo team members have said the well site leaders on the Deepwater Horizon should 

have called back to shore on April 20. But they have been unable to point to any specific company 

policy, written or otherwise, that would have required the well site leaders to seek that second 

opinion.33 When asked whether BP had any relevant policy at the Commission‘s November 8, 

2010 hearing, BP‘s Mark Bly answered, ―It‘s an expectation that if people feel they don‘t 

understand what is going on or they need help, that they will escalate and call back. So

absolutely...I don‘t know if it‘s the policy. It‘s sort of the behavior that we expect from people.‖34

Given the importance of the negative pressure test, calls back to shore should be required as a 

matter of course regardless of the whether results appear anomalous. BP has apparently now 

instituted just such a policy.35

Sharing Lessons Learned

Transocean failed to communicate to BP and its rig crew lessons learned from a similar near miss 

on one of its rigs in the North Sea four months prior to the Macondo blowout. On December 23, 

2009, gas entered the riser while the North Sea rig was displacing a well with seawater during a 

completion operation. As at Macondo, the crew had already run a negative pressure test on the 

lone static barrier between the pay zone and the rig and deemed it successful.

36

 The tested barrier 

failed during displacement. Hydrocarbons flowed into the well, and mud spewed from the rig 

floor. Unlike at Macondo, the crew was able to shut in the well before a blowout occurred but not 

until nearly one metric ton of oil-based mud had spilled into the ocean.

37 The incident cost 

Transocean 11.2 days of additional work and more than 5 million British pounds.

38

 

Transocean subsequently created an internal presentation for a March conference call reviewing 

the near miss. It warned that ―[t]ested barriers can fail‖ and that ―risk perception of barrier 

failure was blinkered by the positive inflow test [negative pressure test].‖39 It pointed out that 

―[f]luid displacements for inflow test [negative pressure test] and well clean up operations are not 

adequately covered in our well control manual or adequately cover displacements in under 

balanced operations.‖40 The presentation concluded with a slide titled ―Are we ready?‖ and ―What 

if?‖ which contained the following bullet points: ―[h]igh vigilance when reduced to one barrier 

underbalanced,‖ ―[r]ecogni[z]e when going underbalanced—heightened vigilance,‖ and 
Chief Counsel’s Report — Chapter 5: Overarching Failures of Management | 231

―[h]ighlight what the kick indicators are when not drilling.‖41 However, the call only involved 

toolpushers operating in the North Sea.

On April 5, 2010, Transocean issued an advisory setting forth anticipated amendments to its Well 

Control Handbook in light of the North Sea incident.42 The advisory sought ―to clarify the 

requirements for monitoring and maintaining at least two barriers when displacing to an 

underbalanced fluid during completion operations.‖43 It noted that a Transocean rig recently 

experienced a well control event ―due to a failure of a tested mechanical barrier.‖44 To prevent a 

recurrence, the advisory required the drill crew to identify: 

(1) the volumes to be pumped, (2) the planned displacement rate(s), (3) the position of 

the fluid interface(s) at all times, (4) the resultant U-tube pressures in the well at all times 

and, (5) most importantly the point at which the completion fluid will become underbalanced with respect to formation pressure.45

 

The advisory ended with an apt warning: ―Do not be complacent because the reservoir has 

been isolated and inflow tested. Remain focused on well control and maintain good well 

control procedures.‖

46

There are two problems with the advisory. First, it unduly limits the amendment to the 

―Completions‖ section of the handbook despite the fact that it should apply equally to temporary 

abandonment procedures such as those at Macondo. Second, it does not appear that anyone 

associated with the Deepwater Horizon ever received the advisory prior to the blowout.47 

Transocean points out that it posted the advisory to an online, e-document platform accessible to

the Deepwater Horizon crew.48 But Transocean never alerted Macondo personnel to the posting, 

and there is no indication anyone actually saw it. 

Transocean issued a more extensive advisory on April 14, less than one week before the Macondo 

blowout.49 The new advisory described the North Sea incident and listed error-inducing 

conditions, missed opportunities, root causes, and contributing factors. Among the errorinducing conditions, it noted that the ―drill crew did not consider well control as a realistic event 

during the...displacement operation as the [downhole barrier] had been successfully [negative 

pressure] tested,‖ and the displacement was set up as ―an open circulating system‖ nullifying pit 

monitoring.50 The advisory admonished rig management that ―[t]ested barriers can fail and risk 

awareness and control measures need to be implemented,‖ ―[s]tandard well control practices 

must be maintained through the life span of the well,‖ and that well programs must ―specify 

operations that induce underbalance conditions in the well bore.‖51 As one Transocean executive 

noted after the incident, reading the advisory would ―increase the awareness of anybody in the 

drilling industry.‖52

But Transocean circulated its April 14 advisory only to North Sea personnel, even though the 

lessons applied globally.53 The company labeled the advisory in a narrow way, describing the 

North Sea event as a ―Loss of Well Control During Upper Completion.‖54 Transocean‘s operations 

manager for the Gulf of Mexico admitted that personnel involved in drilling operations might not 

read an advisory labeled this way.55 Again, there is no evidence that anyone involved with 

Macondo or the Deepwater Horizon ever saw the April 14 advisory. 

Transocean argues that alerting the crew to the advisory was unnecessary because the advisory 

simply restates good well control practice already known to the crew.56 The Chief Counsel‘s team 
232 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

does not agree. There is no evidence the rig crew on the night of April 20 followed any of the five 

steps mandated by the advisory. Asked whether he knew on April 20 that ―monitoring the 

displaced volume alone is inadequate and does not satisfy the requirement for a known monitored 

column of fluid,‖ Transocean‘s rig manager for the Deepwater Horizon, Paul Johnson, answered, 

―No. I‘m thinking hard and clear about this, no.‖57

Transocean has stated that the North Sea incident and advisory were irrelevant to what happened 

in the Gulf of Mexico. The December incident occurred during the completion phase, in the 

North Sea, and involved the failure of a different tested barrier.58 

Transocean‘s post-blowout reliance on these cosmetic differences is not an answer; to the

contrary, these arguments only further reinforce the Chief Counsel‘s team‘s conclusions about the 

compartmentalization of information. The relevant facts of the Macondo and North Sea incidents 

are the same. Indeed, the North Sea incident may have had greater implications and relevance in 

deepwater. There is no reason why the lessons learned in the North Sea would not apply to the 

Gulf of Mexico or non-completion operations. Had Transocean adequately communicated the 

lessons from the North Sea to the crew of the Deepwater Horizon prior to April 20, events at 

Macondo may have unfolded differently.

Procedures

BP failed to provide its well site leaders and the rig crew with clear, detailed, and timely 

procedures. Instead, the evidence shows that BP‘s onshore Macondo team was rushing to design 

and provide procedures in order to keep up with operations on the rig. As a consequence, BP 

employees on the rig were not always sufficiently informed about upcoming operations. 

The most obvious example is BP‘s temporary abandonment procedure. On April 12, for example, 

BP well site leader Murry Sepulvado wrote Morel: ―Brian we need procedures for running casing, 

cementing and T&A work, we are in the dark and nearing the end of logging operations.‖59 As set 

forth in detail in Chapter 4.5, the procedure changed repeatedly in the eight days between that 

email and the day of the blowout. It is not clear to the Chief Counsel‘s team why BP had not 

finalized and vetted the procedure much earlier in the process. The BP Macondo team instead 

waited until the last minute.60 

BP ultimately did not send out the final ―Ops Note‖ to the rig crew until the morning of April 20, 

meaning that once the well site leaders and rig crew did receive the temporary abandonment 

procedures, they had precious little time to digest and understand them (see Table 5.1 for 

breakdown of changes to temporary abandonment procedure).

61 BP could have at least 

ameliorated that problem by providing detailed guidance in the Ops Note to its well site leaders 

explaining how to, among other things, conduct the negative pressure test. 

Contrary to the apparent views of BP‘s shore-based team, negative pressure test procedures are 

not self-evident to rig personnel, particularly in a case like Macondo in which the crew would have 

to displace and monitor a variety of different types of fluids. Sprague testified that, in order to 

interpret a negative pressure test, a well site leader would need to know the following: the 

hydrostatic pressure of fluids in the drill pipe, choke, and kill lines; bottomhole pressure; volumes 

and densities of fluids in the well, drill pipe, choke, and kill lines; and wellbore and drill string 

geometry.62 Sprague acknowledged that ―If you have more time to write detailed procedures, 

there is a greater chance that the result...might be more successful.‖63
Chief Counsel’s Report — Chapter 5: Overarching Failures of Management | 233

Table 5.1. Timeline of changes to the temporary abandonment procedure.

Date Event 

April 12 

BP well site leader Murry Sepulvado emails BP drilling engineer Brian Morel (copying BP 

wells team leader John Guide) stating, “Brian we need procedures for running casing, 

cementing and T&A work, we are in the dark and nearing the end of logging operations.”64

April 12

Morel emails BP's subsea well engineers and asks for details on setting the lockdown 

sleeve: "I need a procedure this morning, do you have one available?"65 He also emails 

the subsea wells team leader separately and explores the possibility of not setting the 

lockdown sleeve at all during temporary abandonment.66

April 12

Morel sends Murry Sepulvado and BP well site leader Ronnie Sepulvado (copying Guide) a 

first draft of the well plan for the final casing string, cement job, and temporary 

abandonment procedure.67 The plan does not include a negative pressure test.68 It calls 

for setting the lockdown sleeve in mud before setting the surface cement plug and setting 

the surface cement plug at ~ 6,000 feet below sea level rather than the eventual 

8,367 feet. Morel says in his email, “This isn’t perfect yet, but I wanted to get everyone a 

copy so you can ensure all the equipment required for our upcoming operations is offshore 

in time. Please let me know if you have any questions or suggestions how to improve the 

procedure.”69

April 13 Ronnie Sepulvado emails Morel (copying Guide) saying “We need to do a negative test 

before displacing 14# mud to seawater.”70

April 13

Morel emails back Murry Sepulvado and Ronnie Sepulvado (copying Guide) saying, “I will 

add details to the program. Currently my thoughts are negative testing with base oil to 

the mud line, you both ok with that?” Murry Sepulvado replies, “Base oil sounds good to 

me.”71

April 14

Morel emails Ronnie Sepulvado and the rig clerk a different procedure.72 This procedure 

sets the cement plug before the lockdown sleeve and in mud instead of seawater. The 

cement plug is moved from ~ 6,000 feet to 8,367 feet below sea level. And Morel adds a 

negative pressure test.

April 15

Morel emails the onshore team from the rig, saying that “Recommendation out here is to 

displace to seawater at 8300' then set the cement plug. Does anyone have issues with 

this? If we do a negative test prior to this with base oil to the wellhead the shoe will see 

about 360 psi less after the hole is displaced. Thoughts?”73 Hafle later replies, “Seems ok 

to me. I really don’t think [MMS} will approve deep surface plug. We’ll see. Did permit 

look ok?”74 

April 15

Morel changes the temporary abandonment procedures in the well plan.75 It now calls for 

running a negative pressure test with base oil to the wellhead after the cement job, then 

running the drill pipe to 8,367 feet and displacing with seawater, then setting the cement 

plug, and then finally setting the lockdown sleeve.76 It contains a contingency, however, 

in case the MMS does not approve the deeper cement plug, calling for setting the 

lockdown sleeve first before setting the cement plug at 5,800 feet below sea level.77

April 16

Hafle emails the temporary abandonment procedure permit request to Heather Powell of 

regulatory affairs, asking her to submit it to the MMS. The submission includes BP’s 

request to set the surface cement plug 3,000 feet below the mudline, which is 2,000 feet 

lower than otherwise allowed by MMS regulations.78 At 10:54 a.m., Powell sends back the 

approved permit, meaning that MMS approved the request in less than 80 minutes.79

April 17 Morel emails the onshore Macondo team asking, “Anyone know if there are any 

requirements in the MMS regs for a negative test, can’t find any specifics?”80

April 20

Morel sends an email titled “Ops Note” to the well site leaders and onshore team. Unlike 

the earlier application submitted to MMS, the Ops Note calls for first running the drill pipe 

to 8,367 feet and displacing with seawater to above the blowout preventer (BOP) before 

running the negative pressure test “with seawater in the kill...[at] ~2350 psi 

differential.”81
234 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Planning problems extended beyond the temporary abandonment procedures. In April, Walz 

emailed Guide: ―I know the planning has been lagging behind the operations and I have to turn 

that around.‖82 Weeks earlier, on March 2, Cocales reassured a well site leader after the rig crew 

had problems interpreting procedures sent by Morel: ―We will work on getting you guys any 

changes in the future sooner so you will have time to review.‖83 And the difficulty appears to 

have extended beyond Macondo. In a meeting of the leadership team for drilling in the Gulf of 

Mexico, O‘Bryan worried that ―just in time delivery of well plans‖ had contributed to problems on 

other rigs.84 

As detailed in Chapter 4, the pace and number of last-minute changes at Macondo apparently 

prompted Guide to write the following email to Sims on the morning of April 17, just three days 

before the blowout: 

David, over the past four days there has been so many last minute changes to the 

operation that the WSL‘s have finally come to their wits end. The quote is ―flying by the 

seat of our pants.‖ Moreover, we have made a special boat or helicopter run every day. 

Everybody wants to do the right thing, but, this huge level of paranoia from engineering 

leadership is driving chaos. This operation is not Thunderhorse. Brian has called me 

numerous times to make sense of all the insanity. Last night‘s emergency evolved around 

30 bbls [barrels] of cement spacer behind the top plug and how it would affect any bond 

logging (I do not agree with putting the spacer above the plug to begin with). This 

morning Brian called me and asked my advice about exploring other opportunities both 

inside and outside of the company. 

What is my authority? With the separation of engineering and operations I do not know 

what I can and can‘t do. The operation is not going to succeed if we continue in 

this manner.85

Rather than react with alarm or stop work on the rig, Sims wrote back: 

John, I‘ve got to go to dance practice in a few minutes. Let‘s talk this afternoon.

For now, and until this well is over, we have to try to remain positive and remember what 

you said below – everybody wants to do the right thing. The WSLs will take their cue 

from you. If you tell them to hang in there and we appreciate them working through this 

with us (12 hours a day for 14 days) – they will. It should be obvious to all that we could 

not plan ahead for the well conditions we‘re seeing, so we have to accept some level of last 

minute changes.

We‘ve both [been] in Brian‘s position before. The same goes for him. We need to remind 

him that this is a great learning opportunity, it will be over soon, and that the same issues 

– or worse – exist anywhere else.

I don‘t think anything has changed with respect to engineering and operations. Mark and 

Brian write the program based on discussion/direction from you and our best 

engineering practices. If we had more time to plan this casing job, I think all this would 

have been worked out before it got to the rig. If you don‘t agree with something 

engineering related, and you and Gregg can‘t come to an agreement, Jon or me gets 

involved. If it‘s purely operational, it‘s your call.
Chief Counsel’s Report — Chapter 5: Overarching Failures of Management | 235

I‘ll be back soon and we can talk,

We‘re dancing to the Village People!

Sims has subsequently explained that he believed Guide was expressing temporary frustration 

and that he saw no cause for alarm. Emails from Guide later the same day support this view.86

But once the well site leaders reported that last-minute changes were causing chaos and confusion 

on the rig, there was simply no reason why BP could not have stopped operations temporarily in 

order to allow planning to catch up.

Employees

Drilling is as much about people as it is about hydrocarbons and equipment. About 30 people 

designed the Macondo well. Roughly 130 others worked on the drilling rig at any given time. 

Success in oil and gas exploration depends on effective management of employees, yet the Chief 

Counsel‘s team observed poor management of staffing and inadequate training at Macondo. 

People especially mattered at Macondo because BP, Transocean, and Halliburton placed heavy 

reliance on human judgment. For instance, during displacement of the riser with seawater, BP 

relied on the bottomhole cement as the only barrier in the wellbore. But awareness of whether 

that barrier was in place—because of the negative pressure test—depended on human judgment. 

Another barrier, the blowout preventer (BOP), also relied on human judgment because of the 

importance of kick detection and kick response. Yet, the companies failed to provide the rig crew 

and well site leaders exercising that judgment with adequate training, information, procedures, 

and support to do their jobs effectively. 

Staffing

BP did a poor job of managing staffing and work assignments at Macondo. BP provided little 

support to a junior drilling engineer charged with critical design decisions and did not effectively 

seek input from technical experts. BP also sent a well site leader from another rig out to the 

Deepwater Horizon without properly determining if he was capable of substituting for one of the 

rig‘s veterans. BP did not supervise and support its employees as necessary to ensure 

safe operations.

Oversight

There were significant gaps in supervision and oversight at Macondo. In some cases, a single 

person made critical decisions and performed critical activities without checks—either by 

supervisors or other companies. 

For example, BP relied very heavily on Morel to design not only the well itself, but also the cement 

program and temporary abandonment procedures at Macondo. Morel received his engineering 

degree in 2005, after which he started full time with BP. His first deepwater well was Mad Dog in 

2007. BP assigned him to the exploration group in 2008, where he helped to plan two wells 

before being transferred to Macondo to work alongside Hafle—a much more senior drilling 

engineer who had been working on deepwater drilling since 1993.87 The Chief Counsel‘s team 

found little evidence that Hafle closely reviewed Morel‘s work in the last few weeks before the 
236 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

blowout. Indeed, none of BP‘s shore-based engineers appear to have reviewed Morel‘s temporary 

abandonment procedures carefully.

While Morel appears to have been talented and capable, it is not apparent why the team would 

put so much on his plate without additional supervision and mentoring.

88

 

Temporary Substitutions

BP mishandled the substitution of Kaluza for regular well site leader Ronnie Sepulvado. 

Sepulvado needed a temporary replacement in order to attend well control training school 

onshore (per MMS regulations and BP policy). BP could have sought dispensation to allow 

Sepulvado to remain on the rig throughout the critical temporary abandonment phase but did 

not. BP instead substituted Kaluza, who was serving as well site leader on the Pride, a moored rig 

in BP‘s Thunder Horse field.89 

It does not appear that BP undertook any significant effort to assure that Kaluza was qualified for 

the tasks he would be overseeing at Macondo. Whenever there is transfer or loss of personnel 

with specific knowledge or experience from a project, BP‘s internal guidelines require 

management to submit the change through a management of change (MOC) process, which 

requires sign-offs from multiple managers.90 BP did not do so for Kaluza,91 even though he had 

not been a well site leader on the Deepwater Horizon previously, did not know the history of the 

Macondo well, and his relief (BP well site leader Don Vidrine) had himself only been on the 

Deepwater Horizon for a few months.92

Training 

BP and Transocean inadequately trained their personnel. BP did not train its well site leaders 

how to properly conduct and interpret a negative pressure test. Transocean did not adequately 

train its rig personnel regarding kick monitoring during end-of-well, nondrilling activities, such 

as temporary abandonment. It also did not adequately train its crews how to respond to 

emergency situations such as those that occurred on the night of April 20. Inadequate training 

set employees up for failure in the face of events outside their expertise and experience.

Nondrilling Situations

BP and Transocean failed to provide its personnel any formal training in how to perform or 

interpret a negative pressure test. This failure is symptomatic of a broader inattention to 

end-of-well, nondrilling activities generally. For instance, Transocean‘s Well Control Manual 

does not contain a section on monitoring or controlling the well during temporary 

abandonment procedures, focusing instead on drilling activities (and to a lesser extent, 

completion operations).93 

The phenomenon is not limited to Transocean or BP. Like Macondo, the Montara blowout off the 

northern coast of Australia occurred after the production casing cement job had been pumped.94 

The Montara blowout lasted 10 weeks beginning on August 21, 2009, and spewed between 400 

and 1,500 barrels per day of oil and gas into the Timor Sea.95

At least one independent expert has testified that in his experience it is not unusual for crew 

members to let down their guard or lose focus during end-of-well activities.96 BP subsea wells 

supervisor Ross Skidmore, who has more than 30 years‘ experience in the industry, admitted that 
Chief Counsel’s Report — Chapter 5: Overarching Failures of Management | 237

once the final cement job has been poured, there is a tendency to think ―everything is going to be 

okay‖ and to begin thinking about the next job.97 

Emergency Situations

As discussed in Chapter 4.9, Transocean did not adequately train its rig crew how to respond to 

emergency well control situations, such as a severe blowout. Transocean required regular well 

control drills, but none focused specifically on emergency situations—how to recognize an 

emergency and what steps to take immediately upon recognizing it.98 Transocean‘s Well Control 

Handbook provides little guidance on emergency situations, focusing instead on how to handle 

and circulate out more routine kicks. For instance, the handbook contains a section on 

―procedures for handling gas in the riser,‖ which provides for the possibility of diverting a severe 

influx of hydrocarbons overboard as the ninth step in a lengthy diagnostic process.99 

Transocean likewise did not adequately train or drill its dynamic positioning officers (DPOs) on 

how to respond to emergency situations. DPOs monitor a panel on the bridge that visually and 

audibly indicates whenever area-specific combustible gas, toxic gas, or fire alarms go off on the 

rig. The DPO acknowledges the alarms, contacts the affected area, and determines whether to 

initiate the general alarm to alert the entire rig (such as when more than one gas or fire alarm in 

contiguous areas goes off).100 

Andrea Fleytas was the Transocean DPO on duty in charge of the alarm panel at the time of the 

blowout. After feeling a first jolt and noticing multiple combustible gas alarms sounding 

throughout the rig, she did not immediately hit the general alarm.101 At the time, she received a 

call from the engine control room asking what was going on but did not instruct them to shut 

down the engines despite the multiple combustible gas alarms sounding throughout the rig.102 

Asked why she hesitated, Fleytas said, ―It was a lot to take in. There was a lot going on.‖103 

Fleytas said that Transocean provided no formal training or simulations on how to respond to 

combustible gas alarms.104 She testified further that Transocean had not trained her to instruct 

the engine room to shut off the engines when combustible gas alarms were sounding.105 

It is imperative that companies train and drill for emergency situations precisely because they 

occur so rarely.106 There is no on-the-job training, as with more common events. Transocean 

senior toolpusher Randy Ezell told the Chief Counsel‘s team that he has worked on 60 to 75 wells 

during his career and has never seen anyone close the blind shear rams or use the emergency 

disconnect system (EDS) for well control purposes. He only had to engage the EDS twice in nine 

years on the Deepwater Horizon, both times when the rig had drifted off-site. He has never 

witnessed anyone divert flow overboard. He only saw the diverter used twice in his nine years on 

the Deepwater Horizon—both times to send returning flow to the mud gas separator.107

Contractors

At one point in time, operators owned their own oil rigs and directly employed the people who 

worked on them. But economic pressure and the complexity of offshore technology have pushed 

the industry away from that system. Modern offshore oil drilling now involves a team effort 

between an ―operator‖ (which may have other oil company partners) and many specialized 

contractors and subcontractors. As Chapter 2 explains, Macondo involved just such a team effort. 

When the well blew out on April 20, only a handful of the 126 people on the rig worked for BP.108 
238 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

The rest worked for one of the dozens of contractors and subcontractors associated with 

the project. 

It is not necessarily problematic to use contractors to drill wells. Nor is it necessarily problematic 

to rely on specialized contractor expertise; drilling operations cannot be performed safely without 

their help, and Transocean and Halliburton are among the largest and best-regarded contractors 

in the oil and gas industry. But while the operator-contractor-subcontractor relationship can be 

beneficial in many ways, it also creates the potential for miscommunication and 

misunderstanding. 

BP and its various subcontractors appear to have lost sight of that danger, compartmentalizing 

information that would have been useful to other companies carrying out their respective tasks. 

The onus fell on BP to ensure that its contractors were providing all of relevant information to the 

respective decision makers. As the party responsible for designing the well and well plan, the 

operator is best positioned to understand the big picture and how decisions and issues regarding 

one aspect of the well might affect decisions and issues regarding another. 

BP’s Oversight of Contractors

BP, like most offshore operators, relied heavily on its contractors to advise its engineers 

regarding important decisions. But BP did not adequately supervise its Macondo contractors in 

several instances. 

The most egregious instances of inadequate supervision concern cementing. After the blowout, 

BP representatives and officials described Halliburton as ―one of the, if not the leading cementing 

contractor in the world‖109 and contended that it relied on Halliburton‘s expertise to highlight 

cementing concerns.110 But documents from before the incident show that BP‘s own employees 

were well aware that Halliburton‘s cementing services could be problematic. For instance, 

Chapter 4.4 discusses a 2007 auditing report prepared for BP, which concluded that Halliburton‘s 

―chemists and senior lab technicians do a very good job of testing cement slurries, but they do not 

have a lot of experience evaluating data or assisting the engineer on ways to improve the 

cementing program.‖111 One of BP‘s top cement experts also described ―the typical Halliburton 

profile‖ as ―operationally competent and just good enough technically to get by.‖112 

More importantly, BP engineers had specific concerns about Halliburton cementing engineer 

Jesse Gagliano, the Halliburton employee working on the Macondo well. Documents show that 

before the blowout, BP engineers thought Gagliano was not providing ―quality work‖113 and was 

not ―cutting it.‖114 They highlighted that Gagliano had a habit of waiting too long to conduct

crucial cement slurry tests. Three days before the blowout, Morel complained that he had ―asked 

for these lab tests to be completed multiple times early last week and Jesse still waited until the 

last minute as he has done throughout this well.‖

115

 Morel found ―no excuse‖ for the tardiness.116 

BP had known of problems with Gagliano for years117 and ―tried to work around‖ his 

shortcomings.118 By the time of the Macondo blowout, BP had even asked Halliburton to reassign 

Gagliano.119 Given this history, while waiting for his replacement, BP should have done more to 

supervise Gagliano‘s work, especially his work on the difficult production casing cement job at 

Macondo. At the very least, BP‘s management should have ensured that their own internal 

experts or senior Halliburton personnel double-checked Gagliano‘s cementing plan and foamed 

cement slurry design. Instead, BP‘s engineers admitted that they did not review his work ―line by 

line‖120 and never fully utilized their in-house cementing expertise. They did not insist that he 
Chief Counsel’s Report — Chapter 5: Overarching Failures of Management | 239

report the final April 18 lab results in a timely manner, let alone review those results before 

allowing Halliburton to pump the final Macondo job. 

BP did not even review the February 10 slurry test results that it did have. If BP had properly 

examined those results, it would have seen that the slurry had failed the foam stability test. The 

Macondo team had consulted BP cementing expert Erick Cunningham on other issues at 

Macondo. But it appears that nobody at BP ever showed him the foam stability slurry design or 

lab testing data. Instead, the Macondo engineering team focused exclusively on reducing ECD in 

order to mitigate the risk of lost returns without ever considering whether the slurry design was 

itself adequate to achieve zonal isolation. 

Contractors’ Deference to BP

If BP did not adequately review the work of some of its contractors, the converse problem was 

that many of BP‘s contractors were unduly deferential toward BP‘s design decisions. A 

Weatherford centralizer technician described the prevailing view as ―Third party, we do what the 

company man requests.‖121 In several instances, BP‘s contractors expressed private reservations 

about the plans and procedures at Macondo but did not more forcefully communicate to BP that 

there were better ways to do things. 

Again, the failures of communication surrounding the cement job are a good case study. As selfdescribed cementing experts, Halliburton had primary responsibility for designing and pumping 

the bottomhole cement. It should have alerted BP to any potential problems with that job. Yet, 

Halliburton often buried its analyses in highly technical reports (including laboratory tests and 

computer modeling) and never drew BP‘s attention to the importance of certain data. 

Despite touting its cementing expertise in promotional materials, Halliburton adopted a posture 

of extreme deference throughout the Macondo project. Prior to the incident, Halliburton 

mentioned two concerns to BP. First, Gagliano mentioned that using a small number of 

centralizers could lead to cement channeling while admitting that he ―did not think there would 

be a well control issue.‖122 Second, a Halliburton cementing technician on the rig briefly 

suggested that a full bottoms up would be advisable.123 But Halliburton never raised a host of 

other concerns to BP. It never pointed out that BP‘s plan called for a low total cement volume, 

noted that BP was using a relatively low flow rate, or argued that BP should perform a cement 

bond log. When asked why, Gagliano explained that this was not Halliburton‘s role. He said ―we 

do not recommend running a [cement] bond log‖124 and, anyway, he ―was never asked.‖125 With 

full knowledge of all of these problems, Halliburton instead pumped the cement job and reported 

that the job had been ―pumped as planned.‖126 

Halliburton failed to highlight the importance of foam stability testing to the Macondo team and 

to communicate test data. In other contexts, Halliburton has argued that its job is merely to do 

what the operator says and pump the job as directed. But that posture is inconsistent with 

Halliburton‘s decision to selectively report stability testing data to BP, as discussed in Chapter 

4.4. It is also inconsistent with Halliburton‘s failure to provide any April foam stability testing 

information to BP before pumping the job. If Halliburton‘s position is that the operator directs all 

aspects of the job, then Halliburton should provide the operator with all of the information 

needed to exercise that authority responsibly. 

Chapter 4.4 also discusses the numerous concerns with Halliburton‘s internal management of its 

slurry design process. Halliburton does not appear to have: (1) ensured that internal experts 
240 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

reviewed the Macondo slurry design; (2) ensured that Gagliano conducted timely lab tests; or 

(3) ensured that it otherwise adequately addressed BP‘s concerns about Gagliano‘s performance. 

Halliburton‘s refusal to provide documents that illuminate its internal policies and procedures 

cannot conceal these defects.

Lack of Clarity About Contractor Expertise and Responsibility

BP and Transocean have sparred since the blowout regarding the relative competence of 

Transocean rig workers to interpret negative pressure test data. But whatever the formal 

allocation of responsibility was or should have been, BP personnel certainly believed that 

Transocean personnel were not only competent to interpret those test results, but experienced 

and worthy of consultation. Based on the accounts of BP‘s well site leaders, the Transocean rig 

crew that participated in the test also believed they were competent to interpret it.

Chapter 4.6 explains that BP‘s well site leaders appear to have accepted a facially implausible 

explanation of the negative pressure test results from Transocean personnel. This was due in part 

to BP‘s inadequate well site leader training. But it was also due to the fact that Transocean 

personnel were experienced and the BP well site leaders thus believed they could rely on 

Transocean personnel. Kaluza and Vidrine both appear to have deferred to Transocean 

toolpusher Jason Anderson‘s experience. And Guide told the Chief Counsel‘s team emphatically 

that the Transocean personnel were in fact capable and competent to recognize the problems with 

the well during the negative pressure test.

127

 Again, even if BP‘s expectations were justifiable, 

they were mistaken.

Transocean has argued after the fact to the Chief Counsel‘s team that its driller and toolpusher 

were merely ―tradesmen‖ and not competent to interpret a negative pressure test. If that is the 

case, it is unclear why they would have advocated the ―bladder effect‖ explanation. The Chief 

Counsel‘s team also finds it difficult to believe that the driller and toolpusher would be any less 

competent than the well site leaders to interpret a negative pressure test. During a negative 

pressure test, the crew underbalances the well to see if it leaks—in other words, whether the well 

kicks. Transocean agrees that its crew is expert in monitoring for and identifying kicks, even in 

underbalanced situations. Hence the rig crew did not call the BP well site leaders for advice when 

they noticed anomalous pressure readings during the displacement of the riser but instead relied 

on their own expertise to determine whether there was a kick. 

Regardless of whether Transocean personnel were competent to interpret the negative pressure 

test, BP failed to adequately ensure that its well site leaders exercised independent judgment 

regarding the test results, or to resolve uncertainties before proceeding. In the absence of a 

clearly defined decision process and success criteria, BP‘s well site leaders appear to have tried to 

create consensus by accepting the explanation of the rig crew rather than independently verifying 

the explanation the rig crew had provided. 

Technology

Deepwater operators employ exceedingly sophisticated technology to drill wells. But BP and its 

contractors had neither developed nor installed similarly sophisticated technology to guard 

against a blowout. 
Chief Counsel’s Report — Chapter 5: Overarching Failures of Management | 241

Displays, Sensors, and Instrumentation

The well monitoring equipment on the Deepwater Horizon was inadequate. For example, the 

data displays depended not only on the right person looking at the right data at the right time, but 

also that the person understood and interpreted the data correctly.128 During the displacement, 

many signs of the kick could have been missed if monitoring personnel were distracted or not 

paying full attention. 

As discussed in Chapter 4.7, the Chief Counsel‘s team believes that rig workers could benefit from 

systems that employ automated alarms, similar to those in airline cockpits, to call attention to 

potential kick indicators.129 Such systems should also inform mudloggers of crucial events—such 

as a change to the active pit system or a change in fluid routing. On the Deepwater Horizon, the 

mud logger depended on direct communication or guesswork to learn what was happening 

elsewhere on the rig.130

As further discussed in Chapter 4.7, the Chief Counsel‘s team was surprised to find that rig 

personnel had to perform basic well monitoring calculations by hand, instead of having 

automated systems to help monitor, for instance, net flow from the well.131 The Chief Counsel‘s 

team was also surprised by inadequacies in the sensors and instrumentation for detecting kicks 

on the Deepwater Horizon.

132

 For instance, there was no camera installed on the rig to monitor 

flow on the overboard line—a person had to look behind the gumbo box to perform a visual 

confirmation of flow.133 Flow sensors could be thrown off by listing seas, crane movement or 

other activity on the rig.134 Where data are unreliable, the crew is more likely to discount 

kick indicators. 

Finally, there was no equipment dedicated to identifying the presence of hydrocarbons in the 

wellbore during nondrilling activities. The oil and gas industry has developed sophisticated 

sensors that can be installed in drilling tools to detect kicks while actively drilling. But the Chief 

Counsel‘s team found no evidence that BP or anyone else in the industry has tried to adapt such 

sensors for routine well monitoring purposes. For instance, such sensors could be developed, 

and installed in the BOP or the wellhead to detect gas and other hydrocarbons before they enter 

the riser. 

Utilizing Data and Equipment

BP and the other companies did not adequately use the data displays and monitoring equipment 

they did have. For instance, BP paid Sperry Drilling to gather and send real-time drilling and 

other data from the rig back to shore. Prior to the blowout, BP maintained large conference 

rooms in its Houston headquarters dedicated to each of its Gulf of Mexico wells. The room for the 

Macondo well had numerous monitors displaying the Sperry-Sun real-time data. The onshore 

team also could access the data remotely over the internet. But BP had no policy requiring 

full-time, or even part-time, monitoring from shore.135 

As discussed in more detail in Chapter 4.7, BP itself apparently recognized the value of having 

engineers monitor data from onshore. As of the time of the blowout, BP had planned over the 

next four years to implement the Efficient Reservoir Access (ERA) advisory system.136 The goal 

was to create a system that integrated real time drilling and mud logging data, displayed it to the 

driller in a more user-friendly and useful manner and simultaneously sent it to a drilling engineer 

or specialist on shore who could provide real time support.137 ―The primary objective of the ERA 
242 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Advisor‖ was ―to facilitate the management of real time drilling data and its integration with 

drilling recommended practices and expertise to ensure the right information is in the right place 

at the right time.‖138 Among the goals of the program were ―[t]o maximize the use of available 

real time data and expertise to inform while-drilling decisions‖ and ―[t]o minimize flying blind by 

improving the quality of real time data....‖139 Among other things, the system would 

―integrat[e]...expertise across multiple sites and multiple disciplines.‖140

While BP did not plan to have the system up and running until November 2013,141 it clearly 

recognized the value of having a second set of eyes onshore—with engineering skills—monitoring 

well data and supporting rig personnel. Yet, the Macondo team did not use the real-time 

monitoring equipment it already had in place, relying instead on its well site leaders to alert 

onshore team members when and if there were issues.142

BP explained the disconnect by noting that it is difficult for onshore monitoring personnel to 

understand the significance of data without knowing what is happening on the rig. But these 

challenges can be overcome. Redundant shoreside monitoring would clearly have helped in 

several instances at Macondo—for instance, during the negative pressure test.143 BP‘s explanation 

is also inconsistent with the entire premise for developing and deploying the ERA advisory 

system.

Risk

Deepwater drilling is a challenging and risky endeavor. It is also a competitive and potentially 

lucrative business that demands constant attention to economic considerations. Balancing the 

need to address risk with the need to manage costs is a constant struggle for operators.

The Chief Counsel‘s team finds that BP and Transocean did not have adequate procedures in 

place to properly account for risk or to assess the overall impact of decisions that appeared to 

relate only to one part of the well project. As a result, understandable cost pressures drove 

decision making and allowed some operational redundancies to be purged as inefficiencies. 

(Again, Halliburton declined to provide documents that would have allowed further insight into 

its operations at Macondo.) 

Risk Assessment

The companies involved at Macondo failed to rigorously analyze the risks created by key decisions 

or to develop plans for mitigating those risks. This appears to have biased decisions in the last 

month at Macondo in favor of cost and time savings while increasing the risk of a blowout.

BP

Despite making multiple changes over the last nine days before the blowout, the Macondo team 

did not formally analyze the risks that its temporary abandonment procedures created. The 

Macondo team never asked BP experts such as subsea wells team leader Merrick Kelley about the 

wisdom of setting a surface cement plug 3,000 feet below the mudline to accommodate setting 

the lockdown sleeve or displacing 8,300 feet of mud with seawater without first installing 

additional physical barriers. It never provided rig personnel a list of potential risks associated 

with the plan or instructions for mitigating those risks. 
Chief Counsel’s Report — Chapter 5: Overarching Failures of Management | 243

BP‘s management system did not prevent such ad hoc decision making. It required relatively 

robust risk analysis and mitigation during the planning phase of the well but not during the 

execution phase. 

Almost every decision the Chief Counsel’s team identified as having potentially contributed to 

the blowout occurred during the execution phase.

144

 

BP‘s Beyond the Best Common Process sets forth BP‘s procedures for selecting, designing, and 

drilling wells in the Gulf of Mexico.145 It lays out a five-stage process: (1) Appraise, (2) Select, (3) 

Define, (4) Execute, and (5) Review. The first two stages consist of identifying and selecting a well 

site. BP plans and permits the well during the Define stage. During the Execute stage, BP and its 

contractors actually drill and complete the well. Finally, once drilling and completion is done, 

there is a Review stage to evaluate the project and to identify areas for improvement.146 The 

engineering team is primarily accountable during the Define stage, although the wells operation 

team is involved. The wells operation team takes over primary accountability during the Execute 

stage, with engineering continuing to support planning and design decisions.

Before proceeding from one stage to the next, a well must satisfy certain ―gate‖ requirements. For 

instance, before moving from the Select to Define and from the Define to Execute stages, the well 

concept, design, and plan must undergo a rigorous peer review process, which consists of ―a 

multi-discipline assessment by an external team of how the balance between risk and value is 

being managed‖ and is led by a member of the functional drilling and completion 

excellence team.147 

There is not, however, any such peer review process during the Execute stage.148 The decision 

whether and to what extent to perform any formal risk analysis is left largely up to the team‘s 

discretion, in particular the wells team leader.149 For instance, BP‘s MOC process—which imposes 

risk analysis, mitigation plan and approval requirements—continues to govern decision making 

during the Execute stage.150 But the MOC process only applies to decisions to deviate from the 

well plan approved during the Define stage, not to drilling procedures (such as temporary 

abandonment procedures).151 

As a result, after spudding the Macondo well, BP invoked the MOC process only a handful of 

times. It invoked the process for only three decisions after the Deepwater Horizon took over 

drilling in February.152 Those three decisions were: (1) the change from a 16-inch to 135⁄8-inch 

casing string; (2) the early total depth decision; and (3) the decision to employ the long string 

instead of a liner.153 And some members of the team thought an MOC was unnecessary 

for the long string decision because the original approved well plan had a long string 

production casing.154 

After the blowout, Walz observed that the MOC process was ―not in place‖ and ―not clear‖ for the 

Macondo team.155 BP investigators summarized Walz‘s view of the team‘s culture as follows: 

―Performance – not require[d] procedures – do what we have been doing.‖156 None of the other 

key decisions identified in this Report, such as those regarding centralizers, cement slurry design, 

temporary abandonment procedures, or simultaneous operations went through the MOC process.

BP was aware that its risk assessment process had flaws, but it acted too late to remedy the gap. 

In 2008, BP‘s own internal review found that risk assessment required improvement in the Gulf 

of Mexico. The review noted the ―need for stronger major hazard awareness‖ and stated that 

―[r]isk assessment processes/results are not integrated.‖157 The review went on to state: ―As we 
244 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

have started to more deeply investigate process safety incidents, it‘s become apparent that process 

safety major hazards and risks are not fully understood by engineering or line operating 

personnel. Insufficient awareness is leading to missed signals that precede incidents and 

response after incidents; both of which increases the potential for, and severity of, process safety 

related incidents.‖158 Though BP later rolled out more robust risk assessment procedures in 

2010,159 the procedures were not in place for Macondo. In an interview after the incident, 

Sprague discussed a new requirement to evaluate the effectiveness of each barrier in a well but 

noted that it was ready only by the time of the incident.160

Problems with risk assessment practices appear to have affected decision making at Macondo in a 

number of ways. First, they allowed decision makers to avoid systematically identifying the risks 

their procedures created and the steps necessary to mitigate those risks. Second, the absence of 

formal risk assessment enabled late and rushed decision making. Third, the lack of rigorous risk 

assessments led decision makers to solve problems in isolation instead of considering the 

cumulative impact their solutions might have on the rest of the project. As discussed above, 

following the lost circulation event at the pay zone, BP‘s shoreside Macondo team focused almost 

exclusively on avoiding further lost returns and no longer considered the more general goal: 

effective zonal isolation. The team designed a cement job that decreased the risk of lost returns 

but increased the risk of cementing failure. The primary criterion the team used to determine the 

success of the cement job was whether there had been lost returns. Seeing none, they sent the 

Schlumberger crew home. With one problem solved, they moved to the next.

Transocean

Transocean‘s crew appears never to have undertaken any risk analysis nor to have established 

mitigation plans regarding their performance of simultaneous operations during displacement 

after the negative pressure test.161 It is not clear what, if any, steps the crew took to ensure that 

they could continuously and reliably monitor return volumes during the displacement prior to 

sending the spacer overboard, or flow-out after they began sending the spacer overboard. There 

is no indication the crew calculated expected pressures during the displacement.162 Internal 

Transocean reviews show that it did not believe that the rig crews could identify and mitigate all 

risks on their own. A Lloyd‘s Register audit of Transocean in 2010 found: ―[Rig crews] don‘t 

always know what they don‘t know. Front line crews are potentially working with a mindset that 

they believe they are fully aware of all the hazards when it is highly likely that they are not.‖163 

Transocean‘s crew seems to have concluded prematurely that risks had receded after the negative 

pressure test. Once the test had been declared a success, the driller and toolpusher appear to 

have put any concerns about the test behind them rather than increasing their vigilance. They did 

not immediately shut in the well upon observing unexpected pressure readings; they did not keep 

the mudlogger apprised of all pit changes and fluid movements and do not appear to have 

monitored data more closely in his absence. 

After the March 8 kick on the Deepwater Horizon, Guide asked Transocean rig manager Paul 

Johnson to consider how to improve the rig crew‘s hazard awareness. Johnson wrote back: ―I 

thought about this a lot yesterday and asked for input from the rig and none of us could come up 

with anything we are not already doing.... You can tell them what the hazards are, but until they 

get used to identifying them their selves, they are only following your lead.... Maybe what we 

need is a new perspective on Hazard recognition from someone outside the industry.‖164
Chief Counsel’s Report — Chapter 5: Overarching Failures of Management | 245

Bias in Favor of Time and Cost Savings

On any drilling rig—no matter who is the operator—―time is money.‖

165

 BP leased the Deepwater 

Horizon at a rate of about $533,000 per day.166 The high daily cost made the rig the single 

greatest expense for drilling the Macondo well.167 It also gave BP a strong incentive to improve 

drilling efficiency. 

The Chief Counsel‘s team observed that the Macondo team understandably made individual 

decisions consistent with an orientation toward efficiency but did not step back to consider what 

the safety implications of those decisions were when taken together. In the absence of a stronger 

emphasis on risk assessment and process safety during the Execute stage, engineering and 

operations decisions tilted toward cost and time savings. The risk register for the Macondo well 

exemplifies the problem. Though the register was intended to help the team identify potential 

problems with the well and the consequences of those hazards, it did not include safety as an 

element.168 The risk register focused exclusively on the impact risks might have on time and 

cost. (And there is no indication the Macondo team even used it once the well entered the 

Execute stage.)169

Examples of Decisions That Increased Risk and Saved Time

BP‘s employees made a number of important decisions that increased risk at Macondo. BP did 

not run a cement evaluation log, nor did it perform further well integrity tests after the 

unexpected results of the negative pressure test. BP did not install additional barriers during 

temporary abandonment, nor did it elect to install the surface cement plug closer to the 

wellhead. The list goes on. Chapter 4 of the Chief Counsel‘s Report provides background and 

detail on these decisions.

Many of the decisions that increased risk also saved time. Take BP‘s decision-making process 

about how many centralizers to use. When Gagliano recommended obtaining additional 

centralizers, Morel responded that it was ―too late‖ to get more centralizers to the rig.170 It is 

never ―too late‖ if one is willing to stop operations and wait for the right equipment. Guide 

informed the Chief Counsel‘s team that he himself had suggested waiting at one point, but in 

emails before the incident he argued against using additional centralizers not only because they 

might hang up, but ―also it will take ten hrs to install them.‖171 (Guide explained to the Chief 

Counsel‘s team that further delaying casing installation would have raised risks of its own. The 

Chief Counsel‘s team notes that BP had left the wellbore open for several days at this point in 

order to log the wellbore, and while that entails some risk, there was no systematic discussion of 

this risk, or the pros and cons of waiting for additional centralizers.) 
246 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

As shown in Table 5.2, the decision about centralizers is not an isolated example of time pressure 

apparently influencing well design or operations at Macondo.

Table 5.2. Examples of decisions that increased risk at Macondo while potentially 

saving time.

Decision

Was There a Less 

Risky Alternative 

Available?

Less Time Than 

Alternative? Decision Maker

Not Waiting for More Centralizers of 

Preferred Design Yes Saved time BP onshore

Not Waiting for Foam Stability Test Results 

and/or Redesigning Slurry Yes Saved time

Halliburton

(and perhaps BP)

onshore

Not Running Cement Evaluation Log Yes Saved time BP onshore

Using Spacer Made From Combined Lost 

Circulation Materials to Avoid Disposal 

Issues

Yes Saved time BP onshore

Displacing Mud From Riser Before Setting 

Surface Cement Plug Yes Unclear BP onshore

Setting Surface Cement Plug 3,000 Feet 

Below Mudline in Seawater Yes Unclear BP onshore(approved by MMS)

Not Installing Additional Physical Barriers 

During Temporary Abandonment Procedure Yes Saved time BP onshore

Not Performing Further Well Integrity 

Diagnostics in Light of Troubling and 

Unexplained Negative Pressure Test Results

Yes Saved time

BP 

(and perhaps

Transocean) 

on rig

Bypassing Pits and Conducting Other 

Simultaneous Operations During 

Displacement

Yes Saved time

Transocean 

(and perhaps BP) 

on rig

Meticulous Tracking of Time and Cost

Each day of drilling counted to BP, and BP counted the cost of each day. BP‘s common process 

for well design and operations required engineers to set out ―detailed time and cost estimates‖ for 

―the operational procedures for drilling‖ the well.172 The estimates were based on prior drilling 

performance on other wells.173 During drilling, BP had its team share with the rig crew every day

how long each task should take.

174

 The actual time to complete a task would then be recorded and 

performance shared with the rig crew.175 
Chief Counsel’s Report — Chapter 5: Overarching Failures of Management | 247

The Deepwater Horizon followed this process meticulously.

176

 The rig had a database of the 

―fastest times‖ to complete ―each task the rig carries out.‖177 The engineers used the database to 

―construct a time estimate for the well being planned.‖178 Every day, ―the actual times for each 

operational task‖ were ―checked against the Best of the Best data.‖179 A spreadsheet accounted for 

all of the rig‘s time, from servicing the rig to running the drill pipe.180 If an activity was ―non 

productive time,‖ then it was marked as such with a brief description of the cause.181 BP may have 

linked this information into a worldwide database.182

BP tracked not only the time to complete each task, but also the cost of every item to drill the 

Macondo well.183 The list runs from $15 for one cargo box to $533,000 for one day of the rig‘s 

time.184 About 10,000 items were accounted for, tallied, and listed by day.185 Daily costs varied 

from over $4 million on March 17, 2010, to as low as $6,300 during the planning of the well 

in 2009.186 

By the time of the blowout, the Macondo well had taken longer to drill and cost much more than 

BP had anticipated. BP had spent more than $142 million on the well.187 The original plans for 

Macondo set out a price tag for the well of $96 million.188 Because the well kept going over 

budget, BP had to return to its partners three times to authorize supplemental expenditures.189 

The final authorization anticipated that the well would cost as much as $58 million more than 

planned.190 The Macondo well had also fallen at least 38 days behind schedule.191

Comparable wells had taken less time and had cost considerably less to drill. Sims testified that 

days per 10,000 feet (a common industry metric) was the most important metric for drilling 

performance.192 Hafle estimated that the well had taken about 70 days for each 10,000 feet 

drilled.193 That performance put Macondo in the bottom 10% of wells drilled (more than 10 days 

per 10,000 feet slower than the threshold for that category).

194

 The well‘s total cost also placed it 

in the bottom 10% of comparable wells.195 So did the amount of what BP classified as 

―non-productive time.‖196 (Nonproductive time is another common industry metric). 

It is unclear as to the full extent to which these cost and time overruns impacted personnel and 

decisions onshore or on the rig. One well site leader remarked that the cost of the Macondo well 

was a concern and that he was aware the rig was running behind.197 However, he and others have 

almost uniformly stated that cost and time pressure was not an issue and that they did not feel 

more pressure to hurry to get things done than would otherwise be the case.198 

Cost accounting is a necessary and reasonable part of running a business. Nonetheless, given the 

many decisions that increased risk but saved time and money, it is a reasonable inference that 

cost and time overruns had an effect, conscious or unconscious, on decision making.

Well Design and Operations Guidance

At the Commission‘s November hearing, Steve Lewis testified: ―[T]he pressure to make progress 

is actually inherent in the business. And it takes a stated, conscious management presence to 

counter that...drillers drill against each other. We want to be the fastest, best driller there is.‖199 

Like many other operators, BP‘s guidance on well design and operations placed a premium on 

drilling quickly. The Beyond the Best Common Process200 emphasized the achievement of the 

―technical limit‖ for drilling a well.201 The term technical limit means ―what drilling times might 

be possible if everything works perfectly.‖202 Achievement of the technical limit depends on the 

elimination of ―non productive time‖ and ―invisible lost time.‖203 Though BP did not expect its 
248 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

engineers to achieve the ―technical limit‖ (at least not yet),204 they were told that the company‘s 

aspiration was to achieve the ―Technical Limit as quickly as possible.‖205 BP asked its engineers to 

accomplish times faster than what had been done before—―the  ̳best of the best.‘‖206 

For well design, the emphasis on drilling performance and technical limit meant that BP 

engineers were expected to carefully account for how long it would take to drill each well. 

Engineers were asked to consider, ―Could the well be constructed more efficiently?‖207 That 

question appears to have been important to the team that designed the Macondo well. 

In an interview with the Chief Counsel’s team, Sims shared that he was always thinking about 

how to drill wells faster.208 He replied ―yeah, that‘s safe to say‖ when asked whether Morel, the 

engineer who designed the temporary abandonment procedures at Macondo, was ―always 

thinking about cost and efficiency.‖209 Guide‘s supervisor flagged in his 2009 mid-year 

evaluation: ―John needs to...take safety performance to the same level as drilling 

performance.‖210

BP‘s focus on driving down the time to drill wells could result in a tendency to treat redundancies 

as inefficiencies. Tasks that took additional time would have counted against the rig‘s time and 

cost performance.211 In the absence of sufficient checks and balances, adding cost that did not 

immediately appear necessary to the safety of the well might not be judged fairly. A cement 

evaluation log may have been perceived as unnecessary when a negative pressure test was 

planned not long after. A mechanical plug or additional cement plug may have seemed 

inefficient when there was cement already at the bottom of the well. The problem is exacerbated 

for very low-frequency events, which might allow poor decisions to go unnoticed for many years

where a particular type of failure (especially one that requires multiple things to go wrong) 

happens only rarely.

Personnel Evaluations and Incentives 

BP provided incentives to its drilling personnel. For more senior personnel, the annual bonuses 

exceeded $100,000 on top of salaries over $200,000.212 BP based the annual bonuses and 

promotions in part on performance evaluations. 

The performance evaluations for the Macondo team emphasized, among other things, drilling 

performance. The Gulf of Mexico‘s metrics for drilling targeted days per 10,000 feet drilled and 

performance against AFE as priorities.213 The AFE is the Approval for Expenditure, a metric for

how much BP planned to spend on a well. Early in 2010, Sims listed delivering the wells ―at or 

below‖ the targeted times as the ―#1‖ priority for him and for Guide in the coming year.214 

O‘Bryan also had drilling efficiency in his performance contract for 2010.215 

The BP team that drilled Macondo had a history of focusing on cost and performance in their 

performance evaluations. Guide‘s list of key indicators for 2008 specified ―performance,‖ 

measured by days per 10,000 feet of drilling.216 After that, Guide had ―All Well Objectives 

delivered at a cost less than AFE.‖217 Guide highlighted that ―[o]perational performance has been 

top quartile,‖ meaning that the rigs had outperformed most other BP rigs in how long it took to 

drill a well,218 and observed that one well ―set numerous industry and B[P] drilling records and 

finished 32day‘s / 10K.‖219 In 2009, Guide‘s supervisor noted that Guide had ―championed the 

every dollar counts culture.‖

220

 ―Every dollar counts‖ became a priority at BP during diminished 

demand for oil in 2008.221 Guide noted in his self-evaluation that ―[d]aily operational decisions 

now include the cost component.‖222 
Chief Counsel’s Report — Chapter 5: Overarching Failures of Management | 249

Sims provided the same level of detail for drilling performance. In 2007, he noted in his interim 

review that ―we have done a good job of delivering fully evaluated wells under time and cost 

targets.‖223 In 2008, Sims observed that the ―Kodiak well finished under AFE cost and with top 

quartile performance.‖224 He also highlighted that the ―Freedom well finished the original scope 

under AFE time and budget.225 In 2009, Sims highlighted when the time to complete a well was 

―top quartile‖ and when wells finished ―under AFE.‖226 

Importantly, BP‘s performance evaluations and internal standards also emphasized the 

importance of safety. BP‘s code of conduct provided: ―BP is committed to providing a safe place 

of work for everyone—that includes stopping work if we ever have concerns about HSSE [health, 

safety, security, and the environment]. BP will not tolerate retaliation against anyone who in 

good faith stops work for HSSE issues—it‘s better to be safe than sorry.‖227 BP also had in place 

―Golden Rules of Safety.‖228 The Golden Rules emphasized that ―Safety is a legitimate personal 

expectation and a constant individual responsibility.‖229 

Though safety was important at Macondo, BP‘s approach was strongest with respect to easily 

measured personal safety metrics, such as injuries, rather than process safety risks of lowfrequency, high-consequence events such as a blowout. BP put safety first on individual 

employees‘ performance evaluation forms,230 but the metrics for safety encompassed only a subset 

of the risks of drilling. Guide‘s evaluation in 2009, for example, put safety at the top of the list of 

key performance indicators, measured by recordable injuries.231 The well site leaders had similar 

standards, which emphasized recordable injuries and safety meetings.232

It is not apparent whether and to what extent BP has or assesses safety metrics regarding drilling 

procedure or well design. BP expected full compliance with its mandatory engineering policies.233 

But BP lacked a systematic way to assess whether engineers complied with those policies, 

especially after the peer review process was complete and the well entered the Execute stage.234 

BP did not track how employee decisions impacted process safety or risk.

It is perhaps not surprising that BP‘s performance evaluations relied on easy-to-track metrics 

such as injuries and safety meetings to account for an employee‘s commitment to safety. It would 

be difficult after the fact to analyze whether an employee‘s decisions actually increased the risk 

profile of a project unnecessarily. That is all the more reason why it was critically important for 

BP to have in place at all stages of the well a formal risk assessment system for evaluating drilling 

decisions that could increase the overall risk profile of the project. 

Closing

As this review of management practices at Macondo demonstrates, the blowout occurred in large 

part because the companies diffused knowledge, responsibility for, and ownership of safety 

among themselves and among groups of people. The people onshore and on the rig had a false 

sense of security. They did not recognize the need for individual leadership in addressing the 

multiple anomalies and uncertainties that they observed. Instead, they relied on many 

ambiguous ―dotted line‖ relationships within and between the companies and personnel involved. 

To prevent an incident at Macondo from ever happening again, it will not be enough merely to 

add regulatory personnel. Just putting more inspectors on the Deepwater Horizon would not 

have prevented this blowout.
250 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Nor will it be enough to issue new prescriptive regulations or write more voluminous safety 

manuals. Adding a new ―don‘t do this either‖ rule after every accident ensures staying behind 

the curve.

What the men and women who worked on Macondo lacked—and what every drilling operation 

requires—was a culture of leadership responsibility. In hostile offshore environments, individuals 

must take personal ownership of safety issues with a single-minded determination to ask 

questions and pursue advice until they are certain they get it right.
Chief Counsel’s Report — Regulatory Observations | 251

OSC

Full report available at www.oilspillcommission.gov.

Figure 6.1. Chapter 3 of the Commission’s full report.

Chapter 6|Regulatory Observations

he Commission‘s full report examines in depth the history and current 

status of Minerals Management Service (MMS) regulatory programs, 

and makes specific recommendations for regulatory reform.* In 

Chapter 3 of that report (displayed in Figure 6.1), the Commission 

finds that:

 MMS had a built-in financial incentive to promote offshore drilling that was in tension 

with its mandate to ensure safe drilling and 

environmental protection;

 revenue increases dependent on deepwater drilling 

came with increased safety and environmental risks, 

but those risks were not matched by greater, more 

sophisticated regulatory oversight;

 MMS was unable to maintain up-to-date technical 

drilling-safety requirements to keep up with 

industry‘s rapidly evolving deepwater technology. As 

drilling technology evolved, many aspects of drilling 

lacked corresponding safety regulations; and

 at the time of the blowout, MMS systematically 

lacked the resources, technical training, or experience 

in petroleum engineering that is critical to ensuring 

that offshore drilling is being conducted in a safe and 

responsible manner.

This portion of the Chief Counsel‘s Report is more modest. It focuses solely on the role that 

MMS regulations in force at the time of the blowout played in guiding design and process 

decisions at Macondo. 

MMS Background

MMS, now the Bureau of Ocean Energy Management, Regulation, and Enforcement, employs 

approximately 600 individuals to run operations in the Gulf of Mexico region.1 About one-fifth of 

that staff is distributed among five district operations offices. Each district office has a small

 

*

The Minerals Management Service (MMS) was renamed the Bureau of Ocean Energy Management, 

Regulation, and Enforcement (BOEMRE) on June 18, 2010. For ease of reference, this Report uses the 

former name, MMS.

T
252 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

TrialGraphix

The New Orleans District office supervised drilling in the region of the Gulf of Mexico that contained the 

Macondo well.

Figure 6.2. BOEMRE organizational chart for the Gulf of Mexico region in July 2010.

cadre of engineers, including drilling engineers. Drilling engineers review drilling permit 

applications. 

The MMS office that supervised drilling in Mississippi Canyon Block 252 was the New Orleans 

District office. The New Orleans District office (in the bottom row of Figure 6.2) reviewed 25% to 

30% of all permits submitted for the Gulf of Mexico.2 The office had one designated drilling 

engineer for the review of permits. That individual thus reviewed several hundred permits each 

year3and approved BP‘s initial application for permit to drill (APD) a well at Macondo, as well as 

subsequent applications modifying that permit. 
Chief Counsel’s Report — Regulatory Observations | 253

APD and APM. An operator’s first submission to the MMS for permission to begin drilling is an 

application for permit to drill, or APD. Subsequent changes to the initial permit are 

requested through an application for permit to modify, or APM.

MMS regulations are located in title 30 of the Code of Federal Regulations, parts 201 to 299. The 

regulations governing review and approval of drilling operations are primarily located in 

part 250. 

MMS Regulations Did Not Address Many Key 

Risk Factors for the Blowout

MMS regulations in force at the time of the Macondo blowout did not address many of the key 

issues that the Chief Counsel‘s team identified as risk factors for the blowout. 

Deepwater Drilling Conditions

At the time of the blowout, most MMS prescriptive and performance-based regulations applied 

uniformly to all offshore wells regardless of their depth. The regulations did not impose 

additional or different performance requirements for deepwater wells. Indeed, MMS personnel 

stated that it had become routine for them to grant certain specific exemptions from regulatory 

requirements, mostly related to blowout preventer (BOP) testing, in order to accommodate the 

needs of deepwater operations.4

While MMS regulators routinely reviewed an operator‘s predictions about shallow drilling 

hazards, they did not review an operator‘s predictions of drilling conditions in deeper areas.5 For 

instance, while MMS regulations required operators to submit predicted pore pressure and 

fracture gradient charts along with well permit applications,6 MMS personnel did not review the 

data in those charts, let alone verify, for example, whether the predictions aligned with offset data 

from other wells in the area. MMS personnel were not aware of any instances in which the agency 

had rejected a permit application because of questionable predictions regarding subsurface 

conditions. (Indeed, MMS personnel rarely questioned any statements or predictions contained 

in permit applications.7)

MMS regulations did require BP to submit for approval all of the well design changes that it made 

in response to drilling conditions or external events.8 As a result, BP submitted more than 10 

separate drilling permit applications for Macondo. For instance, BP submitted a revised permit 

application after Hurricane Ida forced BP to replace the Marianas with the Deepwater Horizon.

9

 

It submitted additional revisions after it was forced to stop drilling when the March 8, 2010 kick 

caused a stuck drill pipe and forced BP to continue drilling with a sidetrack.10 BP also submitted 

revised casing schedules each time drilling conditions required it to alter its overall casing plan. 

BP did not always explain the need for well design changes. For instance, it did not specifically 

explain to MMS that it decided to stop drilling earlier than planned and declare a shallower total 

depth because of the early April lost returns event.
254 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Well Design

At the time of the Macondo blowout, MMS regulations covered only very basic elements of well 

design. The regulations required operators to submit information on the pore pressure and 

fracture gradient they expected to encounter, and the maximum pressures to which they expected 

casing strings and well components to be exposed.11 The regulations also required operators to 

specify the weight, grade, and pressure ratings of casing they planned to install, and generally to 

ensure that casing would ―[p]roperly control formation pressures and fluids.‖12

MMS regulations did not authorize, prohibit, or restrict the use of long string production casings. 

They did not specify any minimum number of annular barriers to flow. They did not address any 

issues related to annular pressure buildup (APB), nor authorize or prohibit any particular APB 

mitigation approaches. Regulations did not specify design measures that would facilitate 

containment or capping measures in the event of a blowout; for instance, the regulations did not 

address the use of burst or collapse disks in casing design, nor require the use of a protective 

casing. (Chapter 4.2 discusses these issues in greater detail.) 

In several instances, MMS personnel involved at Macondo recognized risks that might be posed 

by certain Macondo design features or advantages of certain design features not used at Macondo. 

In each instance, however, the individuals refrained from suggesting or requiring changes. They 

explained that their role was to check compliance with specific regulatory requirements and not to 

provide more generalized design advice to operators. One explained that if he were to 

recommend for or against a particular well design or design feature, he might be held responsible 

if that approach caused problems.13

Cementing Design

MMS regulations contained several provisions that address the use of cement in offshore oil wells, 

but they were quite general. MMS personnel identified four regulations that address cement and 

cementing: 30 C.F.R. § 250.415, 420, 421, and 428. Section 250.415 states only that an operator 

must discuss in its cementing program the type and amount of cement it plans to use. Section 

250.420 adds little of relevance: It provides that cement ―must properly control formation 

pressure and fluids.‖ Section 250.421 is the most prescriptive: It specifies minimum cementing 

volume requirements for each type of casing (conductor, surface, intermediate, and production) 

and states that for a production casing, cement must extend at least 500 feet above all 

hydrocarbon-bearing zones. 

MMS personnel stated that the only cementing requirement they routinely policed was the linear 

coverage requirement in 30 C.F.R. § 250.421.14 The Chief Counsel‘s team noted, however, that 

BP‘s permit applications did not contain information that would allow meaningful review of this 

issue. While BP‘s permit applications did include the height of the top of the cement column, they 

did not include the height of the top hydrocarbon-bearing zone. Without this information, it 

would be difficult to determine whether BP planned to pump enough cement to cover the annular 

space 500 feet above that zone. 

MMS cementing regulations did not address several issues that proved important at Macondo.

 The regulations did not require the use of casing centralizers, nor specify minimum 

standoff percentages or other centralization criteria. 
Chief Counsel’s Report — Regulatory Observations | 255

 The regulations did not address the possibility of cement contamination, nor specify any 

measures to reduce the likelihood of contamination (such as the use of wiper plugs or 

spacer fluids).

 While at least one regulation recommended the use of float valves,15 the regulations did 

not specify whether or how to evaluate float valve conversion or performance.

 The regulations did not require BP to conduct or report cement slurry tests, nor specify 

any criteria for test results.

 The regulations did not address the use of foamed cement (or any other specialized 

cementing technology) at all. The regulations did not require BP to inform MMS that it 

would be using foamed cement, nor specify any technical criteria for foamed cement or 

foamed cement testing.

Cement Evaluation

Section 250.428 of the MMS regulations (displayed in Figure 6.3) is the only one that addresses 

directly the possibility of a failed cementing job. That section states that if an operator has 

―indications of an inadequate cement job (such as lost returns, cement channeling, or failure of 

equipment)‖ the operator should:

1. Pressure test the casing shoe;

2. Run a temperature survey;

3. Run a cement bond log; or 

4. Use a combination of these techniques.

Figure 6.3. MMS regulation 30 C.F.R. § 250.428.

MMS
256 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

This regulation applied at Macondo but had little practical effect. The pressure and volume 

indicators that rig personnel examined did not provide any ―indications of an inadequate cement 

job‖ during the cementing process at Macondo. But as discussed in Chapter 4.3, these indicators 

provide little direct information about cementing success. And while the regulation states that 

indications of ―cement channeling‖ should trigger remedial efforts, it is extremely difficult to 

determine if cement has channeled based on surface indicators. Finally, the regulation‘s remedial 

measure requirement is quite modest; MMS personnel admitted that an operator could satisfy it 

by conducting a positive pressure test on the casing shoe,16 even though such a test would not 

examine cementing success. (As Chapter 4.6 explains, BP did conduct a positive pressure test 

after cementing.)

Negative Pressure Test Procedures

The most notable gap in MMS regulatory structure at the time of the incident was the lack of any 

regulation requiring negative pressure tests before temporary abandonment. 

Representatives of the companies involved and other industry experts uniformly agreed that it is 

crucial to negative pressure test wells like Macondo before temporary abandonment. But while 

MMS regulations contain numerous requirements for pressure tests, such as 30 C.F.R. § 250.423 

and 250.426, they do not require negative pressure tests on any well, let alone specify how such 

tests should be done.17 (In its April 16, 2010 application for permit to modify, or APM,18 BP told 

MMS that it would conduct a negative pressure test.) 

Since the blowout, MMS has promulgated interim regulations that would require negative 

pressure tests. MMS regulation 30 C.F.R. § 250.423(c) not only requires negative pressure tests 

on intermediate and production casing strings, but it also requires operators to submit test 

procedures and criteria with their APD to MMS. It also requires all test results to be recorded and 

available for inspection.19 While this regulation does not specify how the test is to be conducted 

or interpreted, the requirement to file procedures and criteria may prompt operators to establish 

best practices.20

The Chief Counsel‘s team notes that negative pressure tests are not necessary at every well. Some 

operators make a practice of ensuring that wells are ―overbalanced‖ even after they remove the 

riser and, with it, the balancing pressure generated by the mud column in the riser. (This 

pressure is called the ―riser margin.‖) If a well is overbalanced, hydrocarbons cannot flow out of 

the formation into the well even if bottomhole cement and any casing plugs were to fail. Negative 

pressure tests are therefore not necessary for overbalanced wells.

Well Control

MMS regulations do address the importance of well control. Notably, 30 C.F.R. § 250.401 

(displayed in Figure 6.4) required operators to: 

 ―Use the best available and safest drilling technology to monitor and evaluate well 

conditions and to minimize the potential‖ for a kick. Section 250.105 defines the term 

―best available and safest technology‖ to mean technologies that the MMS director 

―determines to be economically feasible wherever failure of equipment would have a 

significant effect on safety, health, or the environment.‖ 
Chief Counsel’s Report — Regulatory Observations | 257

MMS

 Ensure that the drilling crew ―maintains continuous surveillance on the rig floor‖ from 

the start of drilling operations until the well is temporarily or permanently abandoned, 

unless the well is shut in with BOPs.

 Use personnel who have received well control training that meets regulatory 

requirements.

 ―Use and maintain equipment and materials necessary to ensure the safety and 

protection of personnel, equipment, natural resources, and the environment.‖

Figure 6.4. MMS regulation 30 C.F.R. § 250.401.

The Chief Counsel‘s team observed that all key personnel involved in the blowout had received 

MMS-approved well control training. However, the training they received appears to have 

focused primarily on initial kick response during drilling operations—that is, on the process of 

shutting in a well and circulating the kick out. Numerous individuals stated that well control 

training typically does not involve extensive instruction in the subtleties of kick detection and kick 

indicators. Additionally, as discussed further in Chapter 4.8, the training does not appear to have 

covered the proper emergency response to full-scale blowouts.

Despite the aspirational language of the ―best available and safest technology‖ requirement, the 

Deepwater Horizon rig did not include any devices designed specifically to help rig personnel 

detect the presence of hydrocarbons in the wellbore during nondrilling procedures such as 

temporary abandonment. The rig‘s drilling equipment did include sophisticated instruments that 
258 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Figure 6.5. BP’s April 16 application for 

permit to modify.

BP

could detect kicks during the course of actual drilling. But these instruments were part of the rig‘s 

bottomhole assembly (the lower part of the drill string). They were not present in the wellbore 

during cementing and temporary abandonment procedures.

Temporary Abandonment Procedures

MMS regulation 30 C.F.R. § 250.1721 specifies the requirements that an operator must satisfy 

before temporarily abandoning a well. The section contains several provisions, but the only one 

that appears to have guided decision making at Macondo was subpart (d), which states that an 

operator must: ―[s]et a retrievable or a permanent-type bridge plug or a cement plug at least 100 

feet long in the inner-most casing‖ and that the top of the plug must be ―no more than 1,000 feet 

below the mud line.‖

BP‘s last regulatory submission for 

Macondo was an April 16 APM (seen in 

Figure 6.5) in which it requested 

permission to set an unusually deep 

cement plug 3,000 feet below the

mudline—2,000 feet deeper than section 

250.1721 would otherwise require.

21 BP 

made its request by submitting the short 

numbered list of temporary abandonment 

procedures discussed in Chapter 4.5. The 

company stated that it would ―[s]et a 300' 

cement plug (125 cu. ft. of Class H 

cement) from 8367' to 8067',‖ explaining 

its rationale in just 40 words: 

The requested surface plug depth 

deviation is for minimizing the 

chance for damaging the LDS 

sealing area, for future 

completion operations. 

This is a Temporary 

Abandonment only.

The cement plug length has been 

extended to compensate for 

added setting depth.

MMS granted BP‘s request less than 90 minutes after BP submitted it.22 MMS regulation 

30 C.F.R. § 250.141 is the regulation that gives MMS officials authority to grant departures from 

otherwise-applicable regulatory requirements. That regulation states, in relevant part: 

You may use alternate procedures or equipment after receiving approval as described in 

this section...[a]ny alternate procedures or equipment that you propose to use must 

provide a level of safety and environmental protection that equals or surpasses current 

MMS requirements. 
Chief Counsel’s Report — Regulatory Observations | 259

The Chief Counsel‘s team asked MMS personnel why they believed that BP‘s request was 

appropriate. The individual involved in the decision explained that he granted the request after 

speaking with BP and learning that BP needed to set the surface plug deep in order to 

accommodate the setting requirements for its lockdown sleeve. He explained that he viewed it as 

beneficial for BP set its lockdown sleeve during temporary abandonment procedures but admitted 

that he had no training or expertise in lockdown sleeve procedures or best practices.23 Neither 

MMS individuals nor MMS regulations addressed:

 the fact that BP relied on a single wellbore barrier during temporary abandonment;

 the extent to which BP had underbalanced the well during temporary abandonment 

activities;

 whether BP could or should set its surface cement plug in drilling mud, or whether BP 

should satisfy additional requirements before displacing drilling mud from the wellbore 

in order to set its surface cement plug in seawater;

 whether the BOP could be open during riser displacement operations or plug 

cementing; or 

 whether alternatives besides a deep surface plug could accommodate lockdown sleeve 

setting requirements.

BOP Testing

BP applied for and received MMS approval to test several elements of the Deepwater Horizon 

BOP at lower pressures than regulations would normally require. One departure MMS granted 

allowed BP to test the Deepwater Horizon‘s blind shear ram at the same pressures at which it 

tested casing.24 Other departures permitted the rig crew to test the annular preventers at 

reduced pressures. 

MMS regulations required that high-pressure tests for annular preventers equal 70% of the rated 

working pressure of the equipment or a pressure approved in an APD.25 BP filed an APD in which 

it asked permission to reduce testing pressures for the Deepwater Horizon‘s annular preventers 

to 5,000 pounds per square inch (psi) in October 2009.26 In January 2010, BP filed an APD 

asking permission to reduce testing pressures for both annular preventers to 3,500 psi.27 MMS 

granted these requests, which were consistent with industry practice.

MMS personnel did occasionally refuse BP‘s requests for testing modifications. For instance, 

after dealing with a February lost circulation event, BP asked MMS to allow rig personnel to delay 

scheduled BOP testing. This would have allowed the crew to immediately run the next casing 

string, in order to prevent further losses if the lost circulation treatment broke down during 

testing. On March 10, however, MMS personnel rejected that request.28

General Observations on Macondo Permitting Process 

In reviewing BP‘s permit applications, the Chief Counsel‘s team noted that several of them 

included fairly obvious clerical or calculation errors. In some instances, it appears that MMS 

personnel did not recognize these errors. While none of the errors proved consequential—BP in 

most cases corrected them before proceeding—the fact that they escaped MMS attention raises 
260 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

concerns about the thoroughness with which the agency conducted even the relatively modest 

review it did undertake. 

The most notable series of errors comes in three APDs that BP submitted to permit its long string 

production casing: APDs 9511, 9513, and 9515, filed on April 14 and 15. Among the errors in 

those APDs are the following:

 APD 9511: BP‘s written well design information states on one page that the company 

plans to use a single 7-inch long string production casing while another page states that it 

will use a 9-inch casing. Meanwhile, its well schematic states that it plans to use a 

tapered long string casing that includes a 9-inch section and a 7-inch section. 

 APD 9513: BP corrected its mistaken statements about the long string diameter and 

explained that it would be using a tapered long string casing. However, this submission 

omitted the 9-inch liner that it had already installed from the well design information. 

Again, this liner appears in the well schematic.

 APD 9515: BP corrected its mistake again, this time noting that the well would include 

both the prior 9-inch liner and a long string casing tapering from 9 inches to 7 inches. 

 APDs 9511, 9513, 9515: In all three of these permit applications, BP‘s written well 

design information states that it will pump 150 cubic feet of cement to cement the long 

string production casing in place. That volume equates to just 26 barrels—less than the 

60 barrels of cement BP actually planned to pump, and far less than would have been 

necessary to meet MMS linear coverage requirements. 

MMS personnel approved all three of these permit applications despite these errors.

BOP Recertification 

MMS regulation 30 C.F.R. § 250.446(a) requires that BOPs be inspected in accordance with API 

Recommended Practice 53 § 18.10.3.29 This practice requires disassembly and inspection of the 

BOP stack, choke manifold, and diverter components every three to five years.30 This periodic 

inspection is in accord with Cameron‘s manufacturer guidelines, and Cameron would certify when 

the inspections were completed.31 

The rig crew and BP shore-based leadership recognized that the Deepwater Horizon‘s blowout 

preventer was not in compliance with certification requirements.32 BP‘s September 2009 audit of 

the rig found that the test ram, upper pipe ram, and middle pipe ram bonnets were original and 

had not been recertified within the past five years.33 According to an April 2010 assessment, BOP 

bodies and bonnets were last certified on December 13, 2000, almost 10 years earlier.34 An April 

2010 Transocean rig condition assessment also found the BOP‘s diverter assembly had not been 

certified since July 5, 2000.35 Failure to recertify the BOP stack and diverter components within 

three to five years would appear to have violated MMS inspection requirements.36 

An MMS inspection of the Deepwater Horizon on April 1, 2010 did not mention overdue BOP 

equipment certification.37 When visiting a rig, inspectors use a ―potential incidents and 

noncompliance‖ (PINC) list as an inspection checklist.38 Although the PINC list contains 
Chief Counsel’s Report — Regulatory Observations | 261

guidelines not intended to supersede regulations,39 inspectors consider the PINC list a 

comprehensive list of inspection items.40 Because the list does not include verifying compliance 

with 30 C.F.R. § 250.446(a),41 inspectors may simply have not checked whether the Deepwater 

Horizon‘s BOP had been disassembled and inspected in accord with regulations. 

Ethical Considerations

In recent years various bodies have concluded that certain MMS offices and programs have 

violated ethical rules or guidelines. In the wake of the Deepwater Horizon disaster, some 

questioned whether ethical lapses played any role in causing the blowout. The Chief Counsel‘s 

team found no evidence of any such lapses.
262 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Endnotes

Chapter 1

1

Executive Order No. 13543, National Commission on the BP Deepwater Horizon Oil Spill and Offshore 

Drilling, 75 Fed. Reg. 29,397, May 21, 2010.

2

Ibid.

3

Press Release, National Commission, Fred Bartlit Named Chief Counsel, July 22, 2010.

Chapter 3

1

Internal Department of Interior document (OSC-DWH BOEM-WDC-B01-00002-00004).

2

Internal BP document (BP-HZN-MBI 13494). 

3 David Sims (BP), interview with Commission staff, December 14, 2010.

4

Internal BP document (BP-HZN-MBI 13494). 

5 U.S. Geological Survey official, interview with Commission staff, October 21, 2010.

6

Internal BP document (BP-HZN-OSC 4259).

7

Internal BP document (BP-HZN-OSC 4663).

8

Testimony of Paul Johnson (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, August 23, 2010, 352. However, some forms of maintenance, including BOP maintenance, were 

exempt from this provision. Internal BP document (BP-HZN-MBI 4254).

9

Testimony of David Sims (BP), Testimony of before the Deepwater Horizon Joint Investigation Team, 

August 26, 2010, 191; Internal BP document (BP-HZN-MBI 126763).

10 Nonpublic BP document (presentation to the Commission, August 9, 2010), 6. 

11 CNN Money, ―Global 500,‖ Fortune, July 11, 2010.

12 Ibid.

13 Eduard Gismatullin, ―BP Makes  ̳Giant‘ Oil Discovery in Gulf of Mexico.‖ Bloomberg, September 2, 2009. 

14 Internal BP document (BP-HZN-OSC 7093). 

15 Internal BP document (BP-HZN-BLY 47279).

16 Internal BP document (BP-HZN-MBI 100315).

17 Testimony of David Sims, 123. 

18 Internal BP document (BP-HZN-MBI 190507).

19 Testimony of David Sims, 123.

20 Internal BP document (BP-HZN-MBI 190507).

21 Sims, interview.

22 Internal BP document (BP-HZN-MBI 190507).

23 Internal Transocean document (TRN-HCJ 93526).

24 Testimony of Brett Cocales (BP), Hearing before the Deepwater Horizon Joint Investigation Team, August 

27, 2010, 11. 

25 Internal BP document (BP-HZN-MBI 177777).
Chief Counsel’s Report — Endnotes | 263

26 Ibid.

27 Transocean, ―Our Company,‖ accessed November 17, 2010, 

http://www.deepwater.com/fw/main/Our-Company-2.html.

28 Internal Transocean document (TRN-USCG-MMS 30428). 

Chapter 4.1

1

Such evidence includes, but is not limited to, the following: pressure and fluid data from BP‘s September 

16, 2010 Development Driller III relief well intersection of the Macondo well, ongoing analysis of cement 

―rocks‖ found on the Damon Bankston after the blowout, and information on the internal and external 

pressure testing of the connections used in the Macondo well. 

2

BP and Halliburton agree that cement in the annulus did not isolate the hydrocarbon-bearing zones.

Transocean has so far deferred to BP and Halliburton on this issue. Testimony of Mark Bly (BP), Hearing 

before the National Commission, November 8, 2010, 196-97, 326, 328-29; Testimony of Richard Vargo 

(Halliburton), Hearing before the National Commission, November 8, 2010, 196-97, 326, 328-29; Testimony 

of Bill Ambrose (Transocean), Hearing before the National Commission, November 8, 2010, 196-97, 326, 

328-29; BP, Deepwater Horizon Accident Investigation Report (September 8, 2010), 54. 

3

Internal BP document (BP-HZN-MBI 138868).

4

Steve Lewis (Expert witness), interview with Commission staff, September 15, 2010.

5

John Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252 (July 1, 

2010), 20; Testimony of Richard Vargo, 271; BP, Deepwater Horizon Accident Investigation Report, app. M, 

3, 15-19.

6

BP, Deepwater Horizon Accident Investigation Report, 38.

7

Ibid., 74; Confidential industry expert, interview with Commission staff.

8

Confidential industry expert, interview.

9

Testimony of Mark Hafle (BP), Hearing before the Deepwater Horizon Joint Investigation Team, May 28, 

2010, 77; Confidential source, interview with Commission staff.

10 John Smith (Expert witness), interview with Commission staff, September 17, 2010. Of 34 loss of well 

control incidents in offshore wells in U.S. federal waters from 1992 to 2002, 19 (56%) were caused by 

annular flows associated with the cementing process. American Petroleum Institute, Recommended Practice 

65, Part 2: Isolating Potential Flow Zones During Well Construction (May 2010), 57 (―API RP 65 part 2‖). 

The API has identified annular flow as a ―common problem‖ with ―grave consequences.‖ Ibid., 48. Indeed, 

on August 16, 2000, MMS presented safety concerns on uncontrolled annular flows to a new API Work 

Group on Annular Flow Prevention and Remediation. In response, the group developed two recommended 

practices to document industry best practices to improve zonal isolation, and help prevent annular flow 

incidents prior to, during, and after cementing operations, to mitigate and prevent annular flows. Ibid.

11 John Martinez, William McDonald and C. Ray Williams, Study of Cementing Practices Applied to the 

Shallow Casing in Offshore Wells (October 1980), ii.

12 For example, in the August 21, 2009 blowout at the Montara wellhead platform, hydrocarbons entered 

through the cemented casing shoe. David Borthwick, Report of the Montara Commission of Inquiry (The 

Montara Commission of Inquiry, Australia, June 2010), 6-7. The May 19, 2010 loss of well control incident 

at Gullfaks C involved a hole in the 133⁄8-inch casing. Statoil, Gullfaks C Report (April 11, 2010), 6. Similarly, 

a BP injection well in Azerbaijan sustained a leak in its tubing as a result of debris in the seal of a connection; 

the leaking connection had been made up improperly. Steve Morey (BP), interview with Commission staff, 

December 23, 2010. 

13 John Guide (BP), interview with Commission staff, September 17, 2010; David McWhorter (Cameron), 

interview with Commission staff, August 10, 2010; Doug Blankenship (DOE), interview with Commission 

staff, October 26, 2010; Testimony of Richard Vargo, 274-75; Internal BP document (BP-HZN-CEC 18892). 

Some of the containment operations were designed with annular flow as a starting assumption. Stephen 

Wilson, Macondo Radius of Failed Zone at Intercept Depth (June 22, 2010). Indeed, BP used OLGA well 

flow modeling to model the flow rates for both scenarios (flow up the production casing and flow in the 

annulus around the production casing). Internal BP document (BP-HZN-BLY 48212).
264 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

14 Confidential industry expert, interview; Confidential source, interview.

15 BP, Deepwater Horizon Accident Investigation Report, 68-69.

16 Testimony of Bill Ambrose, 185-86. 

17 Testimony of Richard Vargo, 187-94, 266, 270. Halliburton has declined to provide any documentation or 

written explanation of its theory of annular flow. 

18 Tommy Roth (Halliburton), interview with Commission staff, August 17, 2010; Testimony of Richard 

Vargo, 187-94, 266, 270.

19 The Chief Counsel‘s team takes the three companies‘ conclusions with a healthy grain of salt. BP and 

Halliburton in particular each advance flow path explanations that happen to coincide with their own 

financial and litigation interests. Nevertheless, the companies‘ explanations and evidence in support of their 

theories have been helpful to the Chief Counsel‘s team‘s analysis.

20 BP conducted several well interventions after the April 20 blowout and before the October forensic 

operations. These included the August static kill and the September bottom kill, where BP pumped mud and 

cement into the Macondo well. These operations could have affected the condition of the Macondo well 

annulus. 

21 Erosion is expected in light of the force and speed of hydrocarbon flow during the blowout. Testimony of 

Bill Ambrose, 244. 

22 Trace amounts of hydrocarbons in the annulus might be expected even where flow went through the shoe 

track and up the production casing, if the annular mud had been exposed to the formation and stray 

hydrocarbons displaced some of the mud in the annulus during flow. Blankenship, interview; David 

Trocquet (MMS), interview with Commission staff, October 1, 2010. Alternatively, it is possible that the 

annular mud was never exposed to the formation or hydrocarbon flow if, for example, the cap cement 

remained intact as a barrier. BP legal team, interview with Commission staff, January 12, 2011.

23 Internal BP document (BP-HZN-NAE 2412).

24 The BP report estimates the density of hydrocarbons as 5.18 ppg at 239 degrees Fahrenheit at 12,000 psi. 

BP, Deepwater Horizon Accident Investigation Report, app. G, 215. 

25 Internal BP document (BP-HZN-NAE 2412).

26 This flow-out occurs because the gas compresses until the pressures balance. If the annulus is full of liquid 

and able to withstand the increased hydrostatic pressure of the fluid inside the production casing, there 

would be no flow. Steve Lewis (Expert witness), email to Commission staff, December 28, 2010.

27 Internal BP document (BP-HZN-NAE 2412).

28 Blankenship, interview.

29 BP, Deepwater Horizon Accident Investigation Report, 56.

30 Internal BP document (BP-HZN-NAE 2412).

31 Blankenship, interview.

32 Internal BP document (BP-HZN-NAE 2419). 

33 Internal BP document (BP-HZN-NAE 2426). 

34 Ibid. 

35 Ibid. 

36 Internal BP document (BP-HZN-NAE 2436). 

37 Doug Blankenship, interview. For the sake of completeness, it is worth noting that on September 22, 2010, 

BP had Schlumberger perform an acoustic log of the fluid in the annulus of the Macondo well from the 

wellhead to 9,318 feet using an isolation scanner. The results suggested there was lighter density fluid in the 

annulus outside of the 97⁄8-inch production casing. Internal BP document (BP-HZN-NAE 2406). Given that 

the results of the perforation test and the sampling do not support the presence of hydrocarbons, it is likely 

that the log (which is an indirect measurement of annular fluid density) was erroneous.

38 Testimony of John Sprague (BP), Hearing before the Deepwater Horizon Joint Investigation Team, 

December 8, 2010, part 2, 91.
Chief Counsel’s Report — Endnotes | 265

39 Testimony of Bill Ambrose, 244 ―[The flow in t]his particular case, just to put it in perspective, was a 

550-ton freight train hitting the rig floor. Things happened very quickly, and then it was followed by what we 

estimate to be a jet engine‘s worth of gas coming out of the rotary.‖ Ibid.

40 Internal BP document (BP-HZN-NAE 2438).

41 Dril-Quip representatives, interview with Commission staff, October 27, 2010.

42 Ibid.

43 Ibid. The flow passages are approximately 1 inch in diameter. Given that diameter, the total area for flow 

coming through the 18 flow passages absent erosion would have been only 14 square inches. Ibid.

44 Dril-Quip legal team, email to Commission staff, November 2, 2010.

45 Blankenship, interview; Dril-Quip representatives, interview.

46 Nonpublic BP document (presentation to Commission staff on flow rate estimates, October 22, 2010), 16; 

Nonpublic BP document (presentation to Commission staff on BOP, September 8, 2010), 7; Blankenship, 

interview; Internal BP document (BP-HZN-NAE 2432-35).

47 Dril-Quip representatives, interview. 

48 Blankenship, interview; Dril-Quip representatives, interview. Dril-Quip has made representations to the 

Commission staff that the evidence is ―conclusive.‖ Dril-Quip representatives, interview.

49 Dril-Quip representatives, interview. ―It looks pretty good.‖ Testimony of Richard Vargo, 273. 

50 Dril-Quip representatives, interview. 

51 Ibid.

52 Internal BP document (BP-HZN-NAE 2388); Testimony of John Sprague, 89.

53 Internal BP document (BP-HZN-NAE 2388); Testimony of John Sprague, 89. ―The hanger was properly 

landed and the seal assembly was in the place it was supposed to be in.‖ Ibid.

54 Dril-Quip representatives, interview; Merrick Kelley (BP), interview with Commission staff, October 22, 

2010.

55 Kelley, interview.

56 Internal BP document (BP-HZN-NAE 2392). ―TEST 9 7/8′′ PRODUCTION CASING, WELHEAD 

CONNECTOR & UPPER BSR. WITH 13.2 PPG SOBM. TEST TO 250 PSI LOW FOR 5 MINUTES STRAIGHT 

LINE ON CHART & 4,100 PSI FOR 30 MINUTES STRAIGHT LINE ON CHART. PRESSURE UP DOWN 

KILL LINE @ 1⁄2 BPM. TOTAL BBLS PUMPED 6, ISIP 4,270 PSI, FINAL SIP 4,158 AFTER 30 MINUTES. 

BLED OFF PRESSURE. RECOVERED 5.25 BBLS. TEST LOWER BSR TO 250 PSI LOW & 4,100 PSI HIGH 

FOR 5 MINUTES EACH STRAIGHT LINE ON CHART.‖ Ibid.

57 Benjamin Powell (BP legal team), letter to Commission staff, November 1, 2010, 2; Testimony of John 

Sprague, 90. ―Prior to running the lockdown sleeve, we actually tested the seal assembly and hanger to 4100 

PSI and got a good test, which indicated to us that the seals were intact.‖ Testimony of John Sprague, 90.

58 Internal BP document (BP-HZN-NAE 2398). 

59 Testimony of John Sprague, 90. ―We ran the lockdown sleeve, set it, pressure tested it, I think, to 5400 

PSI, which meant both the lockdown sleeve and the seal assembly and the hanger had integrity.‖ Ibid. 

60 Powell, letter. 

61 Donald Godwin (Halliburton), letter to Commission staff, December 9, 2010, 1.

62 Ibid. Halliburton references the relevant time frame as 00:22 to 00:36. Ibid. These timestamps are mere 

reference points on the chart contained in Halliburton‘s post-cement-job report, not the actual times of the 

relevant events during the cement job. Lewis, email, December 28, 2010; Internal Halliburton document 

(HAL_28543). ―Graph created from Sperry‘s data, time of events are not correct.‖ Internal Halliburton 

document (HAL_28543).

63 Steve Lewis (Expert witness), email to Commission staff, December 12, 2010. ―Well bore geometry, when 

related to a finite element hydrostatic balance calculation reveals a sequence of changing pressure balance 

over the last eighty one minutes of the displacement which parallels the trend and approximates the 

magnitude pump pressure response during this period.... A mathematic analysis of the hydrostatic balance of 
266 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

the MC-252#1 cement displacement produces results which move in concert with the observed surface 

pressure.‖ Ibid.

64 Ibid. 

65 Internal Halliburton document (HAL_11005). The model‘s predicted numerical pressures do not appear 

to match precisely with the observed data. This may be due to the predictive nature of the model or 

imprecise inputs. Testimony of John Gisclair (Halliburton), Hearing before the National Academy of 

Engineering, September 26, 2010, 40. But the model does predict the general downward trend observed.

66 Internal BP document (BP-HZN-MBI 129053)(―Just wanted to let everyone know the cement job went 

well. Pressures stayed low, but we had full returns the entire job, saw 80 psi lift pressure and landed out 

right on the calculated volume.‖); Internal Halliburton document (HAL_28538)(―Cement job pumped as 

planned.‖); Mark Bly (BP), interview with Commission staff, September 8, 2010; Kris Ravi (Halliburton), 

interview with Commission staff, September 19, 2010 (circulating pressures appear to be in the correct 

ranges).

67 Testimony of Richard Vargo, 276. ―All of that information has to be explained as to why the pressure drop 

occurred during the displacement of the cementing operation and potentially why there isn‘t a lot of damage 

here.‖ Ibid. 

68 Dril-Quip representatives, interview. 

69 Ibid. 

70 Ibid. 

71 Internal BP document (BP-HZN-OSC 8844); Internal BP document (BP-HZN-OSC 8845).

72 Internal BP document (BP-HZN-OSC 8842); Internal BP document (BP-HZN-OSC 8844).

73 Internal BP document (BP-HZN-OSC 8842); Internal BP document (BP-HZN-OSC 8840)(―The data set 

supports a hypothesis of a casing and drill pipe flow path.‖); Internal BP document (BP-HZN-OSC 8843); 

Internal BP document (BP-HZN-OSC 113099)(―Flowpath tracker indicate that flow path was inside the 

casing only.‖).

74 New evidence about the geometry of the wellbore continues to emerge after the static kill. For example, in 

October, BP obtained new information about the presence of drill pipe above the crossover joint. BP legal 

team, interview.

75 The observed data showed a divergence and then a spike in surface pressure after several hundred barrels 

were pumped. Internal BP document (BP-HZN-OSC 8842); Internal BP document (BP-HZN-OSC 113132). 

Some have suggested that the spike might indicate a breach at the crossover joint. Another explanation for 

the spike is that mud hit the formation earlier than modeled. Blankenship, interview; John Smith (Expert 

witness), email to Commission staff, January 13, 2011; Internal BP document (BP-HZN-OSC 113091-93). ―It 

was expected that the operational results would differ from these theoretical curves due to a strong out 

transition zone between the Macondo oil and the kill mud.... The early increase in pressure at around 500 

bbls pumped is assumed to be due to a long transition zone and  ̳roping‘ of mud. The gradual increase in 

pressure is expected to be due to mud gradually packing off the Macondo reservoir sand face.‖ Internal BP 

document (BP-HZN-OSC 113091-93). BP‘s offshore kill and cement team retained uncertainty: ―After 

pumping 330 bbls of mud into the well, there was a significant deviation from the predicted BOP pressure 

suggesting a flow path outside of the assumptions and geometries incorporated into the diagnostic model.... 

Based on the actual kill data divergence from the predicted pressure schedule, multiple flow path options 

exist for the lower portion of the well, below the 9633.5' MD.‖ Internal BP document (BP-HZN-OSC 113128). 

76 John Smith (Expert witness), email to Commission staff, December 26, 2010. It also appears that the 

modeling did not account for the volume of the shoe track or the annulus below the float collar. Steve Lewis 

(Expert witness), email to Commission staff, December 19, 2010.

77 Internal BP document (Macondo well schematic). 

78 Internal BP document (BP-HZN-BLY 48255, 48259-60).

79 Internal BP document (BP-HZN-MBI 98759).

80 Ibid; Morey, interview. Connections are designed to withstand the same external pressures as the pipe 

body. Morey, interview. 

81 Internal BP document (BP-HZN-MBI 98759).
Chief Counsel’s Report — Endnotes | 267

82 Testimony of Lance John (Weatherford), Hearing before the Deepwater Horizon Joint Investigation 

Team, July 19, 2010, 243. ―We have a thread rep on location which is usually the connection – whatever 

connection we‘re running there and also we have our Jam system that we monitor to make up torques and 

turns. Q. And did you verify that all the connections were to your standard? A. Correct. Well, right away the 

thread rep is there also looking at the graph as it‘s being – the connection‘s being made up.‖ Ibid. 

83 Internal Weatherford documents (WFT 38, 43, 49); Steve Lewis (Expert witness), email to Commission 

staff, January 6, 2011. ―I saw nothing in the WFD data or reports that would make me question their 

statement that all the joints that they made up or checked were made to specification and within normal 

variable limits.‖ Lewis, email, January 6, 2011. 

84 The logs made available to the investigative team did not contain a record of the connections made up 

onshore. Those include the reamer shoe, the centralizer subs, the float collar, and the crossover joint. Lewis, 

email, January 6, 2011.

85 Testimony of Lance John, 255. ―They pulled a connection out of the box. The driller picked up on it. It 

pulled the connection. It‘s a wedge-type connection, so when it pulled it out, it sprung back in and damaged 

the one below it so we laid those out and replaced them with new joints.... We had – one of them was a 

double, so we had to lay out the double and we put a single and we replaced them with new joints.... The 

driller, when he slacked off into the box, slacked off too much and the pipe fell to the side and he was 

straightening it back up and as he was straightening it, is when he pulled it out of the box.‖ Ibid. 

86 Ibid. That action would have resolved the issue. Morey, interview. 

87 Since the blowout, at least one BP engineer involved with the well has testified that there could have been 

a breach in the production casing, namely through one or more of the threaded connections between casing 

joints. ―Every joint of casing is screwed together, and there were several joints having a thread that any of 

those threads could leak.‖ Testimony of Mark Hafle, 77. Transocean‘s internal investigator does not consider 

a break in the casing above the float mechanism a possibility because he views that component as being a 

stronger connection than the ―internal guts‖ of the float assembly. Bill Ambrose (Transocean), interview with 

Commission staff, November 2, 2010. 

88 Testimony of Nathaniel Chaisson (Halliburton), Hearing before the Deepwater Horizon Joint 

Investigation Team, August 24, 2010, 432-34.

89 Ibid.

90 Confidential source, interview.

91 Testimony of Nathaniel Chaisson, 432-34 (―Phone calls were made to BP in Houston and all of those 

phone calls and discussions were handled between BP personnel.‖); Confidential source, interview; Internal 

BP document (BP-HZN-MBI 129068)(Guide, Morel, and Kaluza considered the possibility of a casing 

breach).

92 Internal BP document (BP-HZN-MBI 129068). Clawson was unsure of the meaning of the email, but he 

did not have a follow-up conversation about it with Morel. Bryan Clawson (Weatherford), interview with 

Commission staff, October 28, 2010.

93 Confidential source, interview.

94 Ibid.

95 After the cement job, the rig crew performed a positive pressure test on the well to test the integrity of the 

production casing. They pumped 2,500 psi of pressure into the production casing, which held steady for 30 

minutes. The fact that the positive pressure test passed makes a casing breach unlikely but does not 

definitively rule out a breach. The positive pressure test assesses whether the production casing can hold 

pressure from the inside. It does not test whether the casing can withstand pressure exerted from the 

outside. The positive pressure test also did not test the casing below the top wiper plug. Finally, a casing 

breach could have occurred after the positive pressure test was complete.

96 Smith, email, December 26, 2010. Certain other data that BP employs as the basis for its conclusion that 

there was shoe track flow is similarly insufficiently sensitive to distinguish a casing breach near the bottom 

of the production casing from a failure of the shoe track cement. For example, BP argues that the increase 

(rather than decrease) in drill pipe pressure prior to the blowout indicates that flow came up through the 

production casing and pushed mud up around the drill pipe. BP, Deepwater Horizon Accident Investigation 

Report, app. G, 221. Hydrocarbons entering through a breach near the bottom of the production casing 

could be responsible for pushing up the mud. 
268 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

97 Internal Weatherford documents (WFT 38, 43, 49). The logs made available to the investigative team did 

not contain a record of the connections made up onshore. Those include the reamer shoe, the centralizer

subs, the float collar, and the crossover joint. Lewis, email, January 6, 2011.

Chapter 4.2

1

Steve Lewis (Expert witness), interview with Commission staff, September 21, 2010.

2

Ibid.

3

―In the drilling business it is standard practice to always have multiple barriers in place in the wellbore at 

any given time.... Only when at least two mechanical barriers are in place, and sufficiently tested, can the 

drilling fluid be removed as a barrier.‖ Hearing to Review Recent Issues in Offshore Oil and Gas 

Development, Before the S. Comm. on Energy and Natural Resources, 111th Cong. (May 11, 2010)(statement 

of F.E. Beck, Texas A&M University). Shell‘s standard ―specifies that all planned well operations must 

normally be executed under the protection of two independent barriers between the reservoir and the 

environment....‖ Joseph Leimkuhler (Shell), letter to Commission staff, September 22, 2010. Indeed, BP‘s 

own Drilling and Well Operations Practice manual specifies that (1) ―During well construction and 

maintenance activities, operations shall be conducted with one active barrier and one contingent barrier 

installed to address critical operational risks and contain the well,‖ and (2) ―Prior to breaking containment of 

any well control equipment such as the removal of a tree, BOP or any component, there shall be two 

independent mechanical barriers to flow fitted in all wells.‖ Internal BP document (BP-HZN-MBI 130846, 

130875).

4 Gregg Walz (BP), interview with Commission staff, October 6, 2010.

5

Internal BP document (BP-HZN-MBI 13494).

6 David Sims (BP), interview with Commission staff, December 14, 2010.

7 Guide described the Macondo well as a production well with an exploration tail. John Guide (BP), interview 

with Commission staff, September 17, 2010. So did Walz and Sims. Walz, interview; Sims, interview. 

8 Guide, interview, September 17, 2010.

9

Ibid.

10 Ibid. 

11 Steve Morey (BP), interview with Commission staff, December 22, 2010; Patrick O‘Bryan (BP), interview 

with Commission staff, December 17, 2010.

12 Testimony of Mark Hafle (BP), Hearing before the Deepwater Horizon Joint Investigation Team, May 28, 

2010, 60.

13 Sims, interview.

14 Morey, interview.

15 Internal BP document (BP-HZN-BLY 47277-84).

16 Internal BP document (BP-HZN-BLY 47280-81).

17 Technically, the 16-inch pipe is a ―liner‖ rather than a ―casing,‖ because it hangs 160 feet below the 

wellhead. Casing runs all the way up to the wellhead, where it hangs from a ―casing hanger.‖ A liner does not 

run all the way up to the wellhead and instead hangs from a ―liner hanger‖ placed farther down in the well.

For simplicity‘s sake, and because individuals in the oil and gas industry often use the terms 

interchangeably, this Report nevertheless refers to the 16-inch pipe as a ―casing.‖ 

18 Internal BP document (BP-HZN-MBI 98759).

19 Ibid.

20 Ibid.

21 Ibid.

22 Internal BP document (BP-HZN-MBI 118210).
Chief Counsel’s Report — Endnotes | 269

23 It is worth noting that some refer to the production casing as a protective casing, in that it protects the 

production tubing during later production. Guide, interview, September 17, 2010; John Smith (Expert 

witness), interview with Commission staff, September 7, 2010. 

24 Testimony of Steve Lewis (Expert witness), Hearing before the National Commission, November 9, 2010, 

52; Confidential industry expert, interview with Commission staff. On the relief well, 135⁄8-inch casing ran all 

the way to the wellhead to help ensure better pressure integrity for the dynamic kill. Ronnie Sepulvado (BP), 

interview with Commission staff, August 20, 2010. 

25 Ronnie Sepulvado, interview, August 20, 2010; Confidential industry expert, interview.

26 Ronnie Sepulvado, interview, August 20, 2010. From the beginning, the 16-inch casing was not supposed 

to be seated in the high-pressure housing of the wellhead. And the 135⁄8-inch casing was not supposed to be 

tied back. Guide, interview, September 17, 2010.

27 A 135⁄8-inch protective casing would have eliminated the value of the burst disks in the 16-inch casing.

Guide, interview, September 17, 2010. Almost every exploration well will have an intermediate long string at 

135⁄8 inches; Macondo was different because it had a production casing long string. Sims, interview.

28 Testimony of Mark Bly (BP), Hearing before the National Academy of Engineering, September 26, 2010; 

Ronnie Sepulvado (BP), interview with Commission staff, October 26, 2010.

29 Ronnie Sepulvado, interview, August 20, 2010. To the contrary, BP drilling engineer Brian Morel 

commented, in an email, that BP would ―come back to run the tieback‖ ―at a later date.‖ Internal BP 

document (BP-HZN-MBI 199432). 

30 Testimony of Micah Burgess (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, May 29, 2010, 117. The Horizon crew encountered more problems than usual. E.C. Thomas (Expert 

witness), interview with Commission staff, October 27, 2010. 

31 Internal BP document (BP-HZN-OSC 1449).

32 Internal BP document (BP-HZN-OSC 4094). 

33 Ibid.; Allen Seraile (Transocean), interview with Commission staff, January 7, 2011.

34 John Guide (BP), interview with Commission staff, January 19, 2011.

35 Internal BP document (BP-HZN-OSC 1490); Internal BP document (BP-HZN-OSC 1493).

36 Guide, interview, September 17, 2010.

37 Internal BP document (MC 252-1 DDR).

38 Thomas, interview.

39 Internal BP document (MC 252-1 DDR).

40 Internal BP document (BP-HZN-MBI 324854).

41 Internal BP document (BP-HZN-MBI 109949).

42 Internal BP document (BP-HZN-MBI 197837).

43 One BP engineer said, ―We have been encountering issues on Macondo and the well design is rapidly 

changing.‖ Internal BP document (BP-HZN-MBI 110317).

44 Internal BP document (BP-HZN-MBI 109949).

45 Guide, interview, January 19, 2010.

46 Internal BP document (BP-HZN-CEC 8723).

47 Internal BP document (BP-HZN-MBI 173605); Internal BP document (BP-HZN-CEC 18891).

48 Internal BP document (BP-HZN-MBI 173605); Internal BP document (BP-HZN-CEC 18891).

49 Internal Transocean document (TRN-USCG_MMS 11596).

50 Internal BP document (BP-HZN-MBI 126338); Guide, interview, January 19, 2011.

51 Internal Transocean document (TRN-USCG_MMS 11597).
270 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

52 Internal BP document (BP-HZN-MBI 126338).

53 Ibid.

54 Ibid.

55 Ibid.

56 Ibid.

57 Erick Cunningham (BP), interview with Commission staff, January 19, 2011. As discussed in Chapter 4.4, 

at this meeting the group also considered the merits of using nitrogen foamed cement at the bottom of the 

Macondo well.

58 Ibid. 

59 Ibid. 

60 Ibid. 

61 Ibid. 

62 Ibid. 

63 Confidential source, interview with Commission staff.

64 Ibid.; Walz, interview. BP engineers raised this concern with Gagliano, and Gagliano followed up with 

other Halliburton personnel to run down the cause of the error. Confidential source, interview.

65 Confidential source, interview.

66 Sims, interview; Walz, interview.

67 Walz, interview.

68 Internal BP document (BP-HZN-MBI 127267).

69 Ibid.

70 Internal BP document (BP-HZN-MBI 127266).

71 Ronnie Sepulvado, interview, August 20, 2010.

72 Internal BP document (BP-HZN-MBI 255906).

73 Testimony of Paul Johnson (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, August 23, 2010, 360.

74 Ibid.

75 Cunningham, interview.

76 Confidential source, interview. 

77 It is not clear whether an accurate Halliburton cementing model—with all the correct inputs—was ever 

run. The engineers turned off the faulty part of the model, manually input logging data, and reran the model. 

ECD levels went down but were still too high. Cunningham suggested adding a small amount of base oil in 

front of the spacer fluid in order to lower ECD. Cunningham, interview; Confidential source, interview. 

78 The completion engineers do not appear to have been aware of the final decision at that point. ―[N]o one 

told us what the actual decision was, so we thought y‘all were going with the liner until Doris called me for a 

green light on the MoC.‖ Internal BP document (BP-HZN-MBI 254886).

79 Internal BP document (BP-HZN-BLY 125443).

80 Walz, interview.

81 BP, Deepwater Horizon Accident Investigation Report (September 8, 2010), 76.

82 Testimony of John Guide (BP), Hearing before the Deepwater Horizon Joint Investigation Team, July 22, 

2010, 183.

83 Internal BP document (BP-HZN-MBI 143292). 
Chief Counsel’s Report — Endnotes | 271

84 Testimony of Mark Bly, 306. There was some uncertainty among the team members as to whether a 

formal management of change process was even required because the original well design had included a 

long string production casing, the original well design had already been peer-reviewed, and the team had 

never actually switched the plan in the interim to a liner. Guide, interview, September 17, 2010; Sims, 

interview. Nevertheless, Sims suggested that the team use the process as a vehicle to capture and record the 

issues discussed in the previous few days (April 13 to 15) because there had been a great deal of conversation

about different options. Sims, interview. 

85 Internal BP document (BP-HZN-MBI 143259).

86 Ibid.

87 Ibid.; Internal BP document (BP-HZN-MBI 143292).

88 BP, Deepwater Horizon Accident Investigation Report, app. O, 1-2; Testimony of Charlie Williams (Shell), 

Hearing before the National Commission, November 9, 2010, 40; Confidential industry expert, interview.

89 Anadarko representatives assert, after the blowout, that they would not have installed a long string in the 

Macondo well, given the cement job. Anadarko representatives, interview with Commission staff, September 

29, 2010. The risk of using a long string depends on how reliable the cement job is. According to one 

industry expert, the cement job here should not have been relied on because of inadequate rock strength, 

repeated incidents of lost circulation, slow pump rates, small cement volume, and wiper plugs in tapered 

casing. Confidential industry expert, interview. ―If you‘re concerned that you will lose returns or might lose 

returns when you‘re cementing, running the liner is in my view more straightforward on reestablishing the 

barriers.‖ Testimony of Charlie Williams, 42-43.

90 Bill Ambrose (Transocean), interview with Commission staff, September 21, 2010.

91 Confidential industry expert, interview; Bill Ambrose (Transocean), interview with Commission staff, 

November 2, 2010; Testimony of Tommy Roth (Halliburton), Hearing before the National Academy of 

Engineering, September 26, 2010; Confidential source, interview with Commission staff. To be sure, 

industry engineers usually wipe long string production casings with two wiper plugs, whereas it is common 

practice to wipe a liner with only one wiper plug. In that case, the difference in contamination would be 

reduced. 

92 Erik B. Nelson and Dominique Guillot, eds., Well Cementing, 2nd ed. (Sugar Land, TX: Schlumberger, 

2006), 497.

93 Confidential industry expert, interview. Another reason for this may be wellbore geometry. Mark Bly (BP), 

interview with Commission staff, September 8, 2010. 

94 Murry Sepulvado (BP), interview with Commission staff, December 10, 2010.

95 Confidential industry expert, interview.

96 Testimony of Charlie Williams, 42; Confidential industry expert, interview.

97 Testimony of Charlie Williams, 42.

98 Kris Ravi (Halliburton), interview with Commission staff, September 19, 2010; Ambrose, interview, 

November 2, 2010. 

99 Patrick O‘Bryan, interview.

100 Internal BP document (BP-HZN-OSC 5558). Nonproductive time counts against the performance rating 

of the rig and its personnel. Internal BP document (BP-HZN-OSC 8995); Internal BP document (BP-HZNMBI 117622). 

101 Paul Tooms (BP), interview with Commission staff, October 13, 2010; Internal Department of the Interior 

document (OSC-DWH BOEM-WDC-B06 0001-0007), 133-34.

102 Internal Department of the Interior document (OSC-DWH BOEM-WDC-B06 0001-0007), 133-34.

103 Internal Department of Energy document (presentation on mud flow, June 1, 2010); Internal Department 

of the Interior document (OSC-DWH BOEM-WDC-B06 0001-0007), 133.

104 Coast Guard official, interview with Commission staff; MMS official, interview with Commission staff; 

Senior administration official, interview with Commission staff.

105 Tooms, interview.
272 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

106 Coast Guard official, interview; MMS official, interview; Senior administration official, interview.

107 Government science advisor, interview with Commission staff; Senior administration official interview; 

Internal Department of Energy document (presentation on mud flow).

108 Senior administration official, interview.

109 Internal Department of the Interior document (OSC-DWH BOEM-WDC-B06 0001-0007), 166-68; 

Nonpublic BP document (presentation to the Department of Energy, May 25, 2010), 3-5; BP legal team, 

letter to Commission staff, November 2, 2010, att.

110 Internal Department of the Interior document (OSC-DWH BOEM-WDC-B06 0001-0007), 135; Doug 

Suttles (BP), interview with Commission staff, October 13, 2010. One government official told Commission 

staff that another concern with installing a second BOP was weight: The existing BOP stack was listing at 

2 degrees from vertical, and there was a risk that adding weight to its top would lead to further damage or 

collapse. Senior administration official, interview.

111 BP, letter.

112 BP, letter; Richard Lynch (BP), interview with Commission staff, October 13, 2010; Tooms, interview.

113 Government science advisor, interview with Commission staff.

114 Government science advisor, interview with Commission staff.

115 Confidential industry expert, interview.

116 O‘Bryan, interview.

117 Ibid.; Guide, interview, September 17, 2010.

118 Guide, interview, September 17, 2010.

119 Morey, interview.

120 Guide, interview, September 17, 2010; Mike Zanghi (BP), interview with Commission staff, 

December 15, 2010.

121 O‘Bryan, interview; Internal BP document (BP-HZN-OSC 8007).

122 Morey, interview.

123 Walz, interview.

124 BP, Deepwater Horizon Accident Investigation Report, 75.

125 Confidential industry expert, interview.

Chapter 4.3

1

Erik Nelson and Dominique Guillot, eds., Well Cementing, 2nd ed. (Sugar Land, TX; Schlumberger, 2006), 

143, 445.

2

Ibid, Well Cementing, 148.

3

American Petroleum Institute, Recommended Practices for Isolating Potential Flow Zones in Well 

Construction, 1st ed. (May 2010)(―API RP 65 - Part 2 § 4.8.2.1‖).

4 Norman Hyne, Nontechnical Guide to Petroleum Geology, Exploration, Drilling, and Production (Tulsa, 

Oklahoma; PennWell, 2004), 297-328.

5 Nelson and Guillot, eds., Well Cementing, 445. 

6

Ibid, 445. American Petroleum Institute, Technical Report on Selection of Centralizers for Primary 

Cementing Operations , 1st ed. (May 2008)(―API 10TR4 § 2.1‖). Poor centralization can also lead to gas flow 

during the cement job. Gas flow may occur as the cement begins to set. As the cement gels, it no longer 

transmits the full amount of hydrostatic pressure from the fluids above it in the well. This can allow gas to 

flow into the cement, weakening it. Halliburton legal team, interview with Commission staff, July 27, 2010. 

While inadequate centralization can cause both channeling and gas flow, the two effects are different. 
Chief Counsel’s Report — Endnotes | 273

Halliburton legal team, interview with Commission staff, August 17, 2010. Testimony of Jesse Gagliano 

(Halliburton), Hearing before the Deepwater Horizon Joint Investigation Team, August 24, 2010, 416-17.

7

 Nelson and Guillot, eds., Well Cementing, 188.

8

This is a simplified classification of centralizers for the purposes of this section. The API lists seven 

different types of centralizers falling into three main categories. One expert categorized centralizers as being 

of two types, either bow spring or rigid, each of which could be placed in two ways, either as a ―sub‖ screw-on 

or ―slip-on‖ that is secured by stop collars. Steve Lewis (Expert witness), email to Commission staff, October 

14, 2010.

9 Nelson and Guillot, eds., Well Cementing, 137.

10 Ibid., 164.

11 Ibid., 445.

12 Ibid., 446.

13 Testimony of Daniel Oldfather (Weatherford), Hearing before the Deepwater Horizon Joint Investigation 

Team, October 7, 2010, 44-45.

14 Testimony of Steve Lewis (Expert witness), Hearing before the National Commission, November 9, 2010, 

112-13.

15

 BP, Deepwater Horizon Accident Investigation Report (September 8, 2010), 70.

16

 Testimony of Ronnie Sepulvado (BP), Hearing before the Deepwater Horizon Joint Investigation Team, 

July 20, 2010, 72.

17 API RP 65 - Part 2 § 4.8.4.

18 Nelson and Guillot, eds., Well Cementing, 148.

19 The use of an auto-fill tube permits mud to flow up the casing as the casing is lowered. This means ―old 

mud‖ is also inside of the casing, and not only in the annular space. If the crew circulates bottoms up after 

converting the float equipment, the old mud that was inside the casing is forced into the annular space. In 

order to completely purge the system to entirely ―new mud,‖ inside the casing and in the annular space, it is 

necessary to pump new mud ―surface to surface.‖ That is, pump a volume of new mud equal to the volume of 

the casing plus the volume of the annulus.

20 Nelson and Guillot, eds., Well Cementing, 1.

21 American Petroleum Institute, Technical Report on Cement Sheath Evaluation, 2nd ed. (September 

2008), 1 (―API 10TR § 2‖).

22 API 10TR § 2, 1.

23 Testimony of Ronnie Sepulvado, 112.

24 Ibid., 112-13.

25 John Guide (BP), interview with Commission staff, September 17, 2010; Confidential source, interview 

with Commission staff.

26 Lift pressure calculations can provide a rough estimate of the top of cement.

27 Electric line logs are a type of wire line logs which conduct data to the surface as they are run. Tubing 

conveyed logs may also be used, which are logs run on drill pipe, tubing work string, or coiled tubing.

28 ―Cement Bond Log,‖ Schlumberger Oilfield Glossary, 

http://www.glossary.oilfield.slb.com/Display.cfm?Term=cement%20bond%20log.

29 Nelson and Guillot, eds., Well Cementing, 561-63.

30 Ibid.

31 David Johnson and Kathryne Pile, Well Logging in Non-technical Language, 2nd ed. (Tulsa, OK; 

PennWell, 2004), 196.

32 Nelson and Guillot, eds., Well Cementing, 562.

33 Ibid., 583-85.
274 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

34 ―Cement Bond Log,‖ Schlumberger Oilfield Glossary, 

http://www.glossary.oilfield.slb.com/Display.cfm?Term=cement%20bond%20log.

35 Nelson and Guillot, eds., Well Cementing, 583.

36 API 10TR § 10, 75-77.

37 See, e.g., Nelson and Guillot, Well Cementing, 7.

38 Confidential industry expert, interview with Commission staff. 

39 Testimony of Richard Vargo (Halliburton), Hearing before the National Commission, November 8, 2010, 

320. 

40 Nelson and Guillot, eds., Well Cementing, 24-25.

41 American Petroleum Institute, Recommended Practice for Testing Well Cements 10B-2 (2005)(API RP 

10B - Part 2‖).

42 Nelson and Guillot, eds., Well Cementing, 299-300.

43 Internal Transocean document (TRN-USCG-MMS 11597)(April 9, 2010).

44 Internal BP document (BP-HZN-MBI 126338).

45 Ibid.

46 Internal BP document (BP-HZN-MBI 198602).

47 Brett Clanton, ―New tactic might seal leaking well sooner, BP CEO says,‖ Houston Chronicle, May 5, 2010. 

48 Internal Schlumberger document (SLB-EC 1-2); Internal BP document (BP-HZN-MBI 136824)(April 10, 

2010); Internal BP document (BP-HZN-MBI 136829)(April 11, 2010); Internal BP document (BP-HZN-MBI 

136833)(April 12, 2010); Internal BP document (BP-HZN-MBI 136837)(April 13, 2010); Internal BP 

document (BP-HZN-MBI 136841)(April 14, 2010); Internal BP document (BP-HZN-MBI 136845)(April 15, 

2010). Schlumberger ran a ―triple-combo‖ log that measured formation density, porosity and resistivity, 

natural gamma radiation, hole size, and fluid temperature; a combinable magnetic resonance (CMR) tool 

that could estimate the distribution of pore sizes, an elemental capture spectroscopy (ECS) sonde to measure 

formation lithology, an oil-base microimager (OBMI) tool to visualize the formation, a modular formation 

dynamics tester (MDT) tool to collect samples and make pressure measurements, and coring tools to take 

sidewall samples.

49 Internal Transocean document (TRN-USCG_MMS 11626)(April 16, 2010).

50 Testimony of John Guide (BP), Hearing before the Deepwater Horizon Joint Investigation Team, July 22, 

2010, 150.

51 Internal BP document (BP-HZN-MBI 129617).

52 Confidential source, interview with Commission staff.

53 Internal BP document (BP-HZN-MBI 21304).

54 Chapter 4.4 explains that BP may originally have chosen to use nitrogen foamed cement for other reasons.

55 Internal BP document (BP-HZN-MBI 193550).

56 Ibid.

57 Guide, interview, September 17, 2010.

58 A number of BP personnel have suggested or stated that APB was a factor in determining TOC at 

Macondo. David Sims (BP), interview with Commission staff, December 14, 2010; Guide, interview, 

September 17 2010; Confidential source, interview; Erick Cunningham (BP), interview with Commission 

staff, January 19, 2011. BP‘s technical guidance also states that APB may be a factor in determining TOC. 

Internal BP document (BP-HZN-OSC 8007). However, according to Gregg Walz, the engineering team 

leader, APB concerns did not drive TOC or cement volume decisions at Macondo. Gregory Walz (BP),

interview with Commission staff, October 6, 2010. This view is supported by answers Morel received to 

questions about APB concerns. Limiting TOC was not given as a method to mitigate APB. Internal BP 

document (BP-HZN-BLY 66793). 

59 BP, Deepwater Horizon Accident Investigation Report, 54.
Chief Counsel’s Report — Endnotes | 275

60 Internal BP document (BP-HZN-MBI 143300). The Bly report states that the top hydrocarbon zone was 

17,788 feet. BP, Deepwater Horizon Accident Investigation Report, 54. 

61 Internal BP document (BP-HZN-CEC 20234). 

62 Guide, interview, September 17, 2010.

63 BP‘s April 14 Application for Permit to Drill shows TOC at 17,300. Internal BP document (BP-HZN-MBI 

23746). The Bly report states that the TOC was at 17,260 feet. BP, Deepwater Horizon Accident Investigation 

Report, 54.

64 Internal BP document (BP-HZN-MBI 143259).

65 Ibid.

66 Ibid.

67 Ibid.

68 Internal BP document (BP-HZN-MBI 143291). In that comment, Sims also told Hafle: ―Need to change the 

reviewers to Walz, Reiter, Mix and the approvers to Sims, Sprague, Frazelle.‖

69 Internal BP document (BP-HZN-MBI 143292).

70 Internal BP document (BP-HZN-CEC 22667). BP made this decision out of concern that cement above the 

float collar might interfere with logging.

71 Internal Halliburton document (HAL_11002). 

72 Internal BP document (BP-HZN-MBI 143295); Internal BP document (BP-HZN-CEC 22663); BP, 

Deepwater Horizon Accident Investigation Report, 34. 

73 API RP 65 - Part 2 § 4.6.5.2.

74 API RP 65 - Part 2 § 4.6.5.2.

75 Internal BP document (BP-HZN-MBI 127537-39); Internal Halliburton document (HAL_11196).

76 The September 2009 and January 2010 drilling programs called for a minimum of 5 bpm. Internal BP 

document (BP-HZN-CEC 8860)(September 2009 Drilling Program); Internal Transocean document (TRNHCJ 93593)(January 2010 Drilling Program). Later versions reduced the displacement rate. The April 12 

drilling plan called for a minimum of 3 bpm. Internal BP document (BP-HZN-CEC 21265). The April 15 

drilling plan called for pump rates of 2 to 4 bpm. Internal BP document (BP-HZN-CEC 17626-27).

77 Gagliano claimed that Morel made the decision to use foamed cement, though there is conflicting 

information on this point. Internal BP documents (BP-HZN-BLY 61276); Internal BP document (BP-HZNBLY 61294); Confidential source, interview.

78 Internal BP document (BP-HZN-MBI 218202).

79 Ibid.

80 API 10TR4 § 1; American Petroleum Institute, Recommended Practice for Centralizer Placement and 

Stop-collar Testing, Part 2, 1st ed. (August 2004)(―API 10D2 § 4‖). API does set forth a formula to calculate 

standoff ratios, even though it has no specific recommended ratio. API did have a ―minimum standard‖ ratio 

of 67% standoff for performance of casing bow spring centralizers. But that 67% ratio is simply a means to 

help manufacturers produce API-quality centralizers. No centralization standoff ratio standards, or a 

standard for the distance of centralized casing, were found in API RP 10D-2, API Technical Report 10TR4e1 

or the post-blowout Recommend Practice 65. 

81 Internal BP document (BP-HZN-MBI 193557). BP cementing expert Cunningham explained that a 

―distinct permeable zone‖ could be hydrocarbons or water. For Halliburton, Halliburton engineer Gagliano 

stated that ―you view a percentage standoff and usually shoot for about 70 or above for standoff.‖ Jesse 

Gagliano (Halliburton), interview with the U.S. House of Representatives Committee on Energy and 

Commerce, June 11, 2010.

82 Cunningham, interview.

83 Internal BP document (BP-HZN-CEC 8858). BP actually set forth three different formulas in this 

document, but all result in the running of at least 16 centralizers at the eventual total depth of the well. 

Presumably because every joint to 100 feet above the highest ―permeable zone‖ would be centralized, 
276 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

modeling would reflect that this was sufficiently ―centralized pipe.‖ Internal BP documents (BP-HZN-CEC 

8857-58, 8863).

84 Internal Transocean document (TRN-HCJ 93591). 

85 Internal BP document (BP-HZN-MBI 193557). ETP calls for ―centralised pipe‖ 100 feet above permeable

zone. The original 2009 plan called for centralizers every joint to 500 feet above production interval. As 500 

feet above the production interval also happens to be 100 feet above the highest permeable zone, the 2009 

plan appears to comply with BP‘s internal guidance. The January 2010 plan, however, calls for centralizers 

―every other joint‖ after the first five joints (and the first five joints do not reach 100 feet above the highest 

permeable zone). If centralizers ―every other joint‖ reflected sufficient standoff in modeling, this would 

comply. If centralizers ―every other joint‖ did not show sufficient standoff, it would not comply. 

86 Internal BP document (BP-HZN-BLY 66450-51). 

87 Ibid.; Bryan Clawson (Weatherford), interview with Commission staff, October 28, 2010. Clawson told the 

Chief Counsel‘s team that manufacturing normally takes two to three weeks and that rush jobs can be 

completed in just seven to 10 days.

88 Confidential source, interview; Internal BP document (BP-HZN-MBI 126184)(April 12, 2010). No basis 

was given for this decision. A later cement model was prepared that supported this decision, but this was not 

available to the BP team when they decided six centralizers would be sufficient. Internal BP document (BPHZN-MBI 126815). Wells team leader Guide stated that the decision that six centralizers were sufficient was 

made by Morel or Hafle. John Guide, interview with Commission staff, January 19, 2011.

89 Testimony of Brett Cocales (BP), Hearing before the Deepwater Horizon Joint Investigation Team, August 

27, 2010, 89.

90 Internal BP document (BP-HZN-MBI 126815-34); BP, Deepwater Horizon Accident Investigation Report, 

62.

91 Internal BP document (BP-HZN-MBI 126815-34); BP, Deepwater Horizon Accident Investigation Report, 

62.

92 Gagliano, interview. 

93 Ibid.

94 Ibid.; Testimony of Jesse Gagliano, 253; Internal BP document (BP-HZN-MBI 127363). 

95 Cunningham, interview.

96 Testimony of John Guide, July 22, 2010, 87.

97 Internal BP document (BP-HZN-CEC 22433). Walz emailed Guide to tell him of the decision made in his 

absence. 

98 Ibid. This is what Walz meant when he wrote of his decision, ―we needed to be consistent with honoring 

the model.‖ Testimony of Gregory Walz (BP), Hearing before the Deepwater Horizon Joint Investigation 

Team, October 7, 2010, part 1, 164.

99 Testimony of Jesse Gagliano, 129-30; Internal BP document (BP-HZN-BLY 61327).

100 Internal BP document (BP-HZN-MBI 127363).

101 Internal Halliburton document (HAL_10648); Gagliano, interview.

102 Internal BP document (BP-HZN-BLY 61327); Internal Halliburton document (HAL_10604); Internal 

Halliburton document (HAL_10608); Internal Halliburton document (HAL_10713); Internal Halliburton 

document (HAL_10717). Besides assuming different numbers of centralizers, the two modeling runs differed 

in other ways as well; they assumed different standoff values above the centralized casing section and used 

wellbore survey data in different ways.

103 Testimony of Brett Cocales, 267; Gagliano, interview. Cocales was not given instructions regarding what 

type of centralizers to order for the production casing. In a series of phone calls, Clawson told Cocales that 

that there were 32 centralizers (Cocales remembered 31) that were in BP‘s inventory. Clawson also told 

Cocales that these were bow spring centralizers with stop collars. Clawson, interview; Testimony of Brett 

Cocales, 267. Gagliano‘s testimony suggests that his cement models drove the decision to specifically use 15

additional centralizers, rather than the capacity of the helicopter. Gagliano, interview. However, Walz 

stated that he asked Gagliano to run model with 15 additional centralizers after having determined what 

could be procured. Internal BP document (BP-HZN-BLY 61327). 
Chief Counsel’s Report — Endnotes | 277

104 Testimony of Brett Cocales, 216.

105 Many BP personnel believed that the Thunder Horse centralizers had integrated stop collars. Guide, 

interview, September 17, 2010; Confidential source, interview; Internal BP document (BP-HZN-CEC 22433); 

BP, Deepwater Horizon Accident Investigation Report, 63. 

106 Internal BP document (BP-HZN-MBI 127478-80). Gregg Walz stated that he and David Sims looked at 

the schematics and that both interpreted them as having integrated stop collars. Internal BP document (BPHZN-BLY 61328).

107 Internal BP document (BP-HZN-CEC 22433-34).

108 Testimony of Daniel Oldfather, 6-7.

109 Ibid., 6-9, 11. Because the BP team thought that centralizers had an integrated design, they did not realize 

that a box that Weatherford had delivered with the centralizers contained the stop collars. Instead they 

assumed the box contained equipment and tools. For this reason the team did not consider it a problem that 

the box was shipped by boat, even though shipping the stop collars by this slower method defeated the 

purpose of flying the centralizers by helicopter. Internal BP document (BP-HZN-BLY 61328). The 

accessories‘ arrival was delayed and did not arrive at the rig until just before running casing. Internal BP 

document (BP-HZN-CEC 20268).

110 Testimony of Daniel Oldfather, 9-10; Clawson, interview.

111 Confidential source, interview.

112 Ibid. 

113 Internal BP document (BP-HZN-MBI 255668).

114 Ibid.

115 Internal BP document (BP-HZN-CEC 22433).

116 BP, Deepwater Horizon Accident Investigation Report, 63. Guide was concerned about this scenario 

because it recently happened on another well in the Gulf of Mexico. Testimony of John Guide, July 22, 2010, 

373-74. Guide‘s concern was not unique. The API indicates that ―throughout the industry, concerns have 

been expressed regarding every type of centralizer installation.‖ API 10TR4 § 3.9.

117 In explaining the decision not to run additional centralizers, Cocales stated that there was concern over 

the cost involved. He stated to BP investigators that in addition to concern about the centralizers coming off 

in the well, the centralizers were not installed ―due to time required and labor involved.‖ Internal BP 

document (BP-HZN-BLY 61225). Hafle stated that the installation would have taken even longer, from 12 to 

18 hours. Internal BP document (BP-HZN-BLY 61368). However, Walz told investigators that ―time or costs 

were not discussed as a consideration‖ in a phone call with Guide following the order to cancel the 

installation of additional centralizers. Internal BP document (BP-HZN-BLY 61328).

118 Internal BP document (BP-HZN-BLY 61328-29). Guide said that earlier that morning, when everyone 

believed that the centralizers had integrated stop collars but no one was certain when they would arrive, he 

stated that the rig crew could stop operations to wait for their arrival. But Guide was unwilling to wait when 

he learned they had separate stop collars. He explained that the hole can deteriorate while waiting to run 

casing. Given that the hole had already been open for several days of logging, however, it is unclear how 

urgent it was to run the production casing. 

119 Testimony of John Guide, July 22, 2010, 312; Internal BP document (BP-HZN-CEC 22433); Internal BP 

document (BP-HZN-CEC 22666). According to Walz, this type of centralizer had only been used twice 

before. On one of those two occasions, the rig crew had problems as they were running the casing into the 

hole. Internal BP document (BP-HZN-MBI 61328); BP, Deepwater Horizon Accident Investigation Report, 

63.

120 Internal BP document (BP-HZN-MBI 127087).

121 Internal Halliburton document (HAL_10648).

122 Internal BP document (BP-HZN-MBI 128316-17).

123 Confidential source. Morel may have used the 3-D model to make his centralizer placements, but it 

appears he did not receive it until after he had made his final centralizer adjustments to the casing tally. The 

reference to the 3-D model in Morel's correspondence suggests it was only used to argue that 21 centralizers 
278 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

were unnecessary in a straight hole. Internal BP document (BP-HZNMBI 128430-35); Internal BP document 

(BP-HZN-MBI 128316).

124 Internal Halliburton document (HAL_10649); Internal Halliburton document (HAL_10713); Internal BP 

document (BP-HZN-MBI 127087); Internal BP document (BP-HZN-MBI 128316).

125 Internal BP document (BP-HZN-CEC 22669).

126 Testimony of Brett Cocales, 59-60; Testimony of John Guide, October 7, 2010, part 2, 111-12; Testimony 

of Jesse Gagliano, 264, 284; Gagliano, interview.

127 Internal BP document (BP-HZN-CEC 22670).

128 Transocean was not involved in the determination of how many centralizers to use. Testimony of Jimmy 

Harrell (Transocean), Hearing before the Deepwater Horizon Joint Investigation Team, May 27, 2010, 95.

129 Gagliano, interview; Internal BP document (BP-HZN-MBI 128489).

130 Internal BP document (BP-HZN-MBI 128708); BP, Deepwater Horizon Accident Investigation Report, 

64; Testimony of Richard Vargo, 322.

131 Testimony of Gregory Walz, 53-54. Walz also stated that he ―has a vague recollection that Jesse Gagliano 

made an off-hand comment about gas flow potential‖ during that conversation. Internal BP document (BPHZN-BLY 61332).

132 Testimony of Greg Walz, 53-54. Walz stated that his discussions with Guide that morning centered 

around the increased ECD, channeling, the potential for lost circulation and the contingent use of a CBL in 

that event. There was a brief discussion of the ―SEVERE‖ gas flow potential but that they believed the 

foamed cement slurry design would protect against gas migration. Internal BP document (BP-HZN-BLY 

61332). 

133 Testimony of Jesse Gagliano, 331.

134 BP, Deepwater Horizon Accident Investigation Report, 64; Internal Halliburton document 

(HAL_10990).

135 Internal BP document (BP-HZN-MBI 129221); Internal Halliburton document (HAL_11003).

136 BP admits this. BP, Deepwater Horizon Accident Investigation Report, 63.

137 Internal Halliburton document (HAL_11010); Gagliano, interview. 

138 Internal BP document (BP-HZN-MBI 136936)(April 18); Internal BP document (BP-HZN-MBI 136946). 

139 Testimony of Daniel Oldfather, 45.

140 Internal BP document (BP-HZN-MBI 198504).

141 Guide, interview, September 17, 2010.

142 Ibid.

143 Internal BP document (BP-HZN-MBI 129226).

144 Internal BP document (BP-HZN-BLY 62079).

145 Internal BP document (BP-HZN-MBI 137743).

146 Testimony of Steve Lewis, 91.

147 Calculation based on Internal BP document (BP-HZN-MBI 129229).

148 Internal BP document (BP-HZN-MBI 136941). BP‘s Engineering Technical Practices call for rig personnel 

to convert the float equipment before the casing reaches the hydrocarbon zones. Internal BP document (BPHZN-MBI 130799, 130846). However, BP requested a dispensation from MMS from this step in their 

January 2010 well plan, citing the need to reduce surge pressure given the narrow pore pressure and fracture 

gradient at Macondo. Internal Transocean document (TRN-HCJ 93610). 

149 Internal BP document (BP-HZN-MBI 136941).

150 Ibid.

151 Ibid. 
Chief Counsel’s Report — Endnotes | 279

152 Internal BP document (BP-HZN-MBI 128966).

153

 Clawson, interview. According to John Guide, BP wanted to confirm the rated pressure of the float collar 

and check the compressibility of the mud to ensure they were in fact pressuring up against the float collar 

and not another piece of equipment. They verified the compressibility of the mud, which was consistent with 

pressures expected when pressuring up against the float collar. Testimony of John Guide, July 22, 2010, 197.

154

 Clawson, interview. Independent experts understand this recommendation to mean 6,800 psi was the 

highest differential pressure that could safely be applied to the equipment. 

155

 Internal BP document (BP-HZN-MBI 21330). If the ports on the auto-fill tube are completely clogged 

such that there is no circulation, the pressure differential can build up to levels that will cause the brass pins 

in the collar to fail, pushing the ball through the end of the float equipment. Clawson indicated this would 

occur if a pressure differential of 1,300 psi existed. 

156 Internal BP document (BP-HZN-MBI 21330).

157 Internal BP document (BP-HZN-MBI 136941).

158 Internal BP document (BP-HZN-BLY 61364). Kaluza said Guide gave permission to go to 3,000 psi. 

Internal BP document (BP-HZN-MBI 129616). Testimony is inconsistent as to who from the rig was calling 

Guide to discuss problems converting. Both Morel and Kaluza stated they called Guide. However, Guide 

testified he spoke with Morel regarding float conversion. Testimony of John Guide, July 22, 2010, 197.

159 Internal BP document (BP-HZN-MBI 129068).

160 Ibid.

161 Testimony of Nathaniel Chaisson (BP), Hearing before the Deepwater Horizon Joint Investigation Team, 

August 24, 2010, 432. In addition, Gagliano was informed of the multiple conversion attempts, stating that 

―I guess the concern was after the fact that it took so much pressure to convert the float that they may have 

broke something else down or something else happened.‖ Gagliano, interview. 

162 Internal BP document (BP-HZN-MBI 257031).

163 Testimony of Jesse Gagliano, 287.

164 Internal BP document (BP-HZN-MBI 137367).

165 Halliburton cementer Nathaniel Chaisson testified before the U.S. Coast Guard/BOEMRE Joint 

Investigation ―concern was shown by many people on the rig floor.‖ Testimony of Nathaniel Chaisson, 432.

166 Confidential source, interview.

167 Ibid.

168 Testimony of Brett Cocales, 70-71. Maxie Doyle of M-I SWACO reviewed the modeling with John Guide 

and could not estimate pressures as low as those seen on the drill pipe. Doyle later emailed Brett Cocales, 

John Guide, Mark Hafle, Brian Morel, and Gregg Walz and informed them ―I have had several individuals 

double check and critique[] my inputs and still cannot explain the difference.‖ Internal BP document (BPHZN-MBI 129104).

169 Testimony of Brett Cocales, 72; Internal BP document (BP-HZN-MBI 137367); Internal BP document 

(BP-HZN-MBI 136941).

170 Internal BP document (BP-HZN-MBI 136941); Internal BP document (BP-HZN-BLY 61355).

171 Internal BP document (BP-HZN-MBI 137367). 

172 Internal BP document (BP-HZN-MBI 137367).

173 Ibid. Another source indicated 390 psi. Internal BP document (BP-HZN-MBI 136941); Internal BP 

document (BP-HZN-MBI 129616).

174 Internal BP document (BP-HZN-MBI 137367).

175 Ibid.

176 Internal BP document (BP-HZN-MBI 129221). MMS approved a regulatory dispensation that modified 

the standard testing regime for the diverter sealing element at Macondo. Internal BP document (BP-HZN-
280 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

OSC 512). The Chief Counsel‘s team has not found evidence suggesting that this dispensation affected the 

ability of the diverter sealing element. 

177 Internal BP document (BP-HZN-MBI 21304). The rig crew closed the lower annular and pumped down 

the drill pipe, taking returns up the choke and kill lines. They then shut off the pumps and monitored the 

flow line for losses. The rig crew determined the diverter was closed. Internal BP document (BP-HZN-OSC 

4027); Internal BP document (BP-HZN-MBI 136942); Internal BP document (BP-HZN-MBI 21304).

178 Testimony of Nathaniel Chaisson, 432. Morel was similarly unsure how they established circulation. 

Internal BP document (BP-HZN-MBI 129068).

179 Confidential source, interview. The engineers thought upcoming pressure tests after cementing would 

confirm the integrity of the system. During a positive pressure test, additional fluid is pumped into the well, 

which is then sealed and monitored for pressure changes. Constant pressure confirms the casing, seal 

assembly, and BOP do not contain holes or leaks and can therefore hold pressure. But a positive pressure 

test does not confirm the integrity of the casing below the top wiper plug. On April 20 between 10:30 a.m.

and noon, the crew conducted two positive pressure tests, both of which indicated the well was holding 

pressure. A negative pressure test similarly tests the well system for leaks, but the negative pressure test at 

Macondo did not indicate well integrity.

180 Testimony of Brett Cocales, 72-73.

181 Confidential source, interview.

182 Internal BP document (BP-HZN-MBI 129616).

183 API, Recommended Practices for Isolated Potential Flow Zones During Well Construction, part 2, 1st ed. 

(May 2010), 65 (―API RP 65 § 4.8.4‖). The relevant portion of the second edition (§ 5.8.7) is not as 

prescriptive.

184 Gagliano, interview.

185 Steve Lewis (Expert witness), email to Commission staff, November 19, 2010. The precise calculation is 

2,757.2 barrels. 

186 Testimony of Jesse Gagliano, 341-342. The actual pre-cement circulation time took roughly half an hour. 

Ibid., 343.

187 Internal BP document (BP-HZN-CEC 8860); Internal Transocean document (TRN-HCJ 93593). 

188 Internal BP document (BP-HZN-CEC 21445).

189 Internal BP document (BP-HZN-CEC 21265). This pipe capacity equals 883.82 barrels. Internal BP 

document (BP-HZN-CEC 21445).

190 Internal BP document (BP-HZN-CEC 17626).

191 Testimony of John Guide, July 22, 2010, 150.

192 BP legal team, interview with Commission staff, August 9, 2010.

193 Testimony of Gregory Walz, 10-11.

194 Ibid., 11.

195 Testimony of John Guide, July 22, 2010, 150; Guide, interview, September 17, 2010.

196 Testimony of Nathaniel Chaisson, 437-38.

197 Internal BP document (BP-HZN-CEC 21448). This document was prepared on April 17 by BP well site 

leaders Don Vidrine, Bob Kaluza, BP engineer Brian Morel, Halliburton cementer Nathaniel Chaisson, 

Halliburton foam team leader Paul Anderson, and Terry Leblue of Blackhawk. Testimony of Nathaniel 

Chaisson, 436.

198 Testimony of Nathaniel Chaisson, 436.

199 Sperry-Sun data, April 19, 2010, 16:15 – 16:30. When this circulation was established, the rig crew 

believed the float equipment had converted.

200 Internal BP document (BP-HZN-CEC 21448). Halliburton concluded 346 barrels were circulated prior to 

cementing. Sperry-Sun data, April 20, 2010, 19:20. An independent expert calculated a circulation of 
Chief Counsel’s Report — Endnotes | 281

approximately 352.25 bbl; 350 bbl represents the approximate average, 349.125, of these two figures. Steve 

Lewis (Expert witness), email to Commission staff, November 17, 2010. 

201 Internal BP document (BP-HZN-CEC 21448).

202 This volume is also significantly lower than the 4,140 bbl, or 1.5 annular volume, recommended by API. 

The Chief Counsel‘s team disagrees with BP witness testimony indicating the volume pumped at Macondo is 

in accord with the API RP 65. Testimony of Brett Cocales, 209.

203 Internal Halliburton document (HAL_11196-97).

204 Commission calculation based on internal Halliburton document (HAL_11196-97).

205 Commission calculation based on internal Halliburton document (HAL_10994); Lewis, email, November 

19, 2010.

206 API RP 65 §4.8.4.

207 Commission calculation based on internal Halliburton document (HAL_10994); Steve Lewis, email, 

November 19, 2010.

208 Internal BP document (BP-HZN-CEC 8860).

209 Internal Transocean document (TRN-HCJ 93593).

210 Calculated based on internal BP document (BP-HZN-CEC 21445). Using the internal volume calculated 

by independent experts, 900 barrels, 1.5 × pipe volume would be 1,350 bbl.

211 Internal BP document (BP-HZN-CEC 21265).

212 Internal BP document (BP-HZN-CEC 21445). Independent experts calculated total internal volume at 

900 barrels.

213 Internal BP document (BP-HZN-CEC 17626). Independent experts calculated total internal volume at 

900 barrels.

214 Internal BP document (BP-HZN-CEC 21445).

215 Internal BP document (BP-HZN-CEC 21448).

216 Internal BP document (BP-HZN-MBI 137364).

217 Ibid.

218 Internal Halliburton document (HAL_11196-97).

219 Internal BP document (BP-HZN-MBI 137368).

220 39 barrels unfoamed, 48 bbl after foaming. Internal Transocean document (TRN-USCG_MMS 11640); 

Internal BP document (BP-HZN-MBI 137365)

221 Internal BP document (BP-HZN-MBI 137368)

222 Internal BP document (BP-HZN-MBI 137365).

223 Internal BP document (BP-HZN-MBI 137365).

224 Internal BP document (BP-HZN-MBI 129068); Internal BP document (BP-HZN-MBI 137369).

225 Internal BP document (BP-HZN-MBI 137370).

226 Internal BP document (BP-HZN-MBI 139592).

227 Internal BP document (BP-HZN-MBI 21305).

228 Ibid.

229 Cathleenia Willis (Sperry Drilling), interview with Commission staff, October 21, 2010; Testimony of 

Nathaniel Chaisson, 411-12.

230 Internal BP document (BP-HZN-MBI 137370).

231 Guide, interview, September 17, 2010.
282 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

232 Internal BP document (BP-HZN-MBI 137370); Internal BP document (BP-HZN-MBI 129052).

233 Internal Halliburton document (HAL_11208).

234 Internal BP document (BP-HZN-MBI 137370); Internal Halliburton document (HAL_11208). 

235 Internal BP document (BP-HZN-MBI 129052).

236 Internal BP document (BP-HZN-MBI 129141).

237 Internal BP document (BP-HZN-MBI 129055).

238 Testimony of John Guide, July 22, 2010, 321-22.

239 Testimony of Steve Lewis, 110-11.

240 Testimony of Vincent Tabler (Halliburton), Hearing before the Joint Investigation Team, August 25, 

2010, 21-22.

241 Confidential source, interview; Internal BP document (BP-HZN-CEC 21449).

242 Internal BP document (BP-HZN-CEC 20234); Testimony of Vincent Tabler, 21-22.

243 Testimony of Vincent Tabler, 22, 33-34. 

244 Testimony of Vincent Tabler, 21-22; Confidential source, interview; Internal BP document (BP-HZN-CEC 

21449); Internal BP document (BP-HZN-CEC 20234).

245 Internal BP document (BP-HZN-MBI 136947).

246 Internal BP document (BP-HZN-MBI 143304); Internal BP document (BP-HZN-CEC 21665).

247 BP‘s decision tree is based on the MMS regulation about cement bond logs. 30 C.F.R. § 250.428 states 

that if ―you encounter...lost returns, cement channeling, or failure of equipment...[t]hen you must (1) 

Pressure test the casing shoe; (2) Run a temperature survey; (3) Run a cement bond log; or (4) Use a 

combination of these techniques.‖ BP‘s decision tree meets that regulation and was apparently designed in 

light of it. Gagliano, interview. However, the decision tree violates another provision of the MMS regulations. 

30 C.F.R. § 250.421 requires that cement be at least 500 feet above a pay zone. Here, BP‘s decision tree 

permitted the cement to be as little as 100 feet above the pay zone.

248 Randy Ezell (Transocean), interview with Commission staff, September 16, 2010. Gagliano agreed with 

this focus, stating that ―it was critical that we design the cement job to have full returns because of the fact 

that if we lost returns during the cement job, they would have to run a cement bond log to see where the top 

of the cement was and then potentially remediation would be required.‖ Gagliano, interview.

249 Internal BP document (BP HZN CEC 21288); Internal BP document (BP-HZN-MBI 255705).

250 Testimony of Ronnie Sepulvado, 21; Internal BP document (BP-HZN-MBI 126867).

251 Confidential source, interview with Commission staff.

252 Internal BP document (BP-HZN-MBI 127104).

253 Internal BP document (BP-HZN-MBI 126867). 

254 Internal BP document (BP-HZN-MBI 127104).

255 Internal Schlumberger document (SLB-EC 02); Internal Transocean document (TRN-USCG_MMS 

30414)(April 18, 2010); Internal Transocean document (TRN-USCG_MMS 30422)(April 19, 2010).

256 Testimony of Vincent Tabler, 23.

257 Testimony of John Guide, July 22, 2010, 43-44. According to Walz, who was on the call, Guide noted that 

the indications that they had met their plan and that the CBL had only been a contingency. ―Guide concluded 

that there was no reason to run the CBL and [everyone] on the call agreed.‖ Internal BP document (BP-HZNBLY 61333).

258 Internal Schlumberger document (SLB-EC 02).

259 Confidential source, interview with Commission staff.
Chief Counsel’s Report — Endnotes | 283

260 Testimony of Mark Bly (BP), Hearing before the National Commission, November 8, 2010, 326; 

Testimony of Bill Ambrose (Transocean), Hearing before the National Commission, November 8, 2010, 326; 

Testimony of Richard Vargo, 326.

261 Greg Meeker (USGS), interview with Commission staff, January 27, 2011.

262 Craig Gardner (Chevron), letter to Commission staff, October 26, 2010. 

263 Testimony of Richard Vargo, 331; Testimony of Jesse Gagliano, 321, 337. 

264 Testimony of Richard Vargo, 329, 355.

265 Many would dispute the assumption the model is accurate. Testimony of John Guide, July 22, 2010, 275.

Gagliano stated that BP ―questioned the validity of the model.‖ Testimony of Jesse Gagliano, 386. BP‘s 

cementing specialist Erick Cunningham stated that there are limitations to all such models and that their 

results always require the application of sound engineering judgment. Cunningham, interview. Moreover, 

had BP run the cement job on the basis of the 21-centralizer design April 18 model, BP would apparently 

have relied on the model‘s inaccuracy. That model predicted that the final two barrels of the cement job 

would have exceeded the fracture gradient. Internal BP document (BP-HZN-BLY 61327). For that reason, 

Walz alluded to disagreement over the accuracy of the model. Internal BP document (BP-HZN-CEC 22433). 

266 BP, Deepwater Horizon Accident Investigation Report, 65.

267 Ibid, 35. Internal BP document (BP-HZN-CEC 8858); Internal BP document (BP-HZN-CEC 8858); 

Internal Transocean document (TRN-HCJ 9351); Internal Transocean document (TRN-HCJ 93526). 

268 One of BP‘s representatives stated that Halliburton‘s cement modeling was little more than a marketing 

tool. 

269 Internal BP document (BP-HZN-MBI 136849).

270 Testimony of John Guide, July 22, 2010, 289. 

271 Halliburton observes circulating full bottoms up is a Halliburton ―best practice.‖ Testimony of Jesse 

Gagliano, 263. 

272 BP, Deepwater Horizon Accident Investigation Report, 66.

273 Confidential source, interview.

274 Internal BP document (BP-HZN-MBI 143295); Internal BP document (BP-HZN-CEC 22663); see also

Guide, interview, September 17, 2010; Internal BP document (BP-HZN-CEC 22666). In the April 14 meeting 

discussing the design of the cement job however, neither BP nor Halliburton raised concerns about the 

volume of cement to be used. Internal BP document (BP-HZN-BLY 61326). 

275 BP, Deepwater Horizon Accident Investigation Report, 67. At the same time, BP‘s cementing engineer 

pointed out that there was little additional volume that could have been added. The TOC was reasonably 

close to the previous casing string and the entire annular volume was nearly full of cement. Nevertheless, the 

design would have been different had the well constraints been different. Cunningham, interview. 

276 Gagliano indicated that BP told him to keep ECD below 14.7 ppg. In order to do that the pump rate 

needed to be 4 bbl per minute or less. Testimony of Jesse Gagliano, 282; Testimony of Richard Vargo, 345-

46. One expert estimates the cement flow rate could have been up to twice as fast as the rate pumped at 

Macondo. Steve Lewis (Expert witness), email to Commission staff, October 21, 2010. 

277 Testimony of Jesse Gagliano, 283-284.

278 Confidential sources, interviews with Commission staff; Testimony of Tommy Roth (Halliburton), 

presentation to the National Academy of Engineering, September 26, 2010.

279 Internal BP document (BP-HZN-MBI 117537). 

280 Guide, interview, September 17, 2010.

281 Ibid.; Internal BP document (BP-HZN-CEC 21261). 

282 Testimony of Jesse Gagliano, 259. 

283 Both BP and Transocean personnel testified that additional pressure and multiple attempts at conversion 

are not unusual, particularly where equipment is clogged with debris. John Guide had previously 

experienced cuttings getting stuck between the ball and the tube, and believed this required applying 
284 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

additional pressure. Testimony of John Guide, July 22, 2010, 147-48. Transocean offshore installation 

manager (OIM) Jimmy Harrell stated he was not concerned with additional pressure and that it is not usual 

that several attempts at higher pressures were needed to convert. Testimony of Jimmy Harrell, 85, 122. And 

Transocean senior toolpusher Randy Ezell also stated that the applied pressures were not too high due to 

debris that needed to be cleared. Ezell, interview. Another failure mode could be created by interference of 

the diverter ball, though this seems unlikely. After the casing is installed, the rig crew drops a 1.625-inch

brass ball to close the hole, which closes the diverter gate and seals the inside of the casing from the annular 

space. The ball eventually lands on the float equipment. Email communications indicate the rig crew 

considered this scenario. It appears unlikely the diverter ball prevented conversion, as even with the diverter 

ball there would be more than 2 inches of space for fluid to circulate around the ball and through the float 

equipment. Internal BP document (BP-HZN-MBI 127277). BP‘s post-blowout tests simulated the diverter 

ball on top of the float equipment. BP tests where the Allamon ball was on top of the float collar established 

circulation at 3,210 psi and the float equipment converted at 11.5 bpm in the subsequent flow surge. Internal 

BP document (BP-HZN-BLY 62214-15). 

284 Internal BP document (BP-HZN-CEC 8860).

285 Internal Transocean document (TRN-HCJ 93593).

286 Internal BP document (BP-HZN-CEC 21265).

287 Internal BP document (BP-HZN-CEC 17626).

288 Internal BP document (BP-HZN-MBI 129226-32).

289 Commission calculation based on internal BP document (BP-HZN-MBI 129229); Lewis, email, October 

21, 2010. Evidence has indicated mud weight as both 14.0 or 14.17 ppg. For purposes of this calculation, an 

independent expert used a mud weight of 14.1 ppg. A mud weight in this range would require a flow rate of 

approximately 6 bpm to create a differential pressure of approximately 600 psi to convert the float 

equipment. 

290 Lewis, email, October 21, 2010; Testimony of Steve Lewis, 95.

291 Testimony of Steve Lewis, 93.

292 Internal BP document (BP-HZN-MBI 136941). 

293 Testimony of Steve Lewis, 96; BP, Deepwater Horizon Accident Investigation Report, 70.

294 Commission calculation based on internal BP document (BP-HZN-MBI 129229).

295 Stress Engineering conducted performance tests including flow endurance tests, steady-state flow 

conversion tests, flow-surge conversion tests, flow-surge tests on already converted float equipment, and 

mechanical failure tests of auto-fill tubes. Internal BP document (BP-HZN-BLY 62187).

296 Internal BP document (BP-HZN-BLY 62156).

297 Internal BP document (BP-HZN-MBI 136941).

298 Internal BP document (BP-HZN-BLY 62087). Stress Engineering could not simulate field conditions of 

the surge accurately enough for results to be conclusive. Internal BP document (BP-HZN-BLY 62066).

299 Testimony of Steve Lewis, 112-13.

300 BP, Deepwater Horizon Accident Investigation Report, 71. So does wells team leader John Guide, who 

stated that the team could have been fooled that the floats held because the u-tube pressure during the check 

was so low. Guide, interview, January 19, 2011.

301 Internal Halliburton document (HAL_11004). The Chief Counsel‘s team‘s expert calculated an even lower 

pressure differential. Based on figures in the final cement plan, fluids inside the casing and in the annulus 

may have been in almost perfect balance with only a 0.8 psi differential. Steve Lewis (Expert witness), email 

to Commission staff, December 14, 2010.

302 Lewis, email, December 14, 2010.

303 Testimony of Daniel Oldfather, 49.

304 Testimony of Steve Lewis, 110.

305 Internal BP document (BP-HZN-MBI 137753).
Chief Counsel’s Report — Endnotes | 285

306 Internal BP document (BP-HZN-MBI 21304).

307 Ronnie Sepulvado (BP), interview with Commission staff, August 20, 2010.

308 An obstruction in the reamer shoe could cause pressure to be the same above and below the auto-fill tube, 

which would mean there would be insufficient differential pressure to dislodge the tube.

309 Testimony of Richard Sears, Hearing before the National Commission, November 9, 2010, 324.

310 Internal BP document (BP-HZN-MBI 21330).

311 According to BP‘s John Guide, he and Brian Morel did not discuss this possibility. Testimony of John 

Guide, October 7, 2010, 179-80.

312 Testimony of Steve Lewis, 99; Clawson, interview.

313 BP, Deepwater Horizon Accident Investigation Report, 70.

314 Testimony of Steven Robinson (BP), Hearing before the Joint Investigation Team, December 8, 2010, 

part 1, 39-40; Guide, interview, September 17, 2010. There is some disagreement as to whether float 

equipment constitutes a barrier. An expert retained by the Commission considers float equipment a barrier, 

but only to its pressure rating. Steve Lewis (Expert witness), interview, September 15, 2010. 

315 Clawson, interview.

316 API RP 65 - Part 2 §4.4.3.

317 API RP 65 - Part 2 §3.4.

318 Testimony of John Guide, July 22, 2010, 289.

319 Ezell, interview; Testimony of Jimmy Harrell, 95.

320 Internal BP document (BP-HZN-CEC 22670).

321 Joseph Leimkuhler (Shell), letter to Commission staff, September 22, 2010.

322 BP‘s own report appears to agree that better risk identification and assessment would have helped avoid 

the accident. The Bly report states that a ―formal risk assessment might have enabled the BP Macondo well 

team to identify further mitigation options to address risks....‖BP, Deepwater Horizon Accident 

Investigation Report, 36; Testimony of Mark Bly, 345.

323 Internal BP document (BP-HZN-CEC 17626)(April 15 Drilling Program).

324 Testimony of Steve Lewis, 103; Steve Lewis, email, October 31, 2010.

325 Clawson, interview. 

326 Ibid. BP would have known of the need for 7-inch centralizers at the time they decided to run a 97⁄8-inch

liner. That liner was specified nearly a week earlier in the March 25 APD that BP filed to MMS. Steve Lewis

(Expert witness), email to Commission staff, January 1, 2011; Internal BP document (BP-HZN-MBI 23666). 

When asked by BP investigators why he did not order additional centralizers at the time the APD was 

submitted, Walz stated that he could not recall any specific discussion about centralizers but thought he ―had 

a conversation with Brian Morel about ordering what they normally ordered.‖ Internal BP document (BPHZN-BLY 61329). Morel promptly ordered other 7-inch casing equipment but not centralizers. On March 25, 

for instance, he asked a BP materials coordinator, ―Can you have (2) cross-over made for 7‖ x 9-7/8‖ with a 

rush on it (2 weeks or less)?‖ Internal BP document (BP-HZN-BLY 64818).

327 Confidential source, interview. The ―7-10‖ range was generated within the BP drilling team based on a 

rough estimate for what was needed to cover the pay zone given hole conditions. But it is unclear why the 

goal of the well plan or the well conditions would have been any different than when the original plan was 

designed.

328 Weatherford sales representative Bryan Clawson indicated that in the case of BP‘s final production

casing, Weatherford would have been able to manufacture additional centralizers in time, had they been 

promptly asked. Clawson, interview. Other BP rig well teams faced simultaneous centralizer needs that 

Weatherford could not fill, and approached other suppliers. Internal BP document (BP-HZN-MBI 252278).

329 The Bly report states that the Macondo team ―erroneously believed they had received the wrong 

centralizers.‖ BP, Deepwater Horizon Accident Investigation Report, 63. This statement is ambiguous. The 

well team ―erroneously believed‖ that it had ordered one-piece centralizers and therefore did not expect to 
286 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

receive centralizers with separate stop collars. But the team was correct to conclude that the centralizers 

Weatherford shipped were not, in fact, one-piece centralizers.

330 Internal BP document (BP-HZN-MBI 255906). The ―flying by the seat of our pants‖ quote was apparently 

made by well site leader Vidrine, who was concerned that with all of the special deliveries, crucial pieces 

might be missing for operations. Guide believed that the logistics changes were making things much more 

difficult on the well site leaders. Guide, interview, January 19, 2011.

331 BP, Deepwater Horizon Accident Investigation Report, 63. By contrast, BP had decided to use a long

string using a management of change process—and that management of change process had been based on a 

70% standoff ratio. Internal BP document (BP-HZN-BLY 61198).

332 Testimony of Daniel Oldfather, 9-15. Oldfather had installed centralizers on 10 different occasions, and at 

no time had centralizers gotten hung up in the well. He had heard of other jobs, with different types of 

centralizers, where the centralizers had been damaged. Testimony of Daniel Oldfather, 67, 72. In his defense, 

Guide notes that his personal experience is based on running hundreds of casing strings. Guide, interview, 

January 19, 2010.

333 BP, Deepwater Horizon Accident Investigation Report, 63.

334 Testimony of Jesse Gagliano, 295; Testimony of Gregg Walz, 71.

335 BP, Deepwater Horizon Accident Investigation Report, 64. As discussed, however, the cement modeling 

was rerun on Halliburton‘s initiative.

336 Testimony of John Guide, July 22, 2010, 275.

337 Internal BP document (BP-HZN-CEC 22666).

338 Testimony of Daniel Oldfather, 12. 

339 Ibid., 57.

340 Ibid., 14.

341 Gagliano, interview.

342 Ibid.

343 Testimony of Jesse Gagliano, 259; Internal BP document (BP-HZN-MBI 128489). 

344 If the rig crew believed the gauge was inaccurate, they could have compared pressure readings from that 

gauge to other sources of drill pipe pressure readings on the rig. Rigs typically have several different drill 

pipe pressure gauges, including electronic and analog gauges. The rig crew could have also observed drill 

pipe pressure on gauges at the cementing unit. Darryl Bourgoyne, email to Commission staff, January 1, 

2011.

345 Testimony of Steve Lewis, 105. However, applying back pressure can be undesirable for other reasons. 

Nelson and Guillot, eds., Well Cementing, 366.

346 Ronnie Sepulvado (BP), interview with Commission staff, September 1, 2010.

347 Internal BP document (BP-HZN-MBI 193558).

348 Ibid.

349 Guide, interview, September 17, 2010.

350 When asked by BP investigators if he was aware of BP‘s technical guidance regarding lift pressures, Walz 

stated that at the time he ―didn‘t make the connection‖ but now ―understands that the mud weight 

differentials were not high enough to get a valid confirmation of good cement placement. Internal BP 

document (BP-HZN-BLY 61332). 

351 Confidential industry experts, interview with Commission staff. 

352 Steve Lewis (Expert witness), interview with Commission staff, September 21, 2010.

353 Richard Sears (Expert witness), email to Fred Bartlit, September 20, 2010; Confidential industry experts, 

interviews.
Chief Counsel’s Report — Endnotes | 287

354 BP, Deepwater Horizon Accident Investigation Report, 36. BP investigator Mark Bly elaborated that 

using those criteria, ―in hindsight, those could have caused the team to think a bit more carefully about it.‖ 

Testimony of Mark Bly, 202-03, 375.

355 Internal BP document (BP-HZN-MBI 195582).

356 See, e.g., Steve Lewis (Expert witness), email to Commission staff, October 13, 2010. Not surprisingly, 

Halliburton has stated since the blowout that a cementing operation cannot be successfully concluded 

without performing a cement bond log. Testimony of Richard Vargo, 318-19, 321.

357 Gregg Walz, interview with Commission staff, October 16, 2010.

358 Gagliano, interview; Testimony of Jesse Gagliano, 270-71; Nelson and Guillot, eds., Well Cementing, 583.

359 See, e.g., Tommy Roth (Halliburton), House Energy and Commerce Committee Staff Briefing, June 3, 

2010; Testimony of Tommy Roth, presentation to NAE; Testimony of Richard Vargo, 325.

360 Testimony of Gregg Walz, 53-54.

361 Gagliano, interview.

362 Ibid.

363 Testimony of Jesse Gagliano, 335, 360.

364 Gagliano interview. Gagliano stated that ―I was never directly involved with those conversations. That‘s 

usually a decision made by BP. I was in a room when some of those conversations took place, but they 

weren‘t actually talking directly to me. So I have really no decision in that.‖ Ibid.

365 Testimony of Nathaniel Chaisson, 432.

366 Testimony of Jesse Gagliano, 249-50; Testimony of Nathaniel Chaisson, 442.

367 Internal Halliburton document (HAL_11010). One Macondo well site leader, for instance, did not know 

that the jagged lines indicated channeling. The report did indicate a ―SEVERE‖ potential for gas flow, which 

while not an indication of channeling, can be a product of insufficient centralization.

368 Testimony of Ronnie Sepulvado, 133; Murry Sepulvado, interview with Commission staff, December 10, 

2010.

369 Testimony of Nathaniel Chaisson, 440. In addition, the Halliburton post-job report indicated that the 

TOC was at 17,300 feet, where it would have been expected without any channeling. Internal Halliburton 

document (HAL_11195). However, Halliburton has indicated that this figure is a ―volumetric calculation‖ 

designed simply to reflect full returns and was not an ―engineering analysis.‖ Halliburton legal team, 

interview with Commission staff, September 18, 2010.

Chapter 4.4

1

Erik B. Nelson and Dominique Guillot, eds., Well Cementing, 2nd ed. (Sugar Land, TX: Schlumberger,

2006), 256.

2

Ibid, 256. ―Pounds per gallon‖ (ppg) units are used here for consistency rather than the more technically 

precise ―pounds-mass per gallon‖ (lbm/gal). 

3

Jean de Rozieres and Remi Ferriere, ―Foamed Cement Characterization Under Downhole Conditions and 

Its Impact on Job Design,‖ SPE Production Engineering (August 1991), 298.

4

S.L. Pickett and S.W. Cole, ―Foamed Cementing Technique for Liners Yields Cost-Effective Results,‖ 

Society of Petroleum Engineers 27679 (1994), 521-24. ―Failure to stabilize foam will...cause the [nitrogen] 

bubbles to coalesce and form interconnected flow paths.‖ Ibid., 523-24. 

5 D.S. Kulakofsky, P.G. Creel, and D.L. Kellum, ―Techniques for Planning and Execution to Improve Foam

Cement Job Performance,‖ Society of Petroleum Engineers 15519 (1986), 1-2.

6 Michael T. Olanson, ―Application of Foam Cements in Alberta,‖ Journal of Canadian Petroleum 

Technology (October 1985), 51.
288 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

7 N.R. Loeffler, ―Foamed Cement: A Second Generation,‖ Society of Petroleum Engineers 12592 (1984), 2. 

―[A]ccurate foam slurry design as confirmed by laboratory testing is an indispensable prerequisite to 

effective placement design engineering.‖ Ibid.

8

American Petroleum Institute, Recommended Practice on Preparation and Testing of Foamed Cement 

Slurries at Atmospheric Pressure 10b-4 (July 2004)(―API RP 10b-4‖).

9

Ibid., § 9.3.4.

10 BP and Halliburton used foamed cement on the 28-inch casing and the 22-inch casing. Internal BP 

document (BP-HZN-OSC 603); Internal BP document (BP-HZN-MBI 14118); Internal BP document (BPHZN-MBI 14193). 

11 Internal Halliburton document (GOM foamed cement jobs).

12 Erick Cunningham (BP), interview with Commission staff, January 17, 2011.

13 Ibid.; Internal BP document (BP-HZN-BLY 61276).

14 Internal BP document (BP-HZN-MBI 218202).

15 Jesse Gagliano (Halliburton), interview with Commission staff, September 10, 2010. 

16 Ibid. 

17 The February recipe included more retarder than the final recipe because in February BP expected 

Macondo to be a hotter well than it eventually proved to be. High well temperatures increase the speed at 

which cement cures. And if cement cures prematurely, it may become impossible to pump before it reaches 

the bottom of the well. One way to solve this problem is by adding retarder to the cement recipe. 

18 Internal Halliburton document (HAL_DOJ 61-62, 67-68).

19 Confidential industry expert, interview with Commission staff.

20 Internal BP document (BP-HZN-MBI 109218, 109223-24).

21 Internal BP document (BP-HZN-MBI 117603).

22 Ibid.

23 Gagliano, interview; Internal Halliburton document (HAL DOJ 35).

24 Gagliano, interview.

25 Internal Halliburton document (HAL DOJ 35-36).

26 Halliburton contends that its lab personnel performed this April 13 test improperly. Donald Godwin 

(Halliburton), letter to Commission staff, November 18, 2010.

27 Internal BP document (BP-HZN-OSC 6224).

28 Internal BP document (BP-HZN-MBI 128542).

29 Internal BP document (BP-HZN-BLY 47095).

30 Ibid.

31 Internal BP document (BP-HZN-OSC 6224).

32 Internal Halliburton document (HAL DOJ 42-43).

33 API RP 10b-4 § 7.2(j).

34 Internal Halliburton document (HAL DOJ 43). Cement laboratories routinely process samples around the 

clock in response to the intense time pressures in the drilling industry.

35 Donald Godwin (Halliburton), letter to Commission staff, January 7, 2011, 2. 

36 Halliburton document (presentation to the National Academy of Engineers, September 26, 2010), 7. ―The

foam slurry was transferred to a stability test cell and cured for 48 hours.‖ Ibid.

37 Internal BP document (BP-HZN-MBI 136947).
Chief Counsel’s Report — Endnotes | 289

38 Testimony of Richard Vargo (Halliburton), Hearing before the National Commission, November 8, 2010, 

367-68.

39 Donald Godwin (Halliburton), letter to Commission staff, January 10, 2011, 1; Godwin, letter, January 7, 

2011, 2.

40 Godwin, letter, January 10, 2011, 2.

41 Godwin, letter, January 7, 2011, 2.

42 Internal BP document (BP-HZN-MBI 171151).

43 BP, Deepwater Horizon Accident Investigation Report (September 8, 2010), 55-60, 66-68.

44 BP, Deepwater Horizon Accident Investigation Report, 58. At the time BP issued its report, it was only 

aware of the results of the final April foam stability test conducted by Halliburton on or about April 18. BP 

apparently had not yet realized that its personnel had also received testing data from Halliburton on March 

8, let alone that Halliburton had not reported the results of two foam stability tests to BP at all.

45 Ibid, app. K.

46Ibid, 59.

47Ibid, 60.

48 Craig Gardner (Chevron), letter to Commission staff, October 26, 2010.

49 Donald Godwin (Halliburton), statement to Commission staff, October 12, 2010.

50 Gardner, letter, 2.

51 Confidential industry experts, interviews with Commission staff.

52 Testimony of Richard Vargo, 360-61.

53 Godwin, letter, November 18, 2010. 

54 Fred Bartlit, letter to Donald Godwin, November 23, 2010.

55 American Petroleum Institute, Recommended Practice for Testing Well Cements 10b-2 (January 

2007)(―API RP 10b-2‖).

56 Bartlit, letter, November 23, 2010.

57 Confidential industry experts, interviews.

58 Nelson and Guillot, eds., Well Cementing, 257.

59 Internal BP document (BP-HZN-MBI 171151).

60 Testimony of Richard Vargo, 362.

61 Press Release, Halliburton, Halliburton Comments on National Commission Cement Testing, October 28, 

2010; Godwin, letter, November 18, 2010.

62 Testimony of Richard Vargo, 363. Halliburton expert Richard Vargo admitted that ―based on those 

[February] results, I would not have, at that time on February 17th, chosen to run that [design] in the well.‖

Ibid. 

63 Ibid., 366.

64 Godwin, letter, November 18, 2010; Donald Godwin (Halliburton), letter to Commission staff, December 

9, 2010 (citing HAL DOJ 35, 41, 44).

65 If the latter is true, the Chief Counsel believes that Halliburton personnel may have been motivated in part 

by the fact that a slurry redesign could have required Halliburton to discard the dry blend that was on the 

Deepwater Horizon and deliver a new dry blend to the rig. That process might have cost time and money—

especially if Halliburton first realized the problem just before pumping the job.

66 Internal BP document (BP-HZN-MBI 130830); Internal BP document (BP-HZN-OSC 6225). 

67 Internal BP document (BP-HZN-MBI 117603); Internal BP document (BP-HZN-MBI 6225).

68 Internal BP document (BP-HZN-MBI 255509). 
290 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

69 Internal BP document (BP-HZN-MBI 128542).

70 Internal BP document (BP-HZN-BLY 47093-95).

71 Internal BP document (BP-HZN-MBI 257237).

72 Internal BP document (BP-HZN-MBI 218202).

73 Internal BP document (BP-HZN-OSC 6224).

74 BP, Deepwater Horizon Accident Investigation Report, 68. ―The investigation team saw no evidence that 

the BP Macondo well team confirmed that all relevant lab test results had been obtained and considered by 

the Halliburton in-house cementing engineer before cement placement proceeded.‖ Ibid.

75 Testimony of Mark Bly (BP), Hearing before the National Commission, November 8, 2010, 388.

76

 BP‘s own report admits that ―stronger quality assurance by the BP Macondo well team might have 

identified potential flaws and weaknesses in the slurry design.‖ BP, Deepwater Horizon Accident 

Investigation Report, 68.

77 Internal BP document (BP-HZN-MBI 110151).

78 John Guide (BP), interview with Commission staff, January 19, 2011.

79 Cunningham, interview.

80 Ibid.

81 Internal BP document (BP-HZN-OSC 9337).

Chapter 4.5

1

BP, Deepwater Horizon Accident Investigation Report (September 8, 2010), 72.

2

30 C.F.R. § 250.1721.

3

BP repeated the explanation in its internal investigation report, framing certain steps as ―required,‖ 

without critically analyzing or questioning them. BP, Deepwater Horizon Accident Investigation Report, 72.

―To install the lockdown sleeve, 100,000 lbs of weight was required on the running tool. This required 

approximately 3,000 ft. of drill pipe to be run below the running tool. Allowing for this length of drill pipe 

determined the final cement plug setting depth. In turn, the cement plug setting depth 3,000 ft. below the 

wellhead influenced the differential pressure created during the negative-pressure test.‖ Ibid.

4

John Guide (BP), interview with Commission staff, January 19, 2011; Gregory Walz (BP), interview with 

Commission staff, October 6, 2010; Confidential source, interview with Commission staff; Testimony of Ross 

Skidmore (Swift), Hearing before the Deepwater Horizon Joint Investigation Team, July 20, 2010, 61.

5

Testimony of Ronnie Sepulvado (BP), Hearing before the Deepwater Horizon Joint Investigation Team, 

July 20, 2010, 145; BP, Deepwater Horizon Accident Investigation Report, 72; Confidential source, 

interview; Guide, interview, September 17, 2010.

6

Skidmore, interview; Testimony of Ross Skidmore, 248-49; Walz, interview; Ronnie Sepulvado, interview; 

David Sims (BP), interview with Commission staff, December 14, 2010; Testimony of John Guide (BP), 

Hearing before the Deepwater Horizon Joint Investigation Team, July 22, 2010, 299.

7 Guide, interview, September 17, 2010; Ronnie Sepulvado, interview; Testimony of Mark Bly (BP), Hearing 

before the National Commission, November 8, 2010, 210, 310. A February 11 email discussing an earlier 

surface plug at Macondo suggests that even that plug ―was set in seawater to prevent contamination.‖ 

Internal BP document (BP-HZN-MBI 196335).

8 Ronnie Sepulvado, interview. BP explained this in a filing with the MMS. Internal BP document (BP-HZNMBI 127909). ―The requested surface plug depth deviation is for minimizing the chance for damaging the 

LDS sealing area.‖ Ibid.

9

BP‘s temporary abandonments of previous wells bear this out, as do interviews with several BP engineers. 

Internal BP document (BP-HZN-OSC 6083); Internal BP document (BP-HZN-OSC 6158); Murry Sepulvado 

(BP), interview with Commission staff, December 10, 2010; Ross Skidmore (Swift), interview with 
Chief Counsel’s Report — Endnotes | 291

Commission staff, December 21, 2010; John Guide (BP), interview with Commission staff, September 17, 

2010.

10 Ronnie Sepulvado (BP), interview with Commission staff, October 26, 2010; Merrick Kelley (BP), 

interview with Commission staff, October 22, 2010.

11 Murry Sepulvado, interview; Skidmore, interview; Guide, interview, September 17, 2010; Kelley, interview.

12 Kelley, interview; Internal BP document (BP-HZN-OSC 112833); Internal BP document (BP-HZN-OSC 

113043).

13 Internal BP document (BP-HZN-MBI 119062).

14 Ibid.

15 Ibid.

16 Internal BP document (BP-HZN-MBI 100448).

17 Ibid.

18 Internal BP document (BP-HZN-MBI 100447).

19 Internal BP document (BP-HZN-MBI 100445-46). ―5.5 rig days at $400,000 = $2,200,000.‖ Ibid.

20 Internal BP document (BP-HZN-MBI 100446). 

21 In early January, Hafle inquired: ―I was told the LDS could be installed off critical path with an 

intervention type vessel. Is this possible?‖ Kelley responded: ―We are building the necessary components to 

convert the Thunderhorse open water tool for use on a H-4 wellhead at present. We plan to use this tool for 

the Isabela LDS mid this year. Not sure how successful we will be but will have to rely on the rig as a 

contingency if necessary.‖ Internal BP document (BP-HZN-MBI 100447).

22 Internal BP document (BP-HZN-MBI 100446). ―For the open water cost of installing the 

LDS...$480,000.‖ Ibid. ―If you do it with the rig at the time of the original drilling...$600,000.‖ Ibid.

23 Ibid. ―The risk you are exposed to is if the LDS does not land out correctly or the nose seals are damaged 

and the LDS has to be retrieved (can happen but has not happened to us in the past 5 years).‖ Ibid.

24 Ibid.

25 Internal BP document (BP-HZN-MBI 127907). 

26 Internal BP document (BP-HZN-MBI 119061). 

27 Ibid.

28 Internal BP document (BP-HZN-MBI 199123).

29 Internal BP document (BP-HZN-MBI 126145).

30 Ibid.

31 Internal BP document (BP-HZN-MBI 199123). 

32 Internal BP document (BP-HZN-MBI 126333).

33 Ibid. The next day, Morel forwarded Kelley‘s email to Gregg Walz. Ibid.

34 Internal BP document (BP-HZN-MBI 126450).

35 Internal BP document (BP-HZN-MBI 126495).

36 BP‘s internal investigator acknowledges that there were multiple changes in plan. Testimony of Mark Bly, 

305.

37 Internal BP document (BP-HZN-MBI 199122).

38 Internal BP document (BP-HZN-MBI 126180); Internal BP document (BP-HZN-MBI 126189-90).

39 Internal BP document (BP-HZN-MBI 126585-86).

40 Internal BP document (BP-HZN-MBI 126982). BP has asked the Commission to disregard this procedure 

because, among other reasons, it was an email sent to a rig clerk (rather than the engineering team). 
292 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

However, it was also sent to one of the well site leaders on the rig, Ronnie Sepulvado, and Morel specifically 

asked for feedback on the procedure.

41 Internal BP document (BP-HZN-MBI 126982).

42 Ibid.

43 Internal BP document (BP-HZN-BLY 61203).

44 Internal BP document (BP-HZN-CEC 21281, 21288). Transocean has claimed that conducting a negative 

pressure test on the shoe track rather than the cement plug is unusual. In the January 2010 abandonment of 

the Kodiak well, for instance, the negative pressure test was not done until the cement plug was set. Given 

the risk factors associated with the production casing cement job, it was prudent for BP to conduct a negative 

pressure test before setting the cement plug. It is unclear, however, whether that was the reason that BP 

switched the order of the negative pressure test.

45 Internal BP document (BP-HZN-CEC 21281-88). 

46 Internal BP document (BP-HZN-CEC 20263); Guide, interview, January 19, 2011.

47 Internal BP document (BP-HZN-CEC 21281-88). Morel was not the only one who thought that MMS 

might not approve it. Drilling engineer Mark Hafle emailed Morel and told him, ―I really don‘t think MMS 

will approve deep surface plug. We‘ll see.‖ Internal BP document (BP-HZN-MBI 127489). BP‘s concern that 

MMS might not have approved such a deep surface plug suggests that BP may have recognized the risks 

attendant to setting such a deep plug.

48 Internal BP document (BP-HZN-MBI 127907). The APM said that the test would be conducted with 

―seawater gradient equivalent‖; base oil is understood to be such an equivalent. This change, of course, also 

allowed the rig crew the flexibility to use seawater instead of base oil. Murry Sepulvado, interview. 

49 Internal BP document (BP-HZN-BLY 69066-67); Internal BP document (BP-HZN-MBI 127906).

50 Proponents of this interpretation point to the very plain order provided on the APM: ―1. Negative Test...2. 

TIH [Trip in Hole] with a 3-1/2‖ stinger to 8367; 3. Displace to seawater.‖ Internal BP document (BP-HZNOSC 1436). They note that procedures are meant to be followed sequentially and, as an aside, state that if a 

different order were intended, this procedure was very poorly written. They also note that the order is in 

keeping with the April 15 well plan (which called for a negative pressure test at the wellhead), circulated the 

same day that the APM was prepared. Finally, they note that although a negative pressure test may have 

made most sense at a depth of 8,367 feet to mimic the underbalanced condition of an abandoned well, 

negative pressure tests could be conducted at higher depths in a staged testing process—as the BP 

engineering team in fact planned. Internal BP document (BP-HZN-BLY 61379-80).

51 BP drilling engineer Brett Cocales and Wells Team Leader John Guide read the second and third steps as 

subsets of the negative pressure test. Testimony of John Guide, 329-331; Guide, interview, January 19, 2011. 

Cocales has testified that there would otherwise be no way to know at what depth to conduct the negative 

pressure test. Testimony of Brett Cocales (BP), Hearing before the Deepwater Horizon Joint Investigation 

Team, August 27, 2010, 128-29. Moreover, they believe that 8,367 feet is the only depth at which a negative 

pressure test would make sense, as that is the only depth at which the test would simulate the temporary 

abandonment of the well. Ibid., 129.

52 There may not be much significance beyond that. Conducting the negative pressure test at the wellhead 

rather than at 8,367 feet would probably not have prevented the blowout. In such a test, the pressure 

buildup, if any, would have been much more subtle than the 1,400 psi seen on the drill pipe. Given that the 

rig crew proceeded with abandonment despite observing 1,400 psi on the drill pipe, it is unlikely that they 

would have stopped the operation upon observing even smaller pressures on the drill pipe. John Smith 

(Expert witness), interview with Commission staff, October 22, 2010. In addition, there is no reason to think 

that MMS would have rejected a permit that explicitly stated the negative pressure test would take place at a 

depth of 8,367 feet. Frank Patton (MMS), interview with Commission staff, October 1, 2010. 

53 Internal BP document (BP-HZN-CEC 20273).

54 Internal BP document (BP-HZN-BLY 61379-80); Internal BP document (BP-HZN-BLY 20087).

55 Walz, interview.

56 Internal BP document (BP-HZN-BLY 61380).

57 Internal BP document (BP-HZN-BLY 70087).

58 Guide, interview, January 19, 2011.
Chief Counsel’s Report — Endnotes | 293

59 Morel sent a second Ops Note within 10 minutes after the first one. It added details and did not change the 

order of the procedures. Internal BP document (BP-HZN-MBI 195579-80).

60 Testimony of Bill Ambrose (Transocean), Hearing before the National Commission, November 8, 2010, 

315.

61 This would not be a change if one accepted the interpretation that the negative pressure test in the April 16 

APM would follow displacement. Internal BP document (BP-HZN-MBI 195579-80).

62 Ibid.

63 The Ops Note says, ―With seawater in kill close annular and do a negative test ~2350 psi differential.‖ 

Internal BP document (BP-HZN-MBI 139532). The 2,350 psi is not an expected drill pipe pressure. It 

describes the reduction in pressure at the bottom of the well by replacing the mud with water in the drill pipe 

and drill pipe-casing annulus down to 8,367 feet. Although the initial drill pipe pressure at the beginning of 

the negative pressure test was 2,325 psi, an independent expert has stated that the expected pressure at the 

beginning of the negative pressure test should have been 1,610 psi. John Smith, Review of Operational Data 

Preceding Explosion on Deepwater Horizon in MC252 (July 1, 2010), 9.

64 According to Mark Hafle, John Guide made a conscious decision not to notify the MMS of the change. 

Internal BP document (BP-HZN-BLY 61380). For his part, Guide said he had difficulty remembering any 

discussion or decision regarding notifying MMS, but agreed that MMS did not need to be notified in this 

situation. Guide believed that the plan had always been to conduct the negative pressure test at 8,367 feet. 

Guide, interview, January 19, 2011. Gregg Walz suggested that Hafle may have been the one to make the 

decision not to notify MMS of the change. Walz, interview. This assertion seems to be in tension with the fact 

that Hafle called Kaluza on April 20 out of concern that the new procedure departed from the one approved 

by MMS. Internal BP document (BP-HZN-CEC 20185, 200, 204).

65 According to his supervisor Gregg Walz, Hafle probably did not seek permission from MMS for deviating 

from the APM because the deviation resulted in a stricter test. Walz, interview. Conducting a negative 

pressure test at 8,367 feet would underbalance the well to a much greater degree than conducting a negative 

pressure test at the wellhead. However, displacing so much mud with seawater to conduct the test still 

entailed a level of risk. 

66 Internal BP document (BP-HZN-OSC 6158). As at Macondo, this well altered the procedure to shift from 

(a) conduct negative pressure test, set plug in mud, then displace to seawater, to (b) partially displace, 

conduct negative pressure test, finish displacement, set plug in seawater. This application also stated that the 

reason for combining the displacement and negative pressure test was ―to improve rig efficiency.‖ Ibid.

67 Internal BP document (BP-HZN-CEC 20185, 20200, 20204).

68 This may have been so if rig personnel had conducted a negative pressure test before displacing the well. 

Prior to displacement, there is neither spacer nor drill pipe in the wellbore. So there would have been no 

spacer in the well to potentially clog the kill line. And the crew would have sealed the well using the blind 

shear rams—not the annular preventer—eliminating any suggestion of a ―bladder effect.‖ Darryl Bourgoyne 

(Expert witness), interview with Commission staff, January 26, 2010; Darryl Bourgoyne (Expert witness), 

email to Commission staff, January 26, 2010. 

69 BP representatives agree that displacing 8,367 feet of mud from the wellbore increased the underbalance 

but do not agree that the severity of the underbalance increased risk. ―There‘s no reason at all to believe that 

increases the risk.‖ Testimony of Mark Bly, 209, 215-17. BP is wrong. Greater underbalance in the well places 

greater stress on the bottomhole cement. More broadly, there was no need to create an underbalance in the 

first place or to create one before putting more barriers in place.

70 John Smith (Expert witness), interview with Commission staff, September 7, 2010; Murry Sepulvado, 

interview; John Guide, interview, January 19, 2011.

71 The depth of the surface cement plug at Macondo was extremely unusual—perhaps one-of-a-kind. 

Anadarko representatives, interview with Commission staff, September 29, 2010; Testimony of Richard 

Vargo (Halliburton), Hearing before the National Commission, November 8, 2010, 212 (has set thousands of 

plugs in his career and has ―never seen it set this deep before‖); Walz, interview (cannot recall setting one 

that deep before); Bill Ambrose (Transocean), interview with Commission staff, November 2, 2010 

(unusually deep); Murry Sepulvado, interview (never seen one this deep before); Ronnie Sepulvado, 

interview (deeper than he had ever seen); Confidential source, interview (deepest in experience); Randy 

Ezell (Transocean), interview with Commission staff, September 16, 2010 (unusual); Testimony of John 

Guide, 298 (―it was deeper than normal‖); Testimony of Ross Skidmore, 60 (a lot deeper than he had 

probably seen before); Testimony of Leo Lindner (M-I SWACO), Hearing before the Deepwater Horizon 

Joint Investigation Team, July 19, 2010, 316 (―much further down than usual‖); Allen Seraile (Transocean), 
294 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

interview with Commission staff, January 7, 2011 (unusual, hadn‘t done that before); Transocean legal team, 

interview with Commission staff, September 21, 2010 (poll of 25 Transocean rigs revealed average 

displacement depth of 150 feet below mudline).

72 Testimony of Mark Bly, 308. 

73 BP representatives admit this too. Ibid., 312-13.

74 BP representatives acknowledge this point as well. Ibid, 308-09; Murry Sepulvado, interview.

75 Anadarko representatives, interview; Confidential industry expert, interview with Commission staff; 

Testimony of Merrick Kelley (BP), Hearing before the Deepwater Horizon Joint Investigation Team, August 

27, 2010, 298; Testimony of Ross Skidmore, 250, 259; Steve Lewis (Expert witness), interview, October 20, 

2010. 

76 At least one major operator typically sets the lockdown sleeve prior to the surface plug. Confidential 

industry expert, interview. At least one BP well site leader has done so in the past. Murry Sepulvado, 

interview. But BP wells team leader John Guide stated that, of the 17 lockdown sleeves he has set in his 

career, he set all of them last, and doing so was BP‘s standard practice. Guide, interview, September 17, 2010. 

It is worth noting that all of those 17 lockdown sleeves were a different model than the one set at Macondo 

and did not require downward setting force. Guide, interview, January 19, 2011. 

77 BP engineers state that they needed to set the lockdown sleeve last to avoid damaging it. But BP could 

have managed the risk of damage in other ways and has done so in the past. Kelley, interview. Alternative 

precautions include installing a seat protector and running pipe more carefully. Ibid. 

78 BP, Deepwater Horizon Accident Investigation Report, 72; Confidential industry expert, interview; 

Internal BP document (BP-HZN-MBI 316347)(―Often times this ring is removed.‖); Internal BP document 

(BP-HZN-BLY 61330)(―the OD lock-down ring on casing hanger seal assembly was optional and not being 

run routinely by the E&A team in all wells...it was a common practice‖).

79 Joint Industry Task Force to Address Offshore Operating Procedures and Equipment, ―Recommendations 

for Improving Offshore Safety,‖ May 17, 2010, 4.

80 Internal BP document (BP-HZN-MBI 196718).

81 Internal BP document (BP-HZN-MBI 119061).

82 Internal BP document (BP-HZN-MBI 126145); Internal BP document (BP-HZN-CEC 21268).

83 Skidmore, interview. 

84 Internal BP document (BP-HZN-MBI 126928).

85 Skidmore, interview. Skidmore approached Morel or Vidrine, or both. Ibid.

86 Internal BP document (BP-HZN-MBI 199250). ―DRIL-QUIP recommends running 100,000 lb of weight 

below the Running Tool.... Weight above the Running Tool can be substituted for weight below the Running 

Tool.‖ Ibid.

87 Kelley, interview. 

88 Dril-Quip legal team, email to Commission staff, December 27, 2010; Internal BP document (BP-HZNMBI 44875). ―DRIL QUIP recommends running 100,000 lb of weight below the Running Tool.... Weight 

above the Running Tool can be substituted for weight below the Running Tool.‖ Internal BP document (BPHZN-MBI 44875).

89 Internal BP document (BP-HZN-MBI 44858).

90 Internal BP document (MC 129 #3 APM 82712).

91 Internal BP document (BP-HZN-OSC 6118).

92 Ibid.

93 Kelley, interview.

94 Ibid. (recommended 1,250 to 1,350 feet below the mudline).

95 Internal BP document (BP-HZN-MBI 196174). ―MU & GIH w/ lockdown sleeve on 6-5/8‖ landing string 

w/ drill collars below.‖ Ibid. On November 12, 2009, BP engineer Tippetts told Dril-Quip representative 
Chief Counsel’s Report — Endnotes | 295

Patterson, ―We will be using [drill collars] for the tailpipe on Macondo.‖ Internal BP document (BP-HZNMBI 119061).

96 Internal BP document (BP-HZN-MBI 196174). On February 22, Tippetts asked BP operations engineer 

Brett Cocales whether the Horizon had the equipment necessary to run the planned drill collars. Cocales 

informed Tippetts the next day that the Horizon did not have the requested equipment and that Tippetts 

should plan to get it from a supplier. Internal BP document (BP-HZN-MBI 196720).

97 Internal BP document (BP-HZN-MBI 196719).

98 In the April 14 forward plan, BP lists the supply vessel M/V Hilda Lab as being en route to the rig with 

nine 61⁄2-inch drill collars on board. Internal BP document (BP-HZN-MBI 199282). 

99 Internal BP document (BP-HZN-MBI 252071). ―I keep coming back to sequence of setting casing, set the 

wear bushing, do the T&A work, pull the bushing, pick drill collars and RIH to set the lock down sleeve.‖Ibid.

100 Internal BP document (BP-HZN-CEC 21268).

101 Internal BP document (BP-HZN-MBI 199229, 199239)(~18 61⁄2-inch range 2 drill collars from Alice 

Chalmers listed for use in tailpipe; ―The tail pipe consisting of HT 55 Drill Pipe & 6 1⁄2‖ drill collars will be 

used for achieving the required weight down for the Lock Down Sleeve Installation‖).

102 Internal BP document (BP-HZN-MBI 199282). 

103 Guide, interview, January 19, 2010. Guide stated that the suggestion to use heavyweight drill pipe instead 

of drill collars came from Transocean senior toolpusher Randy Ezell. Ibid.

104 According to Guide, making up drill collars would not necessarily add time because the drill collars could 

be made up offline. Ibid. 

105 On this, all parties (including BP) agree. Testimony of Mark Bly, 211, 213; Testimony of Richard Vargo, 

211; Testimony of Bill Ambrose, 214.

106 Confidential industry expert, interview; Murry Sepulvado, interview; Steve Lewis (Expert witness), 

interview with Commission staff, October 29, 2010. Chemicals in oil-based mud can cause more disruption 

to the physical properties of cement, which is water-based, than seawater. Lewis, interview, October 29, 

2010.

107 Internal BP document (BP-HZN-MBI 196335).

108 Lewis, interview, October 29, 2010; Testimony of Charlie Williams (Shell), Hearing before the National 

Commission, November 9, 2010, 45.

109 BP‘s internal investigator acknowledges that the company could set mechanical plugs. Testimony of Mark 

Bly, 310. Many in the industry believe mechanical plugs should be incorporated into routine well design. 

Confidential industry experts, interview with Commission staff; Murry Sepulvado, interview; Steve Lewis

(Expert witness), email to Commission staff, September 20, 2010; Confidential industry expert, interview.

110 Testimony of Charlie Williams, 44.

111 An earlier surface cement plug at Macondo appeared to have been ―set in seawater to prevent 

contamination,‖ but when the rig returned to resume drilling, they found that ―the surface plug was not 

hard‖ because of ―a cement/water [contamination] issue.‖ That earlier cement plug had been set using a 

parabow (a metal retainer), which held the cement in place but presented separate complications. Internal 

BP document (BP-HZN-MBI 196335).

112 Ibid. 

113 Ibid.

114 Ibid.

115 Testimony of Mark Bly, 213. ―There‘s engineering choices that you make, and I think setting it in mud is 

something that happens sometimes and sometimes people choose to set them in seawater.‖ Ibid.

116 Testimony of Mark Bly, 214. ―It‘s an engineering tradeoff decision.‖ Ibid.

117 Walz, interview; Internal BP document (BP-HZN-OSC 6083), Internal BP document (BP-HZN-OSC

6158).

118 Internal BP document (BP-HZN-MBI 126928).
296 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

119 These include the Halliburton Fas Drill (drillable bridge plug), Baker Hughes GT plug (retrievable bridge 

plug), and parabow (retrievable retainer). Internal BP document (BP-HZN-OSC 6083); Internal BP 

document (BP-HZN-OSC 6158).

120 Notably, BP used GT plugs in at least two other wells in 2010, including MC 822 #5 and MC 877 #22. 

Internal BP document (BP-HZN-MBI 198612). BP engineers also considered running a Halliburton Fas Drill 

plug. Internal Transocean document (TRN-HCJ 93590); Internal BP document (BP-HZN-OSC 112974)(―We 

are considering a Fas-Drill retainer for the TA plug, vs a GT plug in the 9-7/8‖ casing.‖).

121 Internal BP document (BP-HZN-MBI 198666).

122 Internal BP document (BP-HZN-MBI 198602). ―Thanks for confirming the decision to use the GT Plug 

for abandonment.‖ Ibid. In late February, BP set up a meeting where Morel and Hafle would ―go over the 

necessary Macondo data and needs‖ and Baker Hughes representative Mark Plante would then make a 

presentation about the GT plug and procedure. Internal BP document (BP-HZN-MBI 196642). The meeting 

was originally scheduled for March 3, then postponed ―probably until the week of March 8th‖ because Morel 

and Hafle were ―very busy,‖ and finally scheduled for March 10. Ibid; Internal BP document (BP-HZN-MBI 

196652); Internal BP document (BP-HZN-MBI 196643). In April, Morel indicated that there was ―[s]till 

some discussion on‖ whether to use the GT plug and that John Guide would be following up. Internal BP 

document (BP-HZN-MBI 198762). According to Guide, he was not involved in the decision of whether to use 

a GT plug but has stated that Morel would have known that Guide opposes setting GT plugs. Guide, 

interview, January 19, 2011. 

123 Internal BP document (BP-HZN-MBI 198666); Internal BP document (BP-HZN-MBI 198910). ―Met with 

Baker today on this issue, and they are going to come back with a proposal based on fixed and firm 

commitment from BP for the use of these plugs on a longer term basis. Details are TBD, but we talked about 

some high level options and quantities based on your feedback for upcoming/ongoing work at Macondo, 

Atlantis and TH.‖ Internal BP document (BP-HZN-MBI 198910).

124 Internal BP document (BP-HZN-MBI 199275).

125 Internal BP document (BP-HZN-MBI 129149-51).

126 Ibid.

127 Internal BP document (BP-HZN-MBI 128957). ―We are at the end of the week and our district would like 

to know if there is going to be any decision made soon on whether or not the GT packer is going to be run 

and if so. When it is going to be called out. We just want to make sure you are covered in case something 

comes up in the weekend.‖ Ibid.

128 Internal BP document (BP-HZN-MBI 128957).

129 Internal BP document (BP-HZN-MBI 198919).

130 Internal BP document (BP-HZN-CEC 21269).

131 Internal BP document (BP-HZN-MBI 128957).

132 Internal BP document (BP-HZN-MBI 128959).

133 Internal BP document (BP-HZN-MBI 129145).

134 This comment was made on April 14 to the BP engineer negotiating the Baker Hughes contract. Internal 

BP document (BP-HZN-BLY 68031).

135 Ibid.

136 Internal BP document (BP-HZN-MBI 251262); Confidential source, interview; Walz, interview; Guide, 

interview, January 19, 2011; Internal BP document (BP-HZN-OSC 6083); Internal BP document (BP-HZNOSC 6158); Internal BP document (BP-HZN-MBI 252171). 

137 Testimony of Steve Lewis (Expert witness), Hearing before the National Commission, November 9, 2010, 

53-55. 

138 Confidential industry expert, interview with Commission staff; Steve Lewis (Expert witness), interview 

with Commission staff, September 28, 2010. 

139 BP‘s Drilling and Well Operations Practice manual discusses the use of kill weight fluid as a barrier before 

breaking containment but discusses it as a replacement for (instead of addition to) one of the two required 

mechanical barriers. Internal BP document (BP-HZN-MBI 130875).
Chief Counsel’s Report — Endnotes | 297

140 Confidential industry expert, interview with Commission staff; Testimony of Charlie Williams, 45.

141 As far as after the displacement and abandonment of the well, mud would not remain a barrier 

indefinitely. Over time, when left static in the wellbore and not circulated, mud suffers from barite fallout 

and loses its integrity. Therefore, ―mud can only be considered a temporary barrier with a restricted life span 

dependent on the mud weight and temperature.‖ Joseph Leimkuhler (Shell), letter to Commission staff, 

September 22, 2010.

142 BP concedes this. Testimony of Mark Bly, 311, 314.

143 Internal BP document (BP-HZN-OSC 6083); Internal BP document (BP-HZN-OSC 6158). 

144 Testimony of Charlie Williams, 43-44 (Shell sets three to five plugs); Ezell, interview (normally will set 

several plugs in addition to the bottomhole cement); Seraile, interview (normally will set two or three plugs 

before displacing).

145 Guide, interview, January 19, 2011 (does not recall anyone on the Macondo team suggesting that they 

should run more than one plug). This may be because setting multiple, intermediate plugs can complicate 

later re-entry and completion of the well, since retrieving or drilling out the plugs would take time and could 

disperse debris in the well. Ibid. Nevertheless, BP appears to have addressed or accepted these 

complications in other wells where they have set numerous plugs. Internal BP document (BP-HZN-OSC 

6083); Internal BP document (BP-HZN-OSC 6158).

146 Darryl Bourgoyne (Expert witness), interview with Commission staff, September 10, 2010; Steve Lewis

(Expert witness), interview with Commission staff, September 21, 2010.

147 Lewis, interview, September 21, 2010. Performing a displacement with the BOP closed can involve some 

minor encumbrances, including wear of the choke, kill, and boost lines, added time, and greater mixing of 

fluids in the wellbore. Ibid. 

148 Ibid. 

149 Joint Industry Task Force to Address Offshore Operating Procedures and Equipment, 

―Recommendations for Improving Offshore Safety,‖ 4.

150 Testimony of Steve Lewis, 63; Lewis, interview, September 28, 2010. BP wells team leader John Guide 

stated that temporary abandonment procedures are historically written at the end of a well, not incorporated 

into the initial drilling program, because the final dimensions of the well are not yet clear. Guide, interview, 

January 19, 2011. This reasoning is unpersuasive. Many aspects of the well—such as the precise pore 

pressures of yet-undrilled formations—are not yet clear, but operators still create a casing and drilling fluids 

program to guide well operations. The engineers then revise those programs as additional information 

becomes available.

151 Guide, interview, September 17, 2010. Indeed, because BP recognized Macondo‘s production potential 

early on (from the seismic imaging), it involved completion engineers in the well design process from the 

very beginning. Sims, interview.

152 Internal BP document (BP-HZN-MBI 180439); Internal BP document (BP-HZN-CEC 8712).

153 Internal BP document (BP-HZN-CEC 8892).

154 Internal BP document (BP-HZN-MBI 126338).

155 Guide, interview, January 19, 2011.

156 Internal BP document (BP-HZN-MBI 199123).

157 Walz‘s acknowledgment came in the context of the centralizer decision. Internal BP document (BP-HZNCEC 22662). This was not a first for the Macondo team. In early March, onshore engineer Brett Cocales sent 

an email to the rig‘s well site leader Earl Lee canceling the conversion of the float equipment on the 16-inch 

casing. The rig converted the float equipment anyway. This was because Lee did not see Cocales‘ email until 

after the casing had been set and cemented. After learning of the mix-up, Cocales wrote, ―I understand. We 

will work on getting you guys any changes in the future sooner so you will have time to review.‖ Internal BP 

document (BP-HZN-MBI 213550-51). 

158 Testimony of Steve Lewis, 63.

159 A temporary abandonment procedure should be ―designed with the same degree of rigor‖ as the initial 

well design. Changes in the procedure should be treated with similar rigor: ―if you change one cog...you have 

to consider whether or not it meshes with the others.‖ Testimony of Steve Lewis, 63-64. The Macondo team 
298 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

does not appear to have clearly understood whether they should have followed BP‘s management of change 

process when changing the temporary abandonment procedures. Macondo team managers David Sims and 

John Guide stated that changes in the lockdown sleeve setting procedures would not, as a general rule, have 

required a management of change process. Sims, interview; Guide, interview, September 17, 2010. But BP‘s 

own Macondo lockdown sleeve setting procedure appears to set down in writing just such a general rule: 

―Any deviation, exception or addition to this procedure must be approved by BP or designated 

representative. BP MOC procedures must be completed prior to implementing any procedural change.‖

Internal BP document (BP-HZN-MBI 199226).

160 Internal BP document (BP-HZN-MBI 127489).

161 Ibid.

162 Guide, interview, January 19, 2011. 

163 Internal BP document (BP-HZN-BLY 61203).

164 Murry Sepulvado, interview.

165 Internal BP document (BP-HZN-BLY 61361).

166 Testimony of Steve Lewis, 59; Ronnie Sepulvado, interview. 

167 Confidential source, interview; Walz, interview; Kelley, interview; Internal BP document (BP-HZN-OSC 

112884). Before planning the type of pipe, a BP engineer asks ―How much pipe is already on the rig that can 

be used to weight the LIT/LDS?‖ Internal BP document (BP-HZN-OSC 112884).

168 Guide, interview, January 19, 2010. Guide stated that the suggestion to use heavyweight drill pipe instead 

of drill collars came from Transocean senior toolpusher Randy Ezell. Ibid.

169 Internal BP document (BP-HZN-MBI 199236).

170 According to wells team leader John Guide, temporary abandonment procedures were very standard:

displace the wellbore to seawater, negative pressure test, and set a plug. But Guide was speaking only about 

his own experience. Guide, interview, January 19, 2011. A review of past BP temporary abandonment 

procedures shows great variation. Internal BP document (BP-HZN-OSC 6083); Internal BP document (BPHZN-OSC 6158).

171 Internal BP document (BP-HZN-MBI 130875); Internal BP document (BP-HZN-OSC 7918).

172 Internal BP document (BP-HZN-OSC 112993).

173 Internal BP document (BP-HZN-BLY 47094) (―Anyone know if there is any requirements in the MMS 

regs for a negative test, can‘t find any specifics?‖); Internal BP document (BP-HZN-OSC 112888)(―Regs for 

Temp Abandonment‖); Internal BP document (BP-HZN-MBI 128655 )(―If anyone else has any ideas of 

where something else might be let me know.‖).

Chapter 4.6

1

BP, Deepwater Horizon Accident Investigation Report (September 8, 2010), 82; John Smith, Review of 

Operational Data Preceding Explosion on Deepwater Horizon in MC252 (July 1, 2010), 17, 25; John Smith 

(Expert witness), interview with Commission staff, September 7, 2010; Testimony of Mark Bly (BP), Hearing 

before the National Commission, November 8, 2010, 285; Testimony of Bill Ambrose (Transocean), Hearing 

before the National Commission, November 8, 2010, 280; Testimony of Richard Vargo (Halliburton), 

Hearing before the National Commission, November 8, 2010, 285. 

2

Internal BP document (BP-HZN-MBI 136947).

3

Internal BP document (BP-HZN-MBI 136948); BP, Deepwater Horizon Accident Investigation Report, 82.

4

BP, Deepwater Horizon Accident Investigation Report, 82; Smith, Review of Operational Data Preceding 

Explosion on Deepwater Horizon in MC252, 17; Smith, interview, September 7, 2010; Testimony of Mark 

Bly, 285; Testimony of Bill Ambrose, 280; Testimony of Richard Vargo, 285. Even during the negative 

pressure test, a leak in the shoe track cement cannot be identified unless some other component of the 

casing system, such as the float valve equipment, also leaks.
Chief Counsel’s Report — Endnotes | 299

5

Testimony of John Smith (Expert witness), Hearing before the Deepwater Horizon Joint Investigation 

Team, July 23, 2010, 265-67.

6

BP well site leader John Guide said the test was designed ―to see if the float equipment and the cement –

actually the cement...inside of the casing is holding, [a]nd also the casing itself‖ and agreed that the negative 

test is the last evaluative test performed on a well before the BOP is pulled and the rig is demobilized. 

Testimony of John Guide (BP), Hearing before the Deepwater Horizon Joint Investigation Team, July 22, 

2010, 137-38. Daun Winslow, Transocean General Manager for the Gulf of Mexico region, said, ―A negative 

test...is very important to understand that your barriers are in place and they...work and they hold prior to 

displacing the seawater and removing the blowout preventers from the wellhead. It‘s very important.‖ 

Testimony of Daun Winslow (Transocean), Hearing before the Deepwater Horizon Joint Investigation Team, 

August 24, 2010, 209.

7

Testimony of Mark Bly, 204, 326; Testimony of Bill Ambrose, 204, 326; Testimony of Richard Vargo, 204, 

326. 

8

Internal BP document (BP-HZN-OSC 1438).

9

Internal BP document (BP-HZN-CEC 20190, 20204). 

10 Internal BP document (BP-HZN-CEC 20200-02). 

11 Testimony of Leo Lindner (M-I SWACO), Hearing before the Deepwater Horizon Joint Investigation 

Team, July 19, 2010, 273. 

12 Transocean contends that the choke and kill line were not fully displaced of mud. According to their 

calculations, which they have not shared with the Chief Counsel, the kill line had 22 barrels of mud 

remaining in it. Bill Ambrose (Transocean), interview with Commission staff, September 21, 2010. Dr. John 

Smith, an independent expert, has stated that both the volumes pumped and pressures after displacement 

indicate that the kill line was fully displaced with seawater. John Smith (Expert witness), email to

Commission staff, October 3, 2010. 

13 Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 9; Internal 

Halliburton document (HAL_48974). 

14 BP, Deepwater Horizon Accident Investigation Report, 83 and app. Q, 4; Internal BP document (BPHZN-BLY 47100-02); Testimony of Greg Meche (M-I SWACO), Hearing before the Deepwater Horizon Joint 

Investigation Team, May 28, 2010, 215. 

15 Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 18; Testimony 

of Leo Lindner, 287. Dr. Smith writes that ―[a] common industry practice to minimize this occurrence is to 

use an unweighted, viscous spacer to follow a dense fluid that is being displaced up the annulus.‖ Smith, 

Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 18. Leo Lindner, the 

M-I SWACO engineer, stated that despite having seawater and spacer mixing, you could still have a good 

negative pressure test. However, he went on to say that ―ideally‖ you would have all the spacer above the 

annular preventer. Testimony of Leo Lindner, 288.

16 Internal BP document (BP-HZN-MBI 129256). M-I SWACO wrote, ―I do not know the exact [stinger] tool 

that will be used but if there are any small restrictions in the assembly [setting up] this would be a risk.‖ Ibid. 

17 Internal BP document (BP-HZN-BLY 47100-01). The BP well site leader, Murry Sepulvado, stated that the 

shoreside team had supposedly tested the spacer within hours after its use was suggested. Murry Sepulvado 

(BP), interview with Commission staff, December 10, 2010. However, BP‘s own investigation could find no 

evidence of such a test. ―This material is sold by M-I SWACO for lost circulation and has no history or testing 

for use as a spacer. No evidence of compatibility testing could be found for the Macondo well.‖ BP, 

Deepwater Horizon Accident Investigation Report, app. Q, 6. And although M-I SWACO recognized the 

possibility that the lost circulation materials presented certain risks, their communications suggested they 

had assumed rather than tested their compatibility as a spacer. ―We do not feel there would be any 

restriction that would cause the FORM A SQUEEZE to set up and without [an additive in the FORM A SET] 

there is no cross linking agent to cause it to set up.‖ Internal BP document (BP-HZN-MBI 129256). 

Although BP‘s subsequent investigation agreed that it was unlikely that cross-linking caused the blockage, it 

also found that cross-linking was not the only risk. Solids from the spacer could have plugged the kill line, or 

the viscosity or gel strength of the spacer could have been too high to allow pressure to be transmitted 

through the kill line. BP, Deepwater Horizon Accident Investigation Report, app. Q, 3, 9. 

18 Testimony of Ronnie Sepulvado (BP), Hearing before the Deepwater Horizon Joint Investigation Team, 

July 20, 2010, 129.
300 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

19 Testimony of Leo Lindner, 309-11, 320; Testimony of John Guide, July 22, 2010, 324; Internal BP 

document (BP-HZN-MBI 129043); Internal BP document (BP-HZN-MBI 129240); Internal BP document

(BP-HZN-MBI 129256); Internal BP document (BP-HZN-MBI 129268). The Resource Conservation and 

Recovery Act (RCRA) identifies materials that are hazardous waste and regulates how hazardous waste is to 

be managed and disposed of. 42 U.S.C. §§ 6921-6939f. RCRA regulations, however, identify exceptions to 

material which might otherwise be treated as hazardous waste, including ―[d]rilling fluids, produced waters, 

and other wastes associated with the exploration, development, or production of crude oil, natural gas, or 

geothermal energy.‖ 40 C.F.R. § 261.4.

20 Testimony of Leo Lindner, 308-11, 320; Internal BP document (BP-HZN-MBI 129256); Testimony of Greg 

Meche, 216-18.

21 Internal BP document (BP-HZN-BLY 47100). It is unclear whether BP or M-I SWACO came up with the 

original idea to use the lost circulation material as spacer, but BP ultimately approved its use. Testimony of 

John Guide, July 22, 2010, 323. BP well site leader Ronnie Sepulvado stated that M-I SWACO mud engineer 

Leo Lindner had presented the idea to him on the rig, but that he assumed he had talked to either BP or 

M-I SWACO engineers onshore first. Testimony of Ronnie Sepulvado, 126-31. For his part, Lindner testified 

that he broached the subject with Murry Sepulvado (Lindner may have misidentified the well site leader), 

but that ―it wasn‘t an idea that I came up with.‖ Testimony of Leo Lindner, 297.

22 Internal BP document (BP-HZN-MBI 129268); Murry Sepulvado, interview.

23 Testimony of Leo Lindner, 275-76.

24 Internal BP document (BP-HZN-MBI 133083); Testimony of Leo Lindner, 276. In contrast to other 

accounts, the BP Deepwater Horizon Accident Investigation Report indicates that 424 barrels of spacer and 

30 barrels of freshwater were pumped. BP, Deepwater Horizon Accident Investigation Report, 83.

25 Internal BP document (BP-HZN-MBI 133083); BP, Deepwater Horizon Accident Investigation Report, 

83; Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 9; 

Testimony of Jimmy Harrell (Transocean), Hearing before the Deepwater Horizon Joint Investigation Team, 

May 27, 2010, 33; Internal BP document (BP-HZN-CEC 20187, 20204).

26 BP, Deepwater Horizon Accident Investigation Report, 84. 

27 Transocean has indicated that it believes that 100 barrels of spacer remained beneath the BOP, suggesting 

that two-thirds of the annular volume between the drill pipe and casing was filled with spacer rather than 

seawater. Ambrose, interview. Generally consistent with Transocean‘s view, Dr. John Smith, an independent 

expert, has estimated that there was spacer at least 1,830 feet below the mudline. Smith, Review of 

Operational Data Preceding Explosion on Deepwater Horizon in MC252, 9, 18.

28 The drill pipe pressure that should have been expected here was 1,610 psi. Instead, the reading was 

2,325 psi. Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 9; 

Internal Halliburton document (HAL_48974). 

29 None of the temporary abandonment procedures that the BP shoreside team prepared included expected 

pressures for the beginning of the negative pressure test. BP depended on the well site leaders to prepare 

such calculations. Murry Sepulvado, interview. There is no evidence that anyone present at the start of the 

test had calculated what pressure ought to have been expected on the drill pipe. One rig crew member, 

Randy Ezell, reported that toolpusher Jason Anderson had a form with expected drill pipe pressures, but 

there is no evidence in any of the accounts of the negative pressure test that this form was consulted. Nor is 

there evidence that Anderson, who worked the evening shift, would have been in the drill shack at this point. 

Randy Ezell (Transocean), interview with Commission staff, September 16, 2010.

30 Testimony of Ross Skidmore (Swift), Hearing before the Deepwater Horizon Joint Investigation Team, 

July 20, 2010, 386. The kill line pressure had leveled off at 1,250 psi after the rig crew had completed 

displacing it with seawater. Ibid; Internal Halliburton document (HAL _48974). Skidmore said the drill pipe 

was bled to 1,200 psi, an insignificant difference.

31 BP, Deepwater Horizon Accident Investigation Report, 24; Internal Halliburton document (HAL_48974).

32 Testimony of John Smith (Expert witness), Hearing before the National Commission, November 9, 2010, 

139-40. Spacer in the annulus between the drill pipe and the casing would cause the drill pipe pressure to 

increase and the kill line pressure to drop due to a phenomenon called the u-tube effect. A u-shaped tube 

with two differently weighted fluids on each side will tend to show increased pressure on one end of the tube 

as the heavier fluid pushes against the lighter fluid. At Macondo, the heavy weight of the spacer that was only 

on the annular (or kill line) side would push against the lighter seawater below it and exert pressure on the 

drill pipe. At the same time, the heavy fluid would act as a barrier to pressure being felt on the kill line.
Chief Counsel’s Report — Endnotes | 301

33 Evidence suggests that the crew may have recognized the pressure readings were abnormal and ascribed it 

to u-tubing. Internal BP document (BP-HZN-CEC 20188); Testimony of Chris Pleasant (Transocean), 

Hearing before the Deepwater Horizon Joint Investigation Team, May 28, 2010, 116. However, it appears 

that the u-tube effect was attributed to supposed residual mud in the kill line rather than spacer beneath the 

BOP. Testimony of Lee Lambert (BP), Hearing before the Deepwater Horizon Joint Investigation Team, July 

20, 2010, 387. 

34 Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 18-19; 

Testimony of John Smith, November 9, 2010, 140-41. 

35 Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 9; Internal 

Halliburton document (HAL _48974); Testimony of John Smith, July 23, 2010, 283. 

36 Internal Halliburton document (HAL _48974)(23 barrels); Internal BP document (BP-HZN-MBI 129629). 

Although this is the account of the witness at the cement unit, there are other estimates. Two other witnesses 

described a similar gain as the amount bled by bringing the drill pipe pressure down from 2,325 to 1,250 psi. 

Testimony of Ross Skidmore, 386 (25 barrels); Internal BP document (BP-HZN-CEC 20226)(25 bbl). Their 

testimony does not offer how much was bled to bring the drill pipe pressure from 1,250 down to 260 psi. BP 

has at times suggested that this approximate 23-barrel bleed included the later 15-barrel bleed. BP, 

Deepwater Horizon Accident Investigation Report, 25; Internal BP document (BP-HZN-MBI 129637). There 

is also general agreement that 60 to 65 barrels were bled ―total‖ to bring the drill pipe pressure to 0 psi. 

Internal BP document (BP-HZN-CEC 20211); Internal BP document (BP-HZN-CEC 20338, 203347). 

However, it is unclear whether the ―0‖ refers to the first or last time 0 psi was reached on the drill pipe. 

37 According to one well site leader, volumes expected to be bled should always be calculated ahead of time. 

Murry Sepulvado, interview. There is no evidence that any of the crew had prepared estimates of how many 

barrels of seawater would be bled, nor is there any reference in their accounts as to how the volumes bled 

compared to what they were expecting. Testimony of Darryl Bourgoyne (Expert witness), Hearing before the 

National Commission, November 9, 2010, 149-50.

38 Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 10; Internal 

Halliburton document (HAL_48974).

39 By comparison, only approximately 6.5 barrels were needed during the positive pressure test to increase 

the pressure from 0 to 2,500 psi. Internal BP document (BP-HZN-MBI 136948). A return of four times as 

many barrels when reducing the pressure by half as much should have been seen as anomalous. 

40 Smith identified four negative pressure tests that took place, only two of which were recognized by the 

crew. Testimony of John Smith, July 23, 2010, 272; Smith, Review of Operational Data Preceding 

Explosion on Deepwater Horizon in MC252, 18. 

41 Testimony of Randy Ezell (Transocean), Hearing before the Deepwater Horizon Joint Investigation Team,

May 28, 2010, 279-80. The leakage beneath the annular preventer after displacement is not unusual. Murry 

Sepulvado, interview.

42 Some have theorized that the fluid level was falling at this time not because the annular was leaking, but 

because the well was losing returns. The drill pipe pressure was therefore rising because the well was 

flowing, not because spacer was leaking beneath the BOP. Phil Rae, ―The Genesis of the Deepwater Horizon 

Blowout Full Report,‖ Energy Tribune, December 8, 2010. The theory itself suffers from a number of 

shortcomings. It posits that the well was losing returns and flowing at the same time. And even if the well 

was losing returns, if the annular preventer was closed it would have had to have been leaking in order for 

the fluid in the riser to fall. Finally, rig crew accounts state that mud levels in the riser were falling. Kaluza 

said that ―some of the mud had dropped.‖ Internal BP document (BP-HZN-CEC 20187). And Harrell stated 

that ―there was fluid coming out of the riser, dropping down in the riser u-tube.‖ Testimony of Jimmy 

Harrell, 35. 

43 Internal BP document (BP-HZN-CEC 20187). This observation explains how the crew members could 

have identified that the fluid levels were falling, though it took place as the riser was being topped off.

44 Testimony of Steve Bertone (Transocean), Hearing before the Deepwater Horizon Joint Investigation, 

July 19, 2010, 33.

45 Testimony of Daun Winslow, 78; Testimony of Randy Ezell, 279-80.

46 Internal BP document (BP-HZN-CEC 20201); Testimony of Randy Ezell, 279-80; Internal BP document

(BP-HZN-CEC 20226)(20 bbl). Other accounts say the riser was filled with more mud. Internal Halliburton 

document (HAL_48974)(50 bbl); Testimony of Chris Pleasant, 115 (60 bbl).
302 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

47 On the other hand, the crew may not have realized that the dropping fluid levels in the riser meant that 

fluid was leaking beneath the BOP. Chris Pleasant, a subsea engineer, said that Anderson recognized that 

mud in the riser had been lost but was ―convinced that we didn‘t lose no mud through the annular‖ and that 

as a group, ―[w]e never really had a clear understanding of where the fluid went to.‖ Testimony of Chris 

Pleasant, 115-16, 133. Some testimony suggests that the crew believed that mud, rather than spacer, was 

leaking beneath the BOP (though this still should have triggered concerns, as heavy mud could confound the 

test as well as spacer). Testimony of Lee Lambert, 288-89; Internal BP document (BP-HZN-CEC 20174-

201).

48 Internal BP document (BP-HZN-CEC 20187, 20201). Kaluza states that ―nothing had been bled off that I 

know of‖ at the time he arrived. However, he also states that the drill pipe pressure was 1,260 psi when he 

arrived. Kaluza had surely missed the bleeding of the drill pipe from 2,325 to 1,250 psi to match the kill line. 

Given his description of what was occurring on the rig floor when he arrived, he likely also missed the bleed 

of the drill pipe from 1,250 to 260 psi. Internal Halliburton document (HAL_48974). 

49 According to one BP well site leader, it is common to have such leaks at the annular preventer. The 

annular preventer is designed to hold pressure from the bottom, not the top. If large amounts of fluid had 

leaked through, as had happened here, it would be necessary to displace it back to above the BOP. Murry 

Sepulvado, interview. BP wells team leader also stated that he would have expected the rig crew to flush the 

spacer above the BOP after learning that it had leaked below the annular preventer. John Guide (BP), 

interview with Commission staff, January 19, 2011.

50 Internal BP document (BP-HZN-CEC 20188); BP, Deepwater Horizon Accident Investigation Report, 85; 

Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 11; Internal 

Halliburton document (HAL_48974). 

51 BP, Deepwater Horizon Accident Investigation Report, 85; Smith, Review of Operational Data Preceding 

Explosion on Deepwater Horizon in MC252, 19; John Smith (Expert witness), interview with Commission 

staff, September, 14, 2010.

52 When the crew on this occasion shut in the drill pipe, it closed the internal blowout preventer (IBOP). The 

IBOP is a valve in the top drive (a device suspended from the derrick which turns the drill string below it) on 

the rig. As the drill pipe pressure sensor was downstream of the IBOP, closing the IBOP prevented the drill 

pipe pressure from being monitored. When the IBOP was opened, the pressure at the cementing unit 

increased to 773 psi in less than a minute. However, it is likely that the pressure had been gradually building 

up at the IBOP while it had been closed. Smith, Review of Operational Data Preceding Explosion on 

Deepwater Horizon in MC252, 11.

53 Ibid.; Internal Halliburton document (HAL_48974).

54 Internal BP document (BP-HZN-CEC 20201); BP, Deepwater Horizon Accident Investigation Report, 85-

86. 

55 Internal BP document (BP-HZN-CEC 20177, 20189, 20201-02, 20204). According to Kaluza, he wanted to 

discuss with Vidrine which line Vidrine wanted to monitor the negative pressure test on.

56 Internal BP document (BP-HZN-CEC 20202-04); Internal BP document (BP-HZN-MBI 129623); Internal 

BP document (BP-HZN-MBI 129629); Testimony of Chris Haire (Halliburton), Hearing before the 

Deepwater Horizon Joint Investigation Team, May 28, 2010, 247. However, Halliburton cementer Chris 

Haire‘s report of a 15-barrel return is confusing given that he places it after the drill pipe pressure reaches 

1,400 psi. Ibid.

57 If witness testimony is accurate, it would appear that at this point there was good communication between 

the kill line and the drill pipe.

58 Internal BP document (BP-HZN-MBI 129629); BP, Deepwater Horizon Accident Investigation Report,

86; Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 11.

59 Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 11; Internal 

Halliburton document (HAL_48974); BP, Deepwater Horizon Accident Investigation Report, 86. 

60 Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 19. The BP 

investigation also focused on this point in the negative pressure test as a moment of critical interpretation, 

stating that 1,400 psi on the drill pipe was ―unexplained unless it was caused by pressure from the reservoir.‖ 

BP, Deepwater Horizon Accident Investigation Report, 89. 

61 The BP investigation found that ―[t]he 1,400 psi drill pipe pressure observed during the negative pressure 

test best matched communication with the M56A sand through the annulus cement barrier and shoe track 

barriers.‖ BP, Deepwater Horizon Accident Investigation Report, 216. 
Chief Counsel’s Report — Endnotes | 303

62 Internal BP document (BP-HZN-CEC 20201-02, 20204); Internal BP document (BP-HZN-CEC 20346).

63 Witnesses consistently refer only to two negative pressure tests, one conducted on the drill pipe and one 

conducted on the kill line. Internal BP document (BP-HZN-CEC 20353-54); Internal BP document (BPHZN-CEC 20190); Testimony of Jimmy Harrell, 88; Testimony of Randy Ezell, 68.

64 Internal BP document (BP-HZN-CEC 20342, 20348); Internal BP document (BP-HZN-CEC 20205); 

Internal BP document (BP-HZN-CEC 20339); Internal BP document (BP-HZN-CEC 20213); Internal BP 

document (BP-HZN-MBI 129621); Testimony of Lee Lambert, 334; Ezell, interview. Some of the above 

witness accounts include toolpusher Randy Ezell as part of the discussion. Ezell, however, testified that he 

left the drill shack before the drill pipe pressure reached 1,400 psi. Testimony of Randy Ezell, 38-39. Two 

M-I SWACO mud engineers, Gordon Jones and Blair Manuel, and a Dril-Quip service technician, Charles 

Credeur, may have been present on the rig floor but may not have taken part in the discussion. Harrell may 

have been present during an earlier discussion about the negative pressure test—likely regarding the leaking 

annular—but not concerning the pressure abnormalities. Testimony of Jimmy Harrell, 89-90.

65 Internal BP document (BP-HZN-CEC 20334, 20339, 20342, 20346, 20352); Internal BP document (BPHZN-CEC 20177-78, 20190-20221, 20204-05); Testimony of Lee Lambert, 292.

66 Testimony of Lee Lambert, 292.

67 Smith, interview, September 7, 2010.

68 Internal BP document (BP-HZN-CEC 20204).

69 Internal BP document (BP-HZN-CEC 20178).

70 Testimony of Lee Lambert, 395-96.

71 Testimony of Jimmy Harrell, 117; Internal BP document (BP-HZN-CEC 20204); Internal BP document

(BP-HZN-OSC 1438).

72 Internal BP document (BP-HZN-CEC 20200). See also Chapter 4.5 on TA procedures.

73 According to Ezell, Vidrine ―wasn‘t happy with the results from the first test.‖ Testimony of Randy Ezell, 

300.

74 Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 12; Internal 

Halliburton document (HAL_48974); Internal BP document (BP-HZN-CEC 20191, 20205). When the crew 

initially bled the kill line, 0.6 barrels were bled off to reach 0 psi. When the kill line was shut in, pressure 

rose to 30 psi. The crew then bled the pressure down to 0 psi again, bleeding off 0.2 more barrels. Internal 

BP document (BP-HZN-CEC 20205); Internal BP document (BP-HZN-CEC 20351-52). 

75 Internal BP document (BP-HZN-CEC 20339, 20348, 20352).

76 Internal BP document (BP-HZN-CEC 20177-78, 20190, 20204-05). According to Kaluza, the bladder 

effect was first discussed at the end of the negative pressure test on the drill pipe, to explain the rise in drill 

pipe pressure to 1,400 psi. The bladder effect was also then discussed during the test on the kill line as an 

explanation for how there could be 1,400 psi on the drill pipe despite no flow on the kill line. 

77 Internal BP document (BP-HZN-MBI 262896-97).

78 Internal BP document (BP-HZN-CEC 20342, 20359).

79 Testimony of Darryl Bourgoyne, 174-75; Testimony of John Smith, November 9, 2010, 175-76; Testimony 

of Steve Lewis (Expert witness), Hearing before the National Commission, November 9, 2010, 176-77; Murry 

Sepulvado, interview; Ronnie Sepulvado (BP), interview with Commission staff, October 26, 2010.

80 Testimony of Darryl Bourgoyne, 174-75; Murry Sepulvado, interview; Ronnie Sepulvado, interview; 

Testimony of Bill Ambrose, 208.

81 According to Transocean offshore installation manager Jimmy Harrell, both the well site leader and the 

toolpusher were interpreting the negative pressure test data. Testimony of Jimmy Harrell, 91. Although he 

was not on the rig floor during the interpretation of results, Harrell understood the negative pressure test to 

have been successful. Ibid., 117. According to Pat O‘Bryan, BP vice president for drilling and completions, 

Transocean‘s toolpusher and driller would be able to interpret the results of a negative pressure test. 

Testimony of Pat O‘Bryan (BP), Hearing before the Deepwater Horizon Joint Investigation Team, August 

26,2010, 449-50. And according to John Guide, BP wells team leader, the company man was ―one of the 

people‖ who were supposed to determine if the negative pressure test was successful or not. Testimony of 

John Guide, July 22, 2010, 161-62.
304 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

82 Testimony of Randy Ezell, 311-12; Testimony of Paul Johnson (Transocean), Hearing before the 

Deepwater Horizon Joint Investigation Team, August 23, 2010, 356. Though Transocean has also stated it is 

unclear whether or not its rig personnel had the training and experience to interpret the negative pressure 

test. Testimony of Bill Ambrose, 207; Internal BP document (BP-HZN-CEC 20334, 20339, 20342, 20346, 

20352); Internal BP document (BP-HZN-CEC 20177-78, 20190-20221, 20204-05); Testimony of Lee 

Lambert, 292.

83 Vidrine may have made a call to Mark Hafle onshore during the negative pressure test but not talked about 

the results of the test. Internal BP document (BP-HZN-CEC 20339, 20352); Internal BP document (BPHZN-CEC 20245). There is testimony from the rig crew that Kaluza called John Guide after the first 

negative pressure test. Testimony of Chris Pleasant, 117-18. Guide has denied this, and there is no evidence 

of this in BP‘s notes of its interviews with Kaluza. Testimony of John Guide, July 22, 2010, 175. Nor is there 

any conclusive evidence of this in logs of telephone calls made from the rig. While Guide made several brief 

calls to the rig during the negative pressure test (all under five minutes) in an attempt to determine how the 

executives‘ visit was going, he never spoke with the well site leaders. Guide, interview, January 19, 2011; 

Benjamin Powell (BP legal team), letter to Commission staff, December 22, 2010, telephone log attachment. 

Ezell states that the rig crew never asked him about the 1,400 psi during the test, though several witness 

accounts place him in the drill shack for at least some portion of the discussion. Ezell, interview; Internal BP 

document (BP-HZN-CEC 20342, 20348); Internal BP document (BP-HZN-CEC 20205); Internal BP 

document (BP-HZN-CEC 20339); Internal BP document (BP-HZN-CEC 20213).

84 Testimony of Mark Bly, 286-90; Testimony of Bill Ambrose, 286-90; Murry Sepulvado, interview.

85 Testimony of John Guide, July 22, 2010, 133-34; Testimony of John Guide (BP), Hearing before the 

Deepwater Horizon Joint Investigation Team, October 7, 2010 187-92; Testimony of Darryl Bourgoyne, 156-

58. 

86 John Guide (BP), interview with Commission staff, September 17, 2010. Morel indicated in his internal BP 

interview that ―if negative test unsuccessful the decision tree says contact John Guide.‖ Internal BP 

document (BP-HZN-MBI 21306).

87 Testimony of John Guide, July 22, 2010, 234-37. Transocean OIM Harrell had judged even the first test to 

be a successful one. Testimony of Jimmy Harrell, 26.

88 Powell, letter, telephone log attachment. According to notes of BP‘s internal investigation interview of 

Vidrine, Vidrine may have described the test as ―squirrelly‖ but assured Hafle that the 1,400 psi did not 

indicate a problem because ―if there had been a kick in the well we would have seen it.‖ Internal BP 

document (BP-HZN-CEC 20343, 20348). Hafle‘s reaction to the 1,400 psi, if he was told about it, was 

apparently to tell Vidrine to ―check the line up.‖ Internal BP document (BP-HZN-CEC 20359); Internal BP 

document (BP-HZN-BLY 61374). Other accounts suggest Vidrine did not specifically tell Hafle about the drill 

pipe pressure. Internal BP document (BP-HZN-CEC 20234). But Hafle‘s account states that he had INSITE 

up on his computer screen during the call, a program that allowed him to access data transmitted from the 

rig. Internal BP document (BP-HZN-BLY 61374).

89 Telephone logs show that wells team leader John Guide made several brief phone calls to the rig during 

the course of the test. (Powell, letter, telephone log attachment). Guide explained that he was calling to 

inquire about the progress of the VIP tour and did not discuss the course of the negative pressure test. Guide, 

interview, January 19, 2011.

90 There are multiple ways that the spacer could have prevented flow from the kill line. Spacer could have 

clogged the kill line by either a phenomenon known as ―bridging,‖ by acting as a gelatin (the stiffening that 

occurs when the spacer is stationary), or by exerting a higher yield point and yield stress than the seawater 

above it. Regardless of how it acted, the important point may be that the clogging would not have needed to 

act as a complete barrier against the 1,400 psi in the drill pipe. Dr. John Smith has indicated that the spacer 

would only have needed to absorb 100 to 200 psi to prevent flow. Smith, interview, September, 14, 2010. 

Even if it did not clog the kill line, the heavy spacer beneath the BOP would have handicapped the test.

Murry Sepulvado, interview. If the intent in displacing the well with seawater to 8,367 feet was to simulate 

conditions after abandonment, the presence of heavy spacer beneath the BOP defeated it. The cement shoe 

at the bottom of the well was expected to hold back formation pressures from below with only a column of 

water above 8,367 feet on top of it. Like a heavy weight compressing a spring below it, the heavier spacer 

would have exerted additional pressure from above that would have prevented the shoe cement from bearing 

the full formation pressure it would face in abandonment. Once displacement of the riser resumed after the 

negative pressure test, however, this heavy spacer would be removed.

91 There are problems associated with each of these theories. BP has suggested that a valve connecting the 

kill line to the BOP may have been accidentally left closed during the negative pressure test. BP, Deepwater 

Horizon Accident Investigation Report, 87. However, that valve would have been opened minutes before 

during the negative pressure test on the drill pipe. The theory thus assumes that the valve was closed and 
Chief Counsel’s Report — Endnotes | 305

then almost immediately forgotten about. Transocean has suggested the kill line may have been clogged with 

mud, as it was never fully displaced during preparations for the negative pressure test. Ambrose, interview. 

However, Dr. John Smith has stated that both the volumes pumped and pressures after displacement 

indicate the kill line was fully displaced with seawater. Smith, email. While well site leader John Guide and 

drilling engineer Brian Morel have suggested that hydrates from migrating gas may have frozen in the kill 

line, no evidence has been produced suggesting that this actually took place or that gas had made it to the 

BOP as early as the time of the negative pressure test. Guide, interview, September 17, 2010; Internal BP 

document (BP-HZN-CEC 20247).

92 Deepwater Horizon Study Group, The Macondo Blowout: 3rd Progress Report (December 5, 2010), app. 

B, 10; National Academy of Engineering, Interim Report on Causes of Deepwater Horizon Oil Rig Blowout 

and Ways to Prevent Such Events (November 16, 2010), 9-10.

93 Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 19. 

94 For this reason, Transocean indicated ―that spacer placement became ever so important but may have 

been overlooked. And that added confusion, and in that regards the test became more complicated.‖ 

Testimony of Bill Ambrose, 207.

95 Internal BP document (BP-HZN-BLY 47100). 

96 Wells team leader John Guide agreed that personnel on the rig should have done so. Guide, interview, 

January 19, 2011.

97 Testimony of John Guide, July 22, 2010, 333; Testimony of Daun Winslow, 194-95. 

98 Testimony of John Guide, July 22, 2010, 333. Well site leader Don Vidrine stated that there is ―[n]o 

standard procedure on how to do these...leave to rig on how to do procedure.‖ Internal BP document (BPHZN-CEC 20335).

99 Testimony of Daun Winslow, 194-95. The previous negative pressure tests performed by the Deepwater 

Horizon crew at the Kodiak II and Tiber wells had been devised by the well site leader Murry Sepulvado and 

toolpusher Jason Anderson. Their method was to displace the choke, kill, and boost lines with seawater and 

to displace the drill pipe with spacer and seawater until the drilling mud was above the annular preventer.

The method‘s use of the drill pipe to conduct the negative pressure test explains why the test was initially 

conducted on the drill pipe, despite the fact that the later APM stated that the negative pressure test would 

be done ―with the kill line.‖ According to Ezell, this method was printed out and laminated by Murry 

Sepulvado and available in the drill shack. However, neither Murry nor Ronnie Sepulvado recalls such a 

procedure. Moreover, the procedure was ―generic‖ in the sense that it did not include specific volumes or 

pressures to be expected on an individual well. Testimony of Leo Lindner, 347-48; Guide, interview, 

September 17, 2010; Ezell, interview; Murry Sepulvado, interview; Ronnie Sepulvado, interview.

100 Before unlatching from the well in anticipation of Hurricane Ida, Transocean‘s Marianas conducted a 

negative pressure test. The negative pressure test was different in several ways. It used base oil rather than 

seawater. The kill line was displaced rather than the drill pipe. There was no displacement beneath the 

wellhead. The choke and boost lines were not displaced beforehand. Internal BP document (BP-HZN-MBI 

172005). 

101 Testimony of Leo Lindner, 271-72.

102 In September 2010, BOEMRE, the agency formerly known as MMS, proposed to update its regulations. 

The new regulations require that a negative pressure test be performed on intermediate and production 

casing strings, that test procedures and criteria be provided on the permit application, and that the results of 

the test be available for inspection. 30 C.F.R. § 250.423(c); Oil and Gas and Sulphur Operations in the Outer 

Continental Shelf—Increased Safety Measures for Energy Development on the Outer Continental Shelf, 75 

Fed. Reg. 63346, 63373 (October 14, 2010).

103 Negative pressure tests are done only if the well will experience a similar underbalanced pressure 

condition during temporary abandonment. In many wells (especially land wells) the well is abandoned in an 

overbalanced state, so a negative pressure test is not necessary. Testimony of John Smith, November 9, 

2010, 153; Darryl Bourgoyne (Expert witness), email to Commission staff, December 24, 2010.

104 Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 17.

105 Ibid.

106 Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Increased Safety Measures for 

Energy Development on the Outer Continental Shelf, 75 Fed. Reg. 63346, 63373 (October 14, 2010); John

Smith (Expert witness), interview with Commission staff, October 26.
306 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

107 Murry Sepulvado, interview.

108 Internal BP document (BP-HZN-CEC 20352); Internal BP document (BP-HZN-CEC 20191-92); Internal 

BP document (BP-HZN-CEC 20264).

109 Internal BP document (BP-HZN-MBI 262896-97); Internal BP document (BP-HZN CEC 20196).

110 Testimony of Bill Ambrose, 291; Internal Transocean document (TRN-HCEC 5402).

111 Testimony of Bill Ambrose, 205-07.

112 Smith, interview, October 26, 2010; Darryl Bourgoyne (Expert witness), interview with Commission staff, 

October 26, 2010.

113 Guide, interview, January 19, 2010; Pat O‘Bryan (BP), interview with Commission staff, December 17, 

2010.

114 Murry Sepulvado, interview.

115 Internal BP document (BP-HZN-MBI 126180, 126189-90). Morel was certainly unfamiliar with whether 

there were any regulatory requirements for the negative pressure test. He asked in one email, apparently 

sent after the APM had been submitted, ―Anyone know if there is any requirements in the MMS regs for a 

negative test, can‘t find any specifics?‖ and later said ―If anyone else has any ideas of where something else 

might be let me know.‖ Internal BP document (BP-HZN-BLY 47094); Internal BP document (BP-HZN-MBI

128655).

116 Internal BP document (BP-HZN-MBI 126585-86).

117 Testimony of Jimmy Harrell, 26-28; Ezell, interview. Harrell‘s testimony indicates that the omission of 

the negative pressure test may have occurred during briefing on April 19 or April 20. Testimony of Jimmy 

Harrell, 76-77, 115-16. It seems difficult to understand that Kaluza would have omitted the test from a 

briefing on the morning of April 20, as he (1) had discussed the test during the rig call earlier that morning, 

(2) had asked Lindner how they conducted the negative pressure test on earlier wells after the rig call, and 

(3) had just received Morel‘s Ops Note, which included the negative pressure test. Gregory Walz (BP), 

interview with Commission staff, October 6, 2010; Testimony of Leo Lindner, 271-72; Internal BP document 

(BP-HZN-MBI 195580).

118 Independent experts have stated that these calculations should have been part of the temporary 

abandonment procedure. Testimony of John Smith, November 9, 2010, 147; Testimony of Darryl Bourgoyne, 

148.

119 Internal BP document (BP-HZN-CEC 20206).

120 Internal BP document (BP-HZN-BLY 61380).

121 Internal BP document (BP-HZN-MBI 133083).

122 According to Kaluza‘s account in his interview with BP investigators, he left the rig floor after Leo 

Lindner‘s 3 p.m. safety meeting and did not arrive until Wyman Wheeler was filling the riser with mud after 

the fluid level had fallen. Internal BP document (BP-HZN-CEC 20200-01). According to BP‘s own 

investigators‘ notes, Kaluza ―was in office and did not know volume.‖ Internal BP document (BP-HZN-CEC 

20207). However, Randy Ezell‘s testimony suggests that Kaluza may have been present at the time that he 

and the executive tour arrived at the drill shack. Testimony of Randy Ezell, 279-80.

123 If Kaluza was not on the rig floor as the annular leaked, it may explain his statement to investigators that 

―spacer was above the top annular‖ even though it had by this point migrated beneath it. Internal BP 

document (BP-HZN-CEC 20201); Internal BP document (BP-HZN-CEC 20174).

124 Murry Sepulvado, interview.

125 Darryl Bourgoyne (Expert witness), email to the Commission staff, December 18, 2010; Steve Lewis 

(Expert witness), email to Commission staff, December 29, 2010. BP wells team leader John Guide also 

stated that he would expect well site leaders to be in the drill shack when the negative pressure test is run. 

Guide, interview, January 19, 2011. BP management appears to encourage well site leader presence on the 

rig floor. Kaluza‘s most recent performance evaluation before the blowout criticized him for not spending 

enough time there, warning that safety could not be assured from sitting in the well site leader‘s office. It is 

not clear, however, what occasions the evaluation was referring to, as the Chief Counsel‘s team was unable to 

interview Kaluza or his evaluator. Kaluza was criticized for ―giving priority to WSL office preparation for 

meetings;‖ ―can‘t assure HSE [Health, Safety, and Environment] and rig operation performance or be aware 

of the details of how the crews are executing their jobs from WSL office;‖ ―he should spend more time on the 
Chief Counsel’s Report — Endnotes | 307

rig floor;‖ and ―should spend more time out on deck and other parts of the rig to work with the crews 

towards safety performance improvement.‖ Internal BP document (BP-HZN-MBI 193097). 

126 Internal BP document (BP-HZN-CEC 20207).

127 Internal BP document (BP- HZN-CEC 20174, 20185-87, 20201, 20204).

128 Lewis, email. A former well site leader has stated that while he would not have felt that examining it 

personally would have been required, he would have examined the spacer if his time allowed. Bourgoyne, 

email, December 28, 2010. 

129 Testimony of Mark Bly, 286-90; Testimony of Bill Ambrose, 286-90. Morel stated that his Ops Note 

directed that results of the positive pressure test on the surface cement plug were to be sent to Houston, but 

there was ―no similar requirement for negative test.‖ Internal BP document (BP-HZN-CEC 20235).

130Guide, interview, September 17, 2010; Internal BP document (BP-HZN-MBI 21306). 

131 Internal BP document (BP-HZN-MBI 21330); Internal BP document (BP-HZN-MBI 129616); Testimony 

of John Guide, July 22, 2010, 197.

Chapter 4.7

1

Transocean asserts that a reduced pump efficiency during the final displacement potentially ―skew[ed] the 

measurement of returns and potentially mask[ed] the entry of hydrocarbons into the well.‖ Transocean legal 

team, letter to Commission staff, November 5, 2010. Even if true, this assertion does not alter the Chief 

Counsel‘s team‘s findings. The analysis in this section is based on data anomalies that are apparent (despite 

any error in pump efficiency). A correct pump efficiency would only have made more anomalies apparent. 

Furthermore, if the pump efficiency did indeed decrease, rig personnel properly monitoring the data by 

performing volumetric calculations should have detected the change during the displacement itself and 

taken actions to resolve the discrepancy. Darryl Bourgoyne (Expert witness), interview with Commission 

staff, November 23, 2010. 

2 Rig personnel can augment an existing barrier, such as by increasing the weight of the mud in the well, or 

put in place a separate barrier, such as by closing in the well with the BOP.

3 Hearing to Review Recent Issues in Offshore Oil and Gas Development, Before the S. Comm. on Energy 

and Natural Resources, 111th Cong. (May 11, 2010)(statement of F.E. Beck, Texas A&M University).

4

There are several more parameters that rig personnel use to detect whether a kick is developing, including 

rate of penetration and changes in the salinity and electrical resistivity of mud. American Petroleum 

Institute, Recommended Practice for Well Control Operations 59, 2nd ed. (May 2006), 33 (―API RP 59‖).

5

Internal BP document (BP-HZN-BLY 61693).

6

API RP 59, 33; Doug Slitor (MMS), ―Drilling Operations and Equipment‖ (presentation to Commission 

staff, August 3, 2010), 33.

7

A displacement will also not appear to be closed-loop, even if all fluids come into and out of the pits, if the 

pits involved in the fluid transfer are not all selected as part of the active pit system. For example, when fluid 

going into the well is taken from an active pit, but fluid coming out of the well is returned to a reserve pit. 

8

Transocean personnel typically performed this calculation by hand, periodically throughout a

displacement. Allen Seraile (Transocean), interview with Commission staff, January 7, 2011. The Sperry-Sun

system may calculate volume-in automatically. Testimony of Joseph Keith (Halliburton), Hearing before the 

Deepwater Horizon Joint Investigation Team, December 7, 2010, part 1, 193. But it does not compare 

volume-in and volume-out to compute pit gain automatically. Testimony of John Gisclair (Halliburton), 

Hearing before the Deepwater Horizon Joint Investigation Team, December 7, 2010, part 2, 137.

9

Testimony of John Gisclair (Halliburton), Hearing before the Deepwater Horizon Joint Investigation Team, 

October 8, 2010, 100.

10 API RP 59, 33. Because the two numbers are derived in different ways (one a measurement, the other a 

calculation), the difference between them need not be zero so much as constant. Testimony of John Gisclair, 

October 8, 2010, 101. 

11 API RP 59, 33. 
308 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

12 Ibid., 34. Rig personnel should carefully investigate each of these other phenomena as well. Rig heave can 

be accounted for by monitoring for several heave cycles. Thermal expansion would be exceedingly slow and 

should be watched. And ballooning would have to be fingerprinted and applies only if open hole sections are 

exposed, which was not the case at the time of the Macondo explosion. Darryl Bourgoyne (Expert witness), 

email to Commission staff, December 16, 2010.

13 The amount of residual flow is rig-specific and can be as high as 120 barrels. Commission staff site visit to 

Deepwater Nautilus, September 9, 2010. 

14 Testimony of John Guide (BP), Hearing before the Deepwater Horizon Joint Investigation Team, October 

7, 2010, part 2, 199.

15 Testimony of John Guide, October 7, 2010, 199; Testimony of John Gisclair (Halliburton), Hearing before 

the National Commission, November 8, 2010, 230. ―When you‘re staring at these traces, you‘re going to have 

to wait a significant number of minutes in some cases to notice a certain trend.‖ Testimony of John Gisclair, 

November 8, 2010, 230. 

16 Drill pipe pressure is actually represented by stand pipe pressure. The stand pipe is a line connecting the 

pumps to the drill pipe (via the kelly hose and top drive). The pressure sensor is located on that line. 

Commission staff site visit to Deepwater Nautilus, September 9, 2010. 

17 Testimony of John Gisclair, October 8, 2010, 135. 

18 Bourgoyne, email, December 16, 2010.

19 Darryl Bourgoyne (Expert witness), interview with Commission staff, October 26, 2010; John Smith 

(Expert witness), interview with Commission staff, October 26, 2010.

20 Bourgoyne, interview, October 26, 2010; Smith, interview, October 26, 2010.

21 John Smith (Expert witness), interview with Commission staff, September 7, 2010.

22 API RP 59, 34.

23 Darryl Bourgoyne (Expert witness), email to Commission staff, November 23, 2010.

24 API RP 59, 34; Testimony of John Gisclair, October 8, 2010, 227-29; Bourgoyne, interview, October 26, 

2010; Smith, interview, October 26, 2010.

25 API RP 59, 34. But ―Until a confirmation can be made as to whether the cause is a hole or a well kick, a 

kick should be assumed.‖ Ibid.

26 Bourgoyne, interview, October 26, 2010; Smith, interview, October 26, 2010.

27 BP‘s decision tree on monitoring wellbore pressure, included in its Macondo well drilling program, 

identifies an increase in gas as an indication of increasing pore pressure and a reason to stop drilling and 

check for flow. Internal BP document (BP-HZN-BLY 39344).

28 Steve Lewis (Expert witness), interview with Commission staff, September 2, 2010.

29 Bourgoyne, email, December 16, 2010.

30 Internal Transocean document (TRN-HCEC 90727); Bill Ambrose (Transocean), interview with 

Commission staff, September 30, 2010.

31 Internal Halliburton document (MC252_001_ST00BP01_EOWR).

32 Ibid.

33 Testimony of John Gisclair, November 8, 2010, 233. ―Most of the data that is in that Sperry database was 

transmitted to us realtime from Transocean.‖ Ibid.

34 Internal BP document (BP-HZN-BLY 38391); Testimony of John Gisclair, November 8, 2010, 234.

35 Testimony of John Gisclair, November 8, 2010, 233; Testimony of Joseph Keith, 113.

36 Testimony of John Gisclair, October 8, 2010, 96; Commission staff site visit to Deepwater Nautilus, 

September 9, 2010; Internal Halliburton document (MC252_001_ST00BP01_EOWR).

37 Commission staff site visit to Deepwater Nautilus, September 9, 2010.
Chief Counsel’s Report — Endnotes | 309

38 Ibid.; Bill Ambrose (Transocean), interview with Commission staff, September 21, 2010; Testimony of 

John Gisclair, October 8, 2010, 109-10. Indeed, setting an alarm for pit volume change is typically standard 

operating procedure. Ibid., 109-10. 

39 Ronnie Sepulvado (BP), interview with Commission staff, October 26, 2010.

40 Joseph Keith (Halliburton), interview with Commission staff, October 6, 2010; Darryl Bourgoyne (Expert 

witness), interview with Commission staff, September 10, 2010; Commission staff site visit to Deepwater 

Nautilus, September 9, 2010. 

41 Testimony of John Gisclair, October 8, 2010, 99; Internal BP document (BP-HZN-MBI 21292).

42 Internal Halliburton document (MC252_001_ST00BP01_EOWR).

43 Testimony of John Gisclair, October 8, 2010, 97.

44 Internal BP document (BP-HZN-MBI 21292).

45 Testimony of John Gisclair, October 8, 2010, 109; Testimony of Joseph Keith, 113.

46 Another difference between the sensors was their mode of measurement. The Hitec flow-out sensor

measured flow-out in terms of a percentage of total flow; the Sperry-Sun sensor measured it in terms of 

gallons per minute. Randy Ezell (Transocean), interview with Commission staff, September 16, 2010. In 

terms of crew reliance, Transocean and BP rig personnel looked at the Hitec flow-out meter. Testimony of 

John Guide (BP), Hearing before the Deepwater Horizon Joint Investigation Team, July 22, 2010, 302. The 

Sperry Drilling mudlogger did not understand the readings from the Hitec flow-out sensor and did not rely 

on it. Keith, interview; Testimony of Joseph Keith, 172-73.

47 Testimony of Joseph Keith, 152-53.

48 Commission staff site visit to Deepwater Nautilus, September 9, 2010; Murry Sepulvado (BP), interview 

with Commission staff, December 10, 2010. Returns first go to the gumbo box, then split off to either the 

shakers or overboard. Commission staff site visit to Deepwater Nautilus, September 9, 2010.

49 Internal Transocean document (TRN-HCEC 90727). ―There were no reported discrepancies for pit 

volumes, [flow-out] indicators, mud pump strokes or weight,‖ and the inspectors‘ ―scan of the pages did not 

show any anomalies.‖ Ibid. All of the gauges were in good condition and had proper calibration labels; and 

the driller and electronics technician confirmed ―the condition of the drilling instruments and that the 

system operated without any problems.‖ Ibid. 

50 Testimony of Stephen Bertone (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, July 19, 2010, 30; Testimony of Michael Williams, Hearing before the Deepwater Horizon Joint 

Investigation Team, July 23, 2010, 42; Seraile, interview.

51 Testimony of Stephen Bertone, 195-96; Testimony of John Guide, July 22, 2010, 63; Testimony of Michael 

Williams, July 23, 2010, 104.

52 Testimony of Stephen Bertone, 197-200; Testimony of Michael Williams, 42, 99-101. On a prior well, a 

crash of the Horizon A-chair coincided with a well control incident. Ibid.

53 Testimony of John Guide, July 22, 2010, 63; Testimony of Stephen Bertone, 199; Testimony of Michael 

Williams, 102-03. They may have also replaced some of the chairs‘ software. Testimony of Paul Johnson 

(Transocean), Hearing before the Deepwater Horizon Joint Investigation Team, August 23, 2010, part 2, 

164. Transocean planned to entirely upgrade the hardware and software at a later date, after the Horizon left 

the Macondo well. Internal Transocean document (TRN-HCEC 90727); Testimony of Paul Johnson, 164. 

According to one witness, Transocean was waiting to see how the upgraded package worked on a sister rig 

before installing it on the Horizon. Testimony of Michael Williams, 99. 

54 Testimony of John Guide, July 22, 2010, 63; Testimony of Stephen Bertone, 200; Testimony of Paul 

Johnson, 164-65; Seraile, interview. 

55 Internal Transocean document (TRN-HCEC 90727).

56 Testimony of Stephen Bertone, 199. Even if the chairs had crashed on April 20, the Sperry-Sun system 

would have remained operational. Seraile, interview.

57 Testimony of Bill Ambrose (Transocean), Hearing before the National Commission, November 8, 2010, 

239; Testimony of John Gisclair, November 8, 2010, 240-41.

58 Internal BP document (BP-HZN-MBI 21442).
310 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

59 Testimony of Micah Burgess (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, May 29, 2010, 94-95.

60 Internal BP document (BP-HZN-BLY 38370, 38378).

61 Testimony of Mark Bly (BP), Hearing before the National Commission, November 8, 2010, 247-48; 

Testimony of Micah Burgess, 84.

62 Commission staff site visit to Deepwater Nautilus, September 9, 2010.

63 Testimony of Darryl Bourgoyne, 179.

64 Ibid.; Testimony of Micah Burgess, 84. ―Roles as the driller would be just to – I mean, to maintain, 

watching the well, know drilling, and make sure, you know, I had the authority to shut the well in at any time 

I had any doubt about anything.‖ Testimony of Micah Burgess, 84.

65 Internal BP document (BP-HZN-MBI 21434).

66 Ibid.; Testimony of Micah Burgess, 97. 

67 Testimony of Allen Seraile (Transocean), Hearing before the Deepwater Horizon Joint Investigation Team, 

May 29, 2010, 129-30.

68 Internal BP document (BP-HZN-MBI 139541).

69 Commission staff site visit to Deepwater Nautilus, September 9, 2010.

70 Seraile, interview.

71 Testimony of Mark Bly, November 8, 2010, 249.

72 Internal Halliburton document (MC252_001_ST00BP01_EOWR); Testimony of Mark Bly, November 8, 

2010, 249; Testimony of Joseph Keith, 18. ―Sperry Drilling Services (Unit # 82418) was contracted to 

perform surface data logging and pore pressure prediction services by BP Exploration and Production for the 

Macondo Prospect 001 ST00BP00 in Mississippi Canyon Block 252.‖ Internal Halliburton document 

(MC252_001_ST00BP01_EOWR).

73 Internal Halliburton document (MC252_001_ST00BP01_EOWR); Testimony of John Gisclair, October 8, 

2010, 140; Testimony of Joseph Keith, 27.

74 Testimony of Micah Burgess, 100.

75 Cathleenia Willis (Halliburton), interview with Commission staff, October 21, 2010.

76 Testimony of Joseph Keith, 22-23.

77 Internal BP document (BP-HZN-BLY 38334).

78 Internal Halliburton document (MC252_001_ST00BP01_EOWR); Willis, interview.

79 Testimony of Mark Bly, November 8, 2010, 247; Testimony of Ronnie Sepulvado (BP), Hearing before the 

Deepwater Horizon Joint Investigation Team, July 20, 2010, 78.

80 Bourgoyne, interview, September 10, 2010; Steve Lewis (Expert witness), interview with Commission 

staff, September 21, 2010; Ezell, interview. Transocean argues that the BP company man should monitor all 

critical operations and that the final displacement was a critical operation. Transocean legal team, interview 

with Commission staff, August 17, 2010. BP disagrees. Mark Bly (BP), interview with Commission staff, 

September 8, 2010.

81 Lee Lambert (BP), interview with Commission staff, September 17, 2010; Ezell, interview; Testimony of 

Joseph Keith, 110-11; Ronnie Sepulvado (BP), interview with Commission staff, August 20, 2010.

82 Internal BP document (BP-HZN-MBI 21458).

83 Ibid.

84 Ezell, interview.

85 Internal BP document (BP-HZN-MBI 21456).

86 Ezell, interview.

87 Internal BP document (BP-HZN-MBI 21448).
Chief Counsel’s Report — Endnotes | 311

88 Commission staff site visit to Deepwater Nautilus, September 9, 2010; Ezell, interview.

89 This feature was called INSITE Anywhere. Testimony of Michael Beirne (BP), Hearing before the 

Deepwater Horizon Joint Investigation Team, October 6, 2010, part 2, 18-19, 34.

90 Testimony of Bill Ambrose, 240; Testimony of John Guide, July 22, 2010, 418-419.

91 Testimony of Brett Cocales, Hearing before the Deepwater Horizon Joint Investigation Team, August 27, 

2010, 233-35.

92 Testimony of John Guide, October 7, 2010, 152; Internal Halliburton document 

(MC252_001_ST00BP01_EOWR); Internal Halliburton document (HAL_50546)(log showing BP, 

Anadarko, MOEX, and Halliburton personnel accessing INSITE).

93 Testimony of Michael Beirne, 18-19. Co-owners Anadarko and MOEX had a contractual right to the data, 

and their personnel accessed it. Ibid., 18-19, 96-97; Internal BP document (BP-HZN-MBI 173481-83, 174919, 

175868).

94 Testimony of Mark Bly, November 8, 2010, 234; Testimony of Mark Bly (BP), Hearing before the National 

Academy of Engineering, September 26, 2010; Mike Zanghi (BP), interview with Commission staff, 

December 15, 2010; Internal BP document (BP-HZN-MBI 175868).

95 Testimony of John Gisclair, October 8, 2010, 103; Internal Halliburton document 

(MC252_001_ST00BP01_EOWR).

96 Testimony of John Gisclair, October 8, 2010, 107-08; Testimony of John Gisclair, December 7, 2010, 25-

26.

97 Testimony of Brett Cocales, 234; Testimony of Joseph Keith, 242.

98 Testimony of Paul Johnson, 332; Testimony of Bill Ambrose, 240. 

99 Testimony of Bill Ambrose, 238.

100 Commission staff site visit to Deepwater Nautilus, September 9, 2010; Testimony of Bill Ambrose, 223.

Some data display systems record metadata of user settings including what screen the user has up at any 

given time, what alarm thresholds the user has set, when an alarm activates, and when the user 

acknowledges an alarm. Dan Jenkins (Oilfield Instrumentation), interview with Commission staff, 

November 12, 2010. This does not appear to have been the case with the Sperry-Sun and Hitec systems on 

the Deepwater Horizon.

101 Testimony of Bill Ambrose, 223.

102 Testimony of John Gisclair, November 8, 2010, 228.

103 Keith, interview; Seraile, interview; Ronnie Sepulvado, interview, October 26, 2010. 

104 Ronnie Sepulvado, interview, October 26, 2010.

105 Testimony of Bill Ambrose, 224; Testimony of John Gisclair, October 8, 2010, 107, 122; Testimony of 

John Gisclair, December 7, 2010, 70; Willis, interview. The driller would have had standpipe or drill pipe 

pressure on his screen. Testimony of Bill Ambrose, 224.

106 Testimony of John Gisclair, November 8, 2010, 230.

107 Internal BP document (BP-HZN-MBI 133083).

108 Internal BP document (BP-HZN-MBI 139541).

109 Internal BP document (BP-HZN-MBI 21387).

110 Testimony of Charles Credeur (Dril-Quip), Hearing before the Deepwater Horizon Joint Investigation 

Team, May 29, 2010, 62-63; Testimony of Heber Morales (Transocean), Hearing before the Deepwater 

Horizon Joint Investigation Team, May 29, 2010, 143-44; Internal BP document (BP-HZN-MBI 129622); 

Brandon Bouillion (Weatherford), interview with Commission staff, October 22, 2010. One of an assistant 

driller‘s responsibilities is to make up connections and equipment. Internal BP document (BP-HZN-MBI 

21434).

111 Internal BP document (BP-HZN-MBI 139543); Testimony of John Gisclair, November 8, 2010, 249.

112 Internal BP document (BP-HZN-MBI 21406); Sperry-Sun data, April 20, 2010, 20:02. ―Sperry-Sun data‖

references an internal Halliburton document (HAL_48973-74).
312 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

It appears that the crew had a short meeting in the drill shack prior to displacing the riser. The details of the 

meeting are unclear. The drill crew typically uses such meetings to review the remaining steps in the 

operation and discuss expected volumes and pump strokes, but not pressures. Caleb Holloway (Transocean), 

interview with Commission staff, December 20, 2010; Seraile, interview. 

113 Testimony of John Gisclair, October 8, 2010, 129.

114 Testimony of Joseph Keith, 98, 190.

115 Testimony of Joseph Keith, 99; Testimony of Ronnie Sepulvado, July 20, 2010, 137.

116 Testimony of Joseph Keith, 146; Sperry-Sun data, April 20, 2010. 

117 John Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252 (July 1, 

2010), 13.

118 Testimony of Leo Lindner (M-I SWACO), Hearing before the Deepwater Horizon Joint Investigation 

Team, July 19, 2010, 275.

119 John Gisclair (Halliburton), interview with Commission staff, September 20, 2010; Seraile, interview.

120 This behavior was expected. Testimony of Joseph Keith, 134.

121 Transocean legal team, ―April 20 End of Well Activities‖ (presentation to Commission staff, November 5, 

2010); Sperry-Sun data, April 20, 2010.

122 Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 13.

123 Gisclair, interview.

124 Testimony of Joseph Keith, 178-81.

125 Testimony of Bill Ambrose, 220. 

126 BP, Deepwater Horizon Accident Investigation Report (September 8, 2010), 25.

127 Internal BP document (BP-HZN-BLY 61369-74); Internal BP document (BP-HZN-MBI 21406).

128 Testimony of Joseph Keith, 50.

129 Ibid., 51, 102, 114-15.

130 Ibid., 102, 183-84.

131 Ibid., 102 (―Five minutes, eight minutes. No longer than that.‖), 184 (―About 10 minutes. That‘s what it 

seemed like.‖).

132 Nonpublic Transocean document (presentation to Commission staff, August 5, 2010), 14; BP, Deepwater 

Horizon Accident Investigation Report, 25-26.

133 BP, Deepwater Horizon Accident Investigation Report, 92. ―At that point in time it masked what was the 

biggest inflow at that point.‖ Testimony of Bill Ambrose, 221. ―It would have been impossible to tell in 

realtime what increase might have been due to the trip tank drain or what increases might have been due to 

a well influx.‖ Testimony of John Gisclair, December 7, 2010, 12-14, 55.

134 Testimony of John Gisclair, November 8, 2010, 229. Emptying the trip tanks does not affect drill pipe 

pressure, so that action does not explain the increase. Bill Ambrose (Transocean), interview with 

Commission staff, August 17, 2010.

135 Testimony of John Gisclair, November 8, 2010, 228; Bly, interview; Willis, interview.

136 Testimony of John Gisclair, November 8, 2010, 228; BP, Deepwater Horizon Accident Investigation 

Report, 92; Seraile, interview; Willis, interview.

137 Testimony of Joseph Keith, 238. 

138 Internal BP document (BP-HZN-MBI 170828).

139 Testimony of Joseph Keith, 120-21, 196.

140 Internal BP document (BP-HZN-MBI 139549).

141 Ibid.
Chief Counsel’s Report — Endnotes | 313

142 The Deepwater Horizon’s residual flow signature was a straight line evenly going down. Seraile, 

interview.

143 Ambrose, interview, September 21, 2010.

144 Sperry-Sun data, April 20, 2010; Internal BP document (BP-HZN-MBI 139549). 

145 Steve Lewis (Expert witness), interview with Commission staff, September 7, 2010; Darryl Bourgoyne

(Expert witness), interview with Commission staff, November 23, 2010; Keith, interview (watched flow line 

for 30 to 45 seconds); Seraile, interview (Horizon residual flow was typically three to five minutes). 

According to assistant driller Seraile, a credible visual confirmation of no flow required five to seven minutes 

after the pumps stopped. Here, the crew diverted returns within two minutes. Seraile, interview. 

146 Gisclair, interview; Bourgoyne, interview, November 23, 2010.

147 Internal BP document (BP-HZN-MBI 13950); Gisclair, interview.

148 Seraile, interview; Murry Sepulvado, interview; Ronnie Sepulvado, interview, August 20, 2010. 

149 Bourgoyne, email, December 16, 2010.

150 The non-zero reading on the Sperry-Sun flow-out sensor, from 9:09 to 9:21 p.m., likely reflects fluid left 

over in the flow line after the gate to route returns overboard closed. Gisclair, interview; Bly, interview; 

Smith, interview, October 26, 2010.

151 Testimony of Jimmy Harrell (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, May 27, 2010, 28; Internal BP document (BP-HZN-MBI 21305).

152 Transocean legal team, interview, August 17, 2010 (sustained drill pipe pressure increase was 

anomalous); Testimony of John Gisclair, October 8, 2010, 135 (―a curiosity‖); BP, Deepwater Horizon

Accident Investigation Report, 93 (anomalous); Smith, interview, September 7, 2010 (fishy). 

153 Ambrose, interview, September 21, 2010; Testimony of John Gisclair, October 8, 2010, 228-29 (―So it‘s 

not your typical indicator of a kick but it, again, is something to give pause‖). 

154 Testimony of Bill Ambrose, 225-26. This underscores the notion that current kick detection methodology 

depends on the right person being in the right place at the right time. Ibid., 246. 

155 Keith testified that, if he had seen the increase, he would have notified the drill crew. Testimony of Joseph 

Keith, 215. 

156 Ibid., 216, 230-31.

157 The PRV exists ―for the purpose of protecting the pump from excessive high-pressure overloads.‖ Internal 

BP document (BP-HZN-BLY 49091). The PRV is generally ―piped directly into the mud tanks‖ so that, when 

it blows, fluid goes to the pits. Ibid. On the Horizon, the PRVs were probably routed to the slugging pit. 

Internal Transocean document (TRN-HCEC 68478). When the PRV blew, the data showed a gain in the 

slugging pit (pit 11). 

158 Seraile, interview; BP, Deepwater Horizon Accident Investigation Report, 97; Keith, interview. It is 

unlikely that the PRV blew because of pressure from the well. John Smith (Expert witness), interview with 

Commission staff, October 14, 2010.

159 Holloway, interview. That group also included Adam Weise, Shane Roshto, and Roy Wyatt Kemp.

160 Testimony of Bill Ambrose, 380-82. That valve is on the choke manifold, on the rig floor. Commission 

staff site visit to Deepwater Nautilus, September 9, 2010; Holloway, interview; Seraile, interview.

161 Testimony of Randy Ezell (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, May 28, 2010, 282.

162 Testimony of Bill Ambrose, 384; Testimony of John Gisclair, October 8, 2010, 138.

163 Testimony of Bill Ambrose, 80-82. ―When that happened, it had a very strange trend, and over a period of 

about seven minutes it started to build pressure.‖ Ibid.

164 Experts have suggested at least two explanations for this anomaly. One explanation is that the kill line 

pressure was anomalous because it did not sufficiently match the drill pipe pressure. Testimony of Bill 

Ambrose, 381. Another explanation is that the kill line pressure was anomalous because it was higher than it 

should have been, at a time when the crew was not pumping fluid down the kill line. In this latter scenario, 
314 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

the crew closed the kill line valve once they saw the pressure rising. Bourgoyne, interview, November 23, 

2010.

165 Testimony of Bill Ambrose, 384. ―The anomaly was that now that the kill line had been opened, the 

differential was causing some concern.‖ Ibid.

166 Ibid.

167 Testimony of David Young (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, May 27, 2010, 258-59. Tabler entered shortly afterward. Ibid., 276.

168 David Young (Transocean), interview with Commission staff, November 19, 2010.

169 Testimony of David Young, 276. 

170 Young, interview.

171 Testimony of David Young, 276.

172 Seraile, interview; Smith, interview, September 7, 2010.

173 ―With months of work we‘ve determined that it appears as the kick was coming in, the influx was coming 

in, it was changing heights of fluid columns in the well. And the geometry of the well was such that as the 14-

pound mud that was – When this all started, there was about 500 barrels of 14-pound mud below the drill 

pipe, and that had been pushed up into the BOP, and as it hit the BOP it was – it kept a constant pressure, a 

sign that fluids are moving.‖ Testimony of Bill Ambrose, 380-82. ―The drill pipe pressure increased until 

21:35 hours as 14.17 ppg mud rose above the stinger and then declined after that as hydrocarbons rose above 

the stinger. Modeling indicated that this fluctuation was consistent with the change in fluid densities (spacer, 

seawater, mud and hydrocarbons) moving through the various cross-sectional areas in the well.‖ BP, 

Deepwater Horizon Accident Investigation Report, 101. Fluid flow is complex. The two-phase flow pattern, 

in which gas migrates up through the mud instead of completely displacing the mud, can effect unexpected 

pressure fluctuations. Adam T. Bourgoyne, Jr., ―University uses on-campus abandoned well to simulate 

deepwater well-control operations,‖ Oil and Gas Journal (May 31, 1982), 141; Peter G. McFadden, ―The 

Pressure Behavior of a Shut-In Well Due to the Upward Migration of a Gas Kick‖ (thesis, December 1984), 8-

9. 

174 Holloway, interview.

175Ibid.; Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 14; BP, 

Deepwater Horizon Accident Investigation Report, 100.

176 Holloway, interview.

177 Ibid.

178 Testimony of Bill Ambrose, 381.

179 Testimony of John Gisclair, November 8, 2010, 30.

180 Seraile, interview; Internal Transocean document (TRN-HCEC 5415). It is the responsibility of the drill 

crew ―to shut-in the well as quickly as possible if a kick is indicated or suspected.‖ Ibid. Shutting in the well 

also would have involved notifying senior Transocean and BP personnel. Ibid.

181 Testimony of David Young, 259-60.

182 Ibid., 297.

183 Young, interview.

184 Ibid.

185 Ibid.

186 Ibid.

187 Holloway, interview.

188 Testimony of Joseph Keith, 20-21.

189 Testimony of Charles Credeur, 62-63; Bouillion, interview. BP estimates mud overflow at 9:40 p.m. BP, 

Deepwater Horizon Accident Investigation Report, 103; Transocean estimates it at 9:43 p.m. Testimony of 

Bill Ambrose, 383. 
Chief Counsel’s Report — Endnotes | 315

190 Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 14. It 

appears that it was the Horizon‘s practice to ―monitor the flow from the riser via the flowline to the trip 

tank.‖ Internal Transocean document (TRN-HCEC 25883); Seraile, interview; Ezell, interview.

191 Testimony of Chris Pleasant, 166 (BOP panel showed lower annular closed); Testimony of Bill Ambrose,

252; BP, Deepwater Horizon Accident Investigation Report, 104. Though testimony indicates that Anderson 

activated the lower annular, Transocean has contended that the rig crew in fact activated the upper annular, 

not the lower annular. 

192 Internal BP document (BP-HZN-MBI 139551); Internal BP document (BP-HZN-MBI 21421); Internal BP 

document (BP-HZN-MBI 142485); Internal BP document (BP-HZN-CEC 20334); Internal BP document 

(BP-HZN-CEC 20357); BP, Deepwater Horizon Accident Investigation Report, 103.

193 Testimony of Randy Ezell, 283.

194 Testimony of Yancy Keplinger (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, October 5, 2010, part 1, 150, 219, 254-55; Testimony of Andrea Fleytas (Transocean), Hearing before 

the Deepwater Horizon Joint Investigation Team, October 5, 2010, part 2, 13, 39. Floorhand Caleb Holloway 

called Revette via radio during this time but received no response. David Barstow, David Rohde, and 

Stephanie Saul, ―Deepwater Horizon‘s Final Hours,‖ New York Times, December 25, 2010.

195 Internal BP document (BP-HZN-MBI 139551).

196 Testimony of Randy Ezell, 283.

197 Testimony of Yancy Keplinger, 149, 219.

198 Ibid., 252. 

199 Testimony of Paul Meinhart (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, May 29, 2010, 29. Meanwhile, Young had gone by the subsea office and mentioned to Chris Pleasant 

and Allen Seraile that the cement job was delayed because they were ―having some sort of differential 

pressure problem‖ up on the rig floor. Pleasant and Seraile (who was getting ready to come on tour) turned 

to live video feed of the rig floor and saw the mud. Pleasant instantly picked up the phone and called the rig 

floor—all three lines—but got no answer. Young, interview; Testimony of Chris Pleasant, 103-04, 121. 

200 Bly, interview.

201 BP, Deepwater Horizon Accident Investigation Report, 103-04; Testimony of Bill Ambrose, 252-53. It is 

worth noting that Pleasant and Vidrine, once on the bridge, looked at the BOP panel and saw only an 

indication that an annular had been activated, not the variable bore ram. Internal BP document (BP-HZNMBI 21420); Internal BP document (BP-HZN-MBI 142485).

202 Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 23-24; BP, 

Deepwater Horizon Accident Investigation Report, 146. 

203 Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 15; 

Bourgoyne, email, November 23, 2010; Testimony of Joseph Keith, 124.

204 Internal BP document (BP-HZN-MBI 21424); Internal BP document (BP-HZN-MBI 21427).

205 Internal BP document (BP-HZN-MBI 21424); Internal BP document (BP-HZN-MBI 139551).

206 Testimony of Chad Murray (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, May 27, 2010, 335-36.

207 Internal BP document (BP-HZN-MBI 21267). Keith did not notice any anomalies in the data during the 

displacement, with the exception of one instance of pit gain that he learned reflected emptying of the sand 

traps. Testimony of Joseph Keith, 178-81, 193. The first time Keith became aware that the well was flowing 

was, ―When it sounded like it was raining outside my unit and I started smelling gas coming through my 

purge system.‖ Ibid., 32.

208 Testimony of Jimmy Harrell, 64, 128-129118.

209 BP, Transocean, and Halliburton representatives all agree that if skilled personnel had observed the 

Sperry-Sun data, they would have noticed indicators sufficiently clear to cause alarm. Testimony of Mark 

Bly, November 8, 2010, 241-42; Testimony of Bill Ambrose, 241-42; Testimony of John Gisclair, November 

8, 2010, 241-42.

210 Some have suggested that the rig pumping mud to the Damon Bankston interfered with well monitoring 

during the final displacement. Donald Winter et al., Interim Report on Causes of the Deepwater Horizon Oil 
316 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Rig Blowout and Ways to Prevent Such Events (November 17, 2010), 10-11. This is incorrect. Pumping to 

the Bankston had ceased by 5:17 p.m., well before the start of the displacement of the riser. Internal BP 

document (BP-HZN-MBI 139482).

211 Murry Sepulvado, interview.

212 Internal BP document (BP-HZN-BLY 61692); Ronnie Sepulvado, interview, October 26, 2010; Seraile, 

interview.

213 Bourgoyne, email, November 23, 2010. ―The rig crew could decide to fill pits in the active system from the 

sea chest system, then line up the pump to those pits.‖ Ibid.

214 It is worth noting that, even if the gas meter were used for monitoring, it is likely that rig personnel would 

not have seen gas until after most of the mud was ejected from the well. Bourgoyne, email, December 16, 

2010.

215 Earlier in the evening, the crew had been using the cranes to off-load equipment onto a supply ship. The 

starboard crane had been down for repair. Testimony of Heber Morales, 143. By the time of the 

displacement, it was apparently working and in use. Young, interview. The crew may have been testing it. 

Internal BP document (BP-HZN-MBI 139588); Testimony of Joseph Keith, 35. Or they may have resumed 

off-loading equipment. There was also a crane operator in the gantry crane on the port aft deck helping the 

rig personnel at the bucking unit put together the tools necessary for running the lockdown sleeve. 

Testimony of Micah Sandell (Transocean), Hearing before the Deepwater Horizon Joint Investigation Team, 

May 29, 2010, 7-8; Testimony of Heber Morales, 143-44; Testimony of Ross Skidmore (Swift), Hearing 

before the Deepwater Horizon Joint Investigation Team, July 20, 2010, 217-19; Testimony of Joseph Keith, 

35; Internal BP document (BP-HZN-MBI 129622); Internal BP document (BP-HZN-MBI 139583); Internal 

BP document (BP-HZN-MBI 139588); Internal BP document (BP-HZN-MBI 21277).

216 Internal BP document (BP-HZN-MBI 21441).

217 Testimony of John Gisclair, October 8, 2010, 102; Testimony of Joseph Keith, 35, 198; Willis, interview.

218 API RP 59, 46. Persistent rig movement can also make it difficult to calibrate the flow-out sensor. 

Testimony of Joseph Keith, 24-25.

219 Bourgoyne, email, December 16, 2010; Testimony of Joseph Keith, 25.

220 Testimony of Jimmy Harrell, 28; Testimony of Leo Lindner, 279; BP, Deepwater Horizon Accident 

Investigation Report, 91; Internal BP document (BP-HZN-MBI 21305).

221 Testimony of Leo Lindner, 272; Testimony of Joseph Keith, 191; Internal BP document (BP-HZN-MBI 

21250). 

222 Testimony of Bill Ambrose, 221; Ambrose, interview, August 17, 2010.

223 Ambrose, interview, August 17, 2010; Testimony of John Smith (Expert witness), Hearing before the 

Deepwater Horizon Joint Investigation Team, July 23, 2010, 297.

224 Gisclair, interview; Ronnie Sepulvado, interview, August 20, 2010. Another example is the rig‘s flow-out 

meters. According to BP well site leader Ronnie Sepulvado, the rig‘s flow-out meters ―had inherent 

variability and were not completely accurate.‖ Internal BP document (BP-HZN-BLY 61694). Measuring flowout can be challenging because there are few flow-out meters able to handle such a wide variety of fluids and 

pump rates. Bourgoyne, interview, September 10, 2010; Testimony of John Smith, 295.

225 Testimony of John Gisclair, October 8, 2010, 102.

226 Testimony of Mark Bly, November 8, 2010, 246-47; Testimony of Bill Ambrose, 246-47.

227 Commission staff site visit to Deepwater Nautilus, September 9, 2010; Ambrose, interview, September 

21, 2010; Testimony of John Gisclair, October 8, 2010, 109-10.

228 Testimony of John Gisclair, October 8, 2010, 109-10.

229 BP, Deepwater Horizon Accident Investigation Report, app. W.

230 Testimony of Darryl Bourgoyne, 170-72. 

231 Testimony of John Gisclair, November 8, 2010, 228. ―The standpipe pressure, especially that first 

increase, it basically draws a straight line, and it‘s very difficult to spot that 100-pound increase over that 

extended period using that particular presentation.‖ Ibid. 
Chief Counsel’s Report — Endnotes | 317

232 Representatives from BP, Transocean, and Sperry-Sun all agree that kick indications were clear enough 

that, if observed by skilled personnel, they would have allowed the rig crew to have responded earlier. 

Testimony of Bill Ambrose; Testimony of John Gisclair, November 8, 2010, 242; Testimony of Mark Bly, 

November 8, 2010, 242.

233 Of the kicks that occurred during drilling operations, a ―majority of them were observed when drilling 

new hole.‖ Per Holand and Pal Skalle, Deepwater Kicks and BOP Performance (SINTEF, July 2001), 11, 45. 

It is worth noting that Transocean specifically drilled its crew for this situation. Internal Transocean 

document (TRN-USCG_MMS 30540). 

234 Per Holand and Pal Skalle, Deepwater Kicks and BOP Performance, 11, 45-46. 

235 John Guide (BP), interview with Commission staff, January 19, 2011 (if they had already passed the 

negative test, it maybe would not be surprising if he did not check for flow all the time); Testimony of John 

Smith, 301 (―They think they‘ve already proven that the well is safe...if it‘s sealed up and you‘ve proved it‘s 

sealed up and it‘s not going to leak, well, that‘s a reason to [reduce] your rigor.‖); Bourgoyne, interview, 

September 10, 2010; Lewis, interview, September 21, 2010.

236 Internal Transocean document (TRN-PC 3227); David Borthwick, Report of the Montara Commission of 

Inquiry (The Montara Commission of Inquiry, Australia, June 2010), 116.

237 Internal Transocean document (TRN-PC 3227); David Borthwick, Report of the Montara Commission of 

Inquiry (The Montara Commission of Inquiry, Australia, June 2010), 116.

238 Anadarko legal team, interview with Commission staff, September 29, 2010; Testimony of Steve Lewis 

(Expert witness), Hearing before the National Commission, November 9, 2010, 65, 79-80.

239 Local Impact of the Deepwater Horizon Oil Spill, Before Subcomm. on Oversight and Investigations of 

the H. Comm. on Energy and Commerce, 111th Cong. (2010)(statement of Courtney Kemp), 62 (deceased 

husband characterized well as having ―so many problems and so many things were happening...it was just 

kind of out of hand‖); Testimony of Micah Burgess, 117 (―It was a difficult well.‖); Internal BP document (MC 

252-1_DDR)(the Macondo well sustained numerous lost circulation events, two previous kicks, a ballooning 

event, and trouble with LOTs); E.C. Thomas (Expert witness), interview with Commission staff, October 27, 

2010 (the Horizon crew encountered more problems than usual).

240 Internal BP document (BP-HZN-CEC 20200); Ross Skidmore (Swift), interview with Commission staff, 

December 21, 2010 (after the last casing string is run, floorhands are often doing preventative maintenance 

duties and thinking about the next job); Testimony of Greg Meche (M-I SWACO), Hearing before the 

Deepwater Horizon Joint Investigation Team, May 28, 2010, 216-217.

241 Testimony of Ross Skidmore, 263-64.

242 Murry Sepulvado, interview (always monitors final displacements from the rig floor); Guide, interview, 

January 19, 2011 (would have expected the well site leader to be watching the data during the displacement 

and performing flow checks himself); Bourgoyne, email, November 23, 2010. After the explosion, well site 

leader Don Vidrine apparently felt ―like he should have been on the [rig] floor when this happened.‖ Internal 

BP document (BP-HZN-BLY 72265).

243 This critique would apply equally to the Sperry Drilling mudlogger, if he had noticed the pressure 

anomalies. There is no evidence that he did.

244 In addition to the anomalies discussed in this chapter, the negative pressure test repeatedly showed that 

the bottomhole cement job did not isolate hydrocarbons (Chapter 4.6). Testimony of Mark Bly, November 8, 

2010, 203-04. 

245 Testimony of Bill Ambrose, 381; Seraile, interview.

246 Testimony of John Gisclair, November 8, 2010, 30.

247 Testimony of Bill Ambrose, 380-86.

248 Ibid.

249 Ibid., 205, 207, 277; Transocean legal team, interview with Commission staff, December 10, 2010.

250 Testimony of Bill Ambrose, 205 (―when the approval came back [from BP] that it was a good negative 

test, our people proceeded ahead on good faith that it was a good test‖); Transocean legal team, interview, 

December 10, 2010.

251 Transocean legal team, interview, December 10, 2010.
318 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

252 BP‘s Engineering Technical Practice on Simultaneous Operations (GP 10-75) directs its personnel to 

conduct a risk assessment of simultaneous operations ―in order to identify the risks across the complete 

range of well activities‖ and to ―ensure all well activities...are carried out in a safe and controlled manner, 

when these activities are performed in the same space and time as another operation.‖ Internal BP document 

(BP-HZN-OSC 8019). It is not clear whether BP personnel associated with the Deepwater Horizon

conducted any such risk assessment with respect to rig activities going on during the final displacement 

operation. At least one witness has suggested that other well site leaders would not have allowed so many rig 

operations. Keith, interview. 

253 Testimony of John Gisclair, November 8, 2010, 218; Smith, Review of Operational Data Preceding 

Explosion on Deepwater Horizon in MC252, 22.

254 For example, Transocean suggests that the driller may have watched the screens for 60 seconds and then 

turned his back to line up pump 2. Testimony of Bill Ambrose, 225-26.

255 Ezell, interview; Testimony of Paul Johnson, 329-30.

256 Transocean legal team, interview with Commission staff, September 21, 2010; Testimony of Paul 

Johnson, 389 (design decisions affect the crew‘s ability to control the well). 

257 ―Prior to commencing operations, it is advisable that all involved parties understand the objectives, 

procedures, and hazards. All personnel should be encouraged to report abnormal conditions. Alertness and 

speed of communication are critical factors in well control.‖ API RP 59, 40. 

258 The pre-tour meetings that day did not involve any special instructions about the negative pressure test or 

kick detection. Seraile, interview. ―I guess they figured it was going to go the same way as having all these 

other barriers in place.‖ Ibid.

259 Guide, interview, January 19, 2011 (would expect rig crew and well site leader to perform direct visual 

flow checks—not just rely on telemetry—whenever they shut down the pumps).

260 Industry experts recommend a well control plan be ―worked out beforehand.... To be successful, 

subsurface conditions must be predicted, detected, and controlled.‖ API RP 59, 35. It is unlikely that the 

Horizon‘s driller knew what drill pipe pressures to expect during the displacement. Ambrose, interview, 

September 21, 2010. 

261 Rig personnel could communicate with each other through radio, telephone, overhead pages, and 

messenger. Willis, interview; Seraile, interview.

262 Both Ronnie and Murry Sepulvado, alternative BP well site leaders for the Horizon, took actives role in 

ensuring proper communication between the drill crew and mudlogger. They did so by periodically speaking 

with the drill crew and mudlogger when there was a change in rig operations and confirming that the two 

entities had kept each other informed of the change. Murry Sepulvado, interview; Willis, interview.

263 Willis, interview.

264 Ibid.

265 Testimony of Joseph Keith 31-32.

266 This included that the drill crew was switching returns from the active pits to the reserve pits, dumping 

the sand traps into the active pits, emptying the trip tanks, transferring fluid from the active pits (pits 9 and 

10) to reserve pit 6 during the sheen test, and fixing a blown PRV. Ibid., 40, 178, 193; Keith, interview.

267 Testimony of Joseph Keith, 177-78; Transocean legal team, interview, December 10, 2010.

268 Testimony of John Gisclair (Halliburton), Hearing before the National Academy of Engineering, 

September 26, 2010, 18, 63.

269 Ibid.; Willis, interview.

270 Internal BP document (BP-HZN-MBI 193469).

271 Internal BP document (BP-HZN-CEC 20094).

272 Internal BP document (BP-HZN-OSC 5641-44). 

273 Internal BP document (BP-HZN-MBI 193469); Internal BP document (BP-HZN-CEC 20094).

274 Internal BP document (BP-HZN-CEC 20094).

275 Internal BP document (BP-HZN-MBI 128017). 
Chief Counsel’s Report — Endnotes | 319

276 Internal BP document (BP-HZN-MBI 128018).

277 David Sims (BP), interview with Commission staff, December 14, 2010.

278 Internal BP document (BP-HZN-OSC 5522). 

279 Internal BP document (BP-HZN-MBI 127999, 128002, 128018-20); Zanghi, interview.

280 Internal BP document (BP-HZN-MBI 128002, 128018).

281 Zanghi, interview; Internal BP document (128017)(ERA would focus ―primarily on the execute stage of 

well construction‖); Internal BP document (128017, 128002, 128018)(preset configurations for drilling, 

tripping, running casing, and cementing; no mention of abandonment or completion). 

282 Internal BP document (BP-HZN-MBI 127996, 128009). 

283 Testimony of Pat O‘Bryan (BP), Hearing before the Deepwater Horizon Joint Investigation Team, August

26, 2010, 412; Testimony of Brett Cocales, 233.

284 Testimony of Brett Cocales, 233-35; Testimony of Gregory Walz (BP), Hearing before the Deepwater 

Horizon Joint Investigation Team, October 7, 2010, part 2, 21. It is worth noting that, after the blowout, BP 

has been re-evaluating its planned ERA program and is in the process of reshaping it to include more 

attention to well control issues. Zanghi, interview.

285 Internal BP document (BP-HZN-OSC 4095).

286 Ibid. 

287 Internal BP document (BP-HZN-MBI 213677).

288 Internal BP document (BP-HZN-OSC 4095); Internal Halliburton documents (MC252_001_ST00BP00 

Sperry Rpt 037); Internal Halliburton document (MC252_001_ST00BP01_EOWR); Internal BP document 

(BP-HZN-MBI 213677)(there was a 35- to 40-barrel influx).

289 Internal BP document (BP-HZN-OSC 4095); Seraile, interview.

290 Internal BP document (BP-HZN-MBI 197360).

291 Guide, interview, January 19, 2011.

292 Internal BP document (BP-HZN-OSC 1490); Internal BP document (BP-HZN-OSC 1493).

293 BP, Deepwater Horizon Accident Investigation Report, 107; Internal BP document (BP-HZN-MBI 

113015); Internal BP document (BP-HZN-MBI 198127). One TIGER team member went to the Deepwater 

Horizon for several days to implement the suggested improvements.

294 Internal BP document (BP-HZN-MBI 198126, 113018-19)(emphasis added)(―The entire breadth of porepressure indicators need to be evaluated under higher scrutiny.... Thus far on this well, it has been shown 

that one or more pore-pressure indicators have provided ambiguous or even contradictory data. A more 

robust analysis of all indicators would allow us to better discern systemic pore-pressure changes from 

localized anomalies.‖).

295 Internal BP document (BP-HZN-MBI 113018).

296 BP, Deepwater Horizon Accident Investigation Report, 107; Internal BP document (BP-HZN-BLY 

61465). Although BP personnel deemed the drill crew‘s response inadequate, Transocean personnel did not. 

Transocean legal team, interview, September 21, 2010.

297 John Guide (BP), interview with Commission staff, September 17, 2010.

298 Internal BP document (BP-HZN-MBI 113018).

299 Internal BP document (BP-HZN-BLY 61465-66).

300 Guide, interview, January 19, 2011.

301 Internal BP document (BP-HZN-MBI 113018-19)(―drilling practices,‖ ―drilling techniques,‖ ―drilling 

parameters‖).

302 Internal Transocean document (TRN-HCEC 16041).

303 Internal Transocean document (TRN-HCEC 15880).
320 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

304 Internal Transocean document (TRN-HCEC 16041).

305 Ibid.

306 Internal BP document (BP-HZN-BLY 38354-55, 38357-58). The desired completion fluid was base oil, so 

the plan was to clean up the well by swapping out mud first to seawater and then to base oil. Internal BP 

document (BP-HZN-BLY 38357-58). 

307 ―The seawater was pumped via one pit with a constant top up (no volume control).‖ Internal BP 

document (BP-HZN-BLY 38358). 

308 Internal BP document (BP-HZN-BLY 38354-55, 38357-58). 

309 Testimony of Daun Winslow (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, August 24, 2010, 139.

310 Rig personnel noticed an increase in flow show, increase in pits, and problems at the shakers, but made 

different interpretations due to ―changes in clean up parameters on the one pit fill, perceived rig trimming 

issues; and potential blockage in lines from shakers to pits.‖ Internal BP document (BP-HZN-BLY 38358, 

38361).

Chapter 4.8

1

Also known as a ―degasser‖ or ―po‘ boy degasser.‖

2

Internal BP document (BP-HZN-BLY 56833).

3

Internal Transocean document (TRN-HCEC 5708)(Transocean Well Control Handbook). The crew 

conducted an EDS drill on January 31, 2010. Internal BP document (BP-HZN-BLY 55870). The Horizon‘s

EDS also successfully activated and sheared drill pipe on June 30, 2003. Internal BP document (BP-HZNMBI 136652).

4

Internal BP document (BP-HZN-BLY 56833).

5

Ibid.

6

Testimony of Christopher Pleasant (Transocean), Hearing before the Deepwater Horizon Joint 

Investigation Team, May 28, 2010, 165.

7

Internal BP Document (BP-HZN-CEC 45983).

8

There is an inversely proportional relationship between pressure and volume for an ideal gas. Though 

actual conditions in the wellbore might lead to different behavior than what is predicated for an ideal gas, 

the gas almost certainly expanded exponentially—or very near to exponentially. 

9

BP‘s analysis indicates that gas traveled up the 5,000-foot riser in about two minutes. BP, Deepwater 

Horizon Accident Investigation Report (September 8, 2010), 27.

10 Testimony of Bill Ambrose (Transocean), Hearing before the National Commission, November 8, 2010, 

386; Testimony of Mark Bly (BP), Hearing before the National Commission, November 8, 2010, 245.

11 Internal Transocean document (TRN-HCEC 5607).

12 Internal BP document (BP-HZN-MBI 213402). 

13 Internal Transocean document (TRN-HCEC 5607).

14 Testimony of Bill Ambrose, 257.

15 Detailed information on diverters is available in API, Recommended Practice for Diverter Systems 

Equipment and Operations, 2nd ed. (November 2001, reaffirmed March 1, 2007)(―API RP 64‖).

16 Internal Transocean document (TRN-HCEC 5608).

17 Internal BP document (BP-HZN-BLY 49092). 

18 Confidential industry expert, interview with Commission staff.

19 Internal BP document (BP-HZN-BLY 49092); Internal BP document (BP-HZN-BLY 49094).
Chief Counsel’s Report — Endnotes | 321

20 Internal BP document (BP-HZN-BLY 49094).

21 Confidential industry expert, interview.

22 Confidential industry expert, letter to Commission staff.

23 Ibid.

24 Ibid.

25 Internal Transocean document (TRN-HCEC 5606); Confidential industry expert, letter.

26 Confidential industry expert, letter.

27 Gas rises very quickly in deepwater. Internal Transocean document (TRN-HCEC 5607).

28 BP‘s analysis estimates the time at 9:40 p.m. BP, Deepwater Horizon Accident Investigation Report, 28. 

Transocean contends that the time was 9:43 p.m. Testimony of Bill Ambrose, 383. These estimates are 

generally consistent with the testimony of witnesses.

29 Internal Transocean document (TRN-HCJ 120914).

30 Testimony of Micah Sandell (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, May 29, 2010, 10.

31 Testimony of David Young (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, May 27, 2010, 264.

32 Testimony of Bill Ambrose, 244. 

33 Ibid.

34 Testimony of Micah Sandell, 9-10.

35 Internal BP document (BP-HZN-CEC 20357).

36 Testimony of Micah Sandell, 9-10.

37 Ibid.

38 Darryl Bourgoyne (Expert witness), interview with Commission staff, September 9, 2010.

39 Confidential industry expert, interview; Internal Transocean Document (TRN-HCEC 5606).

40 Deepwater Horizon Study Group, The Macondo Blowout: 3rd Progress Report (December 5, 2010), app. 

B, 12.

41 Testimony of Micah Sandell, 10.

42 Internal BP document (BP-HZN-BLY 61525).

43 Testimony of Jimmy Harrell (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, May 27, 2010, 98-99.

44 BP‘s modeling of the flow of mud and gas onto the rig indicates that the mud gas separator equipment may 

have failed. BP, Deepwater Horizon Accident Investigation Report, 115. The Chief Counsel‘s team is not

aware of a sophisticated model that has been completed by an independent party at this time.

45 Internal BP document (BP-HZN-MBI 129187).

46 Confidential industry expert, interview. 

47 John Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252 (July 1, 

2010), 14; Testimony of Bill Ambrose, 252-53; BP, Deepwater Horizon Accident Investigation Report, 28. 

According to subsea supervisor Chris Pleasant, he reset the lower annular regulator pressure to 1,500 psi 

from 1,900 psi soon after 9 p.m. Testimony of Christopher Pleasant, 120. According to BP, 1,500 psi was the 

normal regulator pressure setting for both annular preventers. BP, Deepwater Horizon Accident 

Investigation Report, 145. According to an independent expert, this would not have affected the ability to 

close the annular but it may have affected the equipment‘s ability to seal fully. Confidential industry expert, 

interview with Commission staff; Internal BP document (BP-HZN-BLY 61257).

48 Testimony of Christopher Pleasant, 123. BP post-explosion models also suggest an annular was activated 

at 9:41 p.m. BP, Deepwater Horizon Accident Investigation Report, 104.
322 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

49 Internal Transocean document (TRN-HCJ 121107); Internal BP document (BP-HZN-BLY 61563).

50 Data on well pressures are consistent with the closing of the annular or the variable bore ram. BP, 

Deepwater Horizon Accident Investigation Report, 103-04. Transocean has suggested the rig crew closed 

both variable bore rams. Transocean legal team, interview with Commission staff, December 10, 2010. Postexplosion information indicates that the rig crew may have activated the upper variable bore ram and 

perhaps the middle pipe ram. Response teams closed the upper variable bore ram but pumped only 1.5 

gallons of hydraulic fluid, instead of the 28 gallons typically required to close the ram. This indicates the rig 

crew had likely already closed the upper variable bore ram. BP, Deepwater Horizon Accident Investigation 

Report, 162. Post-explosion pressure measurements also suggest the rig crew may have activated the middle 

pipe ram. Ibid. 

51 Testimony of Bill Ambrose, 256; Internal Transocean document (TRN-HCEC 5487). Because of Macondo, 

some industry experts now question the appropriateness of typical kick response procedures.

52 BP, Deepwater Horizon Accident Investigation Report, 44.

53 Darryl Bourgoyne (Expert witness), interview with Commission staff, September 10, 2010; Testimony of 

Bill Ambrose, 256.

54 MMS regulation 30 CFR § 250.416(e) requires that the BOP description include information that shows 

the blind shear rams installed as capable of shearing the drill pipe in the hole under maximum anticipated 

surface pressures.

55 BP, Deepwater Horizon Accident Investigation Report, 175.

56 Ibid.

57 Ibid., 103-04; Internal Transocean document (TRN-HCEC 5487).

58 Internal Transocean document (TRN-HCEC 5487).

59 Internal Transocean document (TRN-HCEC 5543).

60 BP, Deepwater Horizon Accident Investigation Report, 29.

61 Internal Transocean document (TRN-HCJ 121107).

62 Ibid.

63 Testimony of Daun Winslow (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, August 23, 2010, 447-448.

64 Internal Transocean document (TRN-HCJ 121107).

65 Confidential industry expert, interview.

66 Testimony of William Stoner (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, May 28, 2010, 380. The engines are equipped with shutdown devices. During an audit of the rig in 

April, Engine 3 was out of service and its shutdown function was likely not tested. Internal Transocean 

document (TRN-USCG_MMS 38670).

67 Testimony of Michael Williams (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, July 23, 2010, 11-17.

68 Testimony of Paul Meinhart (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, May 29, 2010, 30; Testimony of Douglas Brown (Transocean), Hearing before the Deepwater Horizon

Joint Investigation Team, May 26, 2010, 100-01.

69 Testimony of Douglas Brown, 130.

70 Testimony of Michael Williams, 16.

71 Testimony of Paul Meinhart, 30; Testimony of Jimmy Harrell, 65; Testimony of Stephen Bertone 

(Transocean), Hearing before the Deepwater Horizon Joint Investigation Team, July 19, 2010, 116. 

72 Internal BP document (BP-HZN-CEC 20285).

73 Testimony of Chris Pleasant, 123.

74 BP, Deepwater Horizon Accident Investigation Report, 150; Internal BP document (BP-HZN-MBI

143364).
Chief Counsel’s Report — Endnotes | 323

75 Internal Transocean document (TRN-HCJ 121114); Testimony of Jimmy Harrell, 21, 66-67, 70-71; Internal 

BP document (BP-HZN-CEC 20285).

76 BP, Deepwater Horizon Accident Investigation Report, 152.

77 The MUX cable reels were located in the moon pool , in the center of the rig underneath the rig floor. BP, 

Deepwater Horizon Accident Investigation Report, 151. 

78 Testimony of Curt Kuchta (Transocean), Hearing before the Deepwater Horizon Joint Investigation Team, 

May 27, 2010, 190.

79 Internal BP document (BP-HZN-BLY 39346); Testimony of Joseph Keith (Halliburton), Hearing before 

the Deepwater Horizon Joint Investigation Team, December 7, 2010, 237; Allen Seraile (Transocean), 

interview with Commission staff, January 7, 2011; Testimony of Darryl Bourgoyne (Expert witness), Hearing 

before the National Commission, November 9, 2010, 179-80.

80 BP‘s modeling indicates that ―the flowing conditions could have prevented an annular preventer from fully 

closing and sealing around the drill pipe.‖ BP, Deepwater Horizon Accident Investigation Report, 146. 

81 Internal Halliburton document (HAL_48973); BP representatives, interview with Commission staff, 

September 8, 2010. 

82 Smith, Review of Operational Data Preceding Explosion on Deepwater Horizon in MC252, 24.

83 Internal Halliburton document (HAL_48973); Smith, Review of Operational Data Preceding Explosion 

on Deepwater Horizon in MC252, 23.

84 Transocean asserts that the variable bore ram was closed. Testimony of Bill Ambrose, 252. Witnesses only 

saw the annular activated. Internal BP document (BP-HZN-MBI 21420).

85 Internal Halliburton document (HAL_48973); Smith, Review of Operational Data Preceding Explosion 

on Deepwater Horizon in MC252, 24.

86 BP, Deepwater Horizon Accident Investigation Report, 172. According to Transocean, the proposal to 

convert the lower annular to a stripping annular was approved on July 29, 2006. Internal BP document (BPHZN-MBI 136646).

87 Internal BP document (BP-HZN-MBI 136646).

88 Darryl Bourgoyne (Expert witness), interview with Commission staff, December 18, 2010.

89 Some industry experts—including Darryl Bourgoyne at Louisiana State University—suggest that the 

diverter should be set automatically to go overboard. If the event is not an emergency, then the rig crew will 

have time to send the influx to the mud gas separator. 

90 Internal Transocean document (TRN-HCEC 5607).

91 Ibid.

92 Confidential industry expert, interview.

93 BP, Deepwater Horizon Accident Investigation Report, 117. 

94 Ibid., app. V, 52.

95 Ibid.

96 Steve Lewis (Expert witness), email to Commission staff, January 11, 2011.

97 The Chief Counsel‘s team thus disagrees with Transocean‘s assertion that flow rate and volume would have 

been so extreme that it necessarily would have overwhelmed the diverter system had the crew sent flow 

overboard.

98 BP, Deepwater Horizon Accident Investigation Report, 117. The Chief Counsel‘s team also requested 

information on the slip joint from Transocean, but it was unavailable at the publication of this report.

99 Ibid., 114.

100 Ibid., 117.
324 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

101 NOAA, ―Meteorological data from NOAA‘s Station PSTL1,‖ 

http://www.ndbc.noaa.gov/view_text_file.php?filename=pstl142010.txt.gz&dir=data/stdmet/Apr/;

Internal BP document (BP-HZN-MBI 129187).

102 NOAA, ―Meteorological data from NOAA‘s Station PSTL1,‖ 

http://www.ndbc.noaa.gov/view_text_file.php?filename=pstl142010.txt.gz&dir=data/stdmet/Apr/; 

Internal BP document (BP-HZN-MBI 129187). 

103 Wind often changes, and BP‘s report has the wind earlier in the day blowing the opposite direction. BP, 

Deepwater Horizon Accident Investigation Report, app. V, 22.

104 The port overboard line was unavailable because the Damon Bankston was on that side of the rig.

105 Deepwater Horizon Study Group, The Macondo Blowout: 3rd Progress Report, app. B, 13.

106 David Izon, E.P. Danenberger and Melinda Mayes, ―Absence of fatalities in blowouts encouraging in 

MMS study of OCS incidents,‖ Drilling Contractor 90 (July/August 2007). The study‘s authors also noted 

that a previous study found that ―22 of the 41 diverter uses were considered successful.‖ Ibid.

107 Confidential industry expert, interview; Deepwater Horizon Study Group, The Macondo Blowout: 3rd

Progress Report, app. B, 13; BP, Deepwater Horizon Accident Investigation Report, 44. 

108 BP, Deepwater Horizon Accident Investigation Report, 44.

109 Rachel Clingman (Transocean legal team), letter to Commission staff, November 16, 2010.

110 BP agrees: ―Transocean‘s shut-in protocols did not fully address how to respond in high flow emergency 

situations after well control has been lost. Well control actions taken prior to the explosion suggest the rig 

crew was not sufficiently prepared to manage an escalating well control situation.‖ BP, Deepwater Horizon 

Accident Investigation Report, 44.

111 Rachel Clingman (Transocean legal team), letter to Commission staff, November 1, 2010, att. The 

Deepwater Horizon—Crew and Safety, 7-8.

112 Testimony of Bill Ambrose, 252.

113 Clingman, letter.

114 Internal Transocean document (TRN-HCEC 5609-5610).

115 Even at the ninth step, the procedures are ambiguous. They say merely to ―be prepared...to send the mud 

overboard,‖ not directly to send the mud overboard. Moreover, the 10th step prescribes continued 

circulation through the mud gas separator. Internal Transocean document. Ibid. 

116 In an interview after the explosion with BP investigators, Mark Hafle, the senior drilling engineer for 

Macondo, agreed. He observed that rig crews conduct frequent drills but not for worst-case scenarios. 

Internal BP document (BP-HZN-BLY 61371).

Chapter 4.9

1

30 C.F.R. § 250.442; 30 C.F.R. § 250.515(b); 30 C.F.R. § 250.1624(b)(1).

2

Internal BP document (BP-HZN-CEC 46007).

3

Internal Cameron document (CAM-GR 101); Internal Transocean document (TRN-HCEC 5543); Testimony 

of Daun Winslow (Transocean), Hearing before the Deepwater Horizon Joint Investigation Team, August 24, 

2010, 137.

4

To avoid having a tool joint lay across the blind shear rams, rig crews engage in a procedure whereby they 

close an annular preventer, strip the pipe upward (through the closed annular) until it hits a tool joint, and 

then lower the pipe a predetermined amount so that the tool joint is out of the way and there is only straight 

pipe across the rams. This procedure requires time and a sequence of steps, which an emergency situation 

may not permit. Commission staff site visit to the Deepwater Nautilus, September 9, 2010.

5

Internal BP document (BP-HZN-BLY 59392-93).

6 Darryl Bourgoyne (Expert witness), interview with Commission staff, January 22, 2011; BP legal team, 

interview with Commission staff, January 25, 2011. Most rigs use range 2 drill pipe, which averages 31 feet in 
Chief Counsel’s Report — Endnotes | 325

length per interval. However, deepwater rigs may use range 3 drill pipe, which comes in 38- to 45-foot 

lengths. Bourgoyne, interview, January 22, 2011.

7

Adding an additional ram may require a reconfiguration of drilling rigs in order to accommodate a taller 

BOP stack.

8 West Engineering Services, Mini Shear Study for U.S. Minerals Management Service (December 2002), 3.

9

Ibid.

10 Michael Montgomery (West Engineering Services), letter to Commission staff, November 12, 2010, 4. 

11 West Engineering Services, Mini Shear Study for U.S. Minerals Management Service, 3. 

12 Ibid., 12. 

13 Ibid. 

14 BP, Deepwater Horizon Accident Investigation Report (September 8, 2010), app. H, 234; Internal BP 

document (BP-HZN-BLY 52594). The test took five seconds to shear the pipe and 12 seconds to completely 

close the shear rams.

15 BP, Deepwater Horizon Accident Investigation Report, 156.

16 Internal BP document (BP-HZN-MBI 136652).

17 30 C.F.R. § 250.449(b), (d).

18 30 C.F.R. § 250.516; Internal BP document (BP-HZN-MBI 133302).

19 30 C.F.R. § 250.446(b) requires visual inspection of subsea BOPs at least once every three days. According 

to witness testimony, ROVs inspected the Deepwater Horizon BOP daily to monitor for equipment 

irregularities including leaks. Testimony of Tyrone Benton (Oceaneering), Hearing before the Deepwater 

Horizon Joint Investigation Team, July 23, 2010, 244. However, according to daily operations reports there 

were some days, including February 18, when ROVs did not dive to the BOP. Internal BP document (BPHZN-MBI 135192). 

20 The blind shear ram was tested to 914 psi. Internal Transocean document (TRN-USCG_MMS 26242). 

According to daily drilling reports, the rig crew pressure tested the blind shear ram on February 6, 2010;

February 9, 2010; March 21, 2010; March 26, 2010; and April 1, 2010. Internal BP document (BP-HZN-OSC 

4074); Internal BP document (BP-HZN-OSC 4099); Internal BP document (BP-HZN-OSC 4191); Internal 

BP document (BP-HZN-OSC 4222); Internal Transocean document (TRN-USCG_MMS 26242).

21 Internal BP document (BP-HZN-OSC 4116)(February 11, 2010); Internal BP document (BP-HZN-OSC 

4139)(February 14, 2010); Internal BP document (BP-HZN-OSC 4207)(February 24, 2010); Internal BP 

document (BP-HZN-OSC 4037)(March 1, 2010); Internal BP document (BP-HZN-OSC 4070)(March 5, 

2010); Internal BP document (BP-HZN-OSC 4158)(March 16, 2010); Internal BP document (BP-HZN-OSC 

4222)(March 26, 2010); Internal Transocean document (TRN-USCG_MMS 26242)(April 1, 2010); Internal 

Transocean document (TRN-USCG_MMS 26266)(April 8, 2010); Testimony of Mark Hay (Transocean), 

Hearing before the Deepwater Horizon Joint Investigation Team, August 25, 2010, 249.

22 Darryl Bourgoyne (Expert witness), interview with Commission staff, January 24, 2011.

23 30 C.F.R. § 250.448(b).

24 Internal BP document (BP-HZN-OSC 619).

25 BP, Deepwater Horizon Accident Investigation Report, app. H, 230. According to daily drilling reports, 

the blind shear ram was tested at various pressures during drilling, including 15,000 psi on the surface 

(February 6, 2010), 6,500 psi (February 9, 2010), 2,400 psi (March 21, 2010), 1,800 psi (March 26, 2010), 

and 914 psi (April 1, 2010). Internal BP document (BP-HZN-OSC 4074); Internal BP document (BP-HZNOSC 4099); Internal BP document (BP-HZN-OSC 4191); Internal BP document (BP-HZN-OSC 4222); 

Internal Transocean document (TRN-USCG_MMS 26242).

26 30 C.F.R. § 250.448(c). The upper annular was rated to withstand 10,000 psi closed on pipe or 5,000 psi 

closed on an open hole. BP, Deepwater Horizon Accident Investigation Report, app. H, 227. After 

conversion to a stripping annular, the lower annular was rated to withstand 5,000 psi. BP, Deepwater 

Horizon Accident Investigation Report, 172. Post-explosion examination of the blue pod found regulated 

pressure on the lower annular preventer was set to approximately 1,700 psi. Ibid, 145. Transocean has 

recently contended the rig crew activated the upper annular, not the lower annular.
326 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

27 Internal BP document (BP-HZN-MBI 130883). 

28 Internal BP document (BP-HZN-OSC 619).

29 Internal BP document (BP-HZN-OSC 925, 931-32).

30 Steve Lewis (Expert witness), interview with Commission staff, September 28, 2010. 

31 Darryl Bourgoyne (Expert witness), interview with Commission staff, December 18, 2010.

32 Ibid.

33 Internal Transocean document (TRN-USCG_MMS 11646).

34 BP, Deepwater Horizon Accident Investigation Report, 175-76. ROVs can also activate the rams 

electronically through subsea controls.

35 Nonpublic BP document (presentation to Commission staff, September 8, 2010), 13.

36 Internal BP document (BP-HZN-CEC 46012-13).

37 Internal BP document (BP-HZN-CEC 46012). 

38 Internal Transocean document (TRN-USCG_MMS 38822).

39 BP, Deepwater Horizon Accident Investigation Report, 29.

40 Internal BP document (BP-HZN-CEC 18896); BP, Deepwater Horizon Accident Investigation Report, 162. 

41 BP, Deepwater Horizon Accident Investigation Report, 29.

42 Internal BP document (BP-HZN-CEC 18896).

43 Internal Department of the Interior document (OSC-DWH BOEM-WDC-B06-00001-0005), 374-79.

44 Internal BP document (BP-HZN-MBI 136647).

45 BP, Deepwater Horizon Accident Investigation Report, 172.

46 Internal BP document (BP-HZN-MBI 136648).

47 Internal BP document (BP-HZN-CEC 18896).

48 Ibid.

49 Testimony of Harry Thierens (BP), Hearing before the Deepwater Horizon Joint Investigation Team, 

August 25, 2010, 104–05. 

50 The modification was made in 2004, and according to BP notes, it was ―overlooked at the time‖ to change 

the ROV hot stab connections. Internal BP document (BP-HZN-MBI 136648); Internal BP document (BPHZN-CEC 18896).

51 Internal BP document (BP-HZN-CEC 18896).

52 Internal Transocean document (TRN-HCEC 5708); Testimony of Daun Winslow (Transocean), Hearing 

before the Deepwater Horizon Joint Investigation Team, August 23, 2010, 515. 

53 BP, Deepwater Horizon Accident Investigation Report, 155.

54 Ibid.; Darryl Bourgoyne (Expert witness), interview with Commission staff, January 21, 2011.

55 Transocean legal team, interview with Commission staff, December 10, 2010.

56 BP, Deepwater Horizon Accident Investigation Report, 156.

57 Internal Cameron document (CAM-GR 209). Each SEM has an AMF card that recognizes when power, 

communication, and hydraulics are lost. BP, Deepwater Horizon Accident Investigation Report, 154 and

app. X, 2. 

58 Internal Cameron document (CAM-GR 209). According to manufacturer specifications, communication 

between the control pods must also be lost in order for the AMF/deadman to activate. It is not certain 

whether the control pods communicate locally or through the MUX cables running to the rig. 
Chief Counsel’s Report — Endnotes | 327

59 Ibid. The rigid conduit line running from the rig continually charged BOP stack accumulators. BP, 

Deepwater Horizon Accident Investigation Report, 160. Pressure sensors compare ambient pressure at the 

seabed with pressure in the conduit line. If conduit pressure is equal or less than ambient hydrostatic 

pressure, the AMF sequence continues. Internal Cameron document (CAM-GR 8041). 

60 BP, Deepwater Horizon Accident Investigation Report, 175-76.

61 Internal Cameron document (CAM-GR 209); Internal BP document (BP-HZN-BLY 56840).

62 Internal Transocean document (TRN-USCG_MMS 38826); BP, Deepwater Horizon Accident 

Investigation Report, 150.

63 BP, Deepwater Horizon Accident Investigation Report, 151.

64 Transocean legal team, interview with Commission staff, September 30, 2010. 

65 BP, Deepwater Horizon Accident Investigation Report, 151. Transocean questions whether hydraulic 

power was severed between the rig and BOP during the explosion. Transocean legal team, interview, 

September 30, 2010.

66 Transocean legal team, interview, September 30, 2010. 

67 Internal BP document (BP-HZN-CEC 18896); BP, Deepwater Horizon Accident Investigation Report, 29.

68 Transocean legal team, interview, December 10, 2010.

69 Internal BP document (BP-HZN-BLY 56143). 

70 Transocean legal team, interview, September 30, 2010. 

71 Internal Transocean document (TRN-HCEC 5708).

72 Rather, Transocean representatives indicated that neither the AMF system nor batteries necessary to 

power the system are regularly tested. Transocean legal team, interview, September 30, 2010. A deadman 

system surface test typically cuts the power and hydraulics to the BOP stack and confirms the rams are 

closed. Internal BP document (BP-HZN-CEC 18893). Testing the deadman subsea is a risk because cutting 

power and hydraulics to the BOP stack could drain the system batteries. The system could also fail to restart 

as designed. However, according to an internal BP memo, these are ―manageable risks.‖ Internal BP 

document (BP-HZN-CEC 18894). 

73 Records indicate ―working on yellow pod‖ on February 1 and 2, 2010. Internal BP document (BP-HZNBLY 55870). Both pods were function tested and powered on February 5, 2010. BP Internal document (BPHZN-OSC 4065).

74 BP, Deepwater Horizon Accident Investigation Report, 153. The 27-volt battery was comprised of three

connected 9-volt battery packs. Ibid., app. X, 2.

75 Ibid., app. X, 2. The sequence may have stopped prior to energizing the conduit and ambient pressure 

sensors, which according to BP testing requires at least 14.4 volts. Ibid., app. X, 4.

76 Ibid., app. X, 4.

77 Testimony of William Stringfellow (Transocean), Hearing before the Deepwater Horizon Joint 

Investigation Team, August 25, 2010, 421.

78 BP, Deepwater Horizon Accident Investigation Report, app. X, 3. The Chief Counsel‘s team received 

protocols used during this initial blue pod testing but awaits more comprehensive results from the ongoing 

government forensic testing of the blowout preventer. 

79 Ibid.

80 After the AMF sequence, the SEM, AMF card, and AMF controller are powered down to preserve battery 

life. Ibid., app. X, 2. 

81 Transocean legal team, interview, September 30, 2010.

82 Important records relating to the blowout preventer were lost with the sinking of the rig. This includes the 

event logger, which continuously records data from both pods and records all BOP functions activated from 

the control panels. BP, Deepwater Horizon Accident Investigation Report, app. H, 232. This lost 

information may have helped to determine what the battery charges were at the time of the incident.
328 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

83 Internal Cameron document (CAM-GR 252). Cameron recommends replacing pod batteries at the 

following times, whichever is earliest: after one year of on-time operation, when a battery is actuated 33 

times, or five years after date of purchase. 

84 Testimony of William Stringfellow, 348-49.

85 Internal Transocean document (TRN-USCG_MMS 38660). 

86 Transocean subsea supervisor Chris Pleasant testified that pod batteries were not replaced immediately 

before the crew lowered the BOP in February 2010. Testimony of Chris Pleasant (Transocean), Hearing 

before the Deepwater Horizon Joint Investigation Team, May 28, 2010, 199. Senior subsea engineer Mark 

Hay testified that the blue pod batteries are ―replaced within a year.‖ Testimony of Mark Hay, 262-63.

87 BP, Deepwater Horizon Accident Investigation Report, 167. 

88 Internal Transocean document (TRN-HCJ 98117)(Pod #2 December 29, 2005 replacement, Cost: 

$17,786.13); Internal Transocean document (TRN-PC 3787).

89 BP, Deepwater Horizon Accident Investigation Report, app. H, 233.

90 Ibid.; Earl Shanks et al., ―Deepwater BOP Control Systems—A Look at Reliability Issues‖ (paper, Offshore 

Technology Conference, Houston, TX, May 2003), 1.

91 BP, Deepwater Horizon Accident Investigation Report, app. H, 233; Cameron representative, interview 

with Commission staff, August 10, 2010.

92 Internal BP document (BP-HZN-BLY 55870). 

93 BP, Deepwater Horizon Accident Investigation Report, 154. These results were witnessed and accepted on 

May 8, 2010. Internal Cameron document (CAMCG 3011).

94 Internal Cameron document (CAMCG 2999).

95 Commission staff site visit to Deepwater Nautilus, September 9, 2010; BP, Deepwater Horizon Accident 

Investigation Report, 173.

96 Testimony of Mark Hay, 262. An April 2010 Transocean rig condition assessment identified an error 

message on the yellow pod indicating a valve was mismatched. Internal Transocean document (TRNUSCG_MMS 38657). However, the audit did not clarify which solenoid valve and left the issue unresolved. 

It is not certain whether this message could be an indication of a faulty solenoid. Internal Transocean 

document (TRN-USCG_MMS 38658). 

97 Darryl Bourgoyne (Expert witness), interview with Commission staff, December 14, 2010. 

98 Internal BP document (BP-HZN-BLY 56842).

99 BP, Deepwater Horizon Accident Investigation Report, 156.

100 Internal BP document (BP-HZN-BLY 55870); Internal Transocean document (TRN-HCEC 5708). The 

autoshear is tested by sending a signal that simulates LMRP disconnection, then verifying the shuttle valves 

for the selected rams worked as intended. This can be done through ―dry firing,‖ meaning with no hydraulic 

pressure. Internal BP document (BP-HZN-CEC 18894). 

101 Internal BP document (BP-HZN-CEC 18896); BP, Deepwater Horizon Accident Investigation Report, 48.

102 Internal BP document (BP-HZN-CEC 18896); BP, Deepwater Horizon Accident Investigation Report, 

156.

103 Nonpublic BP document (presentation to Commission staff on BOP), 15.

104 Preliminary evidence shows the upper annular preventer closed around the drill pipe. Therefore, even if 

pipe severed above the annular preventer, the annular would have prevented that pipe from falling below the 

annular and interfering with the closure of the blind shear ram.

105 BP, Deepwater Horizon Accident Investigation Report, app. H, 228. 

106 Ibid., app. H, 231. The BOP stack accumulators also provided hydraulic fluid should the rig crew directly 

activated the blind shear ram from one of the rig‘s control panels. Ibid. 

107 Ibid., 160.
Chief Counsel’s Report — Endnotes | 329

108 Internal BP document (BP-HZN-BLY 55870); Internal BP document (BP-HZN-OSC 4049). Accumulator 

levels are generally checked prior to or during an accumulator drill. Bourgoyne, interview, January 22, 2011.

109 According to BP‘s internal investigation, if only three accumulators were charged there would not be 

sufficient pressure to shear the pipe and seal the well. BP, Deepwater Horizon Accident Investigation 

Report, 160.

110 Ibid., 170-71. 

111 Ibid., 170.

112 Ibid., 171.

113 Internal BP document (BP-HZN-MBI 135553).

114 Darryl Bourgoyne (Expert witness), email to Commission staff, December 15, 2010.

115 Ibid. 

116 Bourgoyne, interview, January 22, 2011. According to a 2010 West Engineering study on blowout 

prevention equipment reliability, ―a very large percentage‖ of control system failures can be identified by 

function tests. Internal Cameron document (CAM-GR 15911). According to this study, lower pressures may

not allow leaks to be indentified. Internal Cameron document (CAM-GR 15918).

117 Bourgoyne, interview, January 22, 2011.

118 Ibid.

119 Testimony of Mark Hay, 242.

120 The rig crew identified leaks 1, 2, and 5 before the incident. Rachel Clingman (Transocean legal team), 

letter to Commission staff, November 1, 2010.

121 Bourgoyne, interview, December 18, 2010. Post-explosion log books identified more leaks, some of which 

may have developed during the response effort and some of which were identified prior to the incident. 

Internal BP document (BP-HZN-MBI 135553).

122 BP, Deepwater Horizon Accident Investigation Report, 170.

123 Ibid., 156; Clingman, letter.

124 Testimony of John Guide (BP), Hearing before the Deepwater Horizon Joint Investigation Team, July 22, 

2010, 193-95; BP, Deepwater Horizon Accident Investigation Report, 169.

125 Internal BP document (BP-HZN-MBI 135226); Internal BP document (BP-HZN-MBI 192017). The leak 

may have been recognized even earlier than February 23. While inspecting leak 2 on February 19, the rig 

crew isolated the pressure supply to the yellow pod and, using the ROV, observed a pilot system leak on the

yellow pod. This may have been referring to leak 1. Clingman, letter.

126 Clingman, letter; BP, Deepwater Horizon Accident Investigation Report, 169. 

127 Clingman, letter. According to witness testimony, this leak was discovered approximately two weeks after 

landing the BOP on the wellhead. Testimony of Mark Hay, 244. According to BP‘s internal investigation, this 

leak was not identified until post-explosion ROV intervention. BP, Deepwater Horizon Accident 

Investigation Report, 169.

128 BP, Deepwater Horizon Accident Investigation Report, 170.

129 Internal Transocean document (TRN-USCG_MMS 38843).

130 BP, Deepwater Horizon Accident Investigation Report, 170.

131 Internal Transocean document (TRN-USCG_MMS 38843).

132 BP, Deepwater Horizon Accident Investigation Report, 171. 

133 Clingman, letter.

134 Ibid.

135 30 C.F.R. § 250.466(f). 

136 Elmer Danenberger (Expert witness), email to Commission staff, January 5, 2011. 
330 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

137 Internal BP document (BP-HZN-OSC 4199-4202).

138 Internal BP document (BP-HZN-MBI 135226); Internal BP document (BP-HZN-MBI 135558).

139 John Guide, interview with Commission staff, September 17, 2010.

140 Ronnie Sepulvado, interview with Commission staff, August 20, 2010.

141 Clingman, letter. 

142 Internal BP document (BP-HZN-OSC 4175-77).

143 Clingman, letter.

144 Danenberger, email, January 5, 2011.

145 Bourgoyne, interview, January 22, 2011.

146 According to senior subsea supervisor Owen McWhorter, this leak was brought to everyone‘s attention. 

Clingman, letter. BP‘s John Guide called Transocean‘s Paul Johnson and confirmed the leak did not affect 

the ram‘s functionality. Guide, interview.

147 Internal BP document (BP-HZN-MBI 225124).

148 Clingman, letter.

149 Ibid.

150 Ibid.

151 Ibid.; Internal BP document (BP-HZN-MBI 135553).

152 Testimony of Mark Hay, 195.

153 American Petroleum Institute, Recommended Practices for Blowout Prevention Equipment Systems for 

Drilling Wells, 3rd ed. (March 1997, reaffirmed September 2004), 56 (―API RP 53 § 18.10.3‖).

154 Ibid.

155 Testimony of William Stringfellow, 359.

156 Internal Cameron document (CAM-GR 261); Bourgoyne, interview, January 22, 2011.

157 Earl Shanks et al., Deepwater BOP Control Systems—A Look at Reliability Issues (May 2003), 2. 

158 Internal Transocean document (TRN-HCEC 90585).

159 30 C.F.R. § 250.446(a).

160 API RP 53 § 18.10.3.

161 Internal Cameron document (CAM-GR 261-62).

162 Testimony of Mark Hay, 205; Testimony of John Sprague (BP), Hearing before the Deepwater Horizon 

Joint Investigation Team, December 8, 2010, part 2, 79-80.

163 Internal BP document (BP-HZN-MBI 136213); Internal BP document (BP-HZN-MBI 136230).

164 Internal Transocean document (TRN-USCG_MMS 38652). 

165 Internal BP document (BP-HZN-MBI 136230); Testimony of John Sprague, 79-80.

166 Internal Transocean document (TRN-USCG_MMS 38652).

167 Internal Transocean document (TRN-USCG_MMS 38662). The BOP‘s fail-safe valves, designed to shut 

off choke and kill lines remotely and automatically, had also not been certified since December 13, 2000. 

Internal Transocean document (TRN-USCG_MMS 38656).

168 30 C.F.R. § 250.446(a); Danenberger, email, January 5, 2011. To use a stack that was out of compliance, 

BP may have needed to request a regulatory departure under 30 C.F.R. § 250.142. Elmer Danenberger

(Expert witness), email to Commission staff, January 16, 2011.

169 Internal Transocean document (TRN-HCEC 66722); Testimony of Eric Neal (MMS), Hearing before the 

Deepwater Horizon Joint Investigation Team, May 11, 2010, 318-21.
Chief Counsel’s Report — Endnotes | 331

170 Internal MMS document.

171 Testimony of Mark Hay, 255-56.

172 Internal Transocean document (TRN-HCEC 11560).

173 Testimony of William Stringfellow, 414-15.

174 Ibid., 415.

175 Ibid., 413-14 (emphasis added)(condition of BOPs is tracked in the RMS). 

176 Ibid.

177 Ibid., 426-27, 439.

178 BP, Deepwater Horizon Accident Investigation Report, app. AA, 2.

179 Internal BP document (BP-HZN-MBI 136649).

180 Internal BP document (BP-HZN-MBI 136646).

181 Internal Transocean document (TRN-USCG_MMS 38855). 

182 Ibid.

183 BP, Deepwater Horizon Accident Investigation Report, app. AA, 1. According to Transocean, conditions 

after the explosion permitted the control pods to be retrieved despite this modification. Transocean legal 

team, interview with Commission staff, November 2, 2010.

184 BP, Deepwater Horizon Accident Investigation Report, app. AA, 1.

185 Ibid., app. AA, 2.

186 Ibid.

187 Internal Transocean document (TRN-USCG_MMS 38855).

188 Cameron representative, interview.

189 BP, Deepwater Horizon Accident Investigation Report, 172.

190 Ibid., app. AA, 1.

191 Ibid., 172.

192 Internal BP document (BP-HZN-MBI 136649).

193 Internal BP document (BP-HZN-MBI 136648).

194 Ibid.

195 BP, Deepwater Horizon Accident Investigation Report, app. AA, 2.

196 Internal BP document (BP-HZN-MBI 136647).

197 Internal BP document (BP-HZN-MBI 136648).

198 Internal BP document (BP-HZN-MBI 136649).

199 Ibid.

200 Ibid.

201 Internal Transocean document (TRN-HCJ 96972).

202 BP, Deepwater Horizon Accident Investigation Report, 172; Internal BP document (BP-HZN-MBI 

136646).

203 Internal BP document (BP-HZN-BLY 56004).

204 Internal Transocean document (TRN-USCG_MMS 38855).

205 Ibid.
332 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

206 Ibid.

207 Internal BP document (BP-HZN-MBI 136648).

Chapter 4.10

1

Testimony of Daun Winslow (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, August 24, 2010, 87.

2

Internal Transocean document (Transocean, ―Deepwater Horizon Safety and Maintenance Overview,‖ 

presentation to U.S. House of Representatives Committee on Energy and Commerce, August 2010), 13.

3

Ibid, 8, 10.

4

Testimony of Pat O‘Bryan (BP), Hearing before the Deepwater Horizon Joint Investigation Team, August 

26, 2010, 411. 

5

John Guide (BP), interview with Commission staff, September 17, 2010.

6

Testimony of Pat O‘Bryan, 365.

7

Internal BP document (BP-HZN-MBI 198309).

8

Internal Transocean document (TRN-HCEC 5322). Transocean also used a system called ―FOCUS‖ for 

tracking audit items and rig crew training. David Young (Transocean), interview with Commission staff, 

November 19, 2010.

9

Testimony of Paul Johnson (Transocean), Hearing before Deepwater Horizon Joint Investigation Team, 

August 23, 2010, 325. Previously, Transocean used an Empac system. Internal BP document (BP-HZN-MBI 

136212).

10 Internal Transocean document (TRN-HCEC 5340); Testimony of Stephen Bertone (Transocean), Hearing 

before the Deepwater Horizon Joint Investigation Team, July 19, 2010, 231. The Rig Management System 

was the approved Computerized Maintenance Management System (CMMS) for all Transocean installations. 

Witness testimony commonly refers to the RMS as the rig maintenance system. Testimony of Stephen 

Bertone (Transocean), July 19, 2010, 70. 

11 Internal Transocean document (TRN-HCEC 5340).

12 Internal Transocean document (TRN-HCEC 5343).

13 Preventative maintenance refers generally to normally scheduled maintenance, including planned 

maintenance, scheduled overhauls, condition monitoring, and daily and weekly equipment checks and 

measurements. Internal Transocean document (TRN-HCEC 5358). 

14 Testimony of Stephen Bertone, 109.

15 Ibid.

16 Internal Transocean document (TRN-HCEC 5340).

17 Young, interview. Young suggested that a lack of knowledge among the crew may not have been 

problematic because supervisors were familiar with the system. Young handled entries into the system for 

his team such that, according to Young, a lack of system familiarity did not inhibit operations. David Young, 

interview.

18 Internal Transocean document (Transocean, ―Deepwater Horizon Safety and Maintenance Overview,‖ 

presentation to U.S. House of Representatives Committee on Energy and Commerce, August 2010), 16.

19 Testimony of Stephen Bertone, 233.

20 Ibid.

21 Ibid. According to chief engineer technician Mike Williams, there would be up to four listings for the same 

job. Testimony of Mike Williams (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, July 23, 2010, 76.

22 Allen Seraile (Transocean), interview with Commission staff, January 7, 2011.
Chief Counsel’s Report — Endnotes | 333

23 Testimony of Stephen Bertone, 232-33.

24 Seraile, interview. 

25 Testimony of Mike Williams, 75. Transocean has suggested that the rig crew described the implementation 

of the RMS as a ―speed bump.‖ Internal Transocean document (Transocean, ―Deepwater Horizon Safety and 

Maintenance Overview,‖ presentation to U.S. House of Representatives Committee on Energy and 

Commerce, August 2010), 24.

26 Internal Transocean document (TRN-HCEC90590).

27 Ibid.

28 Ibid.

29 Internal Transocean document (TRN-HCEC 90910-11).

30 Testimony of Paul Johnson, 352; Internal BP document (BP-HZN-OSC 4254). However, some forms of 

maintenance, including BOP maintenance, were exempt from this provision. Ibid.

31 Internal Transocean document (TRN-HCEC 90584).

32 Internal Transocean document (TRN-HCEC 90585).

33 Guide, interview.

34 Testimony of Daun Winslow (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, August 23, 2010, 508. Winslow‘s full title is Operations Manager, Performance, North American 

Division. Ibid, 437. 

35 Testimony of Mike Williams, 161.

36 Internal Transocean document (Transocean, ―Deepwater Horizon Safety and Maintenance Overview,‖ 

presentation to U.S. House of Representatives Committee on Energy and Commerce, August 2010, slide 14). 

Internal Transocean document (TRN-HCEC 90585). 

37 Internal Transocean document (TRN-HCEC 90585). 

38 Internal Transocean document (TRN-HCEC 90603). 

39 Transocean legal team, interview with Commission staff, August 6, 2010. 

40 Internal Transocean document (TRN-HCEC 5384). 

41 Testimony of Paul Johnson, 290-91.

42 For example, the September 2009 audit and April 2010 rig condition assessment both identified excessive 

silicon on mud pump covers that could cause pump failure. Internal BP document (BP-HZN-MBI 136221); 

Internal Transocean document (TRN-USCG_MMS 38637). The September 2009 audit identified the pipe 

racking system (PRS) as requiring maintenance before drilling operations resumed; the April 2010 rig 

condition assessment found the PRS in only ―fair‖ condition. Internal BP document (BP-HZN-MBI 136240); 

Internal Transocean document (TRN-USCG_MMS 38666). According to assistant driller Allen Seraile, the 

rig crew was aware of major problems with the PRS. Seraile, interview.

43 Internal Transocean document (TRN-HCEC 90955).

44 Internal Transocean document (TRN-HCEC 90968-69).

45 Testimony of Mike Williams, 115.

46 Guide, interview.

47 Internal Transocean document (TRN-HCEC 90901).

48 Testimony of Michael Saucier (MMS), Hearing before the Deepwater Horizon Joint Investigation Team, 

May 12, 2010, 12-15.

49 Testimony of Paul Johnson, 120.

50 Ibid.

51 Ibid.
334 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

52 The rig audit surveys the condition of the drilling machinery while the marine audit surveys the ability of 

the vessel itself. Testimony of John Guide (BP), Hearing before the Deepwater Horizon Joint Investigation 

Team, July 22, 2010, 96. BP conducts assessments on all vessels owned by third parties that BP employs in 

the Gulf of Mexico. Testimony of Neil Cramond (BP), Hearing before the Deepwater Horizon Joint 

Investigation Team, August 23, 2010, 21-30. The September 2009 audit followed up a previous BP rig audit 

and included a standard marine assessment as prescribed by the International Maritime Contractors 

Association (IMCA). The audit also reviewed the condition of the dynamic positioning system. Ibid, 94-95. 

53 Internal BP document (BP-HZN-MBI 136222).

54 Ibid.; Testimony of Neil Cramond, 94. 

55 The new system showed duplicates and listed jobs with no work history as immediately due because there 

was no history in the new system. Internal Transocean document. (Transocean, ―Deepwater Horizon Safety 

and Maintenance Overview,‖ presentation to U.S. House of Representatives Committee on Energy and 

Commerce, August 2010, slides 16, 24.) Duplicate maintenance orders and orders from other rigs may have 

also inflated the number of overdue items. Ibid, 233.

56 Internal BP document (BP-HZN-MBI 136222); Testimony of Paul Johnson, 314-15, 321-22; Testimony of 

Neil Cramond, 35-36. The Horizon was already in an out-of-service period at the time of the audit so rather 

than stopping ongoing operations, BP requested the rig remain shut down until some repairs were made. 

Testimony of Paul Johnson, 248. This included repairs to the rig‘s pipe racking system, as one of the racking 

arms was bent. Ibid, 315.

57 Testimony of Daun Winslow, August 24, 2010, 187.

58 BP, Deepwater Horizon Accident Investigation Report, app. Y, 1 (September 8, 2010), 1.

59 Angel Rodriguez of BP verified a Transocean spreadsheet of maintenance items. Testimony of Neil 

Cramond, 100-01. Tracking of other audits may not have been as focused. An April 2010 email from John 

Guide to Paul Johnson indicated 36 of 37 action items from an August 2009 environmental audit may have 

remained outstanding as of April 2010. Internal BP document (BP-HZN-MBI 251718).

60 Testimony of Neil Cramond, 74. Four days after the audit ended on September 17, Transocean‘s Paul 

Johnson emailed BP‘s John Guide to inform him Transocean was satisfied the rig could resume operations 

because audit items were either closed out or had ―robust mitigation measures in place.‖ Internal BP 

document (BP-HZN-BLY 55679). The rig audit took place September 13-17. Internal BP document (BPHZN-MBI 136212). 

61 Brett Cocales, Angel Rodriguez, and sometimes John Guide would attend these meetings. Testimony of 

Paul Johnson, 325, 354-55. While meetings were initially weekly, the companies later began meeting 

biweekly or monthly to discuss audit progress. Ibid, 325. 

62 Ibid, 355. BP well site leaders stayed informed by attending 8:30 a.m. rig meetings or had rig crew 

members email them regarding broken parts. Ronnie Sepulvado (BP), interview with Commission staff, 

August 20, 2010.

63 Internal Transocean document (TRN-HCEC 115553).

64 Testimony of Paul Johnson, 247.

65 Ibid, 316; Testimony of Neil Cramond, 115.

66 Sepulvado, interview. 

67 Testimony of Neil Cramond, 116-18.

68 Testimony of John Guide, 201.

69 Internal Transocean document (TRN-HCEC 66722); Testimony of Eric Neal (MMS), Hearing before the 

Deepwater Horizon Joint Investigation Team, May 11, 2010, 318. 

70 Internal MMS document. 
Chief Counsel’s Report — Endnotes | 335

Chapter 5

1

BP, Deepwater Horizon Accident Investigation Report (September 8, 2010), 32 (identifying eight ―physical 

or operational barriers‖ that failed and concluding that ―[i]f any of these critical factors had been eliminated, 

the outcome of Deepwater Horizon events on April 20, 2010, could have been either prevented or reduced in 

severity‖).

2

BP‘s operating management system (OMS) sets out minimum expectations for ―leadership,‖ ―people and 

competence,‖ ―procedures,‖ ―working with contractors,‖ ―technology,‖ and ―risk‖ (among others). Internal 

BP document (BP-HZN-MBI 208576-77). Transocean‘s management system has principles on ―leadership,‖ 

―policies and procedures,‖ ―organization,‖ ―risk management,‖ ―training and competence,‖ and 

―communications.‖ Internal Transocean document (TRN-USCG_MMS 32700). Exxon‘s operations integrity 

management system (OIMS) is also quite similar. ExxonMobil, Operations Integrity Management System.

3

Internal BP document (BP-HZN-MBI 208603).

4

Internal BP document (BP-HZN-MBI 208611).

5

Internal BP document (BP-HZN-MBI 222521).

6

Ibid.

7 David Sims (BP), interview with Commission staff, February 1, 2011. At about the same time, Sims had 

drafted a longer version of the email to Guide that he never sent. Internal BP document (BP-HZN-MBI 

222540). He wrote, ―Everything else is someone else‘s fault. You criticize nearly everything we do on the rig 

but don‘t seem to realize that you are responsible for everything we do on the rig.‖ Ibid. He also wrote, ―You 

seem to not want to make a decision so that you can criticize it later.‖ Ibid. Sims also pointed out a number 

of times when episodes on the rig—including a kick, a crane incident, and an injury—were not reported in a 

timely manner to onshore members of the Macondo team. Ibid. Sims later explained that he was frustrated 

with Guide but later realized he probably should have cut Guide a bit more slack because a member of 

Guide‘s family had recently passed away. Sims, interview, February 1, 2011.

8

Internal BP document (BP-HZN-MBI 212781). The next day, BP senior drilling engineer Mark Hafle asked 

a colleague, ―Have you been within earshot of any of the Sims / Guide conversations lately?‖ Internal BP 

document (BP-HZN-MBI 212781). 

9 David Sims (BP), interview with Commission staff, December 14, 2010; Testimony of John Sprague (BP), 

Hearing before the Deepwater Horizon Joint Investigation Team, December 8, 2010, part 2, 10-11. 

10 Sims, interview, December 14, 2010; Testimony of Gregory Walz (BP), Hearing before the Deepwater 

Horizon Joint Investigation Team, October 7, 2010, part 2, 119. 

11 Internal BP document (BP-HZN-CEC 21533).

12 Internal BP document (BP-HZN-BLY 125441).

13 Sims, interview, February 1, 2011.

14 Internal BP document (BP-HZN-BLY 61356).

15 Internal BP document (BP-HZN-BLY 61470).

16 Internal BP document (BP-HZN-MBI 255906).

17 John Guide (BP), interview with Commission staff, January 19, 2011.

18 Internal BP document (BP-HZN-BLY 61372).

19 Sims, interview, February 1, 2011; Internal BP document (BP-HZN-BLY 125441).

20 BP, Deepwater Horizon Accident Investigation Report, 36.

21 Internal BP document (BP-HZN-BLY 125439).

22 Internal BP document (BP-HZN-BLY 125436).

23 Testimony of Brett Cocales (BP), Hearing before the Deepwater Horizon Joint Investigation Team, August 

27, 2010, 113; Randy Ezell (Transocean), interview with Commission staff, September 16, 2010; Testimony 

of Paul Johnson (Transocean), August 23, 2010, 136-38. Halliburton‘s Vincent Tabler admitted that he read 

the OptiCem report but did not review the portion indicating ―SEVERE gas flow‖ potential. Testimony of 
336 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Vincent Tabler (Halliburton), Hearing before the Deepwater Horizon Joint Investigation Team, August 25, 

2010, 17. 

24 Internal BP document (BP-HZN-BLY 61350).

25 Internal BP document (BP-HZN-MBI 254886).

26 Internal BP document (BP-HZN-MBI 193521).

27 The plan required personnel to call shore for ―Any HSSE incident‖ or ―Anytime operations deviate from 

agreed plan.‖ Internal BP document (BP-HZN-MBI 193528). 

28 Internal BP document (BP-HZN-BLY 61374).

29 Internal BP document (BP-HZN-MBI 308059).

30 Internal BP documents (BP-HZN-MBI 262896-7).

31 Gregory Walz (BP), interview with Commission staff, October 6, 2010; Brett Cocales (BP), interview with 

Commission staff, September 16, 2010; John Guide (BP), interview with Commission staff, September 17, 

2010; Sims, interview, December 14, 2010; Pat O‘Bryan (BP), interview with Commission staff, December 17, 

2010. 

32 It is perhaps not surprising that neither Kaluza nor Vidrine called back to shore. Kaluza was new to the 

Deepwater Horizon, whereas Vidrine had been there for months and Revette and Anderson were 

experienced veterans on the rig. In Kaluza‘s 2009 performance review, BP management observed, ―It 

sometimes appears that Bob is trying too much to impress the Houston office by attempting to have all the 

answers to any questions that may arise.‖ Internal BP document (BP-HZN-MBI 193095-98). As for Vidrine, 

BP management praised him in his 2009 performance review because he only called to shore when needed. 

Internal BP document (BP-HZN-OSC 9089).

33 Guide, interview, September 17, 2010; Murry Sepulvado (BP), interview with Commission staff, December 

10, 2010. 

34 Testimony of Mark Bly (BP), Hearing before the National Commission, November 8, 2010, 286. Even that 

―expectation‖ would have been insufficient, as it would have required the well site leaders to be confused. 

Thus, Kaluza and others twice called back to shore for guidance when they encountered difficulties 

attempting to convert the float equipment. See Chapter 4.3. Whether well site leaders are confused or not, 

they should be required to call back to shore for a second opinion whenever there is anything unusual or 

unexpected with critical tests, such as the negative pressure test. 

35 Testimony of John Sprague, 177 (agreeing that it does not take long to call back to shore). 

36 Internal BP document (BP-HZN-BLY 38354).

37 Internal BP document (BP-HZN-BLY 38355).

38 Ibid.

39 Internal BP document (BP-HZN-BLY 38361).

40 Ibid.

41 Internal BP document (BP-HZN-BLY 38362).

42 Internal Transocean document (HQS-OPS-ADV-09). 

43 Ibid. 

44 Ibid.

45 Ibid.

46 Ibid.

47 Ezell, interview; Testimony of Paul Johnson, 340-342, 344-347; Testimony of Daun Winslow 

(Transocean), Hearing before the Deepwater Horizon Joint Investigation Team, August 24, 2010, 132-

36;Testimony of Jerry Canducci, Hearing before the Deepwater Horizon Joint Investigation Team, 

December 9, 2010, part 1, 171-172.

48 Transocean representatives, interview with Commission staff, December 10, 2010. 
Chief Counsel’s Report — Endnotes | 337

49 Internal Transocean document (TRN-PC 3227-30).

50 Internal Transocean document (TRN-PC 3227).

51 Internal Transocean document (TRN-PC 3229).

52 Testimony of Daun Winslow, 122-23.

53 Internal Transocean document (TRN-PC 3229); Transocean legal team, interview, December 10, 2010. As 

an aside, it appears that BP sometimes shared lessons from well control events on certain wells with rig 

crews operating other wells. Internal BP document (BP-HZN-MBI 221988). It is unclear whether the 

company did this on a systematic basis. In general, it appears that the industry as a whole does not 

systematically share incident reports and ―lessons learned‖ broadly across companies.

54 Internal Transocean document (TRN-PC 3227). Even after the blowout, Transocean continues to insist 

that drilling and completions are so different—like ―apples and oranges‖—as to render the North Sea 

incident irrelevant. Transocean representatives, interview, December 10, 2010.

55 Testimony of Daun Winslow, 129.

56 Transocean legal team, interview with Commission staff, December 10, 2010.

57 Testimony of Paul Johnson, 385. Transocean sent out another, more detailed advisory on April 14, 2010. 

Internal Transocean document (TRN-PC 3227-230). However, it sent the advisory only to its North Sea fleet; 

it did not send it to the Gulf of Mexico. And again, it unduly limited it to completion operations—the title of 

the advisory was ―Loss of Well Control During Completions Operations.‖ Internal Transocean document 

(TRN-PC 3227-30).

58 Transocean legal team, interview, December 14, 2010.

59 Internal BP document (BP-HZN-MBI 199122).

60 Morel was relatively new to drilling engineering and BP. He was assigned to the exploration team in 2008, 

where he helped to plan two wells before being transferred to Macondo to help Hafle. Hafle, by contrast, was 

the senior drilling engineer of the two and has been involved with deepwater drilling since 1993 and has 

personally been involved in between 20 and 50 wells. Testimony of Mark Hafle (BP), Hearing before the 

Deepwater Horizon Joint Investigation Team, May 28, 2010, 8-9. Hafle was on vacation during much of the 

week leading up to the blowout. 

61 Internal BP document (BP-HZN-MBI 195579).

62 Testimony of John Sprague, 175-76. 

63 Ibid., 193-94. Sprague further acknowledged that drill plans should be provided to the rig as soon as 

possible, admitting that ―You can plan and understand things a lot better the sooner they get there, isn‘t that 

true?‖ Ibid., 192.

64 Internal BP document (BP-HZN-MBI 199122).

65 Internal BP document (BP-HZN-MBI 126145).

66 Internal BP document (BP-HZN-MBI 126333).

67 Internal BP document (BP-HZN-MBI 126585-586).

68 Internal BP document (BP-HZN-CEC 21260-279).

69 Internal BP document (BP-HZN-MBI 126585-86).

70 Ibid.

71 Ibid.

72 Internal BP document (BP-HZN-MBI 126982).

73 Internal BP document (BP-HZN-MBI 127489).

74 Ibid.

75 Internal BP document (BP-HZN-CEC 21281-301).
338 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

76 Internal BP document (BP-HZN-CEC 21288-91).

77 Ibid.

78 Internal BP document (BP-HZN-MBI 127909). The April 16 APM provides so little detail on the negative 

pressure test that members of BP‘s Macondo team after the fact disagree as to what it means. Testimony of 

Gregg Walz, Hearing before the Deepwater Horizon Joint Investigation Team, October 8, 2010, 147-48, 150-

51 (Acknowledging it could be subject to different interpretations but that he interpreted it to mean that the 

negative pressure test should be performed after displacing mud from 8,367 feet to above the BOP); Guide, 

interview, September 16, 2010 (Interpreting steps 2 and 3 to be subparts of step 1); Ronnie Sepulvado (BP), 

interview with Commission staff, August 20, 2010 (interpreting step 1 to require performing the test at the 

mudline with base oil and step 3 as a separate flow check after fully displacing the riser).

79 Internal BP document (BP-HZN-MBI 127906).

80 Internal BP document (BP-HZN-BLY 47094).

81 Internal BP document (BP-HZN-CEC 8574).

82 Internal BP document (BP-HZN-CEC 22433-34). Other examples include the last-minute decisions 

regarding the combined spacer and long string versus a liner, the latter prompting Transocean‘s rig manager 

for the Deepwater Horizon, Paul Johnson, to complain to Guide that the crew needed the procedures to plan 

accordingly. Testimony of Paul Johnson, 360-61.

83 Internal BP document (BP-HZN-MBI 213550).

84 Internal BP document (BP-HZN-CEC 21533).

85 Internal BP document (BP-HZN-MBI 255906).

86 Ibid.

87 Testimony of Mark Hafle, 8-9. 

88 Both Guide and Morel also may have been overworked, as suggested by some of the hasty, last-minute 

decisions. In his 2009 performance evaluation of Morel, David Sims wrote that Morel ―[w]ants and needs a 

high work load‖ and went on to describe all of the different projects he was involved with. Internal BP 

document (BP-HZN-OSC 9029). As for Guide, when asked by the MBI panel for any recommendations going 

forward, BP operations engineer Brett Cocales testified, ―I would say with the kind of load that a wells team 

leader is undertaking, that additional resources would be of benefit to that person,‖ including ―[a]dditional 

people to handle the multitasking areas that that person has to undertake.‖ Testimony of Brett Cocales, 268-

69.

89 Testimony of John Sprague, 33-34. 

90 Ibid., 34-37; Internal BP document (BP-HZN-MBI 208674). Section 3.1.13 of BP‘s Drilling and Well 

Operations Practice (DWOP) manual provides: ―Temporary or permanent changes to personnel, systems, 

procedures, programmes, safety and critical data, equipment, facilities, materials or substances should be 

made using the management of change process.‖ Internal BP document (BP-HZN-OSC 7222).

91 Testimony of John Guide, Hearing before the Deepwater Horizon Joint Investigation Team, July 22, 2010, 

110-11. 

92 Testimony of John Sprague, 33-34.

93 Internal Transocean document (TRN-HCEC 5402-797). Although the near miss in the North Sea on 

December 23, 2009 did not occur during end-of-well activities, it took place during similar circumstances—

the single barrier to flow had been tested. The incident prompted Transocean to remind its North Sea fleet 

that ―tested barriers can fail‖ and that ―high vigilance‖ is necessary ―when reduced to one barrier 

underbalanced.‖ Internal BP document (BP-HZN-BLY 38362). 

94 David Borthwick, Report of the Montara Commission of Inquiry (The Montara Commission of Inquiry, 

Australia, June 2010), 5, 26. According to the Report of the Montara Commission of Inquiry, released on 

November 24, 2010, many of the technical and managerial causes of the Montara blowout track those at 

Macondo. For instance, the Commission of Inquiry concluded that the cement job in the 95⁄8-inch casing 

shoe failed, that there were numerous risk factors surrounding the cement job that went unheeded, and that 

the cement job was not properly pressure tested. Ibid., 7. According to the Commission of Inquiry:
Chief Counsel’s Report — Endnotes | 339

The multiple problems in undertaking the cement job—such as the failure of the top and bottom 

plugs to create a seal after ―bumping,‖ the failure of the float valves and an unexpected rush of 

fluid—should have raised alarm bells. Those problems necessitated a careful evaluation of what 

happened, the instigation of pressure testing and, most likely, remedial action. No such careful 

evaluation was undertaken. The problems were not complicated or unsolvable, and the potential 

remedies were well known and not costly. This was a failure of ―sensible oilfield practice 101.‖ 

Ibid. The Commission of Inquiry went on to conclude that while the ―absence of tested barriers was a

proximate cause of the Blowout,‖ the deeper failure was a systemic failure of management on the part of the 

operator, PTTEP Australasia. Ibid., 9. 

95 Ibid.

96 Testimony of Steve Lewis (Expert witness), Hearing before the National Commission, November 9, 2010, 

64-65.

97 Testimony of Ross Skidmore (BP), Hearing before the Deepwater Horizon Joint Investigation Team, July 

20, 2010, 264.

98 Ezell, interview. 

99 Internal Transocean document (TRN-HCEC 5609-10).

100 There were a number of different alarm systems on the Deepwater Horizon, including a general alarm 

audible to the entire rig and localized combustible gas, fire, and toxic gas alarms that were positioned 

throughout the rig. When triggered, the localized alarms would sound automatically in the affected area and 

send a signal back to the DPO‘s panel on the bridge. According to most witness accounts, the general alarm 

was set to ―manual mode,‖ meaning that a person on the bridge had to activate the general alarm in order for 

it to sound to the entire rig. See, e.g., Testimony of Yancy Keplinger (Transocean), Hearing before the 

Deepwater Horizon Joint Investigation Team, October 5, 2010, part 1, 188, 222 (standard practice to have 

general alarm in manual mode in order ―to permit some human judgment to make a determination as to 

whether or not a general alarm should be sounded as opposed to having it on some automated system‖); 

Testimony of Jerry Canducci, 124 (purpose of manual mode is to ―alert somebody so that they can pass 

judgment on the efficacy of the system, and when it is deemed to be a proper alarm, then the alarm is 

sounded to all‖). The Chief Counsel‘s team does not express a view on the wisdom of having the general 

alarms in manual rather than automatic mode except to note that if the alarm is in manual mode, 

Transocean must ensure that its DPOs are trained to deal with emergency situations. See, e.g., U.S. Coast 

Guard, Navigation and Vessel Inspection Circular No. 2089 (August 4, 1999) § 5.2 (stating that a member of 

the crew should decide whether to sound the general alarm, that the alarm must be initiated manually and is 

intended to be sounded by a person on watch or other responsible member of the crew, and that the general 

alarm may be sounded automatically by a safety monitoring system if a fire alarm is not acknowledged 

within a reasonable amount of time).

101 Testimony of Andrea Fleytas, Hearing before the Deepwater Horizon Joint Investigation Team, October 

5, 2010, part 2, 13-14.

102 Ibid. Fleytas did tell the engine control room that the rig was experiencing a well control situation, as she 

had just received a phone call from the drill floor indicating as much. Ibid.

103 Ibid., 65.

104 Ibid., 53-55.

105 Ibid., 40. Asked whether any of the alarms on the panel were from the engine control room, she 

responded, ―There were so many alarms. There were hundreds of them on that page, so I don‘t remember if 

those were some of them.‖ Ibid.

106 Section 15.2.7 of BP‘s Drilling and Well Operations Practice (DWOP) manual provides: ―Kick detection, 

diverter, circulating, stripping, and shut-in drills shall be held regularly until the designated company 

representative is satisfied that each crew demonstrates suitable BP standards.‖ Internal BP document (BP 

HZN-OSC 7267). It is not clear what, if any drills, BP required on emergency kick detection or diverter 

situations. 

107 Ezell, interview.

108 Nonpublic BP document (presentation to Commission staff, August 9, 2010), 6.

109 Testimony of Mark Bly, 335.
340 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

110 For example, see Rick Godfrey‘s questioning of Gagliano. Testimony of Jesse Gagliano, Hearing before 

the Joint Investigation Team, August 24, 2010, 291.

111 Internal BP document (BP-HZN-OSC 9338).

112 Internal BP document (BP-HZN-MBI 255509).

113 Ibid.

114 Internal BP document (BP-HZN-MBI 128542); Internal BP document (BP-HZN-MBI 110151).

115 Internal BP document (BP-HZN-MBI 128542). 

116 Ibid.

117 Sims, interview, February 1, 2011.

118 Internal BP document (BP-HZN-BLY 125446). 

119 Internal BP document (BP-HZN-MBI 212826). 

120 Internal BP document (BP-HZN-MBI 61225). 

121 Testimony of Daniel Oldfather (Weatherford), Hearing before the Deepwater Horizon Joint Investigation 

Team, October 7, 2010, 14.

122 Jesse Gagliano (Halliburton), interview with the U.S. House of Representatives Committee on Energy and 

Commerce, June 11, 2010; Testimony of Gregg Walz, 53-54.

123 Testimony of Nathaniel Chaisson (Halliburton), Hearing before the Deepwater Horizon Joint 

Investigation Team, August 24, 2010, 437-38.

124 Gagliano, interview.

125 Testimony of Jesse Gagliano, August 24, 2010, 335, 360.

126 Internal BP document (BP-HZN-MBI 137370).

127 Guide, interview, January 19, 2011.

128 BP and Transocean agree on this. Testimony of Mark Bly, 246-47; Bill Ambrose (Transocean), Hearing 

before the National Commission, November 8, 2010, 246-247. 

129 See Chapter 4.7.

130 Joseph Keith (Halliburton), interview with Commission staff, October 6, 2010; Cathleenia Willis 

(Halliburton), interview with Commission staff, October 21, 2010. 

131 See Chapter 4.7.

132 See Chapter 4.7.

133 Allen Seraile (Transocean), interview with Commission staff, January 7, 2010. 

134 See Chapter 4.7.

135 Commission staff site visit to Deepwater Nautilus, September 9, 2010. 

136 Internal BP document (BP-HZN-MBI 127997-128022).

137 Ibid.

138 Internal BP document (BP-HZN-MBI 128018).

139 Ibid.

140 Internal BP document (BP-HZN-MBI 128002). 

141 Internal BP document (BP-HZN-MBI 128009).

142 During a visit to BP‘s Houston headquarters to see the Macondo room, BP personnel told the Chief 

Counsel‘s team that BP did not constantly monitor data and other information from onshore because doing 

so tended to disempower personnel on the rig. The Chief Counsel‘s team does not fully understand that 
Chief Counsel’s Report — Endnotes | 341

explanation. In any event, it is inconsistent with BP‘s pre-blowout plan to implement the ERA advisory 

system. 

143 It should be noted that Transocean does not send its data in real time back to shore.

144 The notable exception is the decision to use a long string production casing, which had been the plan all 

along. However, it was not until the lost circulation event and declaration of early total depth that BP‘s 

Macondo team identified many of the risks associated with using a long string at Macondo. 

145 Internal BP document (BP-HZN-OSC 5420). According to the manual, ― ̳Beyond the Best‘ is the strategic 

brand for Drilling & Completions focused on improving performance in drilling and completions efficiency. 

It targets a prize characteri[z]ed by improved safety performance, improved capital efficiency and a bigger 

contribution to production from new wells.‖ Internal BP document (BP-HZN-OSC 5426).

146 Internal BP document (BP-HZN-OSC5428); Internal BP document (BP-HZN-OSC 5434). 

147 Internal BP document (BP-HZN-OSC 5463).

148 Guide, interview, September 17, 2010. 

149 Sims interview, December 14, 2010. Sims told the Chief Counsel‘s team that except for changes to the well 

plan, the wells team leader had discretion whether to subject a particular decision to the MOC process. Ibid.

150 The drilling and completions group‘s Beyond the Best manual requires that ―[a] clear process must be in 

place for management of change throughout any project. This management of change process must be 

auditable and in place during planning as well as operations.‖ Internal BP document (BP-HZN-OSC 5458). 

Among its requirements for a management of change process are: ―A clear project statement saying when the 

Management of Change process will be utilized,‖ ―[i]ncorporate a risk assessment,‖ and ―[h]ave a clear 

approval structure linked to this change process.‖ Ibid.

151 BP‘s exploration and production unit‘s DWOP provides: ―Any significant changes to a well programme 

shall be documented and approved via a formal management of change (MOC) process which includes those 

on the original approval list.‖ Internal BP document (BP-HZN-OSC 7243).

152 See Internal BP document (BP-HZN-MBI 143120-22); Internal BP document (BP-HZN-MBI 143242-44); 

Internal BP document (BP-HZN-MBI00143247-49)(January 27, 2010 MOC for change from Marianas to 

Deepwater Horizon); Internal BP document (BP-HZN-MBI 143251-53); Internal BP document (BP-HZNMBI 143255-57); Internal BP document (BP-HZN-MBI 143259-61); Internal BP document (BP-HZN-MBI 

143292-94). 

153 Internal BP document (BP-HZN-MBI 143251-53); Internal BP document (BP-HZN-MBI 143255-57); 

Internal BP document (BP-HZN-MBI 143259-61); Internal BP document (BP-HZN-MBI 143292-94). The 

Macondo team twice submitted the long string decision to the MOC process because of an error in the first 

MOC.

154 Guide, interview, September 17, 2010. 

155 Internal BP document (BP-HZN-BLY 61195).

156 Internal BP document (BP-HZN-BLY 61205).

157 Internal BP document (BP-HZN-OSC 7105).

158 Internal BP document (BP-HZN-OSC 7128).

159 O‘Bryan, interview.

160 Internal BP document (BP-HZN-BLY 61475).

161 See Chapter 4.7. BP‘s Engineering Technical Practice on Simultaneous Operations (GP 10-75) also directs 

its personnel to conduct a risk assessment of simultaneous operations ―in order to identify the risks across 

the complete range of well activities‖ and to ―ensure all well activities...are carried out in a safe and 

controlled manner, when these activities are performed in the same space and time as another operation.‖ 

Internal BP document. Internal BP document (BP-HZN-OSC 8019). It is not clear whether BP personnel 

associated the ETP with activities on the Deepwater Horizon generally, let alone conducted any such risk 

assessment with respect to rig activities going on during the final displacement operation. At least one 

witness has suggested that other well site leaders would not have allowed so many rig operations. Joseph 

Keith, interview. 

162 See Chapter 4.7.
342 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

163 Internal Transocean document (TRN-HCEC 90501).

164 Internal BP document (BP-HZN-MBI 225048).

165 Discussing the shut-down of a drilling rig in March, BP executive Harry Thierens wrote Gregg Walz and 

several other managers: ―time is money after all.‖ Internal BP document (BP-HZN-MBI 225981).

166 Transocean-BP Drilling Contract No. 980249; Amendment 41 to Drilling Contract No. 980249.

167 Internal BP document (BP-HZN-MBI 126763).

168 Internal BP document (BP-HZN-MBI 269181); see also Internal BP document (BP-HZN-BLY 125444).

169 Sims, interview, February 1, 2011.

170 Internal Halliburton document (HAL_10648).

171 Guide, interview, January 19, 2011; Internal BP document (BP-HZN-CEC 22433).

172 Internal BP document (BP-HZN-OSC 5561).

173 Internal BP document (BP-HZN-OSC 5558).

174 Internal BP document (BP-HZN-OSC 5573).

175 Ibid.

176 Internal BP document (BP-HZN-MBI 117622).

177 Ibid.

178 Ibid.

179 Ibid.

180 Internal BP document (BP-HZN-MBI 126763).

181 Ibid.

182 Internal BP document (BP-HZN-OSC 5558).

183 As of April 13, BP had paid Transocean about $68 million for the rig‘s day rate. The total cost of the well 

up to that point was $137 million. Internal BP document (BP-HZN-MBI 126763).

184 Ibid.

185 Ibid.

186 Ibid.

187 Internal BP document (BP-HZN-MBI 258390).

188 Internal BP document (BP-HZN-MBI 192546).

189 Internal BP document (BP-HZN-MBI 19552); Internal BP document (BP-HZN-MBI 192558); Internal BP 

document (BP-HZN-MBI 192559).

190 The first AFE was $96.1 million. Internal BP document (BP-HZN-MBI 19552). The total authorizations 

added up to $154.5 million. Internal BP document (BP-HZN-MBI 192559).

191 Internal BP document (BP-HZN-MBI 125958).

192 Testimony of David Sims (BP), Hearing before the Deepwater Horizon Joint Investigation Team, August 

25, 2010, 200.

193 Internal BP document (BP-HZN-MBI 128953).

194 BP estimated bottom 10% performance at 58.7 days per 10,000 feet. Internal BP document (BP-HZNBLY 47298).

195 BP estimated bottom 10% performance at $142.16 million. Ibid.

196 Hafle estimated nonproductive time at 48.3%. Internal BP document (BP-HZN-MBI 128953). BP 

estimated bottom 10% performance at 39.8%. Internal BP document (BP-HZN-BLY 47298).
Chief Counsel’s Report — Endnotes | 343

197 Ronnie Sepulvado, interview. 

198Ibid.; Guide, interview, January 26, 2011; Sims, interview; O‘Bryan interview.

199 Testimony of Steve Lewis (Expert Witness), hearing before the National Commission, November 9, 2010, 

79.

200 Internal BP document (BP-HZN-OSC 5420).

201 Internal BP document (BP-HZN-OSC 5437).

202 Internal BP document (BP-HZN-OSC 5557).

203 Ibid.

204 Internal BP document (BP-HZN-OSC 5558).

205 Internal BP document (BP-HZN-OSC 5437).

206 Internal BP document (BP-HZN-OSC 5557).

207 Internal BP document (BP-HZN-OSC 5561).

208 Sims, interview, December 14, 2010.

209 Ibid.

210 Internal BP document (BP-HZN-OSC 8982). 

211 For instance, Ross Skidmore, a BP contractor tasked with setting the lockdown sleeve at Macondo, and 

Merrick Kelley, BP subsea wells team leader and the person at BP responsible for lockdown sleeves in the 

Gulf of Mexico, had planned per their normal practice to perform a separate ―wash trip‖ to clean out any 

debris before running the lead impression tool and lockdown sleeve. Guide rejected their plan, telling 

Skidmore: ―We will never know if your million dollar flush run was needed. How does this get us to sector 

leadership.‖ Internal BP document (BP-HZN-MBI 258507). Guide has subsequently explained that he did 

not believe a separate wash run was necessary because the crew would already have washed out any debris 

when tripping out of the hole with the drill pipe. Guide, interview, January 19, 2011; Internal BP document 

(BP-HZN-MBI 258233). This explanation may be credible, and the Chief Counsel‘s team cannot say that 

Guide‘s decision increased risk at Macondo. Nevertheless, BP experts still questioned Guide‘s views after the 

incident.

212 Confidential Commission staff review of personnel information, December 8, 2010. 

213 Internal BP document (BP-HZN-OSC 7163).

214 Internal BP document (BP-HZN-MBI 98517).

215 Internal BP document (BP-HZN-MBI 261533).

216 Internal BP document (BP-HZN-OSC8980). 

217 Ibid.

218 Internal BP document (BP-HZN-OSC 8982).

219 Internal BP document (BP-HZN-OSC 8980).

220 Ibid.

221 Graham Ruddick, ―BP says  ̳every dollar counts‘ as profits tumble,‖ The Telegraph, February 3, 2009.

222 Internal BP document (BP-HZN-OSC 8981).

223 Internal BP document (BP-HZN-OSC 9060).

224 Internal BP document (BP-HZN-OSC 9067).

225 Internal BP document (BP-HZN-OSC 9068).

226 Internal BP document (BP-HZN-OSC 9074-75). 

227 BP, Letter to the National Commission, November 22, 2010.

228 Ibid.
344 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

229 BP, ―Golden Rules of Safety,‖ 

http://www.bp.com/liveassets/bp_internet/globalbp/STAGING/global_assets/downloads/B/BPs_Golden_

rules_of_safety.pdf.

230 Internal BP document (BP-HZN-OSC 9025).

231 Ibid. 

232 Internal BP document (BP-HZN-OSC 9054).

233 Internal BP document (BP-HZN-OSC 9025).

234 Sims, interview, December 14, 2010.

Chapter 6

1

Troy Trosclair (MMS), interview with Commission staff, October 1, 2010.

2

Testimony of Walter Cruickshank (MMS), Hearing before the National Commission, November 9, 2010, 

186-87.

3 U.S. Department of the Interior, Outer Continental Shelf Safety Oversight Board, Report to the Secretary 

of the Interior (September 1, 2010), 6. ―APMs have increased by 71% from 1,246 in 2005 to 2,136 in 2009 in 

the New Orleans District.‖ Ibid.

4

Frank Patton (MMS), interview with Commission staff, October 1, 2010; David Trocquet (MMS), interview 

with Commission staff, October 1, 2010.

5

Patton, interview.

6

30 C.F.R. § 250.413.

7

Patton, interview.

8

30 C.F.R § 250.428.

9

Internal BP document (BP-HZN-MBI 133874). 

10 Internal BP document (BP-HZN-MBI 23715). 

11 30 C.F.R. § 250. 415, 420. Test pressures are determined based on operator calculation of maximum 

anticipated surface pressure, or the amount of pressure an operator expects to be exerted on casing and 

subsea equipment. Steve Lewis (Expert witness), email to Commission staff, October 27, 2010. Regulations 

expressly leave this calculation to operators. 30 C.F.R. § 250.413(f). In calculating this figure, some 

operators, including BP at the Macondo well, currently assume a well column is 50% gas and 50% drilling 

fluid. Steve Lewis (Expert witness), interview with Commission staff, September 28, 2010. However, during 

a blowout the well column can be entirely empty of mud and instead contain 100% gas. Ibid. The current 

industry norm assuming 50% mud in the well column thus underestimates MASP and results in 

correspondingly low test pressures that do not reflect the worst-case blowout scenario. Ibid. 

12 30 C.F.R. § 250. 415, 420.

13 Patton, interview.

14 Ibid.

15 30 C.F.R § 250.422(a).

16 Testimony of Walter Cruickshank, 198-99.

17 MMS regulations do state that ―[b]efore removing the marine riser, you must displace the riser with 

seawater. You must maintain sufficient hydrostatic pressure or take other suitable precautions to 

compensate for the reduction in pressure and to maintain a safe and controlled well condition.‖ 30 C.F.R § 

250.442(e). A negative pressure test is a way to prove that the well will withstand that reduction of pressure 

as a means of satisfying this requirement. Testimony of John Smith (Expert witness), Hearing before the 

National Commission, November 9, 2010, 152. 
Chief Counsel’s Report — Endnotes | 345

18 Internal BP document (BP-HZN-MBI 23711). Some have questioned whether the temporary abandonment 

procedures in the approved permit would have required a negative pressure test to be conducted at the 

wellhead before displacement, or whether it could be done at 8,367 feet in the middle of displacement (as 

was actually done at Macondo). Regardless of this argument, it is unlikely that the MMS would have rejected 

an APM that said the negative pressure test was to be conducted at a depth of 8,367 feet. Patton, interview. 

Discussed further in Chapter 4.6 (Negative Pressure Test).

19 Oil and Gas and Sulphur Operations in the Outer Continental Shelf—Increased Safety Measures for 

Energy Development on the Outer Continental Shelf, 75 Fed. Reg. 63346, 63373 (October 14, 2010).

20 John Smith (Expert witness), interview with Commission staff, October 26, 2010.

21 Internal BP document (BP-HZN-OSC 1436).

22 Internal BP document (BP-HZN-MBI 127906).

23 During the Commission‘s public hearing, Dr. Walter Cruickshank stated that the official had also drawn 

reassurance from the fact that BP planned to conduct a negative pressure test on the surface cement plug 

prior to abandoning the well and that this test would help ensure safety. Testimony of Walter Cruikshank, 

206. This makes little sense: The procedure that BP submitted specifies that the negative pressure test will 

be done before setting the surface cement plug. Internal BP document (BP-HZN-MBI 23711).

24 Internal BP document (BP-HZN-CEC 20942).

25 30 C.F.R § 250.448(c). The upper annular was rated to withstand 10,000 psi closed on pipe or 5,000 psi 

closed on an open hole. BP, Deepwater Horizon Accident Investigation Report (September 8, 2010), app. H, 

227. After conversion to a stripping annular, the lower annular was rated to withstand 5,000 psi. Ibid., 172. 

Post-explosion examination of the blue pod found regulated pressure on the lower annular preventer was set 

to approximately 1,700 psi. Ibid., 145. According to subsea supervisor Chris Pleasant, he reset the lower 

annular regulator pressure to 1,500 psi soon after 9 p.m. Testimony of Chris Pleasant (Transocean), Hearing 

before the Deepwater Horizon Investigation Team, May 28, 2010, 120. According to BP, 1,500 psi was the 

normal regulator pressure setting for both annular preventers. BP, Deepwater Horizon Accident 

Investigation Report, 145. 

26 Internal BP document (BP-HZN-OSC 867).

27 Internal BP document (BP-HZN-OSC 925).

28 Internal BP document (BP-HZN-MBI 107364-65). 

29 30 C.F.R § 250.446(a).

30 American Petroleum Institute, Recommended Practices for Blowout Prevention Equipment Systems for 

Drilling Wells, 3rd ed. (March 1997, reaffirmed September 2004), 56 (―API RP 53 § 18.10.3‖).

31 Internal Cameron document (CAM-GR 261-62).

32 Testimony of Mark Hay (Transocean), Hearing before the Deepwater Horizon Joint Investigation Team, 

August 25, 2010, 32-33; Testimony of John Sprague (BP), Hearing before the Deepwater Horizon Joint 

Investigation Team, December 8, 2010, 79-80.

33 Internal BP document (BP-HZN-MBI 136213).

34 Internal Transocean document (TRN-USCG_MMS 38652).

35 Internal Transocean document (TRN-USCG_MMS 38662). The BOP‘s fail-safe valves, designed to shut off 

choke and kill lines remotely and automatically, had not been certified since December 13, 2000. Internal 

Transocean document (TRN-USCG-MMS 38656). 

36 30 C.F.R § 250.446(a); Elmer Danenberger (Expert witness), interview with Commission staff, January 5, 

2011.

37 Internal MMS document.

38 Testimony of Eric Neal (MMS), Hearing before the Deepwater Horizon Joint Investigation Team, May 11, 

2010, 325. 

39MMS, National Potential Incident of Noncompliance (PINC) and Guideline List (May 2008). 

40 Testimony of Eric Neal, 326.

41 MMS, National Potential Incident of Noncompliance (PINC) and Guideline List – Drilling (May 2008). 
346 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Appendix A|Blowout Investigation Team

FRED H. BARTLIT, JR.

Chief Counsel

RICHARD SEARS

Senior Science & Engineering Advisor

SEAN C. GRIMSLEY

Deputy Chief Counsel

SAMBHAV N. SANKAR

Deputy Chief Counsel

J. JACKSON EATON

Counsel

BRENT C. HARRIS

Counsel

JON IZAK MONGER

Counsel

SARITHA KOMATIREDDY TICE

Counsel

JOSEPH B. HERNANDEZ

Paralegal

MICHELLE FARMER

Executive Legal Assistant

GRAPHICS AND LAYOUT BY TRIALGRAPHIX
Chief Counsel’s Report — Appendix B: Commission Staff | 347

Appendix B|Commission Staff

Richard Lazarus, Executive Director

Tracy Terry, Deputy Director

Fred H. Bartlit, Jr., Chief Counsel Jay Hakes, Director of Research & Policy

Priya Aiyar

Deputy Chief Counsel

Felicia Barnes

Analyst

Adam Benthem

Analyst 

Gordon Binder 

Senior Policy Advisor

Paul Bledsoe

Senior Policy Advisor 

Jed J. Borghei

Counsel

C. Hobson Bryan

Analyst 

Edwin H. Clark, II

Director of Operations

Kate Clark

Senior Analyst

Dave Cohen

Press Secretary

Cindy Drucker

Director of Public Engagement

Katherine Duncan

Analyst 

J. Jackson Eaton

Counsel

Michelle Farmer

Executive Legal Assistant

Sean C. Grimsley

Deputy Chief Counsel

David Greenberg

Senior Policy Advisor 

Brent C. Harris

Counsel

Lisa K. Hemmer

Senior Legal Advisor

Joseph B. Hernandez

Paralegal 

Joel Hewett

Analyst 

Christiana James

Staff Assistant 

Jill Jonnes

Senior Researcher

Nancy Kete

Senior Analyst 

Caitlin Klevorick 

Policy Advisor 

Emily Lindow

Senior Analyst 

Claire Luby

Assistant to the Executive Director

Bethany Mabee

Communications Coordinator

Scott McKee

Analyst 
348 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Claudia A. McMurray

Senior Counsel for Congressional and State 

Relations

Louise Milkman

Chief of Staff to the Executive Director

Jon Izak Monger

Counsel

Shirley Neff

Senior Analyst 

Pete Nelson

Director of Communications

Elena Nikolova

Analyst 

Jessica O‘Neill

Counsel

Paul Ortiz

Senior Legal Advisor 

Tony Padilla

Analyst 

Tyler Priest

Senior Analyst 

Sarah Randle

Analyst 

Irwin Redlener

Senior Public Health Advisor

John S. Rosenberg

Chief Editor

Eric Roston

Senior Analyst 

Sara Rubin

Analyst

Sambhav N. Sankar

Deputy Chief Counsel

Nicole A. Sarrine

Staff Assistant 

Richard Sears

Senior Science & Engineering Advisor

Steven Siger

Counsel

Robert Spies

Senior Environmental Science Advisor

Danielle Stewart

Staff Assistant 

Marika Tatsutani

Editor

Johnny Tenorio

Information Technology Officer

Saritha Komatireddy Tice

Counsel

Lloyd Timberlake

Senior Researcher

Clara Vondrich

Counsel

Jason Weil

Analyst 

David Weiss

Counsel

Stephen M. Willie

Administrative Officer

Andrea J. Yank

Assistant to Co-Chair William Reilly 
Chief Counsel’s Report — Appendix C: Acronyms | 349

Appendix C|Acronyms

AFE Approval for Expenditure

AMF Automatic mode function

APB Annular pressure buildup

APD Application for permit to drill

API American Petroleum Institute

APM Application for permit to modify

bbl Barrels

BOEMRE Bureau of Ocean Energy Management, Regulation, and Enforcement

BOP Blowout preventer

bpm Barrels per minute

BSR Blind shear ram

CMMS Computerized Maintenance Management System

DP Dynamically positioned 

DPO Dynamic positioning officers

ECD Equivalent circulating density

EDS Emergency disconnect system

ERA Efficient Reservoir Access

ESD Equivalent static density

ETP Engineering Technical Practice

FIT Formation integrity test

gal/sack Gallons per sack

gpm Gallons per minute

HSSE Health, safety, security, and the environment

LDS Lockdown sleeve

LMRP Lower marine riser package

LOT Leak off test

MC 252 Mississippi Canyon Block 252

MD Measured depth

MMS Minerals Management Service
350 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

MOC Management of change

MODU Mobile offshore drilling unit

MUX Multiplex

OIM Offshore installation manager

OMS Operating management system 

PINC Potential incidents and noncompliance 

ppg Pounds per gallon

PRV Pressure relief valve

psi Pounds per square inch

RCRA Resource Conservation and Recovery Act

RMS Rig Management System

ROV Remotely operated vehicle

SG Specific gravity

TD Total depth

TIGER Totally Integrated Geological and Engineering Resource

TOC Top of cement

TVD Total vertical depth

UWILD Underwater Inspection in Lieu of Dry-docking
Chief Counsel’s Report — Appendix D: Chevron Laboratory Report Cover Letter | 351

Appendix D|Chevron Laboratory Report 

Cover Letter
352 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling
Chief Counsel’s Report — Appendix E: Nile and Kaskida | 353

Appendix E|Nile and Kaskida

faced MMS deadlines on the two projects planned for the 

Deepwater Horizon after Macondo—permanent 

abandonment of a Nile well and spudding of a Kaskida well. 

The Chief Counsel‘s team found that these regulatory 

deadlines did not significantly compound the already existing time pressure at 

Macondo.1 

Schedule When the Deepwater Horizon

Arrived at Macondo

The high daily cost of employing the Deepwater Horizon put pressure not just on the immediate 

task of drilling, but also on how BP scheduled future projects for the rig. The schedule for a 

drilling rig should be seamless. Empty days on the calendar waste dollars. BP had to pay 

Transocean a daily lease fee regardless of whether the Deepwater Horizon was drilling or not.2 

Throughout the drilling of the Macondo well, BP focused on how it would keep the rig active after 

Macondo. Delays at Macondo, equipment delays at another well, and regulatory commitments to 

MMS complicated the task.

Long before the Deepwater Horizon arrived at Macondo, BP began planning work for the rig at 

future locations.3 BP‘s schedule for the Deepwater Horizon stretched years into the future, up to 

2013.4 When the Deepwater Horizon arrived at Macondo, BP planned to have the rig on location 

for about 45 days.5

BP planned to then send the rig to Nile for 30 days.6 Nile was in another tract in the Gulf of 

Mexico, located about a day‘s voyage from Macondo. BP faced a July 2, 2010 deadline to 

permanently abandon its well at Nile.7 Federal regulations require a lease holder to ―permanently 

plug all wells on a lease within 1 year after the lease terminates.‖8 Nile had been a productive well 

for BP, and it would be BP‘s first permanent abandonment of a subsea producing well in the Gulf 

of Mexico.9 The task would be complex, and the rig crew worried about its challenges.10 

After Nile, the Deepwater Horizon would go to Kaskida, located in yet another tract in the Gulf of 

Mexico leased by BP.11 Kaskida is about 250 miles southwest of New Orleans and about a 

four-day voyage from Macondo.12 In 2006, the Deepwater Horizon drilled an exploration well at 

Kaskida that proved to be a large discovery.13 MMS required BP to conduct further activities at 

Kaskida by May 16, 2010 to keep its lease.14 Federal regulations require activity on an exploration 

lease every 180 days.15 MMS regulation 30 C.F.R. § 250.180 specifies that a lease ends after a 

certain period ―unless you are conducting operations on your lease.‖16 Drilling counts as 

operations, so long as the ―objective of the drilling‖ is ―to establish production in paying 

quantities on the lease.‖17 Without activity or production, MMS could cancel the lease.18 BP‘s 

original schedule allowed the Deepwater Horizon to carry out the abandonment of Nile first and 

still meet the deadline at Kaskida.

19

BP
354 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

Request to Suspend Operations at Kaskida

While the Deepwater Horizon drilled the Macondo well, BP worried that delays for the Kaskida 

wellhead would leave the rig with too much time after it completed its current well.20 BP required 

a first-of-its-kind wellhead at Kaskida.21 Delivery of that wellhead proved a headache for BP.22 

The emergency seal for the wellhead failed tests.23 These failures led to an ever-changing set of 

delivery dates. In February, BP engineering team leader David Sims expressed his concerns to 

several managers and executives: ―Even with the delays we are experiencing on Macondo, I still 

feel that there is a significant risk that the Horizon will finish the Nile P&A before the DrilQuip 

20K wellhead is delivered.‖24 

Fearing that the rig might be left idle because of the wellhead delays, BP considered several 

options. The company contemplated extending work at Macondo itself and having the rig stay 

longer.25 It explored alternative projects for the Deepwater Horizon after the rig completed 

both Macondo and Nile.26 And it thought about having the rig undergo maintenance to fill gaps in 

the schedule.27 

Toward the end of March, the Deepwater Horizon fell far enough behind schedule at Macondo 

that BP stopped brainstorming additional projects to occupy the rig and determined that the Nile 

project would likely no longer fit in before the 180-day clock ran out at Kaskida. If the Deepwater 

Horizon were going to spud Kaskida despite the delay, that left BP two primary options. One 

option was to go to Nile first and ask MMS for an extension at Kaskida. Another option was to go 

to Kaskida directly and make alternative arrangements for Nile. 

BP weighed going to Kaskida directly.28 Reasons to go to Kaskida included avoiding the hurricane 

season in the Gulf of Mexico and maintaining the schedule for work on the well after the 

Deepwater Horizon‘s spud.29 Ultimately, BP concluded that it preferred to have the Deepwater 

Horizon do the Nile project first. Reasons to go to Nile included continuing concern about the 

wellhead: ―[g]oing to Kaskida post Macondo assumes wellhead ready to utilize, currently planned 

ready ca. 23 April.‖30 BP also wanted to complete Nile in time to fit in a previously scheduled 

crane replacement operation.

31

 On April 8, BP vice president of drilling and completions Pat 

O‘Bryan concluded, ―Sounds like we should leave [Nile] on the Horizon as originally planned.‖32 

Fitting in Nile before going to Kaskida became impossible from a scheduling perspective. BP 

anticipated that Nile would take about 30 days.33 Because BP kept the Nile project on the 

Deepwater Horizon‘s schedule, BP had no choice but to ask MMS for an extension of the deadline 

at Kaskida in order to avoid losing the lease. By April 16, BP had only 30 days until the May 16 

deadline at Kaskida, not counting transit time to get from one well to the next.34 Consequently, 

BP would need a ―suspension of operations‖ at Kaskida. A suspension of operations ―extend[s] 

the term of a lease.‖35

On April 9, Sims began to draft BP‘s request to MMS for a suspension of operations at Kaskida. 36 

On one level, the request to suspend operations was straightforward. A suspension of operations 

may be granted ―when necessary to allow you time to begin drilling or operations when you are 

prevented by reasons beyond your control, such as unexpected weather, unavoidable accidents, or 

drilling rig delays.‖37 The primary test on ―whether you are  ̳prevented beyond your control‘ is 

whether the particular drilling rig was scheduled to conduct operations at your location before the 

lease expiration date.‖38 The Deepwater Horizon had been scheduled to conduct operations at 

the location before the expiration date, and it had faced delays at Macondo.
Chief Counsel’s Report — Appendix E: Nile and Kaskida | 355

Nonetheless, a suspension of operations is granted only ―on a case-by-case basis‖ and typically for 

―a short duration.‖39 Moreover, the delay at Macondo prevented the Deepwater Horizon‘s timely 

arrival at Kaskida only because BP had kept Nile first on the Horizon‘s schedule. Without Nile, 

there would be no need for a suspension. BP‘s situation fit the criteria for a suspension, but not 

definitively. A member of BP‘s offshore land negotiation team commented, ―While the Nile P&A 

timing is critical path to us, the MMS unit group may not see it that way and suggest that 

operation be delayed to avoid the issuance of an SOO.‖40 He then remarked that whether MMS 

would grant the suspension was ―anyone‘s guess.‖41 On April 20, BP sent the request for a 

suspension of operations to MMS.42 

While waiting to hear from MMS, BP planned to send the Deepwater Horizon to Nile.43 BP sent a 

team out to the rig to prepare for the move to Nile.44 Some members of the BP team may have 

perceived pressure to complete the Macondo well quickly. Before the MMS request went out, BP 

subsea wells team leader Merrick Kelley emailed BP drilling engineer Brian Morel: ―I know you 

all are under pressure to finish Macondo so we can get Nile P&A moving and not jeopardize the 

Kaskida well and IFT.‖45 Uncertainty about internal BP plans, or uncertainty about MMS‘s 

decision, may have prompted concern about time pressure. 

Nonetheless, if there was concern, the Chief Counsel‘s team has found no evidence that it was 

widespread. BP drilling engineer team leader Gregg Walz, BP wells team leader John Guide, BP 

well site leader Murry Sepulvado, and Sims said that Nile put no pressure on the temporary 

abandonment of Macondo.46 Similarly, Transocean offshore installation manager (OIM) Jimmy 

Harrell testified that he faced no pressure from BP or Transocean to move on to Nile.47 Moreover, 

BP planned to send the rig directly to Kaskida if MMS denied the request to suspend operations 

and then to ask for an extension at Nile.48 If that happened, the Deepwater Horizon would 

experience downtime, not pressure.49 BP planned maintenance to ―fill any gaps‖ if the wellhead 

arrived late.50 

Though BP‘s decisions at Macondo appear to have been biased in favor of saving time and 

money, the rig‘s next wells do not appear to have been an important contributing factor. BP 

followed the rig‘s schedule closely and, when necessary, took action to relieve the pressure of 

regulatory deadlines.

1

There has been some suggestion that these deadlines increased the time pressure to finish Macondo. See, 

e.g., Joel Achenbach, ―BP Cost-cutting Measures are Focus of U.S. Inquiry into Gulf Spill,‖ Washington Post, 

October 8, 2010.

2 Drilling Contract No. 980249.

3

Internal BP document (BP-HZN-MBI 123225).

4

Internal BP document (BP HZN MBI 98347).

5

Internal BP document (BP-HZN-MBI 125958).

6

Internal BP document (BP-HZN-MBI 123225).

7

Ibid.

8

30 CFR § 250.1710.

9

Internal BP document (BP-HZN-MBI 123225).

10 Internal BP document (BP-HZN-MBI 21305).

11 In its internal plans, BP described Kaskida as ―one of the largest Paleogene discoveries to date.‖ The 

discovery had the potential to support the Gulf of Mexico division‘s goal to ―sustain production over 
356 | National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling

450mboed‖ (million barrels of oil or equivalent daily). BP expected that the project would break even at oil 

prices over $55/barrel and that returns would accrue rapidly above those prices. Internal BP document (BPHZN-MBI 98022). 

12 Press Release, Anadarko Petroleum, BP & Partners Make Discovery at Kaskida Prospect in Gulf of Mexico,

August 31, 2006, http://www.rigzone.com/news/article.asp?a_id=35730.

13 Ibid.

14 Internal BP document (BP-HZN-MBI 123225). Drilling at Kaskida would be cutting edge and challenging. 

The test that BP planned there in preparation for production would be a ―very, very complicated‖ 

completion. Testimony of John Guide (BP), Hearing before the Deepwater Horizon Joint Investigation 

Team, October 7, 2010, part 2, 213. BP described the work as ―the deepest and highest pressure completions 

ever attempted by the industry globally.‖ The reservoir was ―tight‖ and the fluids ―relatively viscous.‖ There 

were also ―[s]alt sutures/inclusions‖ and ―salt exit uncertainty.‖ On top of the difficult geology, the size of the 

casing limited the ―number of contingency strings...imparting drilling complexities normally avoided by 

early appraisal wells.‖ And BP worried about the risks of a ―poor quality cement job.‖ To limit the chance of 

encountering unexpected challenges, BP placed the planned well fewer than five football fields—only 1,400 

feet—from the discovery well. BP would also use a relatively large 81⁄2-inch production casing. Internal BP 

document (BP-HZN-MBI 98022).

15 30 CFR § 250.180.

16 Ibid.

17 Ibid.

18 30 CFR § 256.77.

19 Internal BP document (BP-HZN-MBI 123225). In early January, BP contemplated a start at Kaskida as 

early as mid-March if the Deepwater Horizon performed well on the earlier projects. Internal BP document 

(BP-HZN-MBI 98069).

20 In February, Richard Harland, the drilling engineer for Kaskida, speculated that the timing looked ―tight‖ 

if the Deepwater Horizon delivered the Macondo well early and came in on schedule for Nile. If Nile also 

came in early, there was a ―real schedule issue.‖ Internal BP document (BP-HZN-MBI 100909).

21 Internal BP document (BP-HZN-MBI 98027).

22 Testimony of Gregory Walz (BP), Hearing before the Deepwater Horizon Joint Investigation Team, 105; 

Pat O‘Bryan (BP), interview with Commission staff, December 17, 2010; David Sims (BP), interview with 

Commission staff, December 14, 2010.

23 Internal BP document (BP-HZN-MBI 100909).

24 Internal BP document (BP-HZN-MBI 107569).

25 Sims wrote Pat O‘Bryan, BP vice president of drilling and completions, ―Extend work on Macondo (bypass 

or deepen)...while waiting on 20K wellhead delivery.‖ Internal BP document (BP-HZN-MBI 108874). He 

then reiterated the original schedule for the Deepwater Horizon: ―Do Macondo, Nile, then Kaskida 

IFT.‖Ibid. At about the same time, on March 7, Sims explored engineering possibilities to deepen the 

Macondo well. He wrote BP senior drilling engineer Mark Hafle that he had been exploring whether there 

might be interest in ―deepening or bypass core to buy us some time for Kaskida wellhead to arrive.‖ Internal 

BP document (BP-HZN-MBI 109036). He then asked if a liner or a tieback would be better fit if the well 

went deeper than planned. Ibid. A few days later, BP also considered having the rig undergo maintenance to 

fill gaps in the schedule. Internal BP document (BP-HZN-MBI 113535). 

26 Sims inquired if there was ―any work of relatively short duration (+/-1 month) that we could plan and 

execute if necessary, to allow the wellhead time to be delivered.‖ Internal BP document (BP-HZN-MBI

107569). In response to Sims‘ request, BP engineering manager John Sprague asked another team to 

evaluate if there was anything in the division‘s ―[h]opper‖ that might be available for the Deepwater Horizon 

after Kaskida. Internal BP document (BP-HZN-MBI 108133). On March 1, Sprague heard back that a 

colleague was ―look[ing] through the hopper for any possibilities.‖ Ibid. Without good options forthcoming, 

Sims asked whether another well might be approved by MMS. He wrote on March 5, ―For instance, if we 

needed to accelerate Tiber to follow Nile P&A because the wellhead equipment is not ready could we have 

regulatory approval to spud by mid-April?‖ Internal BP document (BP-HZN-MBI 108827).

27 Sims asked John Guide if Transocean had ―put together a wishlist of work for the rig.‖ Guide replied that 

―we do have a high level wish list.‖ Internal BP document (BP-HZN-MBI 113536).
Chief Counsel’s Report — Appendix E: Nile and Kaskida | 357

28 Sims, interview.

29 Internal BP document (BP-HZN-MBI 118963).

30 Ibid.

31 Internal BP document (BP-HZN-MBI 123225).

32 Internal BP document (BP-HZN-MBI 119027).

33 Internal BP document (BP-HZN-MBI 123225).

34 It would take about a day to get to Nile from Macondo. 

35 30 CFR § 250.169.

36 Internal BP document (BP-HZN-MBI 123225).

37 30 CFR § 250.175.

38 NTL No. 2000-G17.

39 Ibid.

40 Internal BP document (BP-HZN-MBI 127785).

41 Ibid.

42 Internal BP document (BP-HZN-MBI 127785).

43 Testimony of Brett Cocales (BP), Hearing before the Deepwater Horizon Joint Investigation Team, August 

27, 2010, 11; Testimony of Gregory Walz, 104.

44 Testimony of Ross Skidmore, 210.

45 Internal BP document (BP-HZN-MBI 126333).

46 Walz, interview; Sims, interview; Murry Sepulvado, interview; Guide, interview, January 19, 2011.

47 Testimony of Jimmy Harrell (Transocean), Hearing before the Deepwater Horizon Joint Investigation 

Team, May 27, 2010, 29. 

48 Internal BP document (BP-HZN-MBI 128990); Sims, interview, December 14, 2010.

49 Internal BP document (BP-HZN-MBI 128990).

50 Ibid.