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BPXP Plea Agreement

2017

Annual Progress Report

Report publication date:

January 17, 2018

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TABLE OF CONTENTS

Preface ............................................................................................................... 1 Acronyms and Abbreviations ................................................................................................. 2

Report Sections

Safety and Environmental Management Systems (SEMS) Audits (Paragraphs 5-8) .............................................................................................................. 5-8.1

Third Party Verification of Blowout Preventers (BOP) (Paragraph 9) ............................................................................................................. 9.1T

Deepwater Well Control Competency Assessments (Paragraph 10) ............................................................................................................ 10.1

Cement Design and Competency (Paragraph 11) ............................................................................................................ 11.1

Houston Monitoring Center (Paragraph 12) ............................................................................................................ 12.1

Incident Reporting (Paragraph 13) ............................................................................................................ 13.1

Oil Spill Response Plan Training and Exercises (Paragraphs 14-19) ................................................................................................ 14-19.1

OSRP Best Practices (Paragraph 20) ............................................................................................................ 20.1

Safety Technology Developed with Industry (Paragraph 21) ............................................................................................................ 21.1

Other Safety Technology Development (Paragraph 22) ............................................................................................................ 22.1

Transparency (Paragraph 23) ............................................................................................................ 23.1

Rig Equipment - Two Blind Shear Rams (Paragraph 24) ............................................................................................................ 24.1

Safety Organization (Paragraph 25) ............................................................................................................ 25.1

Third Party Auditor (Paragraphs 26-31) ................................................................................................ 26-31.1

BPXP Plea Agreement 2017 Annual Progress Report www.bpxpcompliancereports.com Page 1

Preface

On the evening of April 20, 2010, a gas release and subsequent explosion occurred on the Deepwater Horizon drilling rig working on the Macondo exploration well for BP in the Gulf of Mexico. Eleven people died as a result of the accident and others were injured. We deeply regret this loss of life and recognize the tremendous loss suffered by the families, friends and co-workers of those who died.

The accident involved a well integrity failure, followed by a loss of hydrostatic control of the well. This was followed by a failure to control the flow from the well with the blowout preventer (BOP) equipment, which allowed the release and subsequent ignition of hydrocarbons. Ultimately, the BOP emergency functions failed to seal the well after the initial explosions. Multiple investigations and evidence presented in federal court have shown the accident was the result of multiple causes involving multiple parties.

We regret the impacts on the environment and livelihoods of those in the communities affected. We have, and continue to, put in place measures to help ensure it does not happen again. BP is committed to sharing what we have learned to advance the capabilities and practices that enhance safety in our company and the deepwater industry.

On November 15, 2012, BP reached an agreement with the US Government to resolve all federal criminal claims arising out of the incident. On January 29, 2013, the Plea Agreement was entered and BP Exploration & Production Inc. (BPXP) plead guilty to federal crimes. The Plea Agreement can be found at:

http://www.justice.gov/iso/opa/resources/43320121115143613990027.pdf

As required by the Plea Agreement the following document summarizes the efforts that BPXP has made to comply with the obligations of Paragraphs 5 through 31 of the Remedial Order (Exhibit B) of the Plea Agreement. Each Paragraph section of the Annual Progress Report corresponds to the same Paragraph section of the Remedial Order. Each of the Remedial Order obligations in 2017 were completed by BPXP on time and were in compliance with the requirements.

Paragraph 23 of the Remedial Order requires BPXP to create a public website where the following information must be posted:

• Lessons learned from the Deepwater Horizon incident; • Annual progress reports summarizing BPXP's compliance with Paragraphs 5 through 31 of the Remedial

Order; • Annual summaries of recordable safety incidents, days away from work, hydrocarbon spills and the volume

thereof; and • An annual list of all incidents of non-compliance (INC) with the Bureau of Safety and Environmental

Enforcement (BSEE) or the Bureau of Ocean Energy Management (BOEM) regulations or probation for which BPXP is cited, including corrective actions taken and penalties assessed.

The BPXP public website is found at the following link:

http://www.bpxpcompliancereports.com/ This 2017 Annual Progress Report is BPXP’s fifth and final Annual Progress Report as required under the terms of the Plea Agreement. Since entering into the Plea Agreement on January 29, 2013, throughout the entire five-year term, BPXP has met all of the Remedial Order obligations.

http://www.justice.gov/iso/opa/resources/43320121115143613990027.pdf

http://www.bpxpcompliancereports.com/


List of Acronyms & Abbreviations

AAR After Action Review

ABS No definition – company name

ACP Area Contingency Plan

AIS Automated Identification System

AOM Area Operations Manager

APD Applications for Permit to Drill

API American Petroleum Institute

APM Application for Permit to Modify

APV Air Pressure Vessel

ASME American Society of Mechanical

Engineers

bbl. barrel

BHA Bottom Hole Assembly

BOEM Bureau of Ocean Energy

Management

BOP Blowout Preventer

BPXP BP Exploration and Production

BSEE Bureau of Safety and

Environmental Enforcement

BSR Blind Shear Ram

BST Business Support Team

C&EA Communications and External

Affairs

CADA Cam Actuated Drill Ahead

CAM Contract Accountable Manager

CCM/ER Crisis and Continuity

Management and Emergency

Response

CFR Code of Federal Regulations

CGA Clean Gulf Associates

CI Continuous Improvement

CMC Crown Mounted Compensator

CMOTEP Crisis Management Organization,

Training and Exercise Plan

COP Common Operating Picture

CoP Community of Practice

COS Center for Offshore Safety

CoW Control of Work

CP Command Post

CPRA Coastal Protection and

Restoration Authority

CST Country Support Team

CT Coiled Tubing

CWOR Completion Workover Riser

DAFWC Days Away from Work Cases

DC Direct Current

DC Drilling Center

DC Drilling Contractors

DD III Development Driller III – Drilling

Rig

DD3 No definition – drilling rig

DHFC Downhole Flow Control

DNV Det Norske Veritas

DoA Delegation of Authority

DoFA Delegation of Financial Authority

DPO Dynamic Positioning Officer

DSL Drilling Section Leader

EASY Eliminating Accidents Starts with

You

EHS Environmental Health and Safety

ENVL Environmental Unit Leader

EPA Environmental Protection Agency

ERM-CVS No definition – company name

ERT Emergency Response Team

ESI Environmental Sensitivity Index

EST Executive Support Team

ETP Engineering Technical Practice


FEMA IS Federal Emergency Management

Agency Independent Study

FMC No definition – company name

FRC Fast Rescue Craft

GBS Global Business Services

GIS Geographic Information Systems

GoM Gulf of Mexico

GOO Global Operations Organization

GPO Global Projects Organization

GRA Guideline-less Riser Assist

GRP Geographic Response Plan

GWO Global Wells Organization

H&S TL Health and Safety Team Lead

H2S Hydrogen Sulfide

HAZOP Hazardous Operation Study

HCC Houston Crisis Center

HITRA Hazard Identification Task based

Risk Assessment

HMC Houston Monitoring Center

HOLC Houma Operations Learning

Center

HR Human Resources

HS Health and Safety

HSE Health Safety & Environmental

HSEEP Homeland Security Exercise and

Evaluation Program

HWCG Helix Well Containment Group

HWOF Hot Work Open Flame

I&E Instrumentation & Electronics

IA Issuing Authority

IAP Incident Action Plan

IBOP Internal Blowout Preventer

IC Incident Commander

ICP Incident Command Post

ICS Incident Command System

ID Identification

IFS Seadrill’s Preventative

Maintenance System

IMS Incident Management System

IMT Incident Management Team

INC Incidents of Non-Compliance

INCC Incident Notification and

Coordination Center

IP Injured Person or Party

IPW Incident Potential Worksheet

IRS Intervention Riser System

ISB In-Situ Burn

IT Information Technology

JSA Job Safety Analysis

JSEA Job Safety and Environmental

Analysis

JTRA Job Task Risk Assessment

LDEQ Louisiana Department of

Environmental Quality

LDIS Light Duty Intervention System

LDNR Louisiana Department of Natural

Resources

LEL Lower Explosion Limit

LOSCO Louisiana Oil Spill Coordination

Office

LTPC Long Term Protective Cap

LWSL Lead Well Site Leader

MAR Major Accident Risk

MCC Motor Control Center

MDEQ Mississippi Department of


MOC Management of Change

MODU Mobile Offshore Drilling Unit

MPcp Major Project Common Process

MSL Marine Section Leader


MSRC Marine Spill Response

Corporation

MWCC Marine Well Containment

Company

NALCO Company name – NALCO

Corporation

NDT Non-Destructive Testing

NIMS National Incident Management

System

NOAA National Oceanic and

Atmospheric Administration

NOV National Oilwell Varco – company

name

NPC Non-Productive Cost

NPREP National Preparedness for

Response Exercise Program

NPT Non-Productive Time

NRC National Response Center

NRC National Response Corporation

NRDA Natural Resource Damage

Assessment

OIM Offshore Installation Manager

OLF Off Line Frame

OMER Operations, Maintenance and

Emergency Response

Ops Operations

OSR Oil Spill Response

OSRC Oil Spill Response Coordinator

OSRO Oil Spill Removal Organization

OSRP Oil Spill Response Plan

P&ID Piping and Instrumentation

Drawing

PA Performing Authority

PD Project Director

PDQ Production, Drilling and Quarters

PMF Preservation and Maintenance

Facility

POB Personnel On Board

PPE Personal Protective Equipment

PREP Preparedness for Response

Exercise Program

psi pounds per square inch

PSV Pressure Safety Valve (pressure

relief valve)

PT Pressure-Temperature

QI Qualified Individual

R@R Resources at Risk

RCD Regional Containment

Demonstration

RESL Resource Unit Leader

RIH Run-In-Hole

RLT Regional Leadership Team

ROTA Rotational system used for calling

out mobilization of an entire IMT

group

ROV Remote Operated Vehicle

RP Recommended Practice

RRT Regional Response Team

S&OR Safety and Operational Risk

Organization

SCAT Shoreline Cleanup Assessment

Techniques

SCT Source Control Team

SEMS Safety and Environmental

Management System

SimOps Simultaneous Operations

SITL Situation Unit Leader

SJE Single Joint Elevator

SLA Service Level Agreement

SLB Schlumberger


SLF Steel Flying Lead

SMS Safety Management System

SOBM Synthetic Oil Based Mud

SOC Safety Observation Conversation

SRL Single Random Length

SROT Spill Response Operating Team

SSP Step-by-Step Procedure

STBD Starboard

STC Safety Training Coordinator

STP Site Technical Practice

SWA Stop Work Authority

TBRA Task Based Risk Assessment

TCEQ Texas Commission on


TGLO Texas General Land Office

TH Thunder Horse

TJ Telescoping Joint

TOFS Time Out for Safety

TOI Transocean International

TRG The Response Group

TSJ Tapered Stress Joint

UHP Ultra High Pressure

USCG United States Coast Guard

USFWS US Fish and Wildlife Services

USPL United States Pipelines and

Logistics

USPS United States Postal Service

UTA Umbilical Termination Assembly

UWA Ultimate Work Authority

WCD Worst Case Discharge

WI Work Instruction

WIF Work Instruction Form

WOM Wells Operations Manager

WRA Written Risk Assessment

WSL Well Site Leader

WSUP Wells Superintendent

YTD Year-to-Date


BPXP Plea Agreement

2017

Annual Progress Report Safety and Environmental Management Systems

(SEMS) Audits (Paragraphs 5-8)

BPXP Plea Agreement 2017 Annual Progress Report www.bpxpcompliancereports.com Page 5-8.1

Safety and Environmental Management Systems (SEMS) Audits

BPXP utilizes Safety and Environmental Management System (SEMS) audits to assess conformance with its operating management system in the areas of health, safety and the environment. These audits are led by independent, third party auditors following the “Third Party SEMS Auditing and Certification of Deepwater Operations Requirements” practice, as specified by the Center for Offshore Safety (COS).

5-8.1 Measures Taken to Comply

Throughout 2017, BPXP’s efforts to enhance its SEMS Audit program included, but were not limited to:

1. Continuing to work with COS on industry standardization and audit programs.

2. Verification of COS membership provision in new drilling rig contracts.

3. Revisions to the BPXP Plea Agreement Remedial Order Implementation Plan, Paragraph 8, SEMS Audit Schedule, and the BPXP SEMS Program, to address changes in BPXP’s asset portfolio.

4. Submission of SEMS Audit documentation (e.g. Audit Plan, Audit Report and Corrective Action Plan) to the Bureau of Safety and Environmental Enforcement (BSEE) per the regulatory required timelines.

The report which follows is structured to align with the BPXP Plea Agreement Remedial Order Implementation Plan, Paragraphs 5 through 8, concerning annual reporting for the SEMS Audit program.

5-8.2 Additional Information

5-8.2.1 SEMS Audits for Contracted Drilling Rigs – 2017

The audit plan and schedule, submitted to BSEE in 2016, included a SEMS audit of the Seadrill-owned West Auriga and West Vela drilling rigs to be completed in 2017. These audits were successfully completed in 2017 and are detailed further in the sections to follow. In the 2016 Annual Progress Report (Table 5-8.1), BPXP anticipated utilizing ERM-CVS as the third party SEMS auditor, but after further evaluation, transitioned to Gulf Tech, a COS-certified, third party audit service provider.

5-8.2.2 SEMS Audits for Contracted Drilling Rigs – 2018

Based on the proposed Consent Decree supporting follow-on SEMS Audits, BPXP does not plan to conduct any additional SEMS Audits in 2018. The current schedule will be to complete audits of the Seadrill-owned West Auriga, West Capricorn, and West Vela deepwater drilling rigs before December 31, 2020.


Table 5-8.1: Summary Report on SEMS Audit Plans – 2018 Contracted Drilling Rigs

Drilling Rig Information SEMS Audit Activities*

Rig Owner Rig Name Asset Type

3rd Party SEMS

Auditor

Audit Plan Submission

Audit Start

Audit Completion

Audit Report/ Corrective Action Plan Submission

Type of Audit

N/A N/A N/A N/A N/A N/A N/A N/A N/A

5-8.2.3 COS Affiliation of Existing BPXP Drilling Rig Contractors

In 2017, all of BPXP’s contracted Rig Contractors, with respect to deepwater drilling rigs operating in the Gulf of Mexico, ended the year as members of the Center for Offshore Safety (COS), per paragraph 6.2(1). Seadrill Americas previously let their membership lapse in 2016, but re-established their membership again in 2017. BPXP no longer has deepwater drilling rigs operated by Transocean International so they have been removed from the table. Table 5-8.2 below provides a listing of the current Drilling Rig Contractors along with their COS affiliation status at the end of year 2017.

Table 5-8.2: List of 6.2(1) Drilling Rig Contractors and Their COS Affiliation Status – 2017

Drilling Rig Contractor COS Affiliation Status

Ensco Member

Seadrill Americas Member

5-8.2.4 Non-6.2(1) Deepwater Drilling Contractors and COS Affiliation

BPXP did not contract with any new, non-6.2(1) Deepwater Drilling Rig Contractors for work in the Gulf of Mexico during 2017. BP includes language requiring COS membership for any new deepwater drilling rig contracts.


5-8.2.5 SEMS Audits with Drilling Rig Contractors – 2017

In 2017, BPXP conducted SEMS Audits of the Seadrill-owned West Auriga and West Vela deepwater drilling rigs. These audits are categorized ‘Additional’ as they were not required under applicable regulations, but were required under the BPXP Plea Agreement Remedial Order Implementation Plan. The BPXP SEMS Audit activities are included below in Table 5-8.3 for BPXP drilling rig contractors.

Table 5-8.3: Summary Report on SEMS Audits – 2017 BP Drilling Rig Contractors

Drilling Rig Information SEMS Audit Activities

Rig Owner Rig Name Asset Type 3rd Party

SEMS Auditor


Audit Start *

Audit Completion


Type of Audit

Seadrill Americas

West Auriga Drilling Rig Gulf Tech 8/10/2017 10/23/2017 12/7/2017 TBD – 2/2018 Additional

Seadrill Americas West Vela Drilling Rig Gulf Tech 8/10/2017 10/23/2017 12/7/2017 TBD – 2/2018 Additional

Notes: “Additional” type of audits signify audits that are not required under SEMS regulations. (*) The audit was originally scheduled to start on 9/11/2017, but due to Hurricane Harvey, was rescheduled to October 23, 2017. The other dates have been updated to reflect the new start date.

5-8.2.6 SEMS Audit for BP-owned Platforms/Platform Rigs – 2017

There were no SEMS audits involving BP-owned Platforms/Platform rigs identified within Paragraph 7.2.1 of the BPXP Plea Agreement Remedial Order Implementation Plan.


5-8.2.7 SEMS Audit Activities for Platforms/Platform Rigs

As specified within the requirements of Paragraph 7 of the BPXP Plea Agreement Remedial Order Implementation Plan: BPXP shall conduct one (1) SEMS audit for each of its operated Platforms and Platform Rigs within five (5) years of the Effective Date of the Agreement. As such, BPXP has successfully conducted SEMS audits of each of its BPXP-owned platforms/rigs within the five-year requirement and does not have plans for additional SEMS audits of BPXP-owned platforms/platform rigs in the future, other than as required through the normal regulatory cycle per 30 CFR 250 Subpart S. Table 5-8.4 shows a summary of when each audit of the BPXP-owned platforms/rigs was conducted.

Table 5-8.4: Summary Report on SEMS Audits of BPXP-owned Platforms and Platform Rigs

Asset Information (BPXP) SEMS Audit Activities

Asset Owner Asset Name Asset Type

3rd Party SEMS

Auditor


Audit Start

Audit Completion


Type of Audit

BPXP Thunder Horse Platform ERM-CVS 7/11/2016 8/16/2016 10/20/2016 12/15/2016 Regulatory

BPXP Thunder Horse PDQ

Platform Rig ERM-CVS 7/11/2016 8/16/2016 10/20/2016 12/15/2016 Regulatory

BPXP Mad Dog Spar Platform ERM-CVS 7/11/2016 8/16/2016 10/20/2016 12/15/2016 Regulatory

BPXP Mad Dog Drilling Rig

Platform Rig ERM-CVS 7/11/2016 8/16/2016 10/20/2016 12/15/2016 Regulatory

BPXP Na Kika Platform ERM-CVS 5/13/2014** 6/04/2014** 7/10/2014**

7/07/2014 8/27/2014 9/25/2014 Additional

BPXP Atlantis Platform Det Norske

Veritas (DNV)

04/25/2013 5/29/2013 6/28/2013 7/23/2013 Regulatory

Notes: “Regulatory” audits fulfill BPXP’s obligation under 30 CFR 250 Subpart S. “Additional” audits signify audits that are not required under SEMS regulations.

** Initial SEMS Audit Plan submitted on 5/13/2014. Revisions to the SEMS Audit Plan were submitted on 6/4/2014 and 7/10/2014 to address BSEE recommended changes.

ACRONYMS:

BPXP BP Exploration & Production, Inc. BSEE Bureau of Safety and Environmental Enforcement BSR Blind Shear Ram CFR Code of Federal Regulations COS Center for Offshore Safety DNV Det Norske Veritas ERM-CVS No definition – company name PDQ Production, Drilling and Quarters SEMS Safety and Environmental Management System


BPXP Plea Agreement

2017

Annual Progress Report Third Party Verification of Blowout Preventers

(BOP) (Paragraph 9)

BPXP Plea Agreement 2017 Annual Progress Report www.bpxpcompliancereports.com Page 9.1

Third Party Verification of Blowout Preventers (BOP)

BPXP has developed and implemented processes to sustain enhanced operational oversight of the testing and maintenance of subsea blowout preventers (BOP). Each time BPXP or its contractors initially latch a subsea BOP at the well site and each time the BOP is brought to the surface after it has been latched to a well, BPXP or its contractors, through a third party, verifies that all required surface testing and maintenance of the BOP were performed in accordance with the manufacturer recommendations and American Petroleum Institute (API) API Standard 53.

9.1 Measures Taken to Comply

Multiple processes, tools, and techniques were deployed to sustain enhanced rigor and additional oversight to the BOP testing and maintenance activities. The following activities were used throughout 2017:

• A process and associated checklist to verify that the relevant Applications for Permit to Drill (APD) include the requirement for Third Party Verification.

• A process to maintain a BOP register, which identifies each time a subsea BOP was unlatched from a well and brought to surface. This register indicates the date a BOP was latched at the well site, the date the BOP was unlatched, whether or not the BOP was brought to the surface, the date(s) the verification occurred, identification of the third-party verifier, a link to a copy of the verification letters and additional pertinent information.

• An electronic storage location for verification letters and BOP associated documentation.

9.2 Additional Information

9.2.1 Deepwater Drilling Rigs with Subsea BOPs

During the 2017 calendar year, BPXP operated 4 subsea BOP equipped rigs in the Gulf of Mexico (GoM). The BPXP 2017 GoM operated rigs equipped with subsea BOP are listed below:

1. West Capricorn;

2. West Auriga;

3. West Vela; and

4. Thunder Horse PDQ

The BOP register contains each of the Drilling Rigs and tracks the required BOP activities.

9.2.2 Third Party Verifiers

BPXP interchangeably utilizes two companies to provide third party verification of surface testing and maintenance for each time BPXP or its contractors initially latch a subsea BOP at the well site and each time the subsea BOP is brought to the surface after it has been latched to a well. This verification confirms that such surface testing and maintenance are in accordance with manufacturer recommendations and API Standard 53.


9.3 Certifications

BPXP certified that each time BPXP or its Contractors, in the conduct of Deepwater Drilling Operations that included a subsea BOP on a moored or dynamically positioned Drilling Rig, initially latched a subsea BOP at the well site, and each time the subsea BOP was brought to the surface after it had been latched to a well, a third party verified that all required and recommended testing and maintenance of the BOP was performed on the surface in accordance with manufacturer recommendations and API Standard 53.


BPXP Plea Agreement

2017

Annual Progress Report Deepwater Well Control Competency Assessments

(Paragraph 10)


Deepwater Well Control Competency Assessments

A Well Control Competency Assessment (WCCA) Plan, that exceeds the competency requirements of 30 CFR § 250.1500-1510 (Subpart O), was developed and implemented for Deepwater Well Control Personnel in BPXP in 2013.


During 2017, 2 BPXP Well Control Personnel were assessed against the WCCA Plan. These assessments focus on four key areas, which include: Leadership, Core Technical, Role Specific, and Well Control competencies. Both of the assessed individuals met the established requirements. Neither of the assessed individuals were found in need of further training. Those assessed included 0 Well Site Leaders (WSLs) and 2 Wells Superintendents (WSUPs) (formerly called Wells Team Leaders (WTLs) in previous Annual Reports). Table 10.1 below shows the WCCA training statistics for 2017.

Table 10.1: 2017 Well Control Competency Assessment Statistics

BPXP 2017 Well Control Competency Assessment Statistics

BPXP Aggregate Well Control Personnel for 2017* All WSLs WSUPs

60 51 9

Well Control Competency Assessments No. % No. % No. %

Aggregate assessed in 2017 2 4 0 0 2 22

Aggregate assessed in 2017 found competent (met required proficiency, functioning in role with continuing development opportunities)

2 4 0 0 2 22

Aggregate assessed in 2017 found in need of further training (before functioning in role) 0 0 0 0 0 0

Aggregate further training completed and re-assessed in 2017 0 0 0 0 0 0

Notes: *Aggregate Well Control Personnel for 2017 reflects the aggregate number of persons who held the position at any point during the calendar year, rather than the staffing level at any point in time.


10.2.1 Subpart O - IADC WellCAP Training

The International Association of Drilling Contractors (IADC) WellCAP program is adaptive and changes to meet industry specific needs. The IADC WellCAP program provides the fundamental knowledge and skills for well control personnel, resulting in a comprehensive organizational well control program. BPXP Well Control Personnel have continued to attend IADC WellCAP Supervisory Training. In December 2014, the Bureau of Safety and Environmental Enforcement (BSEE) concurred with a modification to the Subpart O Well Control training requirements to allow for


the use of either the International Well Control Forum (IWCF) Well Control course or the IADC WellCAP course, based on their determination that the courses are equivalent. In December 2014, the U.S. Department of Justice (DOJ) approved the corresponding modifications to Paragraphs 10.2, 10.3, and 12.2 of the BPXP Remedial Order Implementation Plan. On January 15, 2015, BPXP also received approval from the United States Probation Office with respect to the modification previously approved by the DOJ.

In 2017, 29 BPXP Well Control Personnel attended the Drilling Surface and Subsea training sessions; and 36 attended the Well Servicing training sessions. Table 10.2 below shows the training summary for 2017.

Table 10.2: 2017 IADC WellCAP and IWCF Training Summary

BPXP 2017 IADC WellCAP and IWCF Training Summary

BPXP Aggregate Well Control Personnel for 2017* All WSLs WSUPs

60 51 9

Completed Training during 2017 No. % No. % No. %

IADC WellCAP and IWCF Course - Level

Drilling and Subsea - Supervisory Level 29 49 24 47 5 56

Well Servicing - Supervisory Level 36 60 30 59 6 67 Notes: * Aggregate Well Control Personnel for 2017 reflects the aggregate number of persons who held the position at any point during the

calendar year, rather than the staffing level at any point in time.


10.2.2 Additional Training Capability

In addition to the IADC WellCAP and IWCF training noted above, the WCCA Plan includes “Well Control Bundle” training. The Well Control Bundle training covers topics such as well control, pressure testing, well control bridging documents, drilling well control manual, and responsibilities and requirements for well monitoring. The Well Control Bundle training began late in 2013 with a total of four BPXP Well Control Personnel trained. In 2014, 80 BPXP Well Control Personnel attended the training course. In 2015, all the remaining BPXP Well Control Personnel attended the training course. In 2017, BPXP added 3 Well Control Personnel who will take the Well Control Bundle Training within 12 months as prescribed in the WCCA.

As a separate effort from the WCCA Plan requirements, BPXP provides personnel with additional training on various topics. Table 10.3 below illustrates the Well Control Bundle training summary statistics for 2017.

Table 10.3: 2017 Well Control Bundle Training Statistics Since Previous BPXP Annual Report

BPXP 2017 Well Control Bundle Training Statistics

Aggregate in Need of Well Control Bundle Training During 2017

All WSLs WSUPs

3 2 1

Aggregate Who Completed Well Control Bundle Training to Date

No. % No. % No. %

60 100 51 100 9 100

Notes: Aggregate Well Control Personnel for 2017 reflects the aggregate number of persons who held the position at any point during the calendar year, rather than the staffing level at any point in time.


BPXP Plea Agreement

2017

Annual Progress Report Cement Design and Competency

(Paragraph 11)

BPXP Plea Agreement 2017 Annual Progress Report www.bpxpcompliancereports.com A11.1

Cement Design and Competency

In 2013, BPXP developed a procedure that established the framework for screening and selecting Cementing Technical Specialist candidates. This procedure outlines the necessary skills, qualifications, experience, and development for Cementing Technical Specialists as the qualified Subject Matter Expert (SME). Using this procedure to select Cementing Technical Specialists helps maintain enhanced oversight on cement designs used for primary cementing of casing and exposed hydrocarbon zones. The selected Cementing Technical Specialists review and approve cement designs for Deepwater Drilling Operations.


In 2014, an analysis was completed to assure that all four existing Cementing Technical Specialists had fulfilled the requirements of the approved Procedure for Cementing Technical Specialist Candidate Screening. There were no additional BPXP Gulf of Mexico Cementing Technical Specialists hired in 2017.

BPXP utilizes two third party independent laboratories to conduct or witness testing of relevant cement slurry designs for primary cementing of casing and exposed hydrocarbon bearing zones relating to Deepwater Drilling Operations. During the 2017 calendar year, a qualified Cementing Technical Specialist reviewed and approved all the required cement designs and corresponding independent laboratory test results. These laboratory test results were included in the relevant Well Activity Reports (WAR) submitted to the Bureau of Safety and Environmental Enforcement (BSEE).

Throughout 2017, the name and title of the respective Cementing Technical Specialist who reviewed and approved the cement designs were included in each relevant Application for Permit to Drill (APD) submitted to BSEE for primary cementing of casing and exposed hydrocarbon-bearing zones related to the Deepwater Drilling Operation.

11.2 Certifications

11.2.1 Cementing Technical Specialists

BPXP provided a list of the Cementing Technical Specialists and certified that each of them have successfully completed the requirements set forth in the Procedure for Cementing Technical Specialist Candidate Screening.

11.2.2 Applications for Permits to Drill (APD)

BPXP certified that each Application for Permit to Drill submitted in 2017 for Deepwater Drilling Operations included a supplemental attachment containing (a) the name and title of the SME who reviewed and approved the cement designs contained in the APD for primary cementing of casing and exposed hydrocarbon-bearing zones related to the well, and (b) a statement in the supplemental attachment to the APD that lab testing of cement slurries for primary cementing of casing and exposed hydrocarbon bearing zones relating to the well were conducted or witnessed by an engineer competent to evaluate such lab testing or a competent third party independent of the cement provider.

BPXP Plea Agreement 2017 Annual Progress Report www.bpxpcompliancereports.com A11.2

11.2.3 Well Activity Reports (WAR)

BPXP certified that each relevant Well Activity Report (“WAR”) submitted in 2017 to the applicable BSEE field office for Deepwater Drilling Operations included the results of lab testing of cement slurries for primary cementing of casing and exposed hydrocarbon bearing zones relating to the well. The results included the name and title of the engineer competent to evaluate such lab testing or the competent third party, independent of the cement provider, who conducted or witnessed the lab testing.


BPXP Plea Agreement

2017

Annual Progress Report Houston Monitoring Center

(Paragraph 12)


Houston Monitoring Center

BPXP’s Houston Monitoring Center (HMC) started monitoring Gulf of Mexico Drilling Rigs conducting Deepwater Drilling Operations in July of 2011. The HMC was designed to remotely monitor drilling data transmitted from offshore to onshore, which includes active pit volumes, pump pressures, flow rates out, gas units, and trip displacements. It operates 24 hours a day, 7 days a week throughout the year on rotational 12-hour shifts.


Multiple processes, tools, and techniques have been deployed in the maintenance of the HMC. These include, but are not limited to:

• Maintenance of the real-time drilling monitoring center with the capability to monitor Well Control data such as active pit volume, pump pressure, flow rate out, gas units and trip displacement;

• Continuous staffing of the HMC with relevant personnel who possess International Association of Drilling Contractors (IADC) WellCAP certification to monitor such data;

• A written contingency plan addressing appropriate steps and procedures when the operation of the HMC has been disrupted; and

• Well control data backup and retention.


During most of 2017, the Houston Monitoring Center (HMC) operated on the 22nd floor of the Westlake One Building with the following physical address:

501 Westlake Park Boulevard Houston, Texas 77079

In August 2017, it became apparent that Hurricane Harvey was likely to impact the Houston area, the HMC Team initiated its documented contingency plan and on August 24, 2017 the HMC was moved to 8600 Harry Hines Blvd, Dallas Texas 75235, an alternate location in the event of an emergency or evacuation of the Westlake campus. The BP Westlake campus was shut down on August 25, 2017 as a precautionary measure associated with the expected weather conditions including heavy rain and high winds from Hurricane Harvey. All HMC personnel were in place in Dallas and monitoring operations commenced at the start of the “night” shift on August 24, 2017. The operational procedures for performing the remote real-time monitoring were unchanged based on the move and there was no interruption of HMC monitoring during the transition and mobilization of personnel to Dallas.

Due to flood damage sustained to the Westlake One facility, the HMC returned to the Westlake Campus on September 19, 2017 and began occupying the 3rd Floor of the BP Center for High Performance Computing (CHPC). The CHPC is physically located at 225 Westlake Park Blvd, Houston, TX 77079. No interruption to operations or monitoring capability was experienced during the relocation back to the Westlake Campus. It is anticipated that the HMC will continue to reside in the CHPC through the First Quarter of 2018 while Westlake One undergoes facility repairs.


Number and Titles of HMC Staff currently supporting the site include:

• Well Monitoring Specialist – Number is rig count dependent. Each Well Monitoring Specialist monitors no more than two rigs simultaneously per 12-hour shift, 24-hour coverage;

• HMC Well Site Leader – Four total with one per 12-hour shift, 24-hour coverage; • Monitoring Center Wells Superintendent – One total during normal business hours and on-call outside of

business hours; • Information Technology (IT) Support Team - Five staff with one scheduled per 12-hour shift, 24-hour

coverage; and • Software Application Support Team - Four staff with one scheduled per 12-hour shift, 24-hour coverage.

A brief description of the key monitoring staff follows:

• Well Monitoring Specialist – Provides onshore 24 hours a day seven days a week monitoring of the real-time data coming into the HMC from the rig-line operations, based on agreed parameters and protocols; maintains chat session with rig site mud logger to assure understanding of current operations and makes notifications when monitored values fall outside the “normal” range per HMC Monitoring Plan.

• HMC Well Site Leader – Oversees the Well Monitoring Specialists; implements the HMC Monitoring & Response process and follow-up with the rig site teams on actions resulting from alert notifications per the agreed event escalation guidelines and communication protocols; assists with preparation of HMC Monitoring Plans, outlining key parameters that will be monitored and the acceptable ranges.

• Monitoring Center Wells Superintendent – Provides overall supervision for the Houston Monitoring Center, including support teams; interacts with the well planning teams to define and approve the HMC Monitoring Plan for each well; serves as lead interface between HMC and Gulf of Mexico (GoM) Wells Leadership during alert notifications.

The general HMC staffing schedule includes:

• Well Monitoring Specialists and HMC Well Site Leaders work a two-week on/two-week off rotation in 12-hour shifts.

• The Monitoring Center Wells Superintendent works normal business hours and is on-call outside of normal business hours.

• The Support Team personnel typically work one-week on and one-week off in 12-hour shifts, although there is some variability in number of days worked continuously.

• Shift-change and start-times are staggered.

The HMC data is stored electronically and is backed up weekly, with daily incremental backups. The HMC electronic information subject to the implementation plan requirements will be retained for at least five years.

In 2017, the Auditor and representatives of the United States requested access to the HMC on numerous occasions, and all their requests were granted. A summary list of the days when the Auditor or representatives of the United States requested and were provided access to the HMC can be found in Table 12.1.


Table 12.1: 2017 BPXP Houston Monitoring Center Visitor Log

2017 BPXP HMC Auditor or US Representative Visitor Log

Date of Requested Visit Affiliation Request Granted

2/16/2017 BSEE Yes 2/16/2017 BSEE Yes 2/16/2017 BSEE Yes 2/16/2017 BSEE Yes 2/16/2017 BSEE Yes

3/21/2017 Ethics & Compliance Monitor Yes 3/30/2017 BSEE Yes 4/10/2017 BP Third Party Auditor Yes 4/10/2017 BP Third Party Auditor Yes

4/10/2017 BP Third Party Auditor Yes 5/30/2017 BSEE Yes 5/30/2017 BSEE Yes 5/30/2017 U.S. Department of Justice Yes 5/30/2017 U.S. Department of Justice Yes

5/30/2017 U.S. Department of Justice Yes 5/30/2017 BP External Counsel Yes 5/30/2017 BP External Counsel Yes 5/30/2017 Process Safety Monitor Yes

5/30/2017 Process Safety Monitor Yes 5/30/2017 Process Safety Monitor Yes 7/25/2017 SEMS Auditor Yes 7/25/2017 SEMS Auditor Yes

7/25/2017 SEMS Auditor Yes 7/25/2017 SEMS Auditor Yes 7/25/2017 SEMS Auditor Yes 7/25/2017 SEMS Auditor Yes 7/25/2017 SEMS Auditor Yes

7/25/2017 SEMS Auditor Yes 10/11/2017 BP Third Party Auditor Yes 12/06/2017 BP Third Party Auditor Yes

12/06/2017 BP Third Party Auditor Yes

12/06/2017 BP Third Party Auditor Yes


There was one (1) instance during the 2017 calendar year that the HMC was unable to monitor a Drilling Rig for more than eight consecutive hours. On August 28, 2017, the Monitoring Center experienced a Bastion server firewall issue that prevented application support from the temporary Dallas facility for 24 hours and 47 minutes. This outage occurred several days after personnel successfully transitioned and mobilized to Dallas as part of business continuity plan on August 24, 2017 due to the potential impact of Hurricane Harvey.


BPXP Plea Agreement

2017

Annual Progress Report Incident Reporting

(Paragraph 13)


Incident Reporting

In 2017, BPXP continued to document incidents reported per the Bureau of Safety and Environmental Enforcement (BSEE) regulations in 30 CFR § 250.188. These incidents were reviewed monthly to identify trends, address systemic issues, and monitor closure of corrective and/or preventative actions.

In 2017, there were 241 total incidents that were reported to BSEE under 30 CFR § 250.188. Figure 13.1 provides a summary of the 2017 incidents. After further investigation, one of the 24 BPXP incidents was determined to have been an injury that was not work related. The most common types of incidents were those involving injuries, cranes/other lifting devices, incidents that caused greater than $25,000 in damage, musters, and fires. An analysis of the 13 work-related injury incidents shows that six were pinches of the finger or hand, three were knee injuries, one was the result of heat exhaustion, one was a back injury, one was a chest muscle strain, and one was a bicep injury. Learnings from incident investigations of the injuries resulted in improved communications surrounding job execution, development of more robust procedures, improved tools for certain jobs, better pre-job training guides, better scenario assessments for hazard identification, and an integration of certain checklists and pre-work activity directly into Work Instructions. Additionally, BPXP continued to require increased focus by Drilling Rig contractors on safe zone management during crane and other lifting operations, which showed a reduction in red zone incidents over previous years. There were two musters in 2017. One muster was the result of a clogged lint filter that caused a clothes dryer to overheat and the other resulted from an LEL alarm that alerted while draining the mud gas separator (quickly dissipated after the operations were ceased). There were two incidents that caused over $25,000 in damage. One resulted from a rig gripper that malfunctioned during operations which sheared bolts of a support plate and the other was from wires on a crane boom overheating that needed to be replaced. Those two incidents did not result in harm to people or damage to the environment.

Figure 13.1: 2017 Incidents in GoM Region Figure 13.2: Action Items for 2017 Incidents

In 2017, 16 of the 23 incident investigations conducted thus far have resulted in 110 actions, shown in Figure 13.2. As of January 6, 2018, 49 of these actions are closed, 60 remain open with none overdue, and one was cancelled. Of the four remaining actions from previous years, all were closed on-time in 2017.

Of the 49 actions closed throughout 2017, the incident investigation process resulted in 35 changes to the Safety and Environmental Management System (SEMS) plans, including site-specific changes to BPXP or contractor safety and environmental work practices, inspection and maintenance processes, and organizational learning. The most frequent SEMS changes involved improving the contractor management process (11), enhancing organizational learning (7), more robust design and construction (5), and modifying BPXP’s control of work (5). Other SEMS changes

1 Two of the 24 incidents originated in previous years (1 in 2015, 1 in 2016), became reportable under 30 CFR § 250.188 as a result of further medical treatment that occurred during 2017.

6049 12017 Action Item Status

110 Total Actionsas of 1/6/2018

Open

Closed

Cancelled


were in the areas of improving procedures and practices, plant optimization, people and competence, and risk management and learning.


In 2017, BPXP continued to improve its incident investigation processes, analyze trends in incidents and, when informed by incident investigations, make modifications to its management systems to address systemic issues. These improvements led to the release of an updated Group Practice, ‘Upstream HSE Incident and Accident Management’. The incidents were reviewed monthly to evaluate progress and assure proper classification, reporting, and timely closure of corrective and preventative actions.


BPXP Plea Agreement

2017

Annual Progress Report Oil Spill Response Plan Training and Exercises

(Paragraphs 14-19)


Oil Spill Response Training and Exercises

In 2017, BPXP continued to focus on maintaining the capability of its people, facilities, and processes to respond to oil spills and other extraordinary events. The organization conducted periodic reviews of its crisis and continuity and emergency response programs to assure compliance with regulatory and legal requirements and identify opportunities for improvement. BPXP also continued its developmental oil spill response training and exercise program to maintain awareness of risk and to develop leaders within its Incident Management Team (IMT).


For the calendar year 2017, the organization’s efforts to enhance its crisis management and emergency response programs included:

• Maintaining two crisis management centers located in Houston, Texas, and Houma, Louisiana; • Adding the BPXP-Houston Incident Command Post; • Maintaining a crisis management organization of at least six personnel who are experienced in crisis

management; • Revising BPXP’s Crisis Management Organization, Training and Exercise Plan (CMOTEP) to specify training

and exercise requirements for its IMT leadership positions; • Conducting 71 oil spill response training workshops to increase knowledge and enhance the response

capability of the IMT staff; • Utilizing BPXP’s two crisis management centers and the incident command post to conduct three oil spill

response exercises and test scenarios supporting the BP Gulf of Mexico Regional Oil Spill Response Plan (OSRP);

• Supporting the deployment of the Incident Management Team during the Thunder Horse Loss of Power Incident;

• Monitoring and certifying oil spill response training and exercise completion for BPXP IMT leadership positions;

• Submitting notice for BPXP’s 2018 Oil Spill Response Training Plan and Exercises Schedule to BSEE, USCG and other regulatory agencies with invitations for their agents to attend; and

• Maintaining descriptions of exercises and documentation of lessons learned in After-Action Reports for each series of tabletop oil spill response exercises and incident management; internal and industry-sponsored.

The report which follows is structured to align with the BPXP Plea Agreement Remedial Order Implementation Plan Paragraphs 14 through 19, concerning annual reporting.

14-19.2 Additional Information and Certifications

14-19.2.1 Certification of Oil Spill Response Training (14.3.3.a)

BPXP required its Incident Commanders, Section Chiefs, Oil Spill Response Coordinators and their alternates in the IMT to complete position-specific oil spill response training to qualify them for their roles in year 2017. Where applicable, this training covered the subject matter outlined in Incident Command System (ICS) 100, 200, 300 and Federal Emergency Management Agency Independent Study (FEMA IS) 700/800.


For calendar year 2017, BPXP certified that 44 individuals, in the position-specific roles listed in Table 14-19.1, completed the oil spill response training program to qualify them for the roles in the coming year 2018. All 44 of the personnel were in their position-specific roles for the entire calendar year and started either on or before January 1, 2017.

Table 14-19.1: Oil Spill Response Training Summary – 2017

Incident Management Team Position-Specific

Roles

Number Qualified for Role in 2018

Mandatory Training Requirements

MWCC Annual Training

Incident Commander/

Qualified Individual Training

Incident Management Team Annual

Refresher Training

Section Leader-

ship Training

Training Completion

Incident Commander 5 X X X X 100%

Operations Section Chief 7 X X X 100%

Source Control Branch Director

9 X X X 100%

Planning Section Chief 8 X X X 100%

Logistics Section Chief 6 X X X 100%

Finance Section Chief 7 X X X 100%

Oil Spill Response Coordinator

2 X X X 100%

Total 44

Note: The column titled “Number Qualified for Role in 2018” includes a count of the personnel who will act as alternates for the listed “Incident Management Team Position-Specific Roles”.

14-19.2.2 Certification of Oil Spill Response Exercises (14.3.3.b)

BPXP continued to require that its Incident Commanders, Section Chiefs, Oil Spill Response Coordinators and their alternates in the IMT participate in at least one tabletop oil spill response exercise to qualify them for their roles in year 2018. To support completion of this requirement, BPXP conducted three oil spill response exercises that practiced scenarios within its OSRP. All three were internally conducted tabletop exercises, which occurred on May 4, May 25, and June 22, 2017. Each of the exercises included activation of the source control equipment supplier, Marine Well Containment Company (MWCC), and simulated the coordination of response activities related to notification, procurement, personnel, logistics, and other actions necessary to cap/contain a subsea loss of well control. All three tabletop exercises additionally included an element involving wildlife rehabilitation procedures.

BPXP originally scheduled an additional, functional exercise (November 9, 2017) per the Crisis Management Organization, Training and Exercise Plan (CMOTEP) submitted to BSEE on November 16, 2016. However, due to the events surrounding Hurricane Harvey, this functional exercise was cancelled. All 44 personnel completed their exercise requirement based on the three tabletop exercises throughout 2017.


For calendar year 2017, BPXP monitored the completion of oil spill response exercises by its Command Staff, Section Chiefs, Oil Spill Response Coordinators, and their alternates. BPXP certified that all 44 individuals in the position-specific roles listed in Table 14-19.2 completed the exercise program to qualify them for their roles in the coming year 2018. All 44 of the personnel were in their position-specific roles for the entire calendar year and started either on or before January 1, 2017.

Table 14-19.2: Oil Spill Response Exercises Summary – 2017

Incident Management Team Position-Specific Roles


Mandatory Exercise Requirements

BP Oil Spill Exercise

BP MWCC Exercise

Industry Exercise

Exercise Completion

Incident Commander 5 X X 100%

Operations Section Chief 7 X X 100%

Source Control Branch Director 9 X X 100%

Planning Section Chief 8 X X 100%

Logistics Section Chief 6 X X 100%

Finance Section Chief 7 X X 100%

Oil Spill Response Coordinator 2 X X X 100%

Total 44

Notes: 1. The “Number Qualified for Role in 2018” includes a count of the personnel who will act as alternates for the listed “Incident Management Team Position-Specific Roles”.

2. “Industry Exercise” means exercises that were industry-sponsored and in which BPXP personnel participated.

14-19.2.3 Description of Training, Exercises and Lessons Learned (14.3.3.c)

BPXP continued to offer an oil spill response training program which allows personnel to develop through basic, core, advanced, and specialized courses into leadership roles within the IMT. This developmental training program included general and position-specific training to increase knowledge of the regulatory requirements, the ICS structure, and the roles and responsibilities for managing response. Where applicable, the courses included subject matter outlined in ICS 100, 200, 300, and FEMA IS 700/800. After completion of the minimum developmental training for assignment in an IMT leadership role, BPXP requires all the Incident Commanders, Section Chiefs, Source Control Branch Directors, Oil Spill Response Coordinators, and their alternates, to complete annual refresher training addressing the subject matter in Table 14-19.3.


Table 14-19.3: Annual Position-Specific Training for IMT Leadership – 2017

IMT Leadership Position Annual Training Requirements – Year 2017

Incident Commander

Incident Command Tactics and Qualified Individual Workshop

Incident Management Team Annual Refresher

Operations Section Chief

Operations Section Leadership Training

Marine Well Containment Company (MWCC) – Overview and Annual Update


Source Control Branch Director

Source Control Branch Leadership Training



Planning Section Chief

Planning Section Leadership Training


Logistics Section Chief

Logistics Section Leadership Training



Finance Section Chief

Finance Section Leadership Training


Oil Spill Response Coordinator

Source Control Branch Leadership Training



BPXP requires its Incident Commanders, Section Chiefs, Source Control Branch Directors, Oil Spill Response Coordinators, and their alternates to complete at least one oil spill response tabletop exercise each year, which addresses the mandatory exercise requirements outlined in Table 14-19.4, and which tests the procedures identified in the BP Gulf of Mexico Regional Oil Spill Response Plan (OSRP) Revision 18.


Table 14-19.4: Annual Position-Specific Exercise Requirements for IMT Leadership – 2017

IMT Leadership Position


Oil Spill Exercise MWCC Exercise Industry/MWCC Source Control

Exercise

Annual Annual Annual

Incident Commander X X

Operations Section Chief X X

Source Control Branch Director X X

Planning Section Chief X X

Logistics Section Chief X X

Finance Section Chief X X

Oil Spill Response Coordinator X X X

Note: It is possible for the requirements of an Oil Spill Exercise and a MWCC Exercise to be accomplished during the same exercise dependent on the objectives of that exercise.

BPXP conducted three oil spill response exercises in 2017 to support completion of the mandatory exercise requirements. A description of each exercise is provided in Table 14-19.5: Oil Spill Response Exercise Summary – 2017.

Table 14-19.5: Oil Spill Response Exercise Summary – 2017

Oil Spill Response Exercise Participants

Name Description Location/ Duration Date BSEE USCG

United States MWCC BPXP

BP Tabletop

Tabletop Exercise – Day 1 of an incident involving oil spill and source control response, including activation of the Marine Well Containment Company

Houston Major ICP

4-8 hours 5/4/17 X X - X X

BP Tabletop

Tabletop Exercise – Day 1 of an incident involving oil spill and source control response, including activation of the Marine Well Containment Company

Houston Major ICP

4-8 hours 5/25/17 X - - X X

BP Tabletop

Tabletop Exercise – Day 1 of an incident involving oil spill and source control response, assisting BP US Pipelines and Logistics, for a pipeline break in the GoM

Houston Major ICP

8-12 hours 6/22/17 - - - X X

Notes: 1. “ICP” means the Incident Command Post. 2. “BPXP” means the Command Staff, Section Chiefs, Oil Spill Response Coordinator positions and their alternates, as listed in

Paragraphs 14.2.1 and 18.2.1 of the BPXP Plea Agreement Remedial Order Implementation Plan. 3. “United States” means the list of agency personnel identified in Attachment A of the BPXP Plea Agreement Remedial Order

Implementation Plan. 4. “X” means one or more personnel in this category participated in the oil spill response exercise.


An outcome of the three exercises was the identification of several potential opportunities for improvement (i.e. lessons learned). The lessons learned identified (1) clarifying the delegation of authority for an emergency response versus a spill response, (2) ensuring that the 201 packet clearly captures the offshore response organization, and (3) emphasizing the importance of integrating wildlife management into the response process.

14-19.2.4 Preparedness for Response Exercise Program (NPREP) (14.3.3.d)

Every three (3) years (triennial), BPXP must completely exercise the individual sections of the National Preparedness for Response Exercise Program (NPREP) per the requirements of 30 C.F.R. § 254.42. 2016 was the end of the triennial cycle and 2017 began the start of a new triennial cycle. BPXP has monitored the components of NPREP and the sections of the OSRP which were tested in the oil spill response exercises identified above in Table 14-19.5: Oil Spill Response Exercise Summary – 2017. The NPREP components which were completed in the exercises conducted in 2017 and in the course of the response to the Thunder Horse Facility Loss of Power Incident, are documented in Table 14-19.6: BPXP’s Preparedness for Response Exercise Program Triennial Cycle Documentation Form – 2017. Table 14-19.7: BPXP Oil Spill Response Exercise Summary by OSRP Section – 2017 identifies the sections of BPXP’s OSRP that were tested in the oil spill response exercises conducted in 2017 and in the course of the response to the Thunder Horse Facility Loss of Power Incident.


Table 14-19.6: BPXP’s Preparedness for Response Exercise Program Triennial Cycle Documentation Form – 2017 (Oil Spill Response Exercises for Paragraphs 14, 16 and 18)

NPREP Component 2017 Exercises

Comp. Title BP-1 4-May

BP-2 25-May

BP-3 22-Jun

TH-1 18-Sep

1 Notifications X X X X 2 Staff Mobilization X X X X

3 Ability to Operate Within the Response Management System Described in the Plan X X X X

3.1 Unified Command X X X 3.1.1(a) Federal Representation X X X 3.1.2(b) State Representation X X X 3.1.3(c) Local Representation 3.1.4(d) Responsible Party Representation X X X X

3.2 Response Management System X X X X 3.2.1(a) Operations X X X X 3.2.2(b) Planning X X X X 3.2.3(c) Logistics X X X X 3.2.4(d) Finance X X X X 3.2.5(e) Public Affairs X X X X 3.2.6(f) Safety Affairs X X X X 3.2.7(g) Legal Affairs X X X

4 Source Control X X X X 4.1 Salvage N/A N/A N/A N/A 4.2 Firefighting N/A N/A N/A N/A 4.3 Lightering N/A N/A N/A N/A 4.4 Other salvage equipment and devices N/A N/A N/A N/A 4.5 Well Control X X X X 5 Assessment X X X 6 Containment X X X 7 Recovery (Renamed “Mitigation”) X X X

7.1 On-Water Recovery (Removed) X X X 7.2 Shore-Based Recovery (Removed) 8 Protection X X X

8.1 Protective Booming X X X 8.2 Water Intake Protection 8.3 Wildlife Recovery X X X 8.4 Population Protection 9 Disposal 10 Communication X X X X

10.1 Internal Communications X X X X 10.2 External Communications X X X X 11 Transportation X X X X

11.1 Land Transportation X X X X 11.2 Waterborne Transportation X X X X 11.3 Airborne Transportation X X X X 12 Personnel Support X X X X

12.1 Management X X X X 12.2 Berthing X X X X 12.3 Messing X X X X 12.4 Operational and Administrative Spaces X X X X 12.5 Emergency Procedures X


NPREP Component 2017 Exercises

Comp. Title BP-1 4-May

BP-2 25-May

BP-3 22-Jun

TH-1 18-Sep

13 Equipment Maintenance and Support X X X X 13.1 Response Equipment X X X 13.2 Response Equipment (support equipment) X 14 Procurement X X X X

14.1 Personnel X X X X 14.2 Response equipment X X X X 14.3 Support Equipment X X X X 15 Documentation X X X X

Notes: “N/A” means the specific section of the OSRP contains administrative information only that cannot be exercised. “X” means the specific section of the OSRP was tested in the exercise conducted on the listed dates. “TH-1” relates to the Thunder Horse Facility Loss of Power Incident that required the IMT engagement from September 18 –

September 21


Table 14-19.7: BPXP’s Oil Spill Response Exercise Summary by OSRP Section – 2017 (Oil Spill Response Exercises for Paragraphs 14, 16 and 18)

GoM Region OSRP 2017 Exercises

Section Title BP-1 4-May

BP-2 25-May

BP-3 22-Jun

TH-1 18-Sep

1 Quick Guide N/A N/A N/A N/A

2 Preface N/A N/A N/A N/A

3 Introduction N/A N/A N/A N/A

4 Organization X X X X

5 Incident Command Post and Communications X X X X

6 Spill Detection and Source Identification and Control X X X X

7 QI, IMT, SROT, and OSRO Notifications X X X X

8 External Notifications X X X X 9 Available Technical Expertise X X X X

10 Strategic Response Planning X X X X

11 Spill Assessment and Volume Estimation X X X

12 Resource Identification X X X

13 Resource Protection Methods X X X

14 Mobilization and Deployment Methods X X X X 15 Oil and Debris Removal Procedures X X X

16 Oil and Debris Disposal Procedures X X X

17 Wildlife Rehabilitation Procedures X X X

18 Dispersant Use Plan X X X

19 In-Situ Burning Plan X X X

20 Alternative Chemical and Biological Response Strategies

21 Documentation X X X X

22 Prevention Measures for Facilities Located in State Waters N/A N/A N/A N/A

A Facility Information N/A N/A N/A N/A B Training Information N/A N/A N/A N/A C Drill Information N/A N/A N/A N/A D Contractual Agreements N/A N/A N/A N/A

E Response Equipment N/A N/A N/A N/A F Support Services and Supplies N/A N/A N/A N/A G Notification and Report Forms N/A N/A N/A N/A H Worst Case Discharge Scenarios N/A N/A N/A N/A I Subsea Containment Information N/A N/A N/A N/A J Oceanographic and Meteorological Information N/A N/A N/A N/A

K Bibliography N/A N/A N/A N/A Notes: “N/A” means the specific section of the OSRP contains administrative information only that cannot be exercised. “X” means the specific section of the OSRP was tested in the exercise conducted on the listed dates.

“TH-1” relates to the Thunder Horse Facility Loss of Power Incident that required the IMT engagement from September 18 – September 21


14-19.2.5 Crisis Management Centers and Organization (15.3.4.a)

BPXP maintained two crisis management centers throughout 2017: one in its Houston headquarters at the Westlake One office building, located at 501 Westlake Park Boulevard, Houston, Texas, 77079, and the other located in Houma, Louisiana, at the Houma Operations Learning Center (HOLC), 1597 Highway 311, Schriever, Louisiana, 70395-3237.

This is a change from 2016 as BPXP consolidated all its operations in the Westlake One (501 Westlake Park Boulevard) and Westlake Four (200 Westlake Park Boulevard) buildings, into a single building – Westlake One.

Houston Crisis Center (HCC) Houma Operations Learning Center (HOLC)

The HCC meets the needs and requirements for the IMT to respond to a Tier 1 incident size and may be the initial command post for major incidents. In addition to the ability to accommodate approximately 30 people, the Houston Crisis Center provides access to numerous resources available at the BP Westlake Campus including additional workspace if needed and backup electrical power. The Houston Crisis Center serves as the central hub for BPXP crisis management and response.

The HOLC is a 65,000 square-foot facility capable of safely accommodating 300 personnel, and includes access to a cafeteria, adequate parking and flexible meeting spaces to facilitate Incident Management Team operations of varied size and complexity. The HOLC serves as the backup hub for the BPXP crisis management and response teams.

Each center includes the communications equipment and technology to address real or simulated emergency response and incident management.

Additionally, a BPXP-Houston Major Incident Command Post (ICP) was setup in 2017 for use by the C&CM/ER team. It is located on the second floor of the Helios Plaza, 201 Helios Way, Houston, TX, 77079. The Houston Major Incident Command Post offers the flexibility to accommodate changing IMT needs and requirements. In addition to the ability to accommodate approximately 300 people, the Houston Major Incident Command Post provides access to numerous resources available at the BP Helios Campus including additional workspace if needed, high quality meeting facilities, IT and communications equipment, a fully-operational cafeteria, lounge space, and backup electrical power.

BPXP continued to maintain a crisis management organization of six individuals (one supervisor and five Crisis and Continuity Management/Emergency Response (C&CM/ER) Advisors), with responsibilities for maintaining readiness for response. Their responsibilities included management of the crisis management centers and to conduct training

http://www.google.com/url?sa=i&rct=j&q=&esrc=s&frm=1&source=images&cd=&cad=rja&docid=Fru2Q69TqPKmWM&tbnid=U3fWXWU7w7kiqM:&ved=0CAUQjRw&url=http://www.flickr.com/services/feeds/geo/?format=kml&id=81807159@N04&lang=en-us&page=1&ei=ROKQUajxDIrG9gT7gIGgCQ&bvm=bv.46340616,d.eWU&psig=AFQjCNHYqeAgN62G3Axtn8GkAZCAHfKhjg&ust=1368535994667623


to enhance the capability of BPXP’s Incident Management Team. Figure 14-19.1 below shows the reporting structure of the crisis management organization throughout 2017.

Figure 14-19.1: BPXP Crisis & Continuity Management/ Emergency Response Organization – 2017

As in previous years, the offices for the C&CM/ER staff are based in Houston. The staff can also report to the HOLC crisis management center if the Houston location was unavailable during a response. The work schedule for the crisis management organization is based on a 9-day/80-hour format in which the team is off weekends and every other Friday. One C&CM/ER Advisor is also assigned to provide additional 24-hour/7-day week coverage, per the C&CM/ER team’s on-call rotation.

The BPXP C&CM/ER team did not experience any changes to the organizational structure, however the team added one C&CM/ER Advisor, while another left the team. The C&CM/ER organization had six personnel on the team at all times throughout these two transitions.

The individuals in the crisis management organization hold college degrees and/or professional certifications and licenses in the areas of science, environment, safety and emergency management. At a minimum, each staff member has at least three years of experience in emergency management and was trained on the National Incident Management System (NIMS) framework and the subject matter covered in ICS 100, 200 and 300. Each staff member also has experience in responding to oil spills and other oil and gas related crisis events.

14-19.2.6 Availability of Crisis Management Centers (15.3.4.b)

As stated in Section 14-9.2.5 and effective January 1, 2017, the Houston Crisis Center moved buildings from 200 Westlake Park Boulevard, Houston, TX, 77079 to 501 Westlake Park Boulevard, Houston, TX, 77079. During the transition, all operations within the new HCC location were active prior to shutting down the previous HCC. There was no interruption in BPXP’s ability to respond to a crisis.

At least one crisis center was available at all times throughout 2017. There were four instances when the Houston Crisis Center (HCC) was unavailable. On February 4, 2017, there was a partial building outage, which resulted in a lack of access to the HCC. The outage was due to a planned event while completing renovation of some building laboratories and a wellness center. All floors, including the HCC, were available again on February 4, 2017, after the work was completed. On May 13, 2017, the HCC was unavailable due to planned maintenance and testing of the building where it is housed. Access to the HCC floors was prohibited for safety reasons as the utility power was disabled. The HCC was temporarily relocated during the shut down to an unaffected floor and returned the same day after the maintenance operations were completed. There were no delays experienced during the testing and the HCC was available again on May 13, 2017. On August 12, 2017, BP’s High Performance Computing Center and the building housing the HCC were temporarily closed for planned maintenance and testing. The HCC was temporarily located to an adjacent building on campus to accommodate the testing. After the testing was completed, all floors and buildings were available on August 12, 2017. On August 25, 2017, the Houston area was

C&CM/ER Manager

C&CM/ER Advisor

C&CM/ER Advisor

C&CM/ER Advisor

C&CM/ER Advisor

C&CM/ER Advisor


impacted by Hurricane Harvey. The following outlines the Houston Crisis Center activities resulting from impacts due to Hurricane Harvey:

• August 25, 2017: BPXP closes the Westlake One facility which houses the HCC. • August 25 – September 25, 2017: The HOLC was fully operational at all times to accommodate any IMT

needs while the HCC was unavailable. • September 25, 2017: The HCC was re-established in an alternate location (Westlake Four, 200 Westlake

Park Boulevard, Houston, TX, 77079, Room 351).

During all the aforementioned instances when the HCC was unavailable, BPXP was able to utilize the secondary crisis management center (Houma Operations Learning Center), and adjacent offices in the Houston headquarters, as alternate crisis management sites.

14-19.2.7 Description of Training and Exercises Involving Crisis Management Centers and/or Staff (15.3.4.c)

In 2017, the BPXP crisis management organization attended and/or conducted oil spill response training courses in the Houston Crisis Center along with the BPXP-Houston Incident Command Post. This training included courses designed for position-specific IMT leadership roles and courses covering the subject matter outlined in ICS 100, 200, 300, and FEMA IS 700/800. The crisis management organization also coordinated and participated in three oil spill response exercises which were all conducted at the BPXP-Houston Incident Command Post discussed in Section 14-9.2.5. The oil spill response training and exercises were previously described in Section 14-19.2.3: Description of Training, Exercises and Lessons Learned.

14-19.2.8 Certification of OSR Training with MWCC (16.3.4.a)

In 2017, BPXP utilized its source control equipment supplier, MWCC, to conduct specialized training on the process for activating its services for well containment and source control. The training also described the components of MWCC’s containment systems, including subsea dispersant application, capping, interim collection capabilities, and cap-and-flow systems. BPXP’s Operations Section Chiefs and Source Control Branch Directors were required to complete this course to qualify for their position specific roles.

For calendar year 2017, BPXP monitored the completion of MWCC training by its Operations Section Chiefs and Source Control Branch Directors, and certified that 16 individuals in the position-specific roles listed in Table 14-19.8 completed the exercise program to qualify them for their roles in the coming year, 2018. All 16 of the personnel were in their position-specific role for the entire calendar year. BPXP certifies that all 16 individuals completed the exercise program to qualify them for their role in the coming year.


Table 14-19.8: Oil Spill Response Training Summary – 2017

Incident Management Team Position-specific Roles


Mandatory Training Requirements

MWCC Annual Training

Incident Management Team Annual

Refresher Training

Section Leadership Training

Training Completion

Operations Section Chief 7 X X X 100%

Source Control Branch Director 9 X X X 100%

Total 16

Note: The column titled “Number Qualified for Role in 2018” includes a count of the personnel who will act as alternates for the listed “Incident Management Team Position-Specific Roles”.

14-19.2.9 Description of OSR Training with MWCC (16.3.4.b)

BPXP conducted three training workshops including participation with the Marine Well Containment Company (MWCC). Each workshop was four to eight hours in duration and described the equipment and capabilities of MWCC. The subject matter included the process to activate and interface with MWCC during a well control incident, the logistical considerations in activating, moving, and deploying MWCC systems, and the delineation of responsibilities between MWCC and member companies. The course described components of MWCC’s interim containment system, including subsea dispersant application, capping, interim collection capabilities, and cap-and-flow systems.

14-19.2.10 Certification of Participation in Industry OSR Exercises (17.3.2.a)

BPXP certifies that both Oil Spill Response Coordinators (OSRCs) were in his/her position-specific role for the entire 2017 calendar year and completed the exercise program to qualify for his/her role in 2018. Table 14-19.9 summarizes the types of exercises which were completed by the OSRCs for their certification entering 2018.

Table 14-19.9: Oil Spill Response Exercises Summary – 2017

Incident Management Team Position-Specific Roles



BP Oil Spill Exercise

BP MWCC Exercise

Industry Exercise

Exercise Completion

Oil Spill Response Coordinator 2 X X X 100%

Total 2

Note: 1. The “Number Qualified for Role in 2018” includes a count of the personnel who will act as alternates for the listed “Incident Management Team Position-Specific Roles”. 2. “Industry Exercise” means exercises that were sponsored by other companies and in which BPXP personnel participated.


14-19.2.11 Description of Industry OSR Exercises and Lessons Learned (17.3.2.b)

Table A14-19.10 describes the industry oil spill response exercise attended by the OSRCs. Although there were no significant lessons learned affecting BPXP’s OSRP, the OSRCs observed during the exercise that other operators face similar challenges optimizing communications amongst the whole team and the importance of co-locating the various teams within the command post as much as possible.

Table 14-19.10: Industry Oil Spill Response Exercise Summary – 2017

Oil Spill Response Exercise Participants

Sponsor Description Location/ Duration Date BSEE USCG

Other Agency MWCC OSRC

Anadarko Petroleum

Corporation

Source control functional exercise simulating worst case discharge from a well. The well was a cap only well.

BP’s Houma Operations

Learning Center

3/8/17 - 3/9/17 X X X - X

Notes: “X” indicates that one or more personnel participated in the oil spill response exercise.

14-19.2.12 Preparedness for Response Exercise Program (NPREP) (17.3.2.c)

The organization utilized only BPXP-sponsored exercises and the Thunder Horse Facility Loss of Power Incident to evaluate its completion of the National Preparedness for Response Exercise Program (NPREP) components. The NPREP components which were completed in the BPXP exercises were previously addressed in Section 14-19.2.4: Preparedness for Response Exercise Program (NPREP).

14-19.2.13 Certification of OSR Exercise for Activation of MWCC (18.3.3.a)

In 2017, BPXP conducted three oil spill response exercises which had a primary objective to simulate one or more of the source control notification, procurement, personnel, logistics, and other actions necessary to cap or cap and contain a subsea loss of well control. Each of the exercises also included activation of the source control equipment supplier, MWCC. The MWCC personnel participated in each exercise after it was convened.

BPXP certifies that 44 individuals completed the exercise program to qualify them for their position-specific roles in the coming year 2018. All 44 personnel were in their roles on or before January 1, 2017. A summary of the exercise program requirements for the 44 position-specific roles is provided in Table 14-19.2.

14-19.2.14 Description of OSR Exercise for Activation of MWCC (18.3.3.b)

The BPXP-sponsored tabletop exercises, which included activation of the MWCC, were previously described in Section 14-19.2.3: Description of Training, Exercises and Lessons Learned. The lessons learned from the exercises are also described in Section 14-19.2.3.

14-19.2.15 Preparedness for Response Exercise Program (NPREP) (18.3.3.c)

The NPREP components which were completed in the exercises conducted in 2017, along with the Thunder Horse Facility Loss of Power Incident, are documented in Table 14-19.6: BPXP’s Preparedness for Response Exercise Program Triennial Cycle Documentation Form – 2017.


14-19.2.16 Certification of Notice for Oil Spill Response Exercises (19.3.1.a)

For all oil spill response exercises within BPXP’s influence and control, notice was appropriately provided to BSEE, the USCG, and the United States, at least 30 days prior to each of the oil spill response exercises that it intended to use to satisfy the exercise requirements of the Plea Agreement Paragraphs 14, 16, 18, and 19. BPXP invited BSEE, the USCG, and the United States to attend all the BPXP-sponsored exercises. The invitation was not provided for the external industry exercise or for the Thunder Horse Facility Loss of Power Incident, as they were either outside of BPXP’s control and/or occurred without prior notice. Table 14-19.11 provides a summary of the notices which are included in the certification. BPXP will continue to communicate activities for crisis management to encourage feedback and transparency of its oil spill response operations in 2018.

Table 14-19.11: Notices for Oil Spill Response Exercises Summary – 2017

Exercise Name (Applicable Paragraph)

Date(s) Drill

Occurred Exercises Description1 Agency Notified

Date Notified

Email Courier or USPS

NPREP: Spill Management Team Tabletop Exercise

HSEEP/BP: Tabletop Exercise

(14, 16, 18, 19)

5/4/2017 BPXP Tabletop Exercise:

Incident involving oil spill and source control response including activation of the MWCC.

BSEE – Bryan Rogers 11/16/16 11/16/16

USCG – Captain Blake E. Welborn

11/16/16 11/16/16

USCG – Captain Peter F. Martin

11/16/16 11/16/16

USA 11/16/16 11/16/16



(14, 16, 18, 19)





11/16/16 11/16/16


11/16/16 11/16/16

USA 11/16/16 11/16/16



(14, 16, 18, 19)





11/16/16 11/16/16


11/16/16 11/16/16

USA 11/16/16 11/16/16

NPREP: Spill Management Team Functional Exercise

HSEEP: Functional Exercise

BP: Limited Exercise

11/9/2017 – originally scheduled

BPXP Planned Functional Exercise:


NOTE: This exercise was cancelled with BSEE’s approval on 11/8/2017



11/16/16 11/16/16


11/16/16 11/16/16

USA 11/16/16 11/16/16


Exercise Name (Applicable Paragraph)

Date(s) Drill

Occurred Exercises Description1 Agency Notified

Date Notified

Email Courier or USPS

Anadarko Petroleum Corp. Oil and Gas Exercise

Industry-sponsored

(17)

03/08/2017 –

03/09/2017

Industry-sponsored Exercise:

Oil Spill Response exercise conducted by Anadarko Petroleum Corporation, providing their own source control support. This oil spill response exercise had an oil spill component as well as a source control objective. The exercise simulated one or more of the source control activities related to notification, procurement, personnel, logistics and other necessary actions to cap/contain a subsea loss of well control.



1/16/17 1/16/17


1/16/17 1/16/17

USA 1/18/17 1/18/17

Notes: 1. NPREP is National Preparedness for Response Exercise Program 2. Exercise descriptions are based on the original submission. 3. Numbers in parentheses indicate the BPXP Remedial Order Implementation Plan Paragraph satisfied by the exercise 4. “USA” means the list of contacts defined as the “United States” in Attachment A of the BPXP Plea Agreement Remedial Order

Implementation Plan.

14-19.2.17 List of OSR Exercises with United States Participation (19.3.1.b)

BSEE, the USCG and/or the Unites States, participated in some of the BPXP-sponsored exercises either as observers or in role play as active responders. Table 14-19.5 identifies the oil spill response exercises in which they participated. BPXP also had active participation from state regulatory agencies, such as the Texas General Land Office (on 5/4/2017, 5/25/2017, and 6/22/2017).


BPXP Plea Agreement

2017

Annual Progress Report Oil Spill Response Plan (OSRP)

Best Practices (Paragraph 20)


OSRP Best Practices

In 2017, BPXP reviewed and revised its Gulf of Mexico Regional Oil Spill Response Plan (OSRP) to incorporate regulatory updates, operational changes, and the requirements of the Remedial Order Implementation Plan Paragraph 20 (a)-(g):

a. Provisions to maintain access to a supply of dispersant and fire boom for use in the event of an uncontrolled long-term blowout for the length of time required to drill a relief well;

b. Contingencies for maintaining an on-going response for the length of time required to drill a relief well;

c. Description of measures and equipment necessary to maximize the effectiveness and efficiency of the response equipment used to recover the discharge on the water’s surface, including methods to increase encounter rates;

d. Information regarding remote sensing technology and equipment to be used to track oil slicks, including oil spill detection systems and remote thickness detection systems (e.g., X-band/infrared systems);

e. Information regarding the use of communication systems between response vessels and spotter personnel;

f. Shoreline protection strategy that is consistent with applicable area contingency plans; and

g. For operations using a subsea BOP or a surface BOP on a floating facility, a discussion regarding strategies and plans related to source abatement and control for blowouts from drilling.

On June 20, 2017, BPXP submitted proposed changes to BSEE of Revision 18 of the BPXP Oil Spill Response Plan (OSRP). An addendum was submitted on June 21, 2017, which included a document describing where the requirements of Paragraph 20(a)-(g) are located in the OSRP and how they align with the requirements of Paragraph 20 of the BPXP Remedial Order Implementation Plan. The map of these requirements is provided in Table 20.1: BP Gulf of Mexico Regional Oil Spill Response Plan (6/2017) Map to Plea Agreement. Subsequently, by letter on July 19, 2017 and email dated August 7, 2017, BSEE responded that it was not approving the revised OSRP for the following reasons:

• Calculations in support of the proposed increase in the regional drilling worst case discharge (WCD) scenario amount were insufficient;

• Well top hole location was not used in the WCD scenario planning; and • Mad Dog PDQ Facility ID was incorrect.

In response, BPXP resubmitted the OSRP, including the Record of Revision and the BP Gulf of Mexico Regional Oil Spill Response Plan (6/2017) Map to Plea Agreement on August 15, 2017. BSEE approved the resubmission on September 7, 2017.

Additionally, BPXP certified to BSEE and the United States that the BPXP Plea Agreement Remedial Order Implementation Plan Paragraph 20(a)-(g) requirements were located in the OSRP which was approved by BSEE on September 7, 2017.

BPXP continues to review and practice scenarios from its approved OSRP to increase knowledge of responders and continually improve oil spill response.



In 2017, BPXP’s efforts to enhance its Gulf of Mexico Regional Oil Spill Response Plan (OSRP) included:

1. Revising the OSRP to incorporate updates to addresses, phone numbers, companies covered (including the lease list and listing of ACP, updates to VHF FM Marine Channels and Command Post locations, the Gulf of Mexico (GoM) Incident Management Team (IMT) organizational chart and roster, waste management information, dispersant stockpile listing, in-situ burn boom inventory, facility and pipeline information, GoM IMT training information, Oil Spill Removal Organization (OSRO) contract letter, eWell report form, and verification that the BPXP Plea Agreement Paragraph 20(a)-(g) requirements were addressed.

2. Providing a document that describes where the requirements of the BPXP Plea Agreement Remedial Order Implementation Plan Paragraph 20 (a)-(g) are found in the OSRP.

3. Reviewing the OSRP and Certifying that BPXP Plea Agreement Remedial Order Implementation Plan Paragraph 20(a)-(g) requirements were included in the submitted and approved 2017 OSRP.

4. Reviewing and practicing scenarios from its OSRP to increase knowledge of the responders and to continually improve oil spill response.


BP Gulf of Mexico Regional Oil Spill Response Plan (6/2017) Map to Plea Agreement

Table 20.1: BP Gulf of Mexico Regional Oil Spill Response Plan (6/2017) Map to Plea Agreement describes where each requirement of the BPXP Plea Agreement Remedial Order Implementation Plan, Paragraph 20, is located within the Oil Spill Response Plan (“OSRP”). The most recent Revision of BP Gulf of Mexico Regional Oil Spill Response Plan was submitted to the Bureau of Safety and Environmental Enforcement (BSEE) on August 15, 2017, and subsequently approved on September 7, 2017. The OSRP addresses the requirements of Paragraph 20 as outlined below:

Table 20.1: BP Gulf of Mexico Regional Oil Spill Response Plan (6/2017) Map to Plea Agreement

Plea Agreement Remedial Order Paragraph 20 Requirement

Where Requirement is Addressed in the 6/2017 OSRP

Paragraph 20(a): Provisions to maintain access to a supply of dispersant and fireproof boom for use in the event of an uncontrolled long-term blowout for the length of time required to drill a relief well.

• Section 18 (Dispersant Use Plan), Figure 18-2 (Dispersant Inventory): Lists dispersant stockpiles by supplier and phone number, region, physical location of inventory, type of dispersant and quantity available

• Section 18.A (Dispersant Use Plan – Dispersants Inventory, Dispersant Application Assets and Usage): Describes the manufacturer’s (NALCO) capability to ramp up dispersant production for ongoing, long term response. Appendix D (Contractual Agreements) lists the approved organizations for deploying and using the dispersant.

• Section 19.A (In-Situ Burning – In-Situ Burning Equipment): Lists BP’s access to in-situ burn (ISB) systems and describes equipment / supply replacement capabilities for on-going, long term response through various fireproof boom inventory suppliers, as well as Elastec, the primary boom manufacturer. It provides the location, owner, and inventory of various Gulf Coast and Out-of-Region equipment. Additionally, BP describes the incident potential assessment to estimate fire boom demand.




Paragraph 20(b): Contingencies for maintaining an ongoing response for the length of time required to drill a relief well.

• Section 4.B (Organization – Three-Tiered Response Organization): Discusses the utilization of personnel from BP’s Incident Management Teams (IMT), BP’s Business Support Team (BST) and BP’s Executive Support Team (EST) / Country Support Team (CST).

• Section 7.D (QI, IMT, SROT AND OSRO NOTIFICATIONS – OSRO Contact Information): Describes access to BP’s Gulf of Mexico Oil Spill Removal Organizations (OSROs) support capabilities; including contact and internet information for Marine Spill Response Corporation (MSRC), Clean Gulf Associates (CGA), National Response Corporation (NRC) and Marine Well Containment Company (MWCC).

• Section 16 (Oil and Oiled Debris Disposal Procedures): Discusses plans and procedures for oil spill cleanup and waste management.

• Section 18.A (Dispersant Use Plan – Dispersants Inventory, Dispersant Application, Assets and Usage) and Appendix H (Worst Case Discharge): Describes BP’s strategy to ensure availability of dispersant equipment and inventory for the duration of any response.

• Section 19.A (In-Situ Burning – In-Situ Burning Equipment) and Appendix H (Worst Case Discharge): Lists BP’s access to in-situ burn (ISB) systems and describes the strategy of BP to ensure that fire boom is available for the duration of any response.

• Appendix F (Support Services and Supplies): Lists support services and supply vendors for dealing with any response.

• Appendix H.1-13 (Worst Case Discharge): Describes response strategies and capabilities for maintaining an ongoing response for several potential Worst Case Discharge scenarios.




Paragraph 20(c): Description of measures and equipment necessary to maximize the effectiveness and efficiency of the response equipment used to recover the discharge on the water’s surface, including methods to increase encounter rates.

• Section 11.D (Spill Assessment and Volume Estimation – Monitoring and Tracking the Spill Movement), Figure 11-2 (Oil Surveillance and Tracking Technology Chart): Discusses remote sensing technologies with a table outlining various technology capabilities and limitations.

• Section 13 (Resource Protection Methods), Figure 13-1 (Offshore Response Procedures): Discusses offshore response methods, including their applicability and limitations (e.g. containment boom, chemical dispersion, in-situ burning, etc.).

• Section 15.B (Oil and Debris Removal Procedures – Response Efficiency): Discusses the use of aerial surveillance, automated identification systems (AIS) for vessel tracking, and X-band/infrared radar to improve efficiency during a response.

• Section 15 (Oil and Debris Removal Procedures), Figure 15-1 (Offshore Response Procedures): A table which describes offshore cleanup procedures, including mechanical recovery and different types of booming.

• Section 15 (Oil and Debris Removal Procedures), Figure 15-2 (Shallow Water Booming Procedures): A table which describes different shallow water booming methods.

• Appendix H.3 (Worst Case Discharge – Surveillance): Discusses use of systems such as AIS and spotter aircraft with communications systems in the worst case discharge scenarios.

• Appendix H.7 (Worst Case Discharge – Mechanical Recovery): Discusses use of X-band/infrared systems for spill surveillance, along with other technologies to facilitate night time skimming, in a worst case discharge scenario.

Paragraph 20(d): Information regarding remote sensing technology and equipment to be used to track oil slicks, including spill detection systems and remote thickness detection systems (e.g., X-band/infrared systems).

• Section 11.D (Spill Assessment and Volume Estimation – Monitoring and Tracking the Spill Movement), Figure 11-2 (Oil Surveillance and Tracking Technology Chart): Discusses remote sensing technologies with a table outlining capabilities and limitations.

• Section 15.B (Oil and Debris Removal Procedures – Response Efficiency): Discusses use of radio communications, vessel tracking technology and remote sensing technology to aid mechanical recovery resources.

• Appendix H.3 (Worst Case Discharge – Surveillance): Discusses use of a variety of surveillance oil spill detection equipment and technologies, including Automated Identification Systems (AIS).

• Appendix H.7 (Worst Case Discharge – Mechanical Recovery): Discusses use of X-band/infrared systems for spill surveillance, along with other technologies to facilitate night time skimming, in a worst case discharge scenario.




Paragraph 20(e): Information regarding the use of communication systems between response vessels and spotter personnel.

• Section 15.B (Oil and Debris Removal Procedures – Response Efficiency): Describes requirements for automated identification system (AIS) for vessel tracking and the use of air-to-vessel communications during a response.

• Appendix H.3 (Worst Case Discharge – Surveillance): Discusses use of systems such as AIS and spotter aircraft with communications systems in the worst case discharge scenarios.

Paragraph 20(f): Shoreline protection strategy that is consistent with applicable area contingency plans.

• Section 13.A (Resource Protection Methods – Protection Methods–Offshore/Nearshore/Shoreline): Discusses the use of Area Contingency Plans (ACPs), NOAA’s Environmental Sensitivity Index (ESI) maps, and The Response Group’s (TRG) Shoreline Response Guides, to aid in the development of shoreline protection.

• Appendix H.13 (Worst Case Discharge – Shoreline Response): Discusses a shoreline response and equipment that would be needed for protection.

Paragraph 20(g): For operations using a subsea BOP or a surface BOP on a floating facility, a discussion regarding strategies and plans related to source abatement and control for blowouts from drilling.

• Sections 18.D (Dispersant Use Plan – Application Equipment), 18.E (Dispersant Use Plan – Application Methods) and Appendix H.11 (Worst Case Discharge – Subsea Dispersant Application): Discusses various subsea dispersant application methods directly in the source.

• Appendix I (Subsea Containment Information): References the source control information which is included within each Application to Drill (APD) submitted to BSEE. It also references the Regional Containment Demonstration (RCD) information approved by BSEE, which contains strategies, equipment, contractors and personnel allocated for a subsea response.


Acronyms:

ACP Area Contingency Plan

AIS Automated Identification System

APD Applications for Permit to Drill

BOP Blow out Preventer

BPXP BP Exploration and Production

BSEE Bureau of Safety and Environmental Enforcement

BST Business Support Team

CGA Clean Gulf Associates

CST Country Support Team

ESI Environmental Sensitivity Index

EST Executive Support Team

GoM Gulf of Mexico

IMT Incident Management Team

ISB In-Situ Burn

MSRC Marine Spill Response Corporation

MWCC Marine Well Containment Company

NALCO Company name – NALCO Corporation

NOAA National Oceanic and Atmospheric Administration

NRC National Response Corporation

OSRO Oil Spill Removal Organization

OSRP Oil Spill Response Plan

RCD Regional Containment Demonstration

TRG The Response Group


BPXP Plea Agreement

2017

Annual Progress Report Safety Technology Developed with Industry

(Paragraph 21)


Safety Technology Developed with Industry

In 2013, BPXP submitted proposals to the Bureau of Safety and Environmental Enforcement (BSEE) for two Pilot Safety Technology Projects as described. BSEE formally approved the proposed projects on May 30, 2014. BPXP has collaborated with industry to develop these technologies to enhance operational safety with respect to deepwater drilling.

Pilot Project Plan 21.1: Real-Time Remote Blowout Preventer (BOP) Pressure Test Monitoring aims to extend the capabilities of digital BOP testing technology. The system will enable remote observation of pressure testing of subsea BOPs by personnel from onshore.

Pilot Project Plan 21.2: Real-Time Rig-Site Fluid Monitoring aims to identify additional parameters that may be indicative of developing well control or lost circulation events.


The 2017 status of the two Pilot Projects is described below.

Pilot Project 21.1: Real-Time Remote Blowout Preventer (BOP) Pressure Test Monitoring

The following section describes the specifics of the Real-Time Remote BOP Pressure Test Monitoring technology development.

Primary Objective of the Technology:

Demonstrate and deploy significant advances in the display and interpretation of subsea BOP pressure tests, which can be viewed both offshore and, primarily, onshore. This is accomplished via the display of the pressure path within an image of a subsea BOP stack used during deepwater drilling operations.

Pilot Completed: April 5, 2016 and September 29, 2016 (demonstrate with BSEE at their offices in New Orleans, LA)

Pilot Location: Gulf of Mexico, Deepwater Drilling Rig Ensco DS-3 (utilizing an NOV 5th Generation BOP Stack)

Independent Technical Feasibility:

Final release submitted by SwRI to BPXP on July 19, 2017

Independent Economic Evaluation:


Console Collaboration Partner:

Kongsberg Digital Inc., a division of Kongsberg Oil & Gas Technologies Inc.

Cost to Pilot: ~$8 million


In 2013, BPXP proposed development of a project aimed to extend the capabilities of Digital BOP Testing technology – both in terms of wider availability (remote locations including onshore) and in terms of the functionality it provides (to include other positive pressure tests).

As defined in the proposal submitted to the Bureau of Safety and Environmental Enforcement (BSEE), the original project objectives of the Remote BOP Pressure Test Monitoring project were as follows:

• Pressure testing software availability to be extended to on-network applications accessible from multiple locations;

• Pressure test data and data interpretation to be visible in the Houston Monitoring Center (HMC) for the applicable BPXP Gulf of Mexico (GoM) deepwater drilling rig(s);

• Pressure test data and data interpretation observation opportunity to be provided to BSEE GoM Region/District, upon request, via a one-way network accessible communication link. These observations, made during the BP technology pilot, will allow BSEE to gain a better understanding of the technology necessary to conduct remote BOP inspection testing;

• Subsea BOP and valve position data to be visible adjacent to each pressure test display; and

• Pressure paths to be interpreted from position data and highlighted on a BOP diagram.

Status of the key activity areas completed to-date are as follows:

• Develop Feasibility Testing Procedures:

o All activities completed in 2014

• Develop Economic Evaluation Procedures:


• Develop Remote BOP Pressure Testing Dashboard:

o All activities completed throughout 2014 and 2015

o Field trial completed in 2015

• Develop Processes and Training:

o All activities completed throughout 2015 and 2016

• Pilot Deployment:

o All activities completed throughout 2016

o Initiated independent technical feasibility and economic evaluation in 2016

• Final Report:

o Independent technical feasibility report completed in 2017

o Independent economic evaluation report completed in 2017

o Submitted final report with recommendation to BSEE on July 27, 2017

The technical objectives for the Remote BOP Pressure Test monitoring technology were identified in the Pilot Project Plan Proposal that was submitted to BSEE by BPXP. Southwest Research Institute (SwRI) was contracted to perform an independent analysis to determine whether or not the technical objectives were satisfied and the technology was


considered technically feasible. SwRI determined that the technology is technically feasible and an economic evaluation should be pursued.

An economic evaluation was performed by SwRI which captured the length of delay in a well-control event that would be required to justify the costs of implementing the Remote BOP Pressure Test monitoring technology. The costs for the analysis included the hardware and software costs for implementing the console, while the benefits were a change in likelihood or severity of an event.

A breakeven analysis approach was utilized to determine the economic evaluation of the console. The consequence costs used were based on industry-available numbers and were not intended to be reflective of any specific operator. The analysis was performed in a manner that allowed inputs to be varied based on a specific deepwater drilling rig or region, or to simply evaluate other representative cases. In addition, sensitivity analyses were performed to determine the effect of changing the baseline frequency (well-control events per year) and the baseline consequence cost (cost per well-control event). Performing the analyses over a range of variations from the baseline provided additional information for assessing the economic benefit of implementing the Remote BOP Pressure Test monitoring technology throughout BPXP’s Deepwater Drilling Operations.

Due to the limited potential benefit, questionable viability, and the high cost of implementation, this technology was not deemed as economically feasible by SwRI. BPXP supported these findings and is not pursuing implementation of this technology.

Pilot Project 21.2: Real-Time Rig-Site Fluid Monitoring

The following section describes the specifics of Real-Time Rig-Site Fluid Monitoring Pilot Project completion.

Primary Purpose of the Technology:

Collect and present real-time data which will help improve the ability to monitor Pore Pressure and Fracture Gradient (PPFG) against well parameters; with various offshore and onshore displays containing relevant pressure, volume and gas event data.

Pilot Completed: Q1 2016

Pilot Location: Gulf of Mexico, Seadrill’s West Capricorn Deepwater Drilling Rig





Collaboration Partner: Kongsberg Digital Inc., a division of Kongsberg Oil & Gas Technologies Inc.



In 2013, BPXP proposed the development of a real-time rig-site fluid monitoring technology, aimed at identifying parameters, which may be indicative of developing well control, or lost circulation, events. The overall project objective was to improve the ability to monitor Pore Pressure and Fracture Gradient (PPFG) in real-time against the well parameters in order to provide potential early warning indicators of lost circulation and well control events on deepwater drilling rigs.

As defined in the proposal submitted to the Bureau of Safety and Environmental Enforcement (BSEE), the original project objectives of the Rig-Site Fluid Monitoring Project were:

• Reduce the number of well control and lost circulation events and thereby enhance operational safety;

• Enhance the ability to monitor PPFG data in real-time against the pre-well prediction to identify where there is a risk that an influx might enter the wellbore or a lost circulation event may occur;

• Amplify the weak signals of any impending change in PPFG to enable personnel to make timely decisions that may avert a lost circulation or well control event;

• Enhance visibility and shared situational awareness of real-time PPFG data between onshore and offshore, and between the Subsurface and Wells communities; and

• Aid learning and provide consistency for planning and executing well construction.



o All activities completed in 2014 and Q1 2015



• Develop Rig-Site Fluid Monitoring Console:

o All activities completed throughout Q4 2013, 2014 and 2015

o Field trial completed in 2015


o All activities completed throughout 2015 and Q1 2016


o All activities completed throughout 2015 and Q1 2016


• Final Report:




The technical objectives for the Rig-Site Fluid Monitoring technology were identified in the Pilot Project Plan Proposal that was submitted to BSEE by BPXP. Southwest Research Institute (SwRI) was contracted to perform an independent analysis to determine whether or not the technical objectives were satisfied and the technology was


considered technically feasible. SwRI determined that the technology is technically feasible and an economic evaluation should be pursued.

An economic evaluation was performed by SwRI to determine the cost and benefits of implementing the RSFMc as a means of reducing the frequency of well control events.

The evaluation followed the considerations:

• Technology implementation cost and benefits were evaluated for each individual drilling rig, set of drilling rigs, and region;

• The costs identified in the evaluation are transportable to other drilling rigs, operators, and regions of operations;

• The inputs for consequences (i.e., inverse of benefits) are indicative of information sourced for GoM operations and are not BP-specific; and

• The consequence costs are averages and differ for each specific drilling rig.

The evaluation considered only the benefits driven by safety (i.e., reduction in well-control events, as well as the impact of a possible event) and did not factor in other potential benefits (e.g., reduction in non-productive time in well construction operations).

A breakeven analysis approach was used to determine the economic feasibility of the Rig-Site Fluid Monitoring technology. Implementation of the technology would be aimed at reducing the likelihood or severity of events that are fairly infrequent, yet potentially severe.

The conclusion of SwRI’s economic evaluation was that the Rig-Site Fluid Monitoring technology was economically feasible. BPXP supported these findings and is pursuing implementation of this technology at locations where such enhancements are applicable.


BPXP Plea Agreement

2017

Annual Progress Report Other Safety Technology Development

(Paragraph 22)


Other Safety Technology Development

In 2013 and 2014, BPXP submitted proposals to the Bureau of Safety and Environmental Enforcement (BSEE) for three Pilot Projects regarding the development of new technologies in one or more of the following categories:

1. Enhancing functionality, intervention, testing, and activation of blowout preventer (BOP) systems; or

2. Enhancing well design; or

3. Enhancing real-time monitoring offshore and onshore.

On September 20, 2013, the first Pilot Plan, entitled "BOP Health Monitoring", was submitted to BSEE for approval. On February 17, 2014, BPXP submitted plans to BSEE for two additional Other Safety Technology Pilot Projects. These Pilot Projects are described below. These technologies are designed to enhance operational safety with respect to deepwater drilling operations.

Pilot Project 22.1: Blowout Preventer (BOP) Health Monitoring aims to provide real-time information diagnostics on the availability of various BOP functions and positions.

Pilot Project 22.2: Cement Placement Monitoring aims to integrate real-time data, BP global practices, and process to assure well barrier placement.

Pilot Project 22.3: Early Kick Detection aims to leverage mathematical- and physics-based modeling techniques for the purposes of detecting influx occurrences more quickly than current oil industry technologies.

On May 30, 2014, BSEE formally approved all three proposed Pilot Plans for Other Safety Technology Projects.

22.1 Measures Taken to Comply The 2017 status of the three Pilot Projects is described below.

Pilot Project 22.1: Blowout Preventer (BOP) Health Monitoring

The following section describes the specifics of the Blowout Preventer (BOP) Health Monitoring technology development.


Create a Dashboard that simplifies complex BOP diagnostics into a single screen of BOP health and component positions (e.g., rams, annulars, valves)

Pilot Completed: 2Q 2015

Pilot Location: Gulf of Mexico, Ensco DS-3 Deepwater Drilling Rig (utilizing an NOV 5th Generation BOP Stack)








In 2013, BPXP proposed the development of technology for a new BOP health monitoring system, to present simple graphical diagnostics in the form of “traffic lights” and BOP positions to the end-users.

As defined in the proposal submitted to the Bureau of Safety and Environmental Enforcement (BSEE), the original project objectives of the BOP Health Monitoring project were to provide the following:

• 24-hour health log including alarms/alerts;

• “Traffic light” health status;

• Real-time pressure and temperature data; and

• Position history log.



o All activities completed between Q4 2013 and Q2 2014



• Implement BOP Health Monitoring Dashboard:


o Field trial completed in Q2 2014


o All activities completed throughout 2014


o All activities completed throughout 2014-2016 (which included permanent installation on the Ensco DS-3 deepwater drilling rig until it was removed from its BPXP contract)


• Final Report:




The technical objectives for the BOP Health Monitoring technology were identified in the Pilot Project Plan Proposal that was submitted to BSEE by BPXP. Southwest Research Institute (SwRI) was contracted to perform an independent analysis to determine whether or not the technical objectives were satisfied and the technology was considered technically feasible. SwRI determined that the technology is technically feasible and an economic evaluation should be pursued.

An economic evaluation was performed by SwRI to examine the impact of implementing the pilot technology as a means to reduce well-control events. Although BPXP initiated the development of the BOP Health Monitoring technology, various Original Equipment Manufacturers (OEM) manufacturers (e.g. Cameron, GE, and NOV) developed similar technologies supporting each of their own BOPs. As such, SwRI’s economic evaluation considered


both technology options (i.e., BPXP BOP Health Monitoring technology versus the OEM-provided proprietary data systems), which have equivalent benefits but different implementation complexities and costs.

The methodology for SwRI’s economic evaluation is summarized as follows:

• Evaluate the technology implementation cost and resulting benefits for any drilling rig, set of drilling rigs, or region;

• The costs used in the evaluation are transportable to other drilling rigs, operators, and regions of operations;

• The inputs for consequences (i.e., inverse of benefits) are indicative of information sourced for GoM operations and are not BPXP-specific;

• The consequence costs are averages and will differ for each specific drilling rig; and • The evaluation intentionally only considered the benefits driven by safety (i.e., reduction in well-control

events as well as the impact of a possible event) and did not factor in other potential benefits (e.g., reduction in non-productive time in well construction operations or reduced BOP failure severity).

A breakeven analysis approach was used to determine the economic feasibility of the BOP Health Monitoring technology. Implementation of the technology would be aimed at reducing the likelihood or severity of events that are fairly infrequent, yet potentially severe.

The conclusion of SwRI’s economic evaluation was that the BOP Health Monitoring technology is economically feasible. However, the results further demonstrated that the OEM data system provided a quicker investment recovery rate than the BPXP-implemented BOP Health Monitoring technology. BPXP supported these findings and is pursing implementation of the OEM technology at locations where such enhancements are applicable.

Pilot Project 22.2: Cement Placement Monitoring

The following section describes the specifics of the Cement Placement Monitoring technology development.


Develop a console that monitors in real-time the cement placement operation and provides the criteria for verification of cement well barrier elements isolating the annulus.

Phase 1 Pilot Completed: Q2 2014 – Q4 2016

Phase 1 Pilot Location: North Sea, Gulf of Mexico, Azerbaijan-Georgia-Turkey (AGT), Trinidad, and Oman

Phase 2 Pilot Completed: Q4 2016

Phase 2 Pilot Location: Azerbaijan-Georgia-Turkey (AGT)








In 2014, BPXP proposed the development of a real-time cement placement monitoring technology aimed at interpreting and documenting cement placement on deepwater rigs in the Gulf of Mexico. As proposed in 2014, the primary objectives of the Cement Placement Console are to integrate real-time data with BP global practices and processes to assure well barrier placement verification during primary cementing operations by:

• Providing standardized methodology for executing and evaluating cementing operations;

• Displaying pressure signature, stage of operation, cement quality and top of cement position in real-time;

• Automatically estimating cement placement at the end of cementing operations;

• Displaying design criteria versus actual execution parameters;

• Identifying the potential for non-conformance with the BP Group Practice on zonal isolation;

• Providing a repository for Cementing Job Execution and Evaluation data;

• Providing a standard interface for onshore engineers, Well Site Leaders, and other interested stakeholders to monitor cement placement operations simultaneously, regardless of location;

• Aiding learning and providing consistency for planning and executing well construction;

• Supporting continuous improvement, enabling use of lessons learned from previous cementing jobs to proactively enhance future cementing operations;

• Monitoring lost circulation during cement job – important in determining top of cement accurately; and

• Displaying real-time comparisons of Equivalent Circulating Density) against Pore Pressure and Fracture Gradient (PPFG) and real-time flow out versus rig flow out sensor (not pursued for this technology development due to technical considerations).






• Implement Cement Placement Monitoring Dashboard:


o Field trial completed in Q3-Q4 2014






• Final Report:





The technical objectives for the Cement Placement Monitoring technology were identified in the Pilot Project Plan Proposal that was submitted to BSEE by BPXP. Southwest Research Institute (SwRI) was contracted to perform an independent analysis to determine whether or not the technical objectives were satisfied and the technology was considered technically feasible. SwRI determined that the technology is technically feasible and an economic evaluation should be pursued.

An economic evaluation was performed by SwRI to examine the impact of implementing the pilot technology as a means to assist in the verification of zonal isolation through cementing.

SwRI’s charter for the analysis was to assess the “value of benefits” based on one or more of the following:

• Operational efficiencies; • Avoidance of operational upsets and down-time; • Enhancement of the well barriers against catastrophic events; and/or • Estimated savings from the reduction of incidents should the equipment be successfully deployed.

The conclusion of SwRI’s economic evaluation was that the Cement Placement Monitoring technology was not economically feasible if it was independently installed. However, if this technology was to be installed along with other technologies in development (e.g. BOP Health Monitoring, Rig-Site Fluid Monitoring, etc.), the investment recovery rate increased dramatically. BPXP supported these findings and is pursing implementation of this technology at locations where such enhancements are applicable.

Pilot Project 22.3: Early Kick Detection

The following section describes the specifics of the Early Kick Detection (EKD) technology development.


To develop a monitoring system to improve the speed and reliability at which an influx of formation fluids flowing into the wellbore can be identified during deepwater drilling operations. Optimally, in near real-time, based upon statistical analysis and integration of the wellbore hydraulic model with wellbore and real-time data.

Pilot Completed: 1Q 2017

Pilot Location: Well located in the Gulf of Mexico while being monitored in the Houston Monitoring Center (HMC)





Collaboration Partner: University of Texas, Austin

Cost to Pilot: ~$7m

In 2014, BPXP proposed the development of an early kick detection system. BPXP formed an integrated project team with BP resources and University of Texas at Austin for delivery of the project. The overall project objective was to improve the speed at which an influx or ‘kick’ can be identified during deepwater drilling operations. Faster


identification of an influx increases the amount of time personnel have to respond (e.g. shut in the well) in order to reduce operational risk.

The objectives pursued as part of the early kick detection technology were:

1. Determine Feasibility of Approach – determine feasibility of a cyber physical approach for early kick detection using existing data feeds;

2. Confirm Reliability of Models – test reliability of first generation EKD system with additional historical data sets;

3. Improve and Extend Functionality – extend the drilling EKD system to cover kicks that occur during tripping operations and kicks that occur when mud pumps are turned off (i.e., equivalent circulating density (ECD) drops);

4. Test the EKD System in a Controlled Environment – test reliability of the system in a test well; 5. Develop Path to Commercialization – select a third party (e.g., an oil field service company) to collaborate

in developing a commercial model for industry access to the new technology; 6. Develop Operational Protocols and Training Material – define the operational decision-making framework

and develop associated training material; 7. Initiate Pilot Deployment – field trial of the EKD system; and 8. Deploy at Scale – implement the EKD system more broadly for BPXP-operated Deepwater Drilling

Operations in the Gulf of Mexico region.






• Develop Early Kick Detection System:


o Initial field trial testing was completed in a controlled environment (utilizing historical data sets) in Q2-Q3 2015





o Pilot was completed while drilling a single well in the Gulf of Mexico with Seadrill’s West Capricorn deepwater drilling rig


• Final Interim Report:





The technical objectives for the Early Kick Detection (EKD) technology were identified in the Pilot Project Plan Proposal that was submitted to BSEE by BPXP. Southwest Research Institute (SwRI) was contracted to perform an independent analysis to determine whether or not the technical objectives were satisfied and the technology was considered technically feasible. SwRI determined that the technology is technically feasible and an economic evaluation should be pursued.

An economic evaluation was performed by SwRI to examine the impact of implementing the pilot technology as a means to detect kicks earlier than is currently possible and hence reduce the likelihood or severity of such an event.

The conclusion of SwRI’s economic evaluation was that the EKD technology was economically feasible. BPXP supported these findings and is pursing continued development of the technology, alignment with a third-party service provider and a path to commercialization, and a plan for implementation and deployment at-scale.


BPXP Plea Agreement

2017

Annual Progress Report Transparency (Paragraph 23)

THIS PAGE INTENTIONALLY LEFT BLANK


Transparency

BPXP has created, and maintains, a public website where the following information is communicated:

• Lessons learned from the Deepwater Horizon incident; • Annual progress reports summarizing BPXP's compliance with Paragraphs 5 through 31 of the BPXP Plea Agreement

Remedial Order Implementation Plan; • Annual summaries of recordable safety incidents, days away from work, hydrocarbon spills and the volume thereof;

and • An annual list of all incidents of non-compliance (INC) with the Bureau of Safety and Environmental Enforcement

(BSEE) or the Bureau of Ocean Energy Management (BOEM) regulations, or with probation for which BPXP is cited, including corrective actions taken and penalties assessed.

The BPXP public website is found at the following link:

http://www.bpxpcompliancereports.com

The website became active and available on April 22, 2013. While the website has been available and accessible to the public since that time, on August 10, 2017, BPXP became aware that the weblinks were not available and advised the website host of the issue at 13:00 PST. At 15:09 PST, on the same day, all the weblinks had been restored. After the discovery, it was determined by the webhost company that in the process of upgrading its management software to improve its media hosting services, the weblinks for documents posted to the BPXP public website became inaccessible due to an issue with the final conversion.

The new website host began tracking “hits” on the BPXP public website on July 1, 2017. From July 1, 2017 to December 31, 2017, there were over 2,700 hits to the BPXP public website. The public website contains the following Lessons Learned documents:

a. Deepwater Horizon Containment and Response: Harnessing Capabilities and Lessons Learned; b. Deepwater Horizon Accident Investigation Report; and c. Presentation slides on Advancing Global Deepwater Capabilities.

There were no updates to the aforementioned presentations in 2017.

The Annual Progress Reports and incident and spill summaries, have been posted annually, for the previous calendar year, no later than March 31 of the following year; and for this final, 2017 Annual Progress Report, incidents and spill summaries will be posted by January 19, 2018. Through the end of calendar year 2017, the BPXP Gulf of Mexico operations identified and tracked the following safety and performance metrics:

• 10 BSEE reported injury incidents (including one injury that was determined to be non-work related after an investigation);

• 11 Days away from work or restricted work cases;

• 15 Hydrocarbon spill reports of sheen of unknown origin;

• 48 Hydrocarbon spills less than one barrel that totaled approximately 1,939 barrels in volume;

• 0 Hydrocarbon spills between one and ten barrels (1 Hydrocarbon spill that initially measured greater than one barrel, was later reclassified as less than one barrel as some of the release was recovered. The initial volume was approximately 1.13 barrels.)



• 1 Hydrocarbon spill greater than ten barrels that totaled approximately 71 barrels in volume (originally estimated as 90 barrels);

• 6 Incidents of Non-Compliance with BSEE regulations;

• No Incidents of Non-Compliance with BOEM regulations;

• No Incidents of Non-Compliance with Probation;

• No civil penalties assessed by BSEE for 2017 Incidents of Non-Compliance; and

• No civil penalties were paid in 2017 for Incidents of Non-Compliance issued by BSEE in 2016.



23.1.1 BPXP Public Website

The BPXP Public Website was made available on April 22, 2013. The website is located at the following address:

http://www.bpxpcompliancereports.com

23.1.2 BPXP Annual Summary of Recordable Safety Incidents

Throughout 2017, BPXP had ten (10) incidents that were reported to BSEE under 30 CFR § 250.188(a)(1) or (a)(2). Of the ten (10) incidents, one was later determined to be non-work related after an investigation and therefore was not counted in this report as a recordable safety incident. None of the incidents were fatalities. There were eleven (11) incidents that resulted in days away from work (DAFWC) or restricted work cases per 30 CFR § 250.188 (b)(1). A summary of the work-related, recordable safety incidents is provided in Table 23.1 and on the BPXP Public Website at the following address:

http://www.bpxpcompliancereports.com/annual-safety-and-environmental-reports/

Table 23.1: 2017 BPXP Gulf of Mexico Recordable Safety Incidents with Injuries Summary

Recordable Safety Incidents Days Away from Work Cases or Restricted Work Cases Resulting from Recordable Safety Incidents

9 11 Notes: 1. “Recordable Safety Incident” is defined as any work-related incident that is required to be reported under 30 CFR § 250.188 (a)(1) or (a)(2).

30 CFR § 250.188 (a)(1) includes the reporting of fatalities. There were no fatalities on BPXP facilities in 2017. 2. Days away from work/restricted work cases means those cases described in 30 CFR 250.188 (b)(1).

Of the nine (9) recordable safety incidents, three were hand injuries, two were finger injuries, two were knee injuries, one was a chest muscle strain, and one was heat exhaustion. Learnings from incident investigations of the injuries resulted in improved communications regarding job execution, development of more robust procedures, improved tools for certain jobs, better pre-job training guides, better scenario assessments for hazard identification, and an integration of certain checklists and pre-work activity directly into job Work Instructions.

23.1.3 BPXP Annual Summary of Hydrocarbon Spills and the Volume Thereof

In 2017, BPXP reported to the National Response Center (NRC) and/or to BSEE, hydrocarbon spills (including contractor reported spills) that were required to be reported under 30 CFR § 254.46(a) or (b). Fifteen (15) of the spills were reported as sheens of unknown origin in accordance with 30 CFR § 254.46(a)(3). No volume amount has been allocated for sheens of unknown origin. In addition to the sheens of unknown origin, there were a total of 48 hydrocarbon spill incidents in 2017 that were each less than one barrel in volume totaling slightly under 1.94 barrels in volume. There was one spill that was initially estimated as greater than one barrel and less than ten barrels, but was later classified as less than one barrel as some of the release was recovered. The initial release volume was slightly over 1.1 barrels in total volume. There was one hydrocarbon spill incident in 2017 greater than ten barrels in volume. It was initially estimated to be 90 barrels in volume, but later determined to be 71 barrels. A summary of the hydrocarbon spills and volume thereof is provided in Table 23.2 and on the BPXP Public Website at the following address:






Table 23.2: 2017 BPXP Gulf of Mexico Hydrocarbon Spills Summary

Volume Range Number of Hydrocarbon Spills *

Total Volume of Hydrocarbon Spills per Category (barrels) *

Sheen of unknown origin: 15 N/A **

<1 barrel: 48 1.939

≥1 barrel to <10 barrels: 0 0

≥10 barrels: 1 71 ***

Total Volume: 72.939 **** Notes: * Any spill that is required to be reported under 30 CFR 254.46(a) or (b).

** No volume amount is allocated for sheens of unknown origin. *** Synthetic-oil based mud spill originally estimated at 90 barrels and later determined to be 71 barrels **** Approximately 0.3810 barrels were reported as recovered from the Gulf of Mexico after the spill occurred 1. “Hydrocarbon” does not include substances that are excluded from the definition of “oil” in 30 CFR 254.6. 2. “Hydrocarbon Spills” does not include federally permitted releases or spills of hazardous substances otherwise reportable to the National

Response Center under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA).

23.1.4 BPXP Annual List of Incidents of Non-Compliance In 2017, BPXP had no Incidents of Non-Compliance (INC) with Probation, no INCs resulting in a Civil Penalty, no Incidents of Non-Compliance with BOEM regulations, and six (6) Incidents of Non-Compliance with BSEE regulations. A list of the six (6) INCs issued to BPXP from BSEE in 2017, along with the associated corrective actions and penalties assessed, are provided in Table 23.3 and on the BPXP Public Website at the following address:

http://www.bpxpcompliancereports.com/annual-compliance-reports/

http://www.bpxpcompliancereports.com/annual-compliance-reports/


Table 23.3: 2017 BPXP List of Incidents of Non-Compliance (INCs) with BSEE Regulations

Date

Received

BSEE PINC

Number* BSEE PINC Statement*

Authority 30 CFR § 250.

Corrective Actions Taken Penalty

Assessed (If Applicable)

03/09/2017 P-451

Is each required PSV designed, installed and maintained, in accordance with applicable provisions of Sections I, IV and VIII of the ASME boiler and pressure vessel code and set at a pressure no higher than the maximum allowable working pressure?

250.880 (b)(2)

The following actions were taken after a pressure safety valve (PSV) was discovered to be out of tolerance:

• The valve (PSV MD 11602) was subsequently successfully tested at the same time as the inspection.

• Pressure test procedure was communicated to offshore personnel to ensure pressure tests do not exceed 121% of the recommended maximum allowable pressure.

• Reviewed pressure test history for the PSV in question.

N/A

03/16/2017 G-110

Does the Lessee perform all operations in a safe and workmanlike manner and provide for the preservation and conservation of property and the environment?

250.107

The following corrective actions were completed: • The platform coolers were immediately isolated. • A pressure test was performed on the cooling system. • An oil leak was positively identified that was contained within the

cooling medium system. • A project plan executed for replacing the portion of the cooler

system with the leak. • Additional training was provided to platform personnel around US

Outer Continental Shelf engineering standards and US Coast Guard related specific equipment standards.

N/A

06/30/2017 G-116 Are operations conducted in accordance with approved plans?

550.280(a)

The following corrective actions were completed to ensure there would be no future unauthorized discharges of air emissions exceeding approved limits:

• The Air Quality Review was revised. • Air modeling was updated per the Bureau of Ocean Energy

Management protocol. • A revised Development Operations Coordination Document (DOCD)

was submitted, including updated emission estimates, for the affected facility.

N/A


Date

Received

BSEE PINC

Number* BSEE PINC Statement*

Authority 30 CFR § 250.

Corrective Actions Taken Penalty

Assessed (If Applicable)

07/06/2017 G-132

Has the district manager been verbally notified immediately following incidents involving all: fatalities, injuries requiring evacuation, loss of well control, fires, explosions, H2S releases as defined in 30 CFR 250.490(1), collisions, structural damages, crane incidents and safety system damages connected with any operations or activities on a lease, right-of-use and easement, pipeline right-of-way, or other permit issued by BSEE?

250.188

The following corrective actions were completed to ensure that proper communications are made whenever there is an incident that requires evacuation of an injured person:

• Address ways to improve communications with BSEE regarding immediate incident notification.

• Conducted a review of internal communication process when an injury occurs on a rig.

• Explore opportunities to improve the reporting process within BP’s internal safety observations and incident reporting system.

N/A

10/13/2017 E-100 Is the operator preventing unauthorized discharge of pollutants into offshore waters?

250.300(a)

The following corrective actions were completed to minimize the potential of an unauthorized discharge into offshore waters:

• Increase the awareness and learnings regarding valve verification and alignment procedures.

• Evaluate the strength of current procedures to ensure valves are appropriately aligned and their position(s) are verified.

• Investigate the use of technology to increase reliability of valve alignment and verification.

N/A

12/14/2017 F-108

Are electrical installations made in accordance with API RP 500 and API RP 14F or API RP 505 and API RP 14FZ?

250.114(c)

The following corrective actions were completed to remedy an improper seal found on the electrical box:

• The junction box in the Pit Room was properly sealed the same day as the occurrence.

• The electrical switch O-ring on the Vega sensor was also fixed the same day as the occurrence.

N/A

Notes: *A further description of the Potential Incident of Non-Compliance (PINC) issued by BSEE by the PINC number can be found at the following website: https://www.bsee.gov/what-we-do/regulatory-safety-programs/inspection-programs/potential-incident-of-noncompliance-pinc

1. “INC” refers to Incident of Non-Compliance, which is a notice of alleged violation(s) of BSEE or BOEM regulations that is issued to BPXP. 2. Penalties assessed refer only to those BSEE penalties for 2017 INCs that were agreed and paid, if applicable, in 2017. Penalties may be agreed and paid in years subsequent to the year in which the INC was issued.

See Acronyms on next page

https://www.bsee.gov/what-we-do/regulatory-safety-programs/inspection-programs/potential-incident-of-noncompliance-pinc


Acronyms: API American Petroleum Institute APM Application for Permit to Modify ASME American Society of Mechanical Engineers BOEM Bureau of Ocean Energy Management BOP Blowout Preventer BPXP BP Exploration and Production BSEE Bureau of Safety and Environmental

Enforcement

CFR Code of Federal Regulations CWOR Completion Workover Riser DAFWC Days Away from Work Cases DC Drilling Center DHFC Down Hole Flow Control DOCD Development Operations Coordination

Document H2S Hydrogen Sulfide

IBOP Internal Blowout Preventer INC Incidents of Non-Compliance NRC National Response Center PSV Pressure Safety Valve (pressure relief valve) RP Recommended Practice


BPXP Plea Agreement

2017

Annual Progress Report Rig Equipment - Two Blind Shear Rams

(Paragraph 24)


Rig Equipment - Two Blind Shear Rams

BPXP has ensured that all applicable rigs are equipped with the appropriate blind shear ram configuration. All dynamically positioned Drilling Rigs with subsea blowout preventers (BOPs) are equipped with no fewer than two blind shear rams and a casing shear ram. In addition, all moored Drilling Rigs with subsea BOPs are equipped with two shear rams, including at least one blind shear ram and either an additional blind shear ram or a casing shear ram.


The subsea shear ram configuration identified above for all such Drilling Rigs was verified throughout 2017, during the third-party BOP verification process and recorded. Additionally, throughout 2017, each Application for Permit to Drill (APD) submitted to the Bureau of Safety and Environmental Enforcement (BSEE) for Deepwater Drilling Operations included the appropriate shear ram commitment.

24.2 Certifications

24.2.1 APDs for Dynamically Positioned Rigs

BPXP certified that all BPXP Applications for Permits to Drill submitted in 2017 for dynamically positioned Drilling Rigs under contract to BPXP for Deepwater Drilling Operations included a commitment that such Drilling Rigs will use subsea BOPs equipped with no fewer than two blind shear rams and a casing shear ram.

24.2.2 Two Blind Shear Rams on Dynamically Positioned Rigs

BPXP certified in 2017 that all BPXP Deepwater Drilling Operations with a dynamically positioned Drilling Rig have a subsea BOP equipped with no fewer than two blind shear rams and a casing shear ram.

24.2.3 APDs for Moored Rigs

BPXP certified that all BPXP Applications for Permits to Drill submitted in 2017 for moored Drilling Rigs under contract to BPXP for Deepwater Drilling Operations include a commitment that such Drilling Rigs will use subsea BOPs equipped with two shear rams, including at least one blind shear ram and either an additional blind shear ram or a casing shear ram.

24.2.4 Two Blind Shear Rams on Moored Rigs

BPXP certified in 2017 that all BPXP Deepwater Drilling Operations with a moored Drilling Rig for Deepwater Drilling Operations include a subsea BOP equipped with two shear rams, including at least one blind shear ram and either an additional blind shear ram or a casing shear ram.


BPXP Plea Agreement

2017

Annual Progress Report Annual Progress Report

Safety Organization (Paragraph 25)


Description of Safety Organization In 2017, BPXP continued to empower its employees and contractors to intervene or stop any work that is perceived as unsafe. BPXP communicated this expectation via training, leadership discussions and its written Code of Conduct, which states:

“Stop work, your own or others’, if you consider it unsafe…Speak up if you observe an unsafe or unhealthy working environment. Listen to others who speak up.”

BPXP employees certified that they behaved in accordance with the Code of Conduct, and Contractors were encouraged in orientation training, and through their BPXP supervision, to speak up and stop unsafe acts. BPXP provided the normal avenues for reporting through managers, legal, and human resource representatives or compliance and ethics officers. BPXP also continued to offer “OpenTalk”, a 24 hours a day, 7 days a week hotline to enable employees and contractors to raise concerns. As in 2016, OpenTalk was administered by an independent company throughout 2017. BP maintains a zero tolerance policy on retaliation against the personnel who report through OpenTalk.

In addition to the universal authority given to all personnel to stop unsafe work, BPXP continued to maintain an independent Safety Organization with formal authority to assess risk and to intervene or stop any operation it deems unsafe. The Safety Organization is defined as the Global Wells and Gulf of Mexico (GoM) Regional teams within BP’s Global Safety and Operational Risk (S&OR) Organization; supporting deepwater drilling operations. Figure 25.1 depicts the independence of the Safety Organization (highlighted in green) from the Global Wells Organization (highlighted in orange).

25.1 Measures to Comply

In 2017, BPXP’s efforts to create awareness and encourage personnel to intervene and stop unsafe work activity included:

• Maintaining a Safety Organization that has the authority to intervene or stop any operation that it deems unsafe and

• Maintaining registers, tools, and processes for gathering, documenting, monitoring, and improving the communication of intervened or stopped operation events and any major, new or significantly revised, safety-related requirements published by the Safety Organization.


Figure 25.1: Safety Organization (green) and Drilling Organization (orange)

Deputy Group Chief Executive

Executive Vice President S&OR

Upstream Chief Executive

Head of S&OR Upstream

Chief Operating Officer

Upstream S&OR Organization

SAFETY ORGANIZATION

Global Wells Organization

DRILLING ORGANIZATION

Group Chief Executive

Upstream S&OR OrganizationWhat they do:• Setting or supporting the development of

requirements• Assuring conformance to BP's requirements• Form independent view of risk• Provide deep technical expertise in the areas of

safety and operational risk• Intervene if needed

Staff includes:• Engineering technical experts• Operational experts• Health, safety, environmental, and regulatory

compliance experts to provide oversight and assurance

Global Wells Organization (Drilling)

What they do:• Deliver safe, reliable, and compliant operations• Develop and implement the requirements

Staff includes:• Dril l ing operations• Engineering• Health, safety, environmental, and regulatory

compliance day-to-day support• Maintenance and inspection


25.2 Numbers and Qualifications of Personnel

At the end of 2017, the Safety Organization consisted of 35 positions in the roles highlighted in the green boxes in Figure 25.2.

Figure 25.2: Safety Organization (green) Details – 2017

In addition to the Technical Authorities that work full-time for the Safety Organisation, the Global Wells Engineering Authority (GWEA) is supported by 10 other specialists, known as Global Wells Technical Authorities. These specialists work in other parts of BP but also carry the title of Technical Authority (TA) and their job descriptions include a formal link to the Safety Organisation. They are not needed on a full-time basis but are made available when required by the GWEA and fulfil the same functions as the Segment Engineering Technical Authorities (SETAs). Several of the Technical Authorities are former SETAs, who were transferred out of a full-time role in the Safety Organisation as the engineering requirements in their area of responsibility matured. The specialist areas supported by these Technical Authorities are: Well Control, Well Interventions, Well Integrity, Zonal Isolation, Process Safety, BOP Equipment, Directional Drilling & Surveying, Marine Geohazards, Pore & Fracture Pressure, Engineered Equipment, and Subsea Engineering.

The professionals in the overall Safety Organization possess an average of over 20 years of experience in one or more of the fields relating to Engineering and Operations. These personnel hold engineering or other technical degrees and many hold licenses from professional organizations which prescribe continuing education requirements. Many members of the Safety Organization came from the operating teams and have deep knowledge and understanding of the drilling business and risks. These personnel provide guidance and coaching to the operating teams to improve the health of the operations.







Vice President Global Wells and Operating Authority, S&OR

(1)

Vice President Global Wells and Operating Authority, S&OR

(1)

Vice President GoM Region S&OR (1)

Vice President GoM Region S&OR (1)

Upstream Engineering Authority(1)

Upstream Engineering Authority(1)

GoM RegionOperating Authority

(1)

GoM RegionOperating Authority

(1)

GoM RegionEngineering

Authority(1)

GoM RegionEngineering

Authority(1)

UpstreamTechnical

Authorities(10)

UpstreamTechnical

Authorities(10)

Global Wells Engineering Authority (1)

Global Wells Engineering Authority (1)

Wells Operating Technical

Authorities(4)

Wells Operating Technical

Authorities(4) GoM Region

Technical Authorities

(4)

GoM RegionTechnical

Authorities(4)

GoM Region Technical

Authority (1)

GoM Region Technical

Authority (1)

Global WellsTechnical

Authorities(10)

Global WellsTechnical

Authorities(10)


25.3 Summary of Safety Organization’s Work – 2017 While the operating function for the Global Wells Organization retained accountability for delivering safe, reliable, and compliant operations, the Safety Organization maintained its independent view of risk and provided technical expertise to the operating function for:

• Setting or supporting the development of requirements; • Providing technical expertise to drilling operations for implementation of requirements; • Assuring conformance to BP’s Requirements; and • Intervening and escalating as appropriate to cause corrective action.

In 2017, the Safety Organization worked with the Global Wells Organization to publish, revise and/or support the publication of 35 major requirements to address personal and process safety risks for well operations. These requirements were developed with input from the Global Wells Organization while considering the learnings from incidents, audit findings, regulatory changes, and any identified gaps in BPXP’s operating management system.


25.4 Stopping or Intervening Work BPXP employs several mechanisms to check work activity for compliance with safety requirements. Table 25.1 describes some of these mechanisms.

In 2017, BPXP Employees, Contractors, and the Safety Organization intervened or stopped work by exercising one or more of the mechanisms in Table 25.1. The stops occurred most frequently at offshore locations when personnel were preparing for a job, or when unexpected changes occurred while performing a job. The employees and contractors in the Global Wells Organization supporting deepwater drilling operations most frequently used behaviour-based safety observations, pre-job risk assessments, and hazard identification, as the mechanisms for intervening or stopping a job. On the other hand, the Safety Organization applied most of its interventions or work stoppages during the design and planning phases and when conducting inspections and reviews offshore.

For operating year 2017, BPXP is providing 70 examples to BSEE to demonstrate when BPXP employees, contractors and the Safety Organization stopped work and how BPXP responded to these events. The examples came from all of BPXP’s-contracted drilling rigs, as well as BPXP’s-owned drilling rigs, and were typical representations of drilling operations.

BPXP shared key work stoppage events and any lessons learned locally, at the site where the event occurred. Where applicable, BPXP also shared the lessons learned and corrective actions with similar BPXP facilities in the region. Along with coordinating between BPXP contractors and suppliers impacted by work stoppage events, BPXP responded to work stoppages with one or more of the actions below:

• Mentoring and training for personnel; • Reconfiguring and simplifying work areas; • Revising risk assessments and procedures; and • Re-designing equipment, tools or processes to remove defects.

Table 25.1: Stop Work Mechanisms

Stop Work Mechanism Description Work Activity

Houston Monitoring Center (HMC)

The HMC is used to remotely monitor drilling operations and watch for excursions from safe operating limits. The HMC personnel have the authority and expectation to escalate on abnormal parameters which could result in unsafe situations. These reports can result in an intervention which may lead to further action.

Planning/ Oversight

Simultaneous Operations (SIMOPS) Plan

SIMOPS is defined as conducting two or more independent operations in which the events of any one operation may impact the safety of personnel, equipment, or the environment of another operation being conducted at the same time. This could involve any combination of production operations, drilling operations and or project execution operations, and includes any instance where concurrent operations create risk. During these operations, personnel have the opportunity to intervene or stop work.



Rig Assessments Rig Assessments are conducted by BPXP’s Rig Verification Group, to assure that a rig can operate safely. Observations from Rig Assessments can result in interventions or stopped work.

Assurance

Rig Inspections

Rig Inspections are conducted by onshore-based Supervisors, or members of the Safety Organization, to verify the strength of barriers to a potential major accident risk. The observations from inspections provide opportunities to assess the implementation of requirements and to stop or intervene on unsafe work practices.

Hazard Identification/ Hazard Operability Studies

Hazard Identification/Hazard Operability studies are performed prior to operating new equipment, carrying out well intervention operations, and for certain other activities involving live hydrocarbons (e.g. well testing). These studies are used to identify potential safety, environmental, and operability risks. The risks identified in studies can result in interventions with projects to mitigate risk or in stopped work. Risk/Hazard

Identification

Job Task Risk Assessments (JTRA)

Job Task Risk Assessments (JTRA) are used by employees and contractors prior to beginning a job. A JTRA form is used to identify hazards associated with job tasks, assess potential risks, and determine methods of control or mitigation for risks; including “stopping the job” altogether.

Eliminating Accidents Starts with You (EASY) Observations

Eliminating Accidents Starts with You (EASY) is a peer-to-peer program which is intended to empower the workforce to recognize positive, and at-risk, behaviors with the authority to stop work. Employees and contractors on BPXP-owned facilities and drilling rigs, observe personnel performing work activities, identify at-risk behaviors, and then intervene or stop work, to discuss safe solutions for the task at hand. Behavior

Based Safety

Safety Observation Conversations (SOC)

The Safety Observation Conversations (SOC) is a program used by site leaders and safety professionals on offshore, BPXP-owned facilities and contracted drilling rigs. The SOC leader observes work activities and holds conversations with workers to test their understanding of the safety procedures, risk assessments, and controls pertinent to the job at hand. During the SOC, the leader may intervene or stop work if deficiencies are noted.

Control of Work (CoW)

On oil and gas facilities, where multiple tasks are performed simultaneously, the management of work is essential to ensure that these tasks are accomplished safely. CoW procedures establish a formal approach for personnel to effectively and systematically manage and reduce risk to which workers are exposed. During these operations, personnel have the opportunity to intervene or stop work.

Standard Operating

Procedures

Go/No-Go Process The Go/No-Go process is a final check, prior to certain operations starting, to confirm that all requirements of a safe start-up have been met.



Contractor Selection and Retention

Prior to beginning work, the Contractor’s operating management system for health, safety, and the environment (HSE) is assessed to ensure it is consistent with, or exceeds, BPXP’s requirements. Contractor HSE performance is evaluated on an on-going basis and interventions made if gaps are found or performance deteriorates.

Contractual Expectations

Contractor Bridging Documents

Contractor Bridging documents are used to compare BPXP and Contractor health, safety, and environmental (HSE) work practices, and define the hierarchy of procedures for use. As part of this process, if the Contractor’s Stop Work Authority program does not meet the intent of BP’s Stop Work Authority program, additional requirements are documented.

Competency Assessments of Wellsite Leaders

Wellsite Leaders who are responsible for the oversight of drilling operations are assessed on their skills and competence for recognizing, evaluating, responding, and remediating, well control events. If an individual does not meet the requirements, corrective action is taken to mitigate the risk identified in the assessment.


BPXP Plea Agreement

2017

Annual Progress Report Third Party Auditor (Paragraphs 26-31)


Third Party Auditor

As part of the BPXP Remedial Order, Paragraphs 26 through 31 require BPXP to hire an independent Third Party Auditor to report to BPXP, the Department of Justice (DOJ) and the Probation Officer every year on BPXP’s compliance with Paragraphs 5 through 25 of the Remedial Order. The Annual Audit Report is due to the DOJ, Probation Officer, and BPXP on or before August 31 each year during the term of the Plea Agreement.


After following a tender and selection process, Grant Thornton LLP (Grant Thornton) was approved by the DOJ in December 2013. Early in 2014, Grant Thornton was contracted by BPXP as the Third Party Auditor. Grant Thornton has since produced four Reports.

In April 2017, Grant Thornton began their formal review process of BPXP’s 2016 compliance activities with Paragraphs 5 through 25 of the Remedial Order. Grant Thornton performed 170 independent inquiry and inspection procedures as part of their compliance audit and BPXP was found to have satisfactorily completed each requirement.

Grant Thornton stated in their report for the 2016 calendar year that:

“This report represents our fourth report since having been engaged. In all four reports, we have concluded that BPXP was in Compliance with paragraphs 5 through 25 of the Plea Agreement and Implementation Plan. Repeated

Compliance is an indicator that Company policies and procedures in these areas are being remediated and sustained.”

There were no instances of non-compliance identified by Grant Thornton in their July 19, 2017, report for the 2016 calendar year.

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