exon mobile drilling guide

Drilling STANDARD OPERATIONS MANUAL

for

JACK-UP / PLATFORM / BARGE DRILLING

First EditionMay 2003

FOR COMPANY USE ONLY

Houston, Texas U.S.A.

Development

Development

ExxonMobilDevelopment CompanyP.O. Box 4876Houston, TX 77210-4876

An ExxonMobil Subsidiary

May 2003

EMDC Drilling Standard Operations Manual for Jack-Up/Platform/Barge Drilling

To: ExxonMobil Drilling Employees

The enclosed manual is the First Edition of our EMDC Drilling Standard Operations Manual forJack-Up/Platform/Barge Drilling. This manual replaces the Transition Version 1 manual datedOctober 1999. Many changes and upgrades have been made to this manual based oncomments from the Drill Teams and Drilling Support Groups. The preface of the manualdescribes how the manual will be used in our operations. In short, the manual:

1) provides guidelines for conducting drilling operations using jack-up, platform and bargerigs,

2) is used in conjunction with specific well programs and other procedural manuals,including OIMS and SMP, to provide the basic framework and principles required forplanning and conducting drilling operations, and

3) shall be reviewed and understood by all drilling personnel.

Important to note is that significant changes (any change that increases health, safety,public, environmental or financial risk) from the manual need the consent of the OperationsSuperintendent and/or Field Drilling Manager. Also, the guidelines in the manual must beappropriately interfaced with those established by the Drilling Contractor and conflictsaddressed by the Operations Superintendent.

Special appendices are included in each section of the manual for drill teams to customize themanual for their operating area. The tabs for these appendices are labeled “G” for generalinformation and forms/documents that are used company wide and “S” for specific informationand forms/documents that are unique to individual drill teams.

We appreciate the time and effort by the Drill Teams and Drilling Support Groups in reviewingand commenting on the draft manual. Over 150 comments were received with about 90%adopted in the new manual. The remaining comments referred to requests to include localpractices, sections in the draft manual that were removed, general comments with nosuggested changes, items not applicable to this manual, and a very few number of items notagreed to. In order to close the loop, Drill Teams that suggested changes not agreed to willreceive feedback.

This manual will be revised and upgraded in accordance with the revision process in theOIMS manual. In general, this process will involve review of comments received from the DrillTeams, annual review of MOCs, and reviews at periodic intervals.

Please take the time to review this manual and understand the guidelines contained within.

Signature on file Signature on file Signature on file____ D. R. Anglin J. W. Kiker C. W. Sandlin Operations Manager Operations Manager Operations Manager

PREFACE

DRILLING OPERATIONS MANUAL – JACK-UP/PLATFORM/BARGE RIG DRILLING 1 of 1First Edition - May, 2003

The ExxonMobil Development Company, Standard Operations Manual for Jack-Up/Platform/BargeDrilling has been prepared to provide guidelines for conducting drilling operations using jack-up, platformand barge rigs in ExxonMobil Drilling's realm of activities.

This manual, used in conjunction with well-specific Drilling and Completion Programs and other proceduralmanuals, including the Drilling OIMS Manual and the Safety Management Program Manual, will providethe basic framework and principles required for the Operations Supervisors and Drilling Engineers forplanning and conducting drilling operations. Because of the numerous possible variables and conditionswhich can occur, this manual cannot replace the knowledge and good judgment of key drilling personnel onthe drilling rig or in the office. The guidelines contained within this manual are the logical sequence of stepsnecessary to efficiently conduct drilling operations in a safe and environmentally sound manner on a globalscale while complying with applicable regulatory requirements. Although many of the references to U.S.laws and regulations were removed from the previous version due to the global intent of this manual, someremain as examples and may be valuable for international operations.

The guidelines contained herein shall be reviewed and understood by all involved drilling personnel. Inaccordance with the OIMS "Management of Change" element, significant changes (any change thatincreases health, safety, public, environmental or financial risk) from these guidelines are not to beundertaken without the express consent of the Operations Superintendent and/or Field Drilling Manager.

The guidelines contained in this manual shall also be appropriately interfaced with those established by theDrilling Contractor and contained in the Drilling Contractor's operations manuals. Identified proceduralconflicts shall be addressed by the Operations Superintendent and any resulting resolutions shall beprovided to the Operations Supervisors.

Special appendices are included in each section of the manual for drill teams to customize the manual fortheir operating area. The tabs for these appendices are labeled “G” for general information andforms/documents that are used company wide and “S” for specific information and forms/documents thatare unique to individual drill teams.

The manual shall be kept current by including recommended improvements/changes in accordance with thechange process described in the EMDC Drilling OIMS Manual. In general, this process will involve reviewof comments received from the Drill Teams, annual review of MOCs, and reviews at periodic intervals.This process is critical in keeping Drilling abreast of new ideas, advancing technology and regulatorychanges.

This manual was prepared in an attempt to combine the best practices of our drill teams into one manual.Although it does contain a good bit of information from multiple sources, it does not contain all theinformation needed to drill and complete drill wells in all situations. Good sound judgement should alwaysbe exercised in any task and should never be discarded just to follow an outlined step in any process orprocedure

We, the Management and Employees of ExxonMobil Development Company:

• Will relentlessly pursue our ultimate objective of an injury and illness freework place

• Will not compromise our focus on safety in order to achieve any other businessobjective

And We Believe:

• Our safety actions are most effective when we genuinely care about each other

• Each of us has a personal responsibility for our own safety and the safety ofothers -- both on and off the job

• All injuries and illnesses can be avoided when we practice safe behaviors

SAFETY CREDO

STANDARD OPERATIONS MANUALJACK-UP/PLATFORM/BARGE RIG DRILLING

TABLE OF CONTENTS

DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 1 of 5First Edition - May, 2003

1.0 GENERAL INFORMATION1.1 Drilling Operations Manual 11.2 Organization 21.3 EMDC Reports 31.4 Drilling Contractor Reports 61.5 Third Party Service Contractor Reports 9

2.0 GENERAL OPERATIONS2.1 Contracts Administration 12.2 Prespud Meeting 22.3 Security 32.4 EMDC Drilling Operations Personnel Responsibilities 32.5 Drilling Contractor Personnel Responsibilities 82.6 Third Party Service Contractor Personnel Responsibilities 92.7 Special Operations Precautions 142.7.1 Helicopter Operations 142.7.2 Mooring Vessel Operations 142.7.3 Casing pressure Monitoring 142.7.4 Back Pressure Valves 142.7.5 Rotary Table Insert Bushing Locks 142.7.6 Christmas Tree Equipment 142.7.7 Mud Logging Units 15

Appendix G-I EMDC-DO Risk Assessment FormAppendix G-II Risk Assessment Package (example)Appendix G-III EMDC-DO BOPE Exception FormAppendix G-IV Drilling Environmental Performance Indicators Report Form

3.0 MARINE OPERATIONS3.1 Site Survey / Bottom Sweep / SIMOPs review 13.2 Moving 23.2.1 Moving Jack-up Rigs 23.2.2 Moving Platform Rigs 43.2.3 Moving Barge Rigs 53.3 Moving And Positioning 63.4 Pre-Loading (Jack-up Only) 73.5 Cargo Transfers 83.5.1 Precautions 93.5.2 Weather Limits 93.5.3 Heavy Lifts (Jack-Up Lifts in Excess of 10 MT) 93.5.4 Lifting Operations 103.5.5 Rigging Guidelines 113.5.6 Equipment Maintenance 153.6 Transportation & Personnel Transfers 203.6.1 Cargo Transport 203.6.2 Helicopter Operations 213.6.3 Personnel Transport-Helicopter 22


TABLE OF CONTENTS


3.6.4 Personnel Transport-Supply or Stand-By Boat 243.7 Marine Training 24

3.7.1 General 243.7.2 Reporting & Drill Frequency 253.7.3 Marine Drill Process 263.7.4 Fire Drills 273.7.5 Fire Drill-Example 293.7.6 Abandon Rig Drills 303.7.7 Abandon Rig Drill-Example 333.7.8 Man Overboard Drill 343.7.9 Specialized Drills 353.7.10 Principal Aspects of Drills 37

3.8 Ship Collision Avoidance 373.8.1 Detection 383.8.2 Radar Watch Procedures 38

Appendix G-I SIMOPs Checklist MemoAppendix G-II SIMOPs Deviation FormAppendix G-III Study of Pile Interaction with Jack-Up Rig OperationsAppendix G-IV Pre-Startup Inspections for New to Fleet Jackup Drilling Rigs

4.0 DRILLING OPERATION 4.1 Introduction 14.2 General Operations Guidelines 14.3 Pre-Spud Operations 34.4 Structural Drive Pipe 44.5 Conductor and Surface Casing Interval 54.6 Diverter Operations 64.7 Intermediate / Protective Casing Interval 64.8 Production Casing / Liner Interval 74.9 Slot Recovery / Whipstock / Section Mill / Cutt & Pull 74.10 Wellbore Anti-Collision Guidelines 9

4.10.1 Requirements for "Collision Risk" Wells 94.10.2 Requirements for All Directional Wells 10

4.11 Directional Surveying and Deviation Control 114.12 Drill String Design 124.13 Bottom Hole Assemblies 144.14 Hydrogen Sulfide Considerations 174.15 Hydrogen Sulfide Contingency Plan 19

5.0 BIT CLASSIFICATION AND HYDRAULICS5.1 General 15.2 Drill Bits 15.3 IADC Bit Classification System 35.4 IADC Bit Grading System 65.5 Running Procedures for Fixed Cutters 85.6 Hydraulics Program 105.7 Guidelines for Hydraulics Optimization 125.8 Hydraulics Optimization 175.9 Reference Material 18


TABLE OF CONTENTS


6.0 DRILLING FLUID SYSTEM6.1 General 16.2 Solids Control 16.3 Drilling Fluid Treatments 36.4 Drilling Fluid Checks 56.5 High Temperature Drilling 66.6 Stuck Pipe Pills 66.7 Lost Circulation 76.8 Non-Aqueous Fluid Operations 156.9 Rig-Site Dielectric Constant Measurement 336.10 Drilling Fluid System Guidelines 34

Appendix G-I Fluid Transfer ChecklistsAppendix G-II NAF/Oil Base Mud Readiness Checklist

7.0 ABNORMAL PRESSURE DETECTION IN CLASTICS7.1 Background 17.2 Pressure Indicators While Drilling 27.3 Abnormal Pressure Detection Team Responsibilities 107.4 Mud Logging 117.5 Operational Guidelines 15

8.0 FORMATION EVALUATION8.1 General 18.2 Conventional Coring 18.3 Wireline Logging Program 88.4 Sidewall Coring Operations 118.5 Wireline Radioactive Sources 128.6 MWD/LWD Logging 128.7 Mud Logging and Cuttings Samples 14

9.0 CASING OPERATIONS9.1 Casing Running 19.2 Casing Connection Make-Up 59.3 Casing Checklist 5

10.0 CEMENTING10.1 General 110.2 Cementing Guidelines 110.3 Primary Cementing 310.4 Remedial Cementing 510.5 Cementing Checklist 610.6 Reference 7

Appendix G-I Exxonmobil Cement Testing Guidelines

11.0 PRESSURE INTEGRITY TESTS11.1 General 111.2 Casing Test 211.3 Leak-Off Test 311.4 Jug Test (Limited PIT) 4


TABLE OF CONTENTS


12.0 PRODUCTION TESTING12.1 Production Testing Objectives 112.2 Well Test Design 112.3 Test String 312.4 Surface Equipment 412.5 Measurement Equipment 412.6 Safety 512.7 Personnel Responsibilities 612.8 Pre-test Planning and Preparation 912.9 Information Retrieval 1012.10 Well Killing and Zone Abandonment 1112.11 Emergency Procedures 1112.12 Hydrogen Sulfide 1112.13 Hydrates 12

13.0 PLUG AND ABANDONMENT13.1 General 113.2 Permanent Plug and Abandonment 113.3 Temporary Plug and Abandonment 413.4 Site Clearance Verificationa 4

14.0 WELL CONTROL14.1 Well Control – General 114.2 Hole Monitoring 514.3 Equipment Testing 814.4 Equipment Specifications 1014.5 Well Control Drills 1614.6 Well Control Procedures 19


TABLE OF CONTENTS


1.0 GENERAL INFORMATION1.1 Drilling Operations Manual 11.2 Organization 21.3 EMDC Reports 31.4 Drilling Contractor Reports 61.5 Third Party Service Contractor Reports 9

2.0 GENERAL OPERATIONS2.1 Contracts Administration 12.2 Prespud Meeting 22.3 Security 32.4 EMDC Drilling Operations Personnel Responsibilities 32.5 Drilling Contractor Personnel Responsibilities 82.6 Third Party Service Contractor Personnel Responsibilities 92.7 Special Operations Precautions 142.7.1 Helicopter Operations 142.7.2 Mooring Vessel Operations 142.7.3 Casing pressure Monitoring 142.7.4 Back Pressure Valves 142.7.5 Rotary Table Insert Bushing Locks 142.7.6 Christmas Tree Equipment 142.7.7 Mud Logging Units 15


3.0 MARINE OPERATIONS3.1 Site Survey / Bottom Sweep / SIMOPs review 13.2 Moving 23.2.1 Moving Jack-up Rigs 23.2.2 Moving Platform Rigs 43.2.3 Moving Barge Rigs 53.3 Moving And Positioning 63.4 Pre-Loading (Jack-up Only) 73.5 Cargo Transfers 83.5.1 Precautions 93.5.2 Weather Limits 93.5.3 Heavy Lifts (Jack-Up Lifts in Excess of 10 MT) 93.5.4 Lifting Operations 103.5.5 Rigging Guidelines 113.5.6 Equipment Maintenance 153.6 Transportation & Personnel Transfers 203.6.1 Cargo Transport 203.6.2 Helicopter Operations 213.6.3 Personnel Transport-Helicopter 22


TABLE OF CONTENTS


3.6.4 Personnel Transport-Supply or Stand-By Boat 243.7 Marine Training 24

3.7.1 General 243.7.2 Reporting & Drill Frequency 253.7.3 Marine Drill Process 263.7.4 Fire Drills 273.7.5 Fire Drill-Example 293.7.6 Abandon Rig Drills 303.7.7 Abandon Rig Drill-Example 333.7.8 Man Overboard Drill 343.7.9 Specialized Drills 353.7.10 Principal Aspects of Drills 37



4.0 DRILLING OPERATION 4.1 Introduction 14.2 General Operations Guidelines 14.3 Pre-Spud Operations 34.4 Structural Drive Pipe 44.5 Conductor and Surface Casing Interval 54.6 Diverter Operations 64.7 Intermediate / Protective Casing Interval 64.8 Production Casing / Liner Interval 74.9 Slot Recovery / Whipstock / Section Mill / Cutt & Pull 74.10 Wellbore Anti-Collision Guidelines 9

4.10.1 Requirements for "Collision Risk" Wells 94.10.2 Requirements for All Directional Wells 10

4.11 Directional Surveying and Deviation Control 114.12 Drill String Design 124.13 Bottom Hole Assemblies 144.14 Hydrogen Sulfide Considerations 174.15 Hydrogen Sulfide Contingency Plan 19

5.0 BIT CLASSIFICATION AND HYDRAULICS5.1 General 15.2 Drill Bits 15.3 IADC Bit Classification System 35.4 IADC Bit Grading System 65.5 Running Procedures for Fixed Cutters 85.6 Hydraulics Program 105.7 Guidelines for Hydraulics Optimization 125.8 Hydraulics Optimization 175.9 Reference Material 18


TABLE OF CONTENTS


6.0 DRILLING FLUID SYSTEM6.1 General 16.2 Solids Control 16.3 Drilling Fluid Treatments 36.4 Drilling Fluid Checks 56.5 High Temperature Drilling 66.6 Stuck Pipe Pills 66.7 Lost Circulation 76.8 Non-Aqueous Fluid Operations 156.9 Rig-Site Dielectric Constant Measurement 336.10 Drilling Fluid System Guidelines 34


7.0 ABNORMAL PRESSURE DETECTION IN CLASTICS7.1 Background 17.2 Pressure Indicators While Drilling 27.3 Abnormal Pressure Detection Team Responsibilities 107.4 Mud Logging 117.5 Operational Guidelines 15

8.0 FORMATION EVALUATION8.1 General 18.2 Conventional Coring 18.3 Wireline Logging Program 88.4 Sidewall Coring Operations 118.5 Wireline Radioactive Sources 128.6 MWD/LWD Logging 128.7 Mud Logging and Cuttings Samples 14

9.0 CASING OPERATIONS9.1 Casing Running 19.2 Casing Connection Make-Up 59.3 Casing Checklist 5

10.0 CEMENTING10.1 General 110.2 Cementing Guidelines 110.3 Primary Cementing 310.4 Remedial Cementing 510.5 Cementing Checklist 610.6 Reference 7

Appendix G-I Exxonmobil Cement Testing Guidelines

11.0 PRESSURE INTEGRITY TESTS11.1 General 111.2 Casing Test 211.3 Leak-Off Test 311.4 Jug Test (Limited PIT) 4


TABLE OF CONTENTS


12.0 PRODUCTION TESTING12.1 Production Testing Objectives 112.2 Well Test Design 112.3 Test String 312.4 Surface Equipment 412.5 Measurement Equipment 412.6 Safety 512.7 Personnel Responsibilities 612.8 Pre-test Planning and Preparation 912.9 Information Retrieval 1012.10 Well Killing and Zone Abandonment 1112.11 Emergency Procedures 1112.12 Hydrogen Sulfide 1112.13 Hydrates 12

13.0 PLUG AND ABANDONMENT13.1 General 113.2 Permanent Plug and Abandonment 113.3 Temporary Plug and Abandonment 413.4 Site Clearance Verificationa 4

14.0 WELL CONTROL14.1 Well Control – General 114.2 Hole Monitoring 514.3 Equipment Testing 814.4 Equipment Specifications 1014.5 Well Control Drills 1614.6 Well Control Procedures 19

GENERAL INFORMATION

______________________________________________________________________________DRILLING OPERATIONS MANUAL-JACK-UP/PLATFORM/BARAGE RIG DRILLINGFIRST EDITION-MAY 2003

1.0 GENERAL INFORMATION

1.1 Drilling Operations Manual 11.2 Organization 21.3 EMDC Reports 31.4 Drilling Contractor Reports 61.5 Third Party Service Contractor Reports 9

GENERAL INFORMATION


1.1 DRILLING OPERATIONS MANUAL

The EMDC Jack-Up/Platform/Barge Rig Drilling Standard Operations Manual is applicable to productionand exploration wells. The drilling guidelines, principles, and procedures contained in this manual representdrilling practices that ensure the Company's highest commitment to safety, health, and the environment.

Manual Organization

This manual is organized into sections covering critical aspects of Jack-Up/Platform/Barge Rig drilling.Each section is divided into subsections, which address the relevant aspects of each section topic. In eachsection, one subsection is devoted to operations specific Drill Team operations. Appendices thatapply to general drilling operations regardless of area of operation are denoted by a "G" beforethe appendix number. Appendices relating to a specific drill team are denoted by an "S" prefixbefore the appendix number.

Where applicable, this manual will reference other company and industry documents that contain additionalinformation to supplement the guidelines contained here-in.

This manual will present drilling practices common to numerous drilling operations, irrespective of rig type.

GENERAL INFORMATION


1.2 ORGANIZATION

EMDC - Drilling Organization

EMDC Drilling is responsible for ExxonMobil's world-wide production and exploration drilling activities.The Drilling Organization is responsible for the contracting of services and materials suppliers, the planningand preparation of drilling engineering work, and the direct supervision of drilling operations. The DrillingOrganization shall prepare guidelines and procedures, as necessary, so that operations are conducted in asafe and environmentally sound manner. These responsibilities will be met by the following personnel:

• Manager, Drilling• Drilling Operations Manager• Procurement Manager• Drilling Technology Manager• Field Drilling Manager• Operations Superintendent• Engineering Manager• Operations Supervisor• Supervising Engineer• Drilling Engineer• Drilling Materials & Services Supervisor• Procurement Services Advisor• SHE Manager, Drilling• Environmental Coordinator, Drilling

Drilling Contractor and Other Critical Third Party Service Contractors

The Drilling Contractor is an independent contractor who will execute the drilling program to thesatisfaction of the Operations Supervisor on location. The drilling contractor is also responsible foroperating and maintaining the drilling rig in safe working condition and in full compliance with EMDCtechnical specifications and local regulatory requirements, including those requirements as specified in thedrilling contract.

Other critical third party service contractors are independent contractors that will assist in executing thedrilling program. These contractors are responsible for operating and maintaining their equipment in fullcompliance with EMDC technical specifications and/or contract requirements, and local regulatoryrequirements.

The drilling contractor and other critical third party service contractors provide services where inadequateperformance could result in a Level 1, 2, or 3 incident (OIMS Element 9). These contractors must meetor exceed EMDC requirements in the area for which the contract is issued. This includes the following:

• Safety, Health, and Environmental Policy Statement• Drug and Alcohol Policy• Contractor Safety Program

GENERAL INFORMATION


• Technical Equipment Documentation• Work Permit System• Hazardous Material Handling/Storage Procedures• Procedure to Control Equipment/Safety Policy Changes

Service Companies/Third Party Services

Service companies/third party service contractors are independent contractors who will assist in executingthe drilling program to the satisfaction of the Operations Supervisor on the drilling rig. These contractorsare also responsible for operating and maintaining their equipment in full compliance with EMDC technicalspecifications and local regulatory requirements, including those as specified in the various contracts.

1.3 EMDC- DRILLING REPORTS

Critical drilling operations information and relevant aspects of the daily drilling activities will be documentedin the standard reports developed by EMDC and its contractors. This manual describes the preparationand distribution of these reports.

Daily Drilling Report

The Operations Supervisor will record drilling activities on the DRS and transmit it, usually via the LAN ortelephone line (modem), to the Drilling Information Management Center (DIMC) each morning.

The Daily Drilling Report will cover a 24 hour period with the current day's drilling activities.

Minimizing drilling cost per foot and achieving an overall increase in the efficiency of a drilling operationrequires that Management, the Operations Superintendent, and Engineering receive accurate, factual,complete reports from the rig Operations Supervisor on a daily basis. Effective management control of thedrilling operation cannot be effected without input from the entire drilling organization, and the daily drillingreport is the base document from which most information is drawn. The following are guidelines on someaspects of the Daily Drilling Report:

• Drilling operation events should be time separated to correspond with EMDC rig-time distribution codes(not IADC). The DRS manual contains a guide on the coding of operations.

• Depth of the well is determined by steel line measurement of the drill string.• There should be reasonable agreement between the DDR and the IADC report.• A better report will result if each Operations Supervisor writes the operations summary for his/her tour.• Do not report opinions or guesses unless they are so identified. If an opinion is reported as fact, the rig

supervisor will know this, but the office staff may not.• Use only standard abbreviations. Do not make up abbreviations.• Electric logging: specify logs run, depth interval logged, bottom hole temperature, and tight hole depth.• Circulation: specify why the mud is being circulated, and circulation rate/ pipe rotation if any.

GENERAL INFORMATION


Daily Cost Report

The Operations Supervisor should complete the DRS Daily Cost Report and transmit it to the DIMC eachmorning.

The Daily Cost Report should capture all substantial drilling costs including services utilized, rentalequipment, and consumed materials. Where exact costs are not known, reasonable estimates should bemade and included in the Daily Cost Report. Some contractor costs will not be known exactly until theend of a month. The rig should not attempt to estimate what the discounted charge will be; the rig is toenter the ticket charge on the cost screen. The Drilling Engineer is responsible for monitoring discountedmaterials and services costs and communicating any adjustments to the Operations Supervisor formodification of cost sheets.

It is the Drilling Engineer's responsibility to include the cost of all materials and services in appropriateprocedures for Operations Supervisor use in completing the Daily Cost Report. The Drilling Engineer isalso to provide initial fixed costs to Operations Supervisor and to check the entries for errors or omissions.

ATF Bomb Threat Checklist

Operations Supervisors need to be prepared to respond effectively should they receive a bomb threat overthe telephone. It is very important to take the caller seriously. Ask the person to repeat the message.Record every word spoken by the person. Complete the bomb threat checklist and transmit to theOperations Superintendent. Reference OIMS manual (10-5) for further information.

Casing Tally Report

The Casing Tally Report should be prepared for every casing string run. A copy of the report will be kepton the drilling vessel for reference during logging, production testing, completion, plug and abandonmentoperations, etc.

The Operations Supervisor is responsible for completing the casing run tally report and forwarding it to theDrilling Engineer after each casing string is run. While it is not necessary to transmit the off-load tally fromthe rig, it is necessary to create a DRS off-load tally to be able to complete the casing description part ofthe DRS "as run" tally. OIMS requires a DRS casing tally report where possible.

Environmental Performance Indicators (EPI) Report

At the end of every well, the Drilling Engineer and EMDC Domestic Regulatory Technician will completethe Environmental Performance Indicators (EPI) Report for inclusion in the Final Well Report. This formcontains four sections; Well Information, Emissions Data, Environmental Regulatory Compliance Data, andWaste Data.

Drilling Reporting System (DRS)

When the DRS system is in place, the following DRS reports will be maintained and transmitted from therig daily or when pertinent, 1) Daily Drilling Report, 2) Casing Report, 3) Cementing Report, 4) Lithology,

GENERAL INFORMATION


5) Logging Run, 6) Milestones, 7) Mud, 8) Mud Product Usage, 9) Perfs, 10) RFT, 11) Drillstring, 12)Weather, 13) Well Test, 14) Stratigrophy.

Equipment Failure Report

An equipment failure report will be prepared to document equipment failures which result in significanteconomic impact or failures which could have safety implications. The equipment failure report shouldadequately describe the nature of the failure, identify the cause of the failure, document the associateddowntime due to the failure, and recommend ways to prevent the failure from occurring in the future.

The Operations Supervisor is responsible for preparing the report and forwarding it to the OperationsSuperintendent. Engineering will review the report to determine if further analysis or action is required.

Hand-Over Notes

Hand-over notes will be prepared by the Operations Superintendents (when working on a rotationalschedule) and Operations Supervisors prior to their respective crew changes. The purpose of these notesis to document all situations and/or activities that will require follow-up by the relieving personnel, as well asto address significant operational events that took place during the hitch.

Material Transfer/Cargo Manifest

A material transfer/cargo manifest should be prepared for all material shipments to and from the drilling rig.Manifests should be prepared by the Base Manager/Materials Coordinator for all to-rig shipments and bythe drilling rig's storekeeper (if on contract) for all from-rig shipments.

The cargo manifest should list all materials transferred, giving quantity, description, weight, and thecontainer number in which it is stored.

Material transfers are prepared for EMDC material and will usually list the commodity number. Hazardousmaterial should be identified on the manifest. Under no circumstances should used casing thread protectorsbe sent to the United States in a container unless all thread compound is removed. There will be venturespecific materials procedures.

Once completed, the manifest should be signed by the originator and forwarded to the receiver of thegoods by the most expedient means (usually via fax). A copy of the manifest should be given to the captainof the transferring vessel. The Operations Supervisor should sign the manifest for the goods received at therig. Rental tools should be tracked, preferably in a rental tool log book or in a clipboard maintained on therig.

Pressure Integrity Test Record

Pressure Integrity Tests are covered in Section 11 of this manual. The pressure integrity test (PIT) formwill be prepared for all tests conducted. Additional information regarding PIT procedures and analysis iscontained in the EPRCo publication "Pressure Integrity Test - Field Guide".

GENERAL INFORMATION


The Operations Supervisor is responsible for completing the PIT form and forwarding it to the OperationsSuperintendent and Drilling Engineer as soon as practical after completing the test.

Safety Incident and Spill Reports

Refer to the Drilling Safety Management Program (SMP) and OIMS Manual for guidelines on incidentreporting.

A Reportable Safety Incident is defined by OIMS as being a Lost Time Incident, Restricted WorkIncident, or a Medical Treatment Incident.

An oil spill is any liquid hydrocarbon release greater than 1 barrel (or affiliate/regulatory required minimum)which falls onto water or onto the ground that could enter the ground water.

A copy of the report will be provided to the Operations Supervisor for forwarding to the OperationsSuperintendent.

Safety Meeting Record

The Operations Supervisor should record the issues addressed/discussed at the general safety meeting, aswell as the topics of the drill crew pre-tour safety meeting and any critical operations safety meeting inDIMS and the IADC report. The minutes of the general safety meeting can be hand written and do nothave to be duplicated on the DIMS report. Forward copies of the contractor's safety meeting minutes tothe Operation Superintendent.

Well Killing Worksheet

After the BOP stack is installed, the Well Killing Worksheet will be prepared in accordance with theguidelines specified in Section 14 of this manual. The worksheet will be maintained for the current wellboreconfiguration and updated at least daily (or as well conditions change) while drilling is in progress ormaintain the KIK PC program data up to date.

The Operations Supervisor is responsible for completing the worksheet. There are multiple acceptableformats including the traditional EPRCo form, Randy Smith form, EUSA form, and KIK PC program.

Other Reports

Additional reporting requirements should be followed/completed as detailed in the Drilling OIMS Manualand the Safety Management Program.

1.4 DRILLING CONTRACTOR REPORTS

BOP Test Record

The results of all BOP tests and any deficiencies should be recorded on the Daily Drilling Report andIADC Report. Detailed test data will also be recorded by the Drilling Contractor on a BOP test formdesigned specifically for the drilling rig. This report should include the information specified in Section 14 ofthis manual.

GENERAL INFORMATION


The completed BOP test form, signed by the test pump operator, tool pusher/OIM, and OperationSupervisor, will be provided to the Operation Supervisor. All pressure test charts will be dated, andproperly labeled as to each component tested in accordance with applicable EMDC and regulatoryrequirements. All records pertaining to the BOP tests should be retained on the drilling rig until completionof the well. The records should then be forwarded to the nearest production facility or host platform forretention in accordance with applicable regulatory requirements or forwarded to OperationsSuperintendent for inclusion in the well file (international exploration drilling operations).

Current Status Board

A current status board should be maintained at the driller's station. It should include the BOP ram elevationand other helpful information and regulatory mandated postings or documentation.

Daily Personnel Record

A listing of all personnel on the rig (POB list) and their positions will be scrupulously maintained by adesignated representative of the Drilling Contractor. The POB list will be updated and distributed daily.

A copy of the POB list will be provided to the Operations Supervisor at midnight. This list will be availableto be faxed to the Operations Superintendent when needed. A copy of the current POB list will bemaintained on the drilling rig.

Drilling Recorder Chart

The Drilling Contractor should annotate all major drilling activities (drilling, tripping, circulating, runningcasing, cementing, etc.) on the continuous recording strip chart which records depth, time, hookload, pumppressure, rotary torque, and weight-on-bit, as a minimum. The strip chart should also be annotated by theDrilling Contractor to note significant activities such as filling hole, flow check, connection, tight hole,mechanical problems, stuck pipe, etc.

A copy of the chart will be provided to the Operations Supervisor for forwarding to the OperationsSuperintendent when requested.

IADC Reports

The IADC Report will be prepared daily by the Drilling Contractor and signed by both the drillingcontractor's senior drilling representative and the Operations Supervisor. The IADC Report will detail theevents of each day's drilling activities, giving a time breakdown for each major event.

Events which are subject to different rig cost rates, as specified in the drilling contract, should be clearlyseparated. Significant events such as safety incidents, safety meetings, BOP tests, major equipment failures,etc. will be documented on the IADC Report. Drilling Contractor personnel should be identified by name,position and hours worked (including any overtime).

The Operations Supervisor will send the original (white) and pink copies to the Operations Superintendentweekly. The blue copy should be kept in the Operations Supervisors office onboard the drilling vessel.The green and white (last) copy will be left for the Drilling Contractor.

GENERAL INFORMATION


The Operation Superintendent will forward the original to the accounting department and retain the pinkcopy in the drilling office files.

Safety Incident Reports

Refer to the Drilling Safety Management Program for a description of reports required from thecontractors.

The Drilling Contractor will prepare an incident report for all lost time incidents, fatalities, restricted workincidents, medical treatment incidents, first aid treatments, regional illness events, near misses, andsignificant near misses onboard the drilling rig. The incident report will, as a minimum, describe the natureof the incident, list the names of all persons involved (both witnesses and victims), describe the contributingcircumstances, and identify remedial steps and recommendations to prevent further occurrences.

Safety Meeting Reports

The Drilling Contractor will prepare a report summarizing discussions held in the general safety meeting.The safety meeting report should, as a minimum, describe safety topics discussed, identify the status of anyoutstanding safety items and provide a list of all meeting attendees. A handwritten report is acceptable. Acopy of the report will be provided to the Operations Supervisor for forwarding to the OperationsSuperintendent.

Trip Book

The primary monitoring of the volume of mud added to the hole to replace the drill string displacement ontrips is the responsibility of the drilling crew. When full service mud logging is available, the mud loggersshall provide a backup trip book log. The trip tank will be used for all trips unless otherwise addressed bythe field drilling manager. The trip book must compare measured volume with theoretical volume as well asprevious trip volume. Refer to Section 14.

Well Control Readiness Checklist

At the Operations Supervisor's option, this checklist can be used as an aid in establishing rig floor crewwell control competency. This checklist is in Section 6 of the OIMS Manual and guidelines are in Section14 of this manual.

GENERAL INFORMATION


1.5 THIRD PARTY SERVICE CONTRACTOR REPORTS

Cementing Chart

A cementing recorder chart (pressure vs. time) will be prepared for all operations, such as casingcementing, equipment pressure testing, PITs, etc. The chart will be annotated with all significant eventssuch as pumping spacers, pumping lead and tail cements, bumping the plug, etc. (as required by localaffiliate and regulatory agencies).

The chart will be provided to the Operations Supervisor for forwarding to the Operations Superintendentand Drilling Engineer when requested or retained as required by local regulations.

Daily Drilling Fluids Report

The Drilling Fluids Engineer will prepare a Daily Drilling Fluids Report in accordance with the guidelinesspecified in Section 6 of this manual. Unless otherwise specified by the Operations Supervisor, a minimumof two complete "In" and "Out" checks of the drilling fluid should be made daily during drilling operations.

The report will be provided to the Operations Supervisor for forwarding to the Drilling Engineer eachmorning.

Directional Data

For directional wells, the Directional Drillers will prepare a bottom hole assembly sheet and BHA checklistfor all BHAs run in the well in accordance with the guidelines specified in Section 4 of this manual. Thedirectional driller will also maintain a wellbore trajectory record and current wellbore plot in the OperationsSupervisor's office.

The Directional Driller and Operations Supervisor should collaborate to complete and sign the directionaldrilling pre-job survey data sheet (PJSDS) and forward to the directional drillers coordinator as well as tothe Drilling Engineer. A pre-job checklist for directional wells should be used to verify that all operationalconcerns have been addressed. Both the above items are OIMS required documents. Anticollision/wellinterference calculation should be updated at each survey point and a minimum of two directionalcontractor representatives should be onboard when wellbore interference issues exist. Theminimum curvature calculation technique should be used.

A copy of the wellbore trajectory record will be provided to the Operations Supervisor for forwarding tothe Drilling Engineer each morning.

Mud Logger's Reports

The Mud Loggers will prepare a Mud Log and Daily Mud Logging Report in accordance with theabnormal pressure detection guidelines specified in Section 7 of this manual.

GENERAL INFORMATION


A copy of the log/report will be provided to the Operations Supervisor and wellsite geologist forforwarding to the Operations Superintendent and operations geologist each morning.

Pit Volume Totalizer Chart

A properly labeled and dated Pit Volume Totalizer (PVT) chart should be maintained by the companycontracted to provide same.

Radiation Safety Checklist, Well Site

Periodic assessment will be made of the adequacy of the safety programs of rig site contractors who useradioactive sources. Refer to the Drilling Safety Management Program and the OIMS checklists.

Vessel Daily Log

A Daily Log will be completed by all supply/standby vessels on contract and forwarded to the BaseManager/Materials Coordinator on a weekly (or other timely) basis.

GENERAL OPERATIONS

____________________________________________________________________________________________________________DRILLING OPERATIONS MANUAL - JACKUP/PLATFORM/BARAGE RIG DRILLINGFIRST EDITION - MAY 2003

2.0 GENERAL OPERATIONS

2.1 Contracts Administration 12.2 Prespud Meeting 22.3 Security 32.4 EMDC Drilling Operations Personnel Responsibilities 32.5 Drilling Contractor Personnel Responsibilities 82.6 Third Party Service Contractor Personnel Responsibilities 92.7 Special Operations Precautions 14

2.7.1 Helicopter Operations 142.7.2 Mooring Vessel Operations 142.7.3 Casing pressure Monitoring 142.7.4 Back Pressure Valves 142.7.5 Rotary Table Insert Bushing Locks 142.7.6 Christmas Tree Equipment 142.7.7 Mud Logging Units 15


GENERAL OPERATIONS


2.1 CONTRACTS ADMINISTRATION

After the execution of the various contracts between EMDC-Drilling and the individual contractors,the Operations Superintendent and Operations Supervisor will administer the contracts based on thefollowing responsibilities:

Operations Superintendent

1. Administer the contract terms and provisions between EMDC-Drilling and the Drilling Contractor andother critical and non-critical third party service contractor.

2. Copies of applicable contracts are maintained by the EMGSC procurement group for various drillingoperations.

3. Address questions from the Operations Supervisors regarding contract terms or exceptions.

Operations Supervisor

1. Become familiar with each contract as necessary to conduct drilling operations and abide by the termsof the contracts.

2. Ensure that all equipment on the Drilling Rig is in accordance with contract terms.

3. Ensure that a representative of each service company completes service tickets in accordance withthe contract terms.

4. Conduct a safety/operational ("prespud") meeting prior to the start-up of drilling operations with theappropriate management of the Drilling Contractor and other critical third party service contractors.Refer to Drilling Safety Management Program for meeting guidelines

5. Document safety meetings in the DRS and keep attendance list and presentation materials in the fieldwell file. Note any special problems addressed and/or discussed at these meetings in a memo to theOperations Superintendent.

Critical Service Contractor's Responsibilities

1. Have in place a safety and environmental program and discuss this with EMDC-Drilling Managementwhen requested.

2. Identify the disposal method/sites used for contractor waste. This is a contractual requirement of thirdparty contractors for US East Development Drilling Operations.

3. Provide personnel with adequate qualifications consistent with the qualifications in the Responsibilitysection (Section 2.4) and if applicable comply with 3rd party SSE policy and requirements.

GENERAL OPERATIONS


4. Have in place maintenance programs, inspection programs, internal control programs, etc., andreview these with EMDC-Drilling Management as requested.

5. It is desirable to have acceptance inspection checklist for the following third party services: mudlogging, production testing equipment, waste transportation, storage, disposal, self-containedbreathing equipment, cementing unit, wireline logging, perforating, and LWD with radioactive source.

2.2 PRE-SPUD MEETING

A pre-spud meeting will be held prior to the start of drilling operations on each drilling campaign.Key personnel (Operations, Engineering, Geology, Drilling Contractor, Third Party Contractors, etc.)should attend this meeting. During the meeting, the following points should be addressed:

1. Safety, health, and environmental policies.

2. Expectations in the following areas:

• Safety• Job Planning• Communications• Regulatory Compliance• Emergency Procedures and Contingency Plans• Security of well data

3. Ensure that contractors clearly understand their responsibility for transportation and disposal ofcontractor waste.

4. Ensure that both EMDC-Drilling and contractor's personnel clearly understand the chain of commandand the personnel responsible for various decisions.

5. Discuss well drilling plans including relevant geology and drilling hazards.

6. Communicate results of the risk assessment.

7. Copies of the Drilling Program should be furnished to the Drilling Contractor and third partycontractor personnel at the pre-spud meeting, as required.

8. Operations Integrity Management Systems, especially Management of Change.

9. Drilling Safety Management Program

10. Non proprietary pre-spud meeting materials can be circulated to all personnel for their reference.

2.3 SECURITY

GENERAL OPERATIONS


All personnel (EMDC-Drilling and contractors) must obtain, maintain, and retain well data, especiallyinformation relating to depths, operational problems, and formation evaluation according to their jobrequirements and release such information to others on a strictly "need-to-know" basis. All personnelwill be reminded of the proprietary nature of the geological and critical well data.

2.4 EMDC DRILLING OPERATIONS PERSONNEL RESPONSIBILITIES

Operations Superintendent Responsibilities

1. Communications:

• Provide communications, as necessary, between the Operations Supervisor on the Drilling Rigand EMDC-Drilling Management.

• Keep Field Drilling Manager and other off-site personnel informed of all aspects of the operation.• Interface daily with Production Management to ensure operational continuity.• Attend daily coordination meeting with Production Supervisor on manned platforms

2. Supervise Operation:

• Ensure that all operations are in compliance with OIMS, Drilling Safety Management Program,Drilling Operations Manual, and approved Drilling, Completion, and Production Testing Programsand Procedures.

• Confer with Geological Personnel to ensure maximum data acquisition at minimum time and cost.• Communicate with accounting group and EMDC-DFS group to ensure proper documentation and

validity of charges.• Work with Engineering staff to compile manuals, programs, and procedures.• Assist the Operations Supervisors with daily decisions necessary to help the Drilling Contractor

implement the approved Drilling, Completion, and Production Testing Programs and Procedures.• Conduct audits, inspections, and safety programs in accordance with OIMS and the Drilling Safety

Management Program.• Coordinate materials requests and logistics with Materials Group and/or Production Organization

to facilitate timely arrival of required supplies.• Advise Field Drilling Manager when to initiate rotation of Operations Supervisor to ensure sufficient

lead time for full implementation of OIMS.• Attend rig site safety meetings and pre-tour safety meetings.• Attend daily coordination meeting with Production Supervisor on manned platforms.

3. Local Coordination of Manuals, Programs and Procedures:

• Communicate requests from the Operations Supervisor to make exception(s) to certain guidelinesor procedures in the Drilling Operations Manual.

GENERAL OPERATIONS


• Request verbal approval from the Field Drilling Manager for exception(s) to certain guidelines orprocedures in accordance with the Management of Change Process described in OIMS.

Note: Using good judgement, Operations Superintendent may take exception to aguideline or procedure worded with "should" and "ought" without prior approval.

• Solicit change(s) to the Drilling Operations Manual from the Operations Supervisors according tothe change process described in this manual.

• Review and approve procedures as necessary to implement the approved Drilling, Completion,and Production Testing Programs and Procedures.

• Ensure that Operations Supervisors receive drilling procedures in a timely manner.• Notify the Field Drilling Manager, as soon as practical, of exception(s) made to guidelines or

procedures of the Drilling Program or Drilling Operations Manual.

Note: All requirements worded with "will", "shall", or "must", will be approved by the Field Drilling Manager prior to the exception.

• Ensure that all safety and operating manuals are available at the rig site.• Review and approve operations safety plan.

4. Compliance with ExxonMobil and Government Regulations:

• Become familiar with applicable laws and regulations, and ensure compliance.• Ensure that all applicable regulatory permits are on the Drilling Rig to conduct operations.• Ensure that required reports (as identified in approved Drilling, Completion, and Production

Testing Programs and Procedures) and/or operations permits are sent to applicable regulatorybodies.

• Request any regulatory exceptions either from the necessary regulatory agency or the appropriateregulatory contact within ExxonMobil.

• Report incidents of non-compliance.• Maintain current knowledge of authority guides.

5. Contractor Supervision:

• Steward contractors and suppliers to maximize cost-effectiveness and safety.• Coordinate contractors and suppliers to ensure timely arrival of equipment, supplies and

personnel.• Ensure contractor compliance with all contract terms.• Monitor contractor compliance with safety, environmental, and drug and alcohol policies stated in

contract.

Operations Supervisor Responsibilities

GENERAL OPERATIONS


1. Supervise Operations at Drill Site:

• Ensure the Drilling Program is executed by contract personnel in a safe and efficient manner.• Work with Engineering Staff to ensure technical goals are operationally feasible. Make

recommendations for changes to Drilling, Completion, and Production Testing Programs andProcedures to increase safety and/or efficiency.

• Work with Drilling Contractor to develop procedures and plans to implement Drilling Program.• Review daily plans of the Drilling Contractor and coordinate the activities of Third Party Contract

Personnel (i.e. Service Companies) to implement approved Drilling, Completion, and ProductionTesting Programs and Procedures.

• Ensure compliance of Drilling Contractor and Third Party Contractors with terms of appropriatecontracts. Ensure that all parties understand their responsibilities per this Manual.

• Communicate materials requirements to Operations Superintendent and follow up on delivery;assist in logistics as necessary. Coordinate transportation of equipment and personnel to and fromthe drilling rig as necessary.

• Ensure Contractors are maintaining the required equipment and conducting efficient operations in asafe and environmentally sound manner.

2. Ensure Compliance with OIMS and the Drilling Safety Management Program

• Communicate ExxonMobil requirements and expectations regarding safety and performance to allrig site personnel.

• Assist Drilling Contractor with implementing the Safety Program in accordance with the DrillingSafety Management Program.

• Ensure that equipment and procedures meet OIMS guidelines.• Recommend change(s) to OIMS or the Drilling Operations Manual as necessary to improve or

correct certain operations.• Notify the Operations Superintendent, of exception(s) that need to be made to certain guidelines

or procedures of the Drilling Operations Manual. Once proper approval is granted, document theexceptions on DIMS and maintain a record of all significant changes on the rig.

• Monitor daily operations to ensure Regulatory compliance. Report any incidents of non-compliance.

• Ensure that all required reports and records are accurate and complete and issued in a timelymanner.

Drilling Engineer Responsibilities

1. Ensure the Application of the Best Available Technology in Drilling Operations:

• Prepare the Site Construction Plan considering surface constraints such as local population,logistics, environmental impact, archaeological surveys, bottom sweeps, and rig positioning.

GENERAL OPERATIONS


• Prepare the Drilling, Completion, and Production Testing Programs and Procedures based on allavailable geologic and drilling information from nearby offset wells in the area. This Drilling andEvaluation Program shall include the best available technology for drilling operations.

• Be knowledgeable of the operating and construction characteristics of all components in thedrilling system to be used and be knowledgeable about alternative systems and procedures thatmight be implemented to improve operational efficiency. Ensure operations staff understands thefundamentals behind successfully implementing the new technology.

2. Prepare Standards and Procedures:

• Prepare a site specific Emergency Response/SIMOPS (if applicable) attachment for theOperations Manual

• Prepare the Drill Well Data Package to meet Regulatory requirements.• Ensure that all Standards and Procedures are in compliance with OIMS.• Prepare Operations Safety Plan in accordance with Safety Management Program

3. Coordinate a Risk Assessment for all drillwells:

• Organize meetings with the Operations Supervisor, Operations Superintendent, Field DrillingManager, Production personnel, Third Party Contractors, and others (as required) to assess andmitigate the particular hazards associated with the planned operations.

• During the course of the Risk Assessment process, the Drilling Engineer is to ensure that the RiskAssessment Form /Action Status Report (Section 2 – G-I) is completed and routed forendorsement.

• EMDC-DO has compiled a list of base case failure event scenarios that are common to most ofour activities. This list should be reviewed during the Risk Assessment and if any additional riskscenarios are identified, these should be documented using the format supplied and routed forendorsement with the RAF. A cover memo is used to concisely communicate the results of theRisk Assessment. An example Risk Assessment package has been included in Section 2 –Appendix G-II. The base case risk scenarios can be referenced in the OIMS manual.

• An additional requirement is the assessment of the rig's BOPs to determine compliance with theSurface Blowout Prevention And Well Control Equipment Manual. The Blowout PreventerEquipment Exception form (Section 2 – Appendix G-III) is to be completed and routed with theRAF. Any requested exceptions regarding the rig's BOP configuration will be approved throughendorsement of this form.

• All follow-up items will be documented in the Risk Assessment package.

4. Provide Engineering Support:

• Provide surveillance of day-to-day drilling progress to ensure that the Drilling and Evaluationprogram is conducted to apply the best available technology and propose modifications, asnecessary.

GENERAL OPERATIONS


• Evaluate and recommend materials and equipment.• Analyze drilling performance at intermediate well depths and work with the Operations

Superintendent and Operations Supervisor to implement changes in procedures and equipmentbased on the results of this analysis.

• Develop and write supplemental procedures for all major drilling and completion operations. Ifapplicable use the Standard or Core Procedure templates found in this Operations Manual.

• Prepare cost estimates for the selection of optimum procedural alternatives and equipmentmodifications.

• Counsel the Operations Superintendent and Operations Supervisor on critical activities andproblems such as equipment failures, mud and hole problems (including tectonics and wellborestability), etc.

• Provide rig site technical assistance in abnormal pressure detection, running and cementing criticalcasing strings/liners, production testing operations, and well control.

• Monitor well costs and ensure that all costs are kept up to date and accurate (including DRS).• Review DRS Report and ensure that input data are accurate and complete (coding, etc.).• Participate in wellsite incident investigations, as required in SMP.• Perform bid preparations and analysis in conjunction with the EMDC Procurement Group.• Keep the Supervising Engineer / Engineering Manager informed of all activities.• Prepare AFEs and Supplements.• Complete a Final Well Report package at the conclusion of each well. Generally, this will include:

• Final well cost summary sheet• EPI form• Final Well Report form• Production Casing and Tubing Tallies

• Acquire technical support from Drilling Technical and/or URC as necessary.

GENERAL OPERATIONS


2.5 DRILLING CONTRACTOR PERSONNEL RESPONSIBILITIES

Drilling Contractor Responsibilities:

Refer to the Safety Management Program for a listing of additional responsibilities

1. Operate as an independent contractor and execute the Drilling Program to the satisfaction of theOperations Supervisor on the Drilling Rig.

2. Operate and maintain the Drilling Rig in a safe working condition and in full compliance with EMDC-Drilling technical specifications and local regulatory requirements, including those requirements asspecified in the drilling contract.

3. Develop and use safe working procedures. Ensure that the following programs and/or systems are inplace and functioning properly (Drilling OIMS Manual Element 8, Section E and Safety ManagementProgram):

• Safety Program• Quality Assurance/Quality Control Program• Emergency Preparedness Program• Preventative Maintenance Program• Risk Assessment Program• Work Permit System• Appropriate Affiliate Simultaneous Operations (SIMOPs) program for development drilling

operations adjacent to production facilities.• SSE program if applicable

4. Provide qualified personnel that can efficiently operate the Drilling Rig in a safe and environmentallysound manner.

Offshore Installation Manager (OIM) Representative

1. Represent the Drilling Contractor as the person in charge and responsible for the overall operationand safety of the Drilling Unit and personnel.

2. Ensure that the rig operation meets all applicable regulatory requirements.

3. Implement the Drilling Contractor Safety Program

4. Ensure that all safety equipment is in proper working condition.

5. Secure necessary training for Drilling Contractor personnel.

6. Plan and supervise training drills.

GENERAL OPERATIONS


7. Ensure compliance/supervise SSE program if applicable

Toolpusher Responsibilities

1. Supervise the Drilling Contractor personnel that perform drilling related operations.

2. Monitor the wellbore for hole problems and abnormal pressure indicators.

3. Provide a communication link between the Operations Supervisors and Drilling Contractor.

4. Make recommendations to the Operations Supervisor as appropriate.

5. Ensure that daily planning meetings are held which focus on conducting the required operations in asafe and efficient manner.

6. Conduct drills, safety meetings, and training.

7. Ensure that Drilling Contractor personnel document drilling operations properly and that all reportsare complete (IADC, BOP test forms, marine deck logs, etc.)

Safety Coordinator Responsibilities

Refer to Drilling Safety Management Program

2.6 THIRD PARTY SERVICE CONTRACTOR PERSONNEL RESPONSIBILITIES

Service Company Responsibilities

1. Operate as independent contractors that will assist in the executing the Drilling Program to thesatisfaction of the Operations Supervisor onboard the Drilling Rig.

2. Operate and maintain service equipment in full compliance with EMDC-Drilling technicalspecifications and local regulatory requirements, including those requirements specified in the contract.

3. Develop and use safe working practices (including written JSAs for applicable critical tasks).

4. Provide qualified personnel that can efficiently perform the required services in a safe andenvironmentally sound manner. Comply with contractual personnel requirements and Short ServiceEmployee (SSE) program requirements.

5. Each service company is to designate a representative on location, to coordinate the operations andservices directed by the Company.

6. Ensure that all service company personnel attend and participate in safety meetings, drills, and criticaloperations safety meetings (including pre-tour safety meetings).

GENERAL OPERATIONS


Drilling Fluids Engineer Responsibilities

1. Maintain the drilling fluid system in accordance with the Drilling Program and Section 6 of this manual.

2. Conduct a minimum of two (2) complete "In" and "Out" checks of the drilling fluid daily during drillingoperations.

3. Notify the Operations Supervisor of any significant changes in the "In" or "Out" properties of thedrilling fluid system.

4. Notify the driller and toolpusher of changes in weight, chloride content, gas, or any other property thatmay indicate a significant change in formation or entry into abnormal pressure. Ensuring mud is incondition to log by static – ageing a sample of "in" fluid 24-48 hours prior to logging and checkproperties. Report results to Operations Supervisor

5. Take an "Out" sample of the circulating drilling fluid prior to pulling out of the hole (POOH) forlogging and give to the Wireline Logging Engineer along with, a fluid filtrate sample, and the associatedfilter cake. This information will be recorded on the Electric log.

6. Maintain the drilling fluid weight in the active pits during trips and any time that the drill string is out ofthe hole.

7. Ensure that Drilling Contractor personnel are weighing the drilling fluid and measuring the funnelviscosity of the drilling fluid with properly calibrated equipment.

8. Ensure that Drilling Contractor personnel are recording drilling fluid weight and funnel viscosity on 15-30 minute intervals as measured at the flow line and the suction pit.

9. Monitor and assist Drilling Contractor personnel when continuously weighing drilling fluid at the flowline and downstream of the degasser when circulating high gas cut fluid from wellbore.

10. Advise the Operations Supervisor daily of the performance of all solids control equipment.

11. Assist in optimizing the solids control equipment (e.g., recommend screen sizes for the shale shakers,etc.). Advise drilling contractor about screen inventory.

12. Obtain approval from the Operations Supervisor prior to diluting the drilling fluid system to maintainthe drilling fluid properties specified in the Drilling Program.

13. Communicate all planned changes to pit levels in the active system to the Mud Logger and driller.

14. Monitor drilling fluid properties daily to help identify trends or sudden changes from drilling fluidtreatments.

GENERAL OPERATIONS


15. Prepare a Daily Drilling Fluids Report in accordance with the guidelines specified in Section 6.

16. Maintain an inventory of all drilling fluid products onboard the Drilling Rig.

17. Assist the Operations Supervisor when ordering appropriate quantities of drilling fluid products.

18. Ensure that a Material Safety Data Sheet (MSDS) is available for each drilling fluid product on drillingrig.

Directional Driller Responsibilities

1. Recommend Bottom Hole Assemblies (BHAs) to the Operations Supervisor for each hole section ofa directional well as specified in the Drilling Program.

2. Oversee the assembly of all directional BHAs by Drilling Contractor personnel.

3. Ensure that directional drilling practices conform with anti-collision standards contained in this manual.

4. Complete the directional drilling pre-job survey data sheet, sign, and present to the operationssupervisor.

5. Complete a BHA report form for all BHAs run in the well that includes connection type, ODs, IDs,lengths, and serial numbers for each component.

6. Assist Drilling Contractor personnel, as directed by Operations Supervisor, when adjusting drillingparameters to achieve the desired BHA performance. (Bit weight, RPMs, etc.)

7. Maintain a wellbore trajectory record in the Operations Supervisor's office by calculating the azimuthand inclination of the wellbore from surveys.

8. Maintain a current wellbore plot in the Operations Supervisor's office using the wellbore trajectoryrecord.

9. Provide a daily cost to the Operations Supervisor for directional equipment/tools and servicesprovided by the Directional Company.

10. Maintain an inventory of directional equipment/tools on the Drilling Rig.

MWD/LWD Engineer Responsibilities

1. Maintain the MWD/LWD unit and related equipment on location as specified in the contract.

2. Ensure that sufficient MWD/LWD tools are on site as specified in the contract.

3. Maintain 24 hour surveillance of the wellbore from the MWD/LWD unit during drilling operations.

GENERAL OPERATIONS


4. Maintain a record of all MWD surveys taken.

5. Assist the Directional driller, as directed by the Operations Supervisor, when calculating the azimuthand inclination of the wellbore from MWD surveys. Ensure that survey correction factors areunderstood and endorsed by Drilling Engineer, Operations Supervisor, and DirectionalDriller.

6. Complete the directional drilling pre-job survey data sheet, sign, and present to the operationssupervisor.

7. Maintain a pipe tally which is separate from the driller's pipe tally.

8. Provide the Operations Supervisor a copy of the MWD/LWD log daily and fax a copy of the log toExxonMobil personnel as directed by the Operations Supervisor/Wellsite Geologist.

9. Protect personnel from exposure to radioactive sources if such sources are present on location forLWD services.

Mud Logger Responsibilities

1. Maintain the Mud Logging unit and related equipment on the Drilling Rig as specified in the contract.

2. Maintain 24 hour surveillance of the wellbore from the Mud Logging unit during all drilling operations.

3. Notify the driller and the Operations Supervisor of all drilling breaks, unreported changes in pit level,increases in flow, and high gas units.

4. Notify the driller and the Operations Supervisor of any changes in cuttings, such as quantity, size andshape or any parameter that may indicate an increase in pore pressure or the presence ofhydrocarbons.

5. Monitor the trip tank while on trips, logging, and any other time that the trip tank is used.

6. Maintain a pipe tally which is separate from the driller's pipe tally.

7. Maintain a current wellbore sketch that includes volumes and capacities of each hole section in thewellbore.

8. Calibrate the gas detector a minimum of once every 12 hours and after circulating out gas units nearsaturation.

9. Provide the Operations Supervisor a copy of the Mud Log and Mud Logging Report daily and fax acopy to EMDC personnel as specified by the Operations Supervisor/Wellsite Geologist.

GENERAL OPERATIONS


10. Ensure that a Material Safety Data Sheet (MSDS) is available for each mudlogging product on thedrilling rig.

Note: Where mud logging units have hydrogen gas feeding the Flame Ionization Detector (FID),post warning signs indicating the flammable/explosive characteristics of the gas. Inspectthe hoses (typically polyflow) every 2-3 months, and replace if it has been pinched, isbrittle, or is discolored from normal clear or white color (OIMS manual element 6).

Cementer Responsibilities

1. Maintain the cementing unit and related equipment as specified in the contract.

2. Advise the Operations Supervisor of any deficiencies in cement storage/transfer equipment.

3. Calculate the cement slurry volumes, mix water, and displacements for cementing operations asspecified in the Drilling Program.

4. Verify cement volume calculations with the Operation Supervisor prior to starting the cementingoperation.

5. Calibrate the liquid additive system (LAS), if applicable, prior to starting the cementing operation.

6. Collect cement and cement additive samples from the necessary cement P-tanks and liquid additivesystem prior to starting the cementing operation.

7. Operate the cementing unit during cementing operations as directed by the Operations Supervisor.

8. Maintain an inventory of all cement additives and cementing equipment on the Drilling Unit.

9. Assist the Operations Supervisor when ordering appropriate quantities of cement products.

10. Document all pumping/cementing activities in accordance with regulatory requirements using recordingequipment (chart recorders, densiometers, etc.) and provide the Operations Supervisor with properlydocumented charts.

11. Ensure that a Material Safety Data Sheet (MSDS) is available for each cement product on the drillingrig.

2.7. SPECIAL OPERATING PRECAUTIONS

2.7.1 Helicopter Operations

Provide accurate cargo and weight manifests for all helicopter transportation.

GENERAL OPERATIONS


Lower and secure all crane booms before helicopter landing/departure. (Crane operator muststep out of the crane cab until the pilot has stopped the rotation of the rotor blades.)

Make public announcement of helicopter landing/departure.

Provide safety orientation/ditching instructions for passengers.

Establish flight tracking procedures.

Helideck fire fighting system shall be manned during refuelling.

Rapid/hot refuelling is not authorized. See Safety Manual for exceptions.

2.7.2 Mooring Vessel Operations

Use a "Clear Deck of Personnel" policy on work boat when work wire is under tension.

2.7.3 Casing Pressure Monitoring

Casing annulus pressures shall be monitored weekly at all rigs with surface wellheads. Ifcasing pressure is detected, it shall be reported on the Daily Drilling Report. The situationshall be reviewed with the Operations Superintendent to determine if any corrective actions,are warranted, e.g. bleed off, increased monitoring, etc.

2.7.4 Back Pressure Valves

Whenever a back pressure valve (BPV) is to be removed from a tubing hanger, a lubricatorshall be installed and anchored. Prior to retrieving the plug, confirmation of pressureequalization shall be made, if possible. If working on a well with H2S gas, all workers in thearea shall mask up while retrieving the plug.

2.7.5 Rotary Table Insert Bushing Locks

Rotary table insert bushings shall be kept locked at all times (or removed) except whenprocedures specifically require them to be temporarily unlocked. A means of visuallydetermining locked status shall be provided.

2.7.6 Christmas Tree Equipment

Have an OEM (Original Equipment Manufacturer) service representative on location duringinstallation and pressure testing of all christmas tree equipment.

All wellhead and christmas tree equipment has the potential to trap unexpectedly deadlypressure between seals, in gate valve cavities, under pipe plugs, lockdown screws, greasefittings and in small porting which has become plugged. Some models of gate valves areespecially prone to trapping pressure in the gate valve cavities. Trapped pressure mostcommonly occurs in the split gate style valves and especially the WKM models. Any valvethat has service fittings, which access the valve body, should have a permanent warning signstating "WARNING: This valve has the potential to internally trap pressure!"

GENERAL OPERATIONS


2.7.7 Mud Logging Units

Where mud logging units have hydrogen gas feeding the Flame Ionization Detector (FID) postwarning signs indicating the flammable/explosive characteristics of this gas. Inspect the hose(typically Polyflow) every 2-3 months, and replace if it has been pinched, is brittle, or isdiscolored from normal clear or white color.

Responsibility: Operations Supervisor

Approval Authority for exceptions: Operations Superintendent.

GENERAL INFORMATION

DRILLING OPERATIONS MANUAL- JACK-UP/PLATFORM/BARGE RIG DRILLING 1 of 1First Edition - May, 2003

SECTION 2 - APPENDIX G-IEMDC-DO RISK ASSESSMENT FORM REVISED 06/23/99 (EDO_RAF.DOC)

ROUTING & APPROVALGENERAL APPROVED DATEWELL: FIELD: ENGR.

SUPV.ENGR.

DEPTH: RIG: COUNTY: STATE:OPER. SUPT.DRLG. ENGR.MANAGER

TOTAL DAYS PRESPUDMEETING

HELD

WELL TYPE(CHECK ALL THAT APPLY)

WELL CATEGORYFIELD DRILLINGMANAGER

q YES q NO q DRILLWELL q W/O q I+ q I q II q IIIRETURN TO ENGR.

q P&A q COMPLETIONSECRETARY(COPY /DISTR.)

CATEGORY ASSESSMENT - KEY WELL CHARACTERISTICS

CATEGORY 1+q OFFSHORE DRILLING OPERATIONS CATEGORY II

FROM PLATFORM OR MODUq REQUIRES AN ABNORMAL PRESSURE DETECTION

q LIVE/HORIZONTAL DRILLING TEAM TO DETERMINE TD

q EXTREMELY SENSITIVE ENVIRONMENT q SUSPECTED SHALLOW GAS OR CHARGED SANDSABOVE THE SURFACE CASING SETTING DEPTH

q 250 ppm ROE OF H2S THAT INCLUDESOCCUPIED STRUCTURES, HEAVILY TRAVELED q MAY ENCOUNTER SEVERE LOST RETURNS, SLOUGHINGROAD, RAILROAD, BUSY WATERWAY OR AIRPORT SHALE, OR OTHER SEVERE HOLE PROBLEMS RESULTING

IN RELATIVELY HIGH COST

CATEGORY 1 q WELL IS LOCATED WITHIN 500' OF AN OCCUPIEDRESIDENCE, LAKE, STREAM OR HEAVILY TRAVELED

q REQUIRES AN ON-SITE PRESSURE DETECTION ROAD, RAILROAD, AIRPORT OR PLANT/TREATINGTEAM FOR SETTING PROTECTIVE CASING INTO FACILITYABNORMAL PRESSURE TRANSITION ZONE

q OVERBALANCED / HORIZONTAL DRILLINGq REQUIRES > 13 PPG MUD TO DRILL FORMATIONS

SUSPECTED OF CONTAINING HYDROCARBONS q 250 ppm ROE OR H2S THAT IS LESS THAN 300 FEET

q EXTREMELY REMOTE SITE THAT IS A CONSIDERABLE q EXCEPTION FOR OFFSITE AND/OR MULTIPLEDISTANCE FROM SERVICE COMPANIES THAT WOULD RIG SUPERVISION REQUESTEDBE REQUIRED DURING WELL CONTROL PROBLEMS

q WELL IS CAPABLE OF FLOWING HYDROCARBONSAND IS LOCATED WITHIN 2000' OF A DENSELYPOPULATED AREA OR HEAVILY TRAVELED ROAD,RAILROAD, WATERWAY, OR AIRPORT CATEGORY III

q AREA OF ANTICIPATED LOST RETURNS AND KNOWN q LOW RISK, FIELD DEVELOPMENT WELL WITHSHALLOW GAS SANDS CAPABLE OF FLOWING TO GOOD OFFSET DATA, MINIMAL PUBLIC ANDSURFACE PRIOR TO SETTIN G SURFACE CASING ENVIRONMENTAL EXPOSURE, MODERATE COSTS,

AND NORMAL MUD WEIGHTSq 250 ppm ROE OF H2S THAT EXTENDS OUT GREATER

THAN 300 FEETOIMS RISK ASSESSMENT:REQUIRED ON ALL 1+ WELLS AND ANY WELL WITH A BOLD ITALIC KEY WELL CHARACTERISTICOIMS RISK ASSESSMENT REQUIRED? q YES q NO OIMS DRILLING MANAGEMENT REVIEW MEETING HELD?BASE CASE RISK ASSESSMENT REVIEWED? q YES q NO q YES q NO DATE HELD:(IF YES, ATTACH OIMS RISK ASSESSMENT REPORT) MEETING ATTENDEES:ADDITIONAL FAILURE EVENT SCENARIOS IDENTIFIEDq YES q NO (IF YES, INCLUDE SCENARIOS IN REPORT)NUMBER OF ADDITIONAL SCENARIOS:NAMES OF PERSON(S) INVOLVED IN BASE CASE REVIEWAND ADDITIONAL SCENARIO ASSESSMENTS :

LIST OF CONTINGENY PLANS REQUIRED:

SIMOP’S MEETING HELD?q YES q NO q NA DATE HELD:

OTHER CONSIDERATIONS

TYPE WELL (CHECK ALL THAT APPLY) MAX ANTICIPATED SITP HYDROCARBON ZONES WILL FLOW IF q YESq OIL q GAS q INJECTOR q CONDENSATE INSUFFICIENT HYDROSTATIC HEAD q NO

SHALLOWEST GAS OR OIL @: ppm H2S: 250 ppm ROE: HOUSE WITHIN 500': DRILL STEM TEST:q YES q NO q YES q NO

ANTICIPATED WATER BOARD RULING / EXCEPTION REQUIRED / APPLIED FOR: DIRECTIONAL PLAN: q STRAIGHTq YES q NO q YES q NO q N/A q DIRECTIONAL:MUD TYPE (CHECK ALL THAT APPLY) MAX MW LINE RESERVE PITq FW MUD q SW MUD q OIL (q ESCAID q DIESEL) q BRINE WTR q ________ q YES q NO q N/A

ADDITIONAL INFORMATION (IF REQUIRED)

ATTACHMENTS

q WELL PLAN / POWER PT. DIAGRAM q BOPE & EXCEPTION(S) FORM* q DAYS/DEPTH CURVE q MAP OF OFFSET WELLS q BOPE SKETCHES q RIG POSITION ON LOCATION q DIRECTIONAL WELL PLATS q WELLBORE & WELLHEAD SKETCHES q FORM. TOPS/PRESSURES/CONTENT q SUMMARY OF DRILLING HAZARDS q OFFSET WELL PRESSURE CHECKLIST q GEOL. X SECTION & STICK CHARTS q MAP OF GENERAL WELL LOCATION q CIVIL ENGR. DRILL SITE REPORT q OIMS RISK ASSESSMENT REPORT* REQUIRED FOR ALL WELLS. ORIGINAL: WELL FILE XC: OP. SUPT., DRLG. ENGR. & RIG SUPT.(s) OIMS RISK ASSESSMENT REPORT - XC: SYSTEM 2 CUSTODIAN.

XC: R.N. Mefford, C.W. Sandlin

DRILLING OPERATIONS MANUAL- JACK-UP/PLATRFORM/BARGE RIG DRILLING 1 of 9First Edition - May, 2003

SECTION 2 - APPENDIX G-II

MEMORANDUMEMDC DRILLING ORGANIZATION

TO: Clyde J. Baldwin

FROM: Grand Isle 16 OCSG 031 R-22 ST#1 "Sandberg" Drilling Team

DATE: February 17, 2000

SUBJ: OIMS Risk Assessment for GI 16 OCSG 031 R-22 ST#1 "Sandberg" Drillwell

Consistent with Operations Integrity Management, the drilling team has completed a “Risk Assessment” forthe upcoming GI 16 OCSG 031 R-22 ST#1 "Sandberg" drillwell. Enclosed please find the scenarioworksheets for the four incidents identified as potential hazards by the team. Please note that these fourscenarios addressed in the attached worksheets are unique to this location and are not covered by theexisting EMDC Base Case Risk Assessment. The EMDC Base Case Failure Event Scenario List is includedfor your reference.

If you should have any questions regarding this assessment, please do not hesitate to contact any memberof the team for clarification.

xc: H. J. Longwell, IIIEnsco 99 Drilling SuperintendentsElement 2 Risk Assessment Custodian


ELEMENT 2 RISK ASSESSMENTFAILURE EVENT SCENARIO LIST - BASE CASE

Description Barge Land Platform Jack-up **

Surface blow-out with BOP stack on drillwell. X X X X

Surface blow-out with Diverter on drillwell. X X X

Surface blow-out due to surface equipment(drillpipe connection, safety valve, control head)failure during underbalanced perforating,perforation surging, or well lifting/jettingoperations.

X X X X

Surface blow-out while conductingcompletion operations in clear fluids withopen perforations.

X X X X

Explosives (perforating guns, string shots, etc.)detonated at the surface.

X X X X

Drilling rig crane failure /operator mishap. X X X

Rig hoisting equipment failure /mishap. X X X X

Drill rig support vessel/vehicle accident. X X X X

Helicopter/seaplane crash/mishap. X X X

Hazardous chemical accident/mishap. X X X X

Fuel, oil-based drilling fluid, or oil transfer spill. X X X X

Critical supply or personnel transfer isprohibited by weather.

X X X X

Severe weather impacts drilling operations. X X X X

Drilling regulatory noncompliance orinfraction.

X X X X

Derrick barge lift accident/mishap. X

Jack-up rig punch-through. X

Barge rig capsizing during sinking/refloatingoperation.

X

Marine vessel collision with rig/platform. X X X

Lifeboat launch failure . X X

Worker incident on rig. X X X X

Fire/explosion on rig. X X X X

Person overboard. X X X

Diver incident. X X

** applicable to R-22 ST#1 "Sandberg" drillwell


ADDITIONAL FAILURE EVENT SCENARIOSSPECIFIC TO ENSCO 99 and R-22 ST#1 "Sandberg" DRILL WELL

Description Barge Land Platform Jack-up **

Oil Based Drilling Fluid Annular InjectionAccident/Mishap

X

Oil Based Drilling Fluid Spill X

Oil Based Drilling Fluid Fire in Pits X

Well Control Incident Due to Striking OffsetWell.

X

** applicable to R-22ST#1 "Sandberg" drillwell

GENERAL OPERATIONS


R-22 ST#1 "Sandberg"-SPECIFIC OPERATIONS RISK WORKSHEET #1 EMDC RISK MATRIX

A B C D E

HYPOTHETICAL FAILURE EVENT SCENARIO: I H

Unplanned Shallow Gas Problems during Conductor-less Drilling II E F

III P

LOCATION: Jack-up Drilling Rig IV

DESCRIPTION: Unexpected shallow gas is found when drilling surface hole withoutconductor.

CONSEQUENCES: HEALTH/SAFETY

I

PUBLIC DISRUPTION

III

ENVIRONMENTAL IMPACT

II

FINANCIAL IMPACT

II

RESPONSE TIME: Minutes for rig personnel to respond to initial event.

ALTERNATE TO OPERATION: Drill and set a 13-3/8" conductor at about 1000'.

PREVENTATIVE MEASURES: All prudent precautions will be taken to prevent this occurrence.

1. A thorough review of the most recent ST54 drilling program was performed to observe expected gas units, mud weights used,etc.

B21 ST-1 in 2/98 was last drillwell prior to this current planned 3 well program.

B-31, "Hesperides," is the 1st well in this current 3 well program. R-22 ST#1, "Sandberg," will be the 2nd well in the program.

2. Preventative measures noted and planned for R-22 ST#1 include (1) control drilling to maintain low mud weight "out" to preventlost returns and (2) preparation of a Lost Returns plan.

GENERAL OPERATIONS


3. A thorough review of the well logs near surface indicated no presence of shallow hydrocarbon-bearing sands. Both the originalB-1 logs, the more recent B-21 and B-31 logs have been evaluated.

4. Casing pressures have been measured on all annuli. The one well with notable pressure (110 psi) on the surface casing was bledto zero and remained at zero after 24-hr monitoring; B-21 will continue to be monitored and reported until spud.

5. An evaluation of well interference indicates that (a) most wells from the "B"-platform were drilled vertically and therefore inparallel to depths near 5000', and (b) directional driller will drill vertically to ~4,500' MD , which is below the surface casingsetting depth for "Sandberg," and then kick-off

MITIGATION PLANS:

As a result of the SIMOPS meeting with drilling, production, and operations personnel in attendance, the following plans wereestablished: 1) The PIC is the EMDCDO Drilling Superintendent. 2) Emergency shutdown links are established by NOPO fieldoperations. 3) Communication links are established with the NOPO field foreman and GI 16 P platform base, which is the G platform.

The diverter will be nippled up and tested while drilling surface hole.

Diverter drills will be performed with all crews.

The offset drive pipe for the B-30 well, Adonis, which is yet to be drilled, will be blanked off at the surface to prevent an alternate conduitto the surface.

GENERAL OPERATIONS


RISK WORKSHEET #1

HYPOTHETICAL FAILURE EVENT SCENARIO: Oil Based Drilling Fluid Annular InjectionAccident/Mishap

LOCATION: GI 16 R-Platform and Ensco 99

DESCRIPTION: Mishandling, mechanical failure results in exposure of personnel to Oil Based DrillingFluid and to potential additives.

CONSEQUENCES:

HEALTH/SAFETY

III

PUBLIC DISRUPTION

IV

ENVIRONMENTAL

IMPACT

IV

FINANCIAL

IMPACT

IV

RESPONSE TIME: Minutes to respond to personnel injury. Potential for extended response to fire incident.

ALTERNATE TO OPERATION: Store oil based drilling fluid cuttings in boxes and ship via boat back to land. This would impose significant costincreases on this well. This alternative operation carries with it its own risks.

PREVENTATIVE MEASURES:

Personnel training (HAZCOM). MSDS available. Proper PPE. Equipment inspection, and maintenance. Hydrotesting / leak testing of allinjection well facilities. Injection of seawater prior to any oil based mud / cuttings. JSA's. Rig will be set up for "Zero-Discharge Operation,"with appropriate plugs set in all jack-up deck drains. Contracting with competent contractors, either Apollo or National Injection Services.Injection skirt installed around the top of the surface casing

MITIGATION PLANS: Medic on-site for water locations. Emergency equipment. Proper PPE. Fire fighting teams and training.

EMDC RISK MATRIX

A B C D E

I

II

III H

IV P,E,F

GENERAL OPERATIONS


RISK WORKSHEET #2

HYPOTHETICAL FAILURE EVENT SCENARIO: Oil Based Drilling Fluid Spill

LOCATION: GI 16 R Platform and Ensco 99

DESCRIPTION: Oil spill in water during any oil transfer operation due to mechanical failure and/orhuman error.

CONSEQUENCES:

HEALTH/SAFETY

IV

PUBLIC DISRUPTION

III(a)

ENVIRONMENTAL

IMPACT

II(b),III(b)

FINANCIAL

IMPACT

II(b),III(b)

(a) - This potential failure event has potential for adverse media attention.

(b) - Spill size dependent.

RESPONSE TIME: Hours to days to contain and clean up oil transfer spill.

ALTERNATE TO OPERATION: Do not use oil based mud (potential differential sticking, higher torque, and ultimate inability to reach targetobjectives)

PREVENTATIVE MEASURES: Oil transfer Policies & Procedures. Ensco 99 will be in "Zero Discharge Operation". Oil based drilling fluiddisposal company personnel on board. Recent vibrator hose upgrades. Equipment to be checked and tested for leaks prior to first shipmentof OBM. Transfer hoses shall have appropriate certification and testing records prior to first shipment of OBM. Transfer hoses shall bechecked periodically and shall be replaced if any deficiencies are noted. An exercise will be conducted with all transfer personnel prior to firstshipment of OBM. All appropriate personnel will be in constant communication during OBM transfers, especially with boat captain, and noactivity associated with OBM movement will be unsupervised. Weather conditions shall be favorable for any transfer from vessel and mooringlines shall be checked periodically. Fire protection equipment will be located in strategic positions to protect personnel inside of the changeroom and offices. JSAs for all activities will be prepared and thoroughly reviewed prior to any activity associated with OBM. Proper PPE willbe utilized when handling OBM.

MITIGATION PLANS: Oil Spill Contingency Plan for water locations, emergency response drills.

EMDC RISK MATRIX

A B C D E

I

II E,F

III E,F P

IV H

GENERAL OPERATIONS


RISK WORKSHEET #3

HYPOTHETICAL FAILURE EVENT SCENARIO: Oil Based Drilling Fluid Fire in Pits

LOCATION: Ensco 99 while drilling at GI 16 R platform.

DESCRIPTION: Fire/Explosion on drilling rig caused by accidental ignition of oil based drilling fluid.This could be caused by welding, electrical spark, etc.

CONSEQUENCES:

HEALTH/SAFETY

I, II, III

PUBLIC DISRUPTION

IV(a)

ENVIRONMENTAL

IMPACT

III,IV

FINANCIAL

IMPACT

III,IV

(a) - This failure event has potential for adverse Media attention.

RESPONSE TIME: Minutes to hours to extinguish. Potential for protracted response to major incident.

ALTERNATE TO OPERATION: Do not use oil based drilling fluid (too detriment of drilling performance and costs). Other risks inherent to drillingoperations.

PREVENTATIVE MEASURES: Pits and shakers have a Skelton Foam Deluge System. Foam Deludge System: Test procedure will bereviewed, complete water test the system & review of foam deluge shut down & startup procedure. Exxon Safety Manual, JSAs. Properventing and purging of enclosed spaces. Specification of safe welding areas and electrical classification areas (see API RP 500). Goodhousekeeping practices. Gas and fire detection systems. Independent electrical inspection of rig. Contractor preventive maintenanceprogram. Personnel training on hazards of oil based mud. Oil mud has high flash point. Adequate fire equipment.

MITIGATION PLANS: Onsite medic for water operations. Contractor fire fighting training and equipment. Emergency evacuation plan. Firedrills. Escaid 110 invert emulsion oil mud typically has flashpoint > 220° F

EMDC RISK MATRIX

A B C D E

I H

II H

III H E, F

IV E,F,P

GENERAL OPERATIONS


RISK WORKSHEET #4

HYPOTHETICAL FAILURE EVENT SCENARIO: Well Control Incident Due To Striking OffsetWell.

LOCATION: Ensco 99 while drilling at GI 16 R platform.

DESCRIPTION: While drilling, a kick occurs as a result of striking an offset well. Subsequent lostreturns during well control operations causes a blowout and spill at the surface.

COMMENT: Only one live wellbore on the R platform, R-21.

CONSEQUENCES:

HEALTH/SAFETY

I

PUBLIC DISRUPTION

III (a)

ENVIRONMENTAL

IMPACT

III

FINANCIAL

IMPACT

II

(a) - This failure event has potential for adverse Media attention.

RESPONSE TIME: Minutes to respond to initial event, days to several weeks to control blowout.

ALTERNATE TO OPERATION: Inherent risk. Drill free standing well away from current wellbores.

PREVENTATIVE MEASURES : Well path design with an emphasis on collision avoidance. Use two directional drillers plotting collision coursewhen close to offset wellbores. Critical well will be temporarily P&A'd above the depth of closest approach and GLG bled off the well. Will useOp Tech Bulletin #99-111 as a guide to avoid wellbore collision. EMDC well control practices and policies. Technically and operationallysound drilling practices. EMDC BOP testing guidelines and EMDC BOP function testing standards. Casing design specifications, casinginspection programs, casing connection make up procedures, casing pressure tests, wellhead QA/QC program. Rig supervisor well controltraining, NODO technical and operational personnel staffing requirements. Ensco personnel well control training, drilling crew tour proficiencydrills, drilling rig critical alarms and instrumentation. NODO critical valve "soft-lock" program. Adequate offset well drilling and formationpressure information.

MITIGATION PLANS : Onsite medic. Oil spill response plan. Critical operations and curtailment plan. Fail-safe surface and subsurface ESDsystems. Fire fighting equipment/training. Joint drilling/production evacuation drills.

EMDC RISK MATRIX

A B C D E

I H

II F

III P E

IV

GENERAL INFORMATION


SECTION 2 - APPENDIX G-III

ExxonMobil Development Company – Drilling OrganizationBOPE EXCEPTIONS

Well Name: Risk Category: EngineerField/Prospect: Depth: Engr. Supv.County, State ppm H2S: Opt. Supt.

Rig: 250 ppm H2S ROE: Drlg. Engr. Mgr.

Field Drlg. Mgr.

Max. MWRequired to

Casing Balance Pore HC Exposed? MASP BOP Flowline Choke ChokeSize Depth Drilled Interval Pressure Y/N Type PSI Type Type Type Min. WP

ExceptionExceptionRequested Justification for Exception

1. Flexible hoses for BOP opening & closing lines notconsistent with API RP 16D.

2. Flexible hoses for choke and kill lines not consistent withAPI RP 16C.

3. Low risk well package:a) Type RX ring gasket reuse allowed after visual insp. by

ExxonMobil Supervisor (BOP WP ≤ 3,000 psi).b) Low carbon steel Type R ring gasket use and reuse

allowed in non-load bearing API Type 6B flanges withType R flat bottom grooves. (Flange bolt tighteningcheck required, BOP WP ≤ 3,000 psi).

c) Low carbon steel ring gaskets allowed in gas or sour oilenvironments (BOP WP ≤ 3,000 psi).

d) Only one outlet valve required on each wellheadsection (Xmas tree WP ≤ 3,000 psi).

e) BOP control panel at accumulators only.f) Accumulator capacity sufficient if all preventers can be

closed, the HCV opened, and 1,400 psi maintained onthe manifold with no pumps operating.

4. Mud-gas separator not required.

5. Double manual valves in kill line used in lieu of check v.

6. Subsequent press tests of opening & closing lines for BOPs& HCV will be 1,500 psi (BOP WP ≤ 3,000 psi).

7. Flow rate sensors and pit volume totalizers not required.

8. Type 2 and Type 3 choke manifolds will not requirestraight-through line (BOP WP ≤ 3,000 psi).

9. Casing rams not required.

10. Drilling spool not required.

11. SA BOP will not require double valves on each outletfor choke and kill lines.

12. Handwheels for BOPs not required on location.

13. Drill pipe to casing crossovers not required on location.(Must have access to them if needed).

14. H2S trim for BOP stack is not required.

Other Exceptions

1.

2.

GENERAL INFORMATION


SECTION 2 - APPENDIX G-IVExxonMobil Development Company

Drilling Environmental Performance Indicators Report

Well: Location:

Rig: Days:

TD Depth (MD/TVD): FRR Date:

Offshore or Onshore:

Emissions Data

Rig Fuel Consumption gallons (U.S.)

Regulatory Compliance Data

Exceedances reported to regulatory agencies* No. to air No. of NOV's

No. to water No. R.Q. ExceedancesNo. to Land No. Fines

Other Fines Amount ($US)

Total Exceedances

Oil Spills* > 1 bbl. No. to land Vol. to land bbls.No. to water Vol. to water bbls.

Chemical Spills* > 100 kg. No. to land Vol. to land kgs.No. to water Vol. to water kgs.

[Vol.(gal.)*Specific Gravity *(8.3 lbs./1 gal)*(1kg/2.2 lbs.)] =Mass(kg)

*Please send all spill or exceedance reports to Drilling Environmental Coordinator fax 281-423-4337

Waste Data Drilling Fluid Type: SW, FW, NAF (OBM/SBM/OTHER)

Drill Cuttings (Only complete for drill cutting with NAF discharged to sea)

NAF Drill Cuttings disposed at sea Vol. bbls. %NAF on CuttingsUse gauge hole volume

Hazardous Waste (classified as Hazardous Waste by regulatory authorities)

Net Generated (lbs.)

External Recycled (lbs.)

Ongoing (lbs.)Periodic (lbs.)

Engineer: Eng. Manager:

Include completed record in Final Well Report and send copy to EMDC Drilling Environmental Coordinator.

MARINE OPERATIONS

______________________________________________________________________________DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLINGFIRST EDITION - MAY, 2003

3.0 MARINE OPERATIONS

3.1 Site Survey / Bottom Sweep / SIMOPs review 13.2 Moving 2

3.2.1 Moving Jack-up Rigs 33.2.2 Moving Platform Rigs 43.2.3 Moving Barge Rigs 5

3.3 Moving and Positioning 63.4 Pre-Loading (Jack-up Only) 73.5 Cargo Transfers 8

3.5.1 Precautions 93.5.2 Weather Limits 93.5.3 Heavy Lifts (Jack-Up Lifts in Excess of 10 MT) 93.5.4 Lifting Operations 103.5.5 Rigging Guidelines 113.5.6 Equipment Maintenance 15

3.6 Transportation & Personnel Transfers 203.6.1 Cargo Transport 203.6.2 Helicopter Operations 213.6.3 Personnel Transport-Helicopter 223.6.4 Personnel Transport-Supply or Stand-By Boat 24

3.7 Marine Training 243.7.1 General 243.7.2 Reporting & Drill Frequency 253.7.3 Marine Drill Process 263.7.4 Fire Drills 273.7.5 Fire Drill-Example 293.7.6 Abandon Rig Drills 303.7.7 Abandon Rig Drill-Example 333.7.8 Man Overboard Drill 343.7.9 Specialized Drills 353.7.10 Principal Aspects of Drills 37



MARINE OPERATIONS


3.1 SITE SURVEY/BOTTOM SWEEP/SIMOPS REVIEW

For applicable marine operations, a site specific operability study can be conducted by the EMDCTechnology Group or an approved Marine Engineering contractor.

Before a new rig is added to the fleet, a series of inspections must be performed on the new rig.Section 3 -Appendix G-V is a guide to the specific inspections that must be done. Additionalinspections may be completed as required by the specific rig or drilling program requirements.

Prior to moving the rig onto a new or preexisting location, a shallow hazards assessment of the site(OIMS Element 3) is to be conducted. The assessment will aid in the location of submarine cables,pipelines, buoys, boulders, shallow gas, etc. should such obstructions exist in the vicinity of theproposed location. The assessment should include a review of existing information for any evidenceof shallow hazards. Sources may include the following:

• Offset well/soil data, previous bottom sweeps, site surveys, appropriate geological andgeophysical data, and offset well casing pressure.

• Up-to-date maps of pipelines (including platform vent/flare lines) and data regarding theposition and characteristics of previous rigs that worked in the area.

• Up-to-date drawings of production platform and facilities to assess interference potentialand identify SIMOPs requirements associated with conducting Jack-Up DrillingOperations over production platforms.

• Diagrams of Production Platform support piling positions and driven depths to assess JURspud can and platform pile interference potential (be sure to account for productionplatform leg batter). Section 3 -Appendix G-IV (" Amoco/McClelland Study "Jack-UpRig Soil Disturbance") is the subject of a memo written by E. J. Henkhaus. The DrillingEngineer is to reconcile all MIRU plans with this memo (and ExxonMobil's CivilTechnology Group, if required).

• Regional seismicity (i.e., number and intensity of earthquakes) in earthquake prone areas.

• Existence of natural seeps.

• Literature (company and public).

Based on results of the shallow hazard assessments, a site survey may be conducted. The site surveymay include:

• Bathymetry Profile via Echo Sounder

• Sub-bottom profiler

• 2-D high resolution multifold seismic

• Side Scan Sonar

• Magnetometer

• Soil Boring (100' -150')

MARINE OPERATIONS


For JU rigs, adequacy of JUR leg length must be considered. This will include spud can penetrationbased on maximum previous penetration or soil boring analysis estimate (if first time at a location),water depth, required JUR hull air gap, production platform deck, and equipment elevations.

Review the potential for JUR leg run or punch through during pre-load operations. Previous preloadexperience in the area and/or soil boring analysis will be good predictors of this.

A bottom sweep of the area in which the JUR will be positioned adjacent to the production platformshall be conducted for each JUR/Production drilling program.

• The area swept should include all area where the Jack-Up rig could set its legs onto theseafloor (generally, this is within 500' of the platform).

• All pipelines within 490' of the JUR spud cans shall be marked with sonar reflectors andsurface buoys, a safe entry/exit area cordoned off with markers, or proper waivers will beobtained-from appropriate EMDC and EMPC management and regulatory agencies.

• Company providing bottom sweep will provide a diagram of bottom sweep areaidentifying pipelines marked and any underwater obstructions or previous spud can holeidentified. This should be included in the MIRV Procedure.

• If there is significant delay between when the sweep is performed and when the rig willactually move onto location (e.g. greater than 30 days) or if there is any significantactivity near the platform (e.g. construction), review with Production and the rigcontractor to determine if another bottom sweep should be performed.

A SIMOPs Checklist Memo (Section 3 - Appendix G-I) and review between appropriate EMDCDrilling Op. Supt. and EMPC Op Supt shall be completed prior to JUR mobilization for eachJUR/Production drilling program.

• If the decision is made to make any deviations from the guidelines set out in the SIMOPsmanual, this may be accomplished by routing a SIMOPs deviation for approval byProduction. A blank form is attached as Section 3 -Appendix G-II.

A platform survey meeting will be held to discuss platform specific issues (e.g., moving stairways,moving cranes, process equipment protection near the cantilever, etc). This meeting should include arepresentative from EMDC Drilling, EMPC, and the rig contractor.

3.2 MOVING

3.2.1 MOVING – JACK-UP RIGS

Prior to commencement of any marine movement operations it is imperative that a review oflocal regulations for notices be conducted to ensure the necessary permission has been obtained.This information can then be used to evaluate the potential impacts of exploration operations andidentify mitigating options. Valid discharge and drilling permits, from state and or federal agencies,must be posted at the rig prior to the rig MIRU on location. Other permits DOCD, APD, MMS, andState O&G Boards’ “Plans for Exploitation” should also be available.

MARINE OPERATIONS


The following general operational guidelines apply to the Jack-Up barge during preparation for andexecution of transit operations.

1. A marine procedure must be documented in accordance with the drilling contractor’s MarineOperation Manual.

2. Towing arrangements will be made well in advance.

3. Size and number of tow vessels required considering:

• Government regulations

• Contractor’s insurance requirement

• Expected currents and weather

• Distance of tow

• Positioning requirements at the mobilization location and final drilling site.

4. Prior to initiating the move, inspection of all towing vessels shall include:

• Towing wire and accessories

• Tow winch

• Tow rigging such as towing eyes, etc

• Communications equipment (must include two separate systems)

• General condition of the tow vessels

5. All equipment onboard must be properly secured prior to rig moves. Particular attention willbe given to the BOP stack and tubular goods.

6. Jack-Up vessel stability calculations after loading Company and third party equipment.

7. Function test the jacking equipment.

8. Description and or map of tow route.

9. A contingency procedure will be in place for heavy weather including:

• Pre-determined safe shelter location or locations along route.

• Mitigating towing procedures such as slowing and turning into heavy weather.

10. In areas where applicable rig moves, should consider a “lump-sum” mobilization cost quote tobe obtained from the drilling contractor and an economic analysis should be conducted todetermine if EMDC Drilling will accept the lump sum proposal or choose to mobilize the JURon dayrate.

MARINE OPERATIONS


3.2.2 MOVING – PLATFORM RIGS

Prior to commencement of any marine movement operations it is imperative that a review oflocal regulations for notices be conducted to ensure the necessary permission has been obtained.This information can then be used to evaluate the potential impacts of drilling operations and identifymitigating options. Valid discharge and drilling permits, from state and or federal agencies, must beposted at the rig prior to spud. Other permits DOCD, APD, MMS, and State O&G Boards’ “Plans forExploitation”.

The following general operational guidelines apply to the platform during preparation for andexecution of transit operations.


2. A person designated by the project team conducts an onsite inspection to determine the preferredplacement of all rig packages in relationship to pipelines, facility process equipment, drainsystems, blowdown vent lines, and any other equipment that may be affected.


4. Crane barge arrangements will be made well in advance.

5. Check platform loading as it relates to the rig package equipment and secure StructuralEngineering’s concurrence with the rig mobilization plan.

6. Review the proposed locations of living quarters, escape routes, diesel storage tanks, etc. anddetermine what fire protection is necessary. A load down sequence should be planned &documented to determine the sequence in which rig components should be loaded onto theplatform based on priority.

7. Locate all fire protection equipment stations on the main deck, and assess the need to relocate.

8. Survey the platform’s firewater system to determine where a tie-in can be made to supply water tothe rigs fire main, and that piping pressure design is compatible. Ensure that the platform’sfirewater pumps meet the GPM requirements for that facility.

9. Inspect all main deck drains to ensure they are clear of any obstruction, and determine if anydrains need to be isolated/modified due to the positioning of the rig packages.

10. A scale drawing depicting platform/rig equipment layout shall be developed highlighting thedesignated safe welding area, as well as areas in which Hot Work is prohibited.

11. Locate all incoming and outgoing pipeline risers, and determine what protection these requireduring the MIRU and drilling phase.

12. Ensure that a communication link is established between the barge and platform, particularlybetween the barge crane operator and those persons spotting equipment on the main deck of theplatform.

MARINE OPERATIONS


13. Ensure that the contractor crane complies with the inspection requirements of API RP2D.Documentation of this inspection is required.

14. Review critical processes (i.e., NGL/high pressure injection lines) and assess the need for specialconsiderations in regards to emergency situations.

15. Review all electrical classifications applicable to the planned locations of the living quarters andrig components.

16. Inspect the platform’s diesel storage tanks, potable water storage, and various transfer pumps todetermine if they meet the needs of the rig. If the platform has a helicopter refueling system,examine the piping and determine if the pump can be used if refueling station installation on therig's heliport is required.

17. Inspect all deck grating, plating, and handrails and arrange for repair or replacement a needed.Examine the condition of any downcomers that may be installed for previously mobilized platformrigs, and assess whether they can be reused.




• Expected currents and weather

• Distance of tow


19. Description and or map of tow route.



• Mitigating towing procedures such as slowing and turning into heavy weather.

3.2.3 MOVING – BARGE RIGS

Prior to commencement of any marine movement operations it is imperative that a review oflocal regulations for notices be conducted to ensure the necessary permission has been obtained.This information can then be used to evaluate the potential impacts of drilling operations and identifymitigating options. Valid discharge and drilling permits, from state and or federal agencies, must beposted at the rig prior to spud. Other permits DOCD, APD, MMS, and State O&G Boards’ “Plans forExploitation”.

The following general operational guidelines apply to the barge during preparation for and executionof transit operations.

MARINE OPERATIONS



2. If historical data is absent, a soil bore sample may be analyzed in order to facilitate design/buildingof a rockpad.

3. Surveying and dredging arrangements will be made well in advance.





• Expected weather

• Distance of tow


6. All equipment onboard must be properly secured prior to rig moves. Particular attention willbe given to the BOP stack and tubular goods.

7. Description and or map of tow route and location of pipeline crossings and other facilities thatcould impact rig move.



9. For barge rig moves the payment details should be specified in the drilling contract (i.e., dayrate or lump sum).

3.3 MOVING AND POSITIONING

A procedure for moving and positioning at the drilling site shall include:

Towing

1. A lead vessel and tow master will be clearly established.

2. Obtain weather from the weather service and/or surrounding rigs/vessels along the proposedtow path.

Note: The tow is not to be undertaken if winds and seas are expected to exceed 25 knotsand/or 5 feet at the mobilization location, the tow route, the final location, or during thefinal jack-up and pre-loading operations. The Rig Contractor's insurance requirementsshould be considered.

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3. Attending tow vessels are to be attached by towing wires to the Jack-Up prior to the final jack-down. This operation should be carried out in good weather and in daylight when possible.GOM production JUR night move-in and positioning requires approval of appropriate EMDCand EMPC management through the SIMOPs checklist/review process and appropriatewaivers/approvals from the MMS (if all pipelines are not adequately marked).

4. Actual draft, after all the legs are free of the sea bottom, will be compared to the calculatednumber to ensure stability calculations are correct.

5. The crew must ensure that a continuous check is maintained on the draft of the hull during thetow.

6. All navigation lights on the rig will be operational.

7. The fog horn will be tested to ensure that it is operational.

8. A 24 hour watch will be maintained, during the entire tow, for shipping traffic and obstacles(buoys, platforms, etc.).

Note: Specific individuals are to be assigned watch duty and such duty shall not be for morethan 2 hours continuous without a break.

Positioning

A surface positioning system will be utilized to monitor the drilling rig's position as it is navigatedonto the proposed location. The specific navigation procedure will be dependent upon the welllocation and will be specified in the Move-In Rig-Up Procedure. The final position of the drilling rigis to be verified after the legs have been pinned. The drilling rig's exact location, determined after anadequate number of satellites passes, is to be within the stated tolerance as specified in the MIRUprocedure. For a rig cantilevered over an existing platform, the position will be deemed acceptable ifthe hookload requirement can be met after positioning the drill package over the appropriate slot(s).

The drilling rig's heading will be specified in the Move-In Rig-Up Procedure drilling program orsupplemental procedure. This will generally be determined by cantilever/rotary table accessibility ofthe desired well conductor slot on the production platform and the direction of the prominent windsand wave forces for the proposed location and time of year. Engineer will specify the maximumcantilever loads that will be available in the skidded- out position in the Move-in Rig-Up Procedureand confirm that these will meet maximum well design loads both before and after final JURpositioning. In a multi-well drilling program, the hookloads for all wells and positions must beacceptable. Factors such as crane position, workboat logistics, etc. may also affect the programmedheading of the rig.

Note: Anchors will not be used to hold the Jack-Up barge on location prior to pinning thelegs. Any use of anchors will require use of a detailed procedure and will necessitate anexception to the standard (approval of the Field Drilling Manager).

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3.4 PRE-LOADING (JACK-UP ONLY)

Prior to leg penetration of the sea floor (pinning), an inspection of the sea bottom may be carried outto ensure that pipelines, shipwrecks, spent armaments, and other debris are not present. Thisinspection may be included in the site survey if one is conducted.

Prior to jacking-up to the predetermined work height, a pre-load must be applied. In general, pre-loading must be conducted consistent with the rig contractors and rig manufacturer's standardoperating procedures. However, the following general guides apply as a checkpoint.

1. The pre-load for the first cycle is to be applied with the bottom of the hull approximately 3-5feet above the wave action line. Once the hull of the barge touches the wave action line duringpre-loading, all of the ballast water is discharged and the Jack-Up barge can subsequently bejacked up to a 5 feet air gap above the wave action line.

Continue pre-loading until the Jack-Up stands firmly with no subsidence. The final pre-loadwill be held for a minimum of 3 hours without further subsidence.

2. The preload requirements are to be in compliance with the Drilling Contractor's StandardOperating Procedure, typically at or near maximum loading.

Note: Preload weights are to be included in the Core Jack-Up Move-In Rig-Up Procedure.

3. The actual leg penetrations are to be compared to the calculated values and previous Jack- Uprig positions at the same production platform, and, if significantly different, additional sea bedcores should be considered to determine the reason for the discrepancy and the actual sea bedintegrity.

4. During jacking operations, the sea water tower must operational at all times, with the normalsupply of sea water available in an emergency situation.

3.5 CARGO TRANSFERS

Cargo Transfer

Cargo transfer between supply vessels and offshore rigs/platforms represents one of the morehazardous undertakings in the offshore environment. A Back-Down Buoy when servicing a Jack-Uprig is recommended, especially during strong current/wind conditions. When setting a Back-DownBuoy, ensure that it is not set on a pipeline or other subsea hazard. Do not use a production platform tostore drilling equipment without involving EMPC to ensure the structure can handle the planned loadwith acceptable safety factors.

Guidelines in this section cover some of the major transferring operations. While there is no substitutefor good common sense, Marine and Jack-Up rig personnel are to use these guidelines and goodjudgment to conduct transferring operations in a safe manner. A JSA (Job Safety Analysis) is requiredprior to all lifting operations. A JSA is mandatory for all blind lifts and personnel lifts.

Definition: Heavy lift is defined to be any lift greater than 10 (ten) MT.

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3.5.1 PRECAUTIONS

Certification/Communication Guidelines

Jack-Up Contractor is to have and provide:

1. Third Party certification for all Jack-Up cranes in accordance with API RP 2D.

2. Certification documents for all Jack-Up crane operators.

3. All slings are to have been certified and marked as to their ratings inclusive of end terminationand are to be re-certified every 6 months.

4. Crane hooks equipped with functioning safety latches, which are in good workable condition.

5. Crane operators who are properly trained and certified for Jack-Up work.

6. Good communications during all cargo-transferring operations (i.e., radio headsets, walkie-talkie, etc.).

3.5.2 WEATHER LIMITS

Cargo Transfer Weather Guidelines

1. A void general cargo transfers in heavy weather conditions, particularly heavy lifts.

2. Consider suspending drilling operations until weather conditions improve before transferringheavy cargo in heavy weather.

3. Only transfer small pieces of equipment, necessary to avoid suspension of operations, from asupply vessel in heavy weather conditions and only if the boat captain, DIM, and OperationsSupervisor are all in agreement it is safe to do so.

Note: "Snatch Lifts" are to be undertaken only with pre-slung lifts where a sling attached tothe cargo can be attached to the crane hook. Shackling slings to cargo when the sling isattached to the crane is not permitted for snatch lifts.

3.5.3 HEAVY LIFTS (JACK-UP LIFTS IN EXCESS OF 10 MT)

The following shall apply for heavy lifts:

1. Lifts in excess of 10 MT are to be supervised by an Operations Supervisor and the ContractorOIM or his designate.

2. Heavy lifts should be planned for daylight hours when possible.

3. Heavy lifts should have pre-slung, certified lifting slings and shackles.

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4. Hold a coordination meeting for heavy lifts (i.e., over 10 MT) with the Crane Operator,Toolpusher, and Operations Supervisor present and discuss:

• Type of rigging necessary.

• Visual inspection of the rigging.

• Signaling methods.

• Overall plan for off loading and placement of lift.

Note: The above applies to any lift means, i.e., crane, BOP trolley, or any other lifting device.

3.5.4 LIFTING OPERATIONS

Crane Operator Responsibilities

1. Operate cranes in a safe and reasonable manner.

2. Complete daily crane inspections and present complete inspection reports to supervisors.

3. Perform daily maintenance on cranes and rigging equipment.

4. Maintain good house keeping in cargo areas.

5. Use adequate and safe slinging arrangements.

6. Participation in crane inspections by Company Personnel.

7. Ensure good communications are used between the signaler and himself.

8. Obtain Work Permit for heavy lifts or any lift over platform facilities (if applicable).

Lifting Guidelines

1. Handle cargo so that it remains visible to the Crane Operator whenever possible.

2. Use relay personnel in situations where cargo is not visible to Crane Operator (JSAMandatory).

Note: Crane Operator and the relay personnel are to have visual contact with each other andcommunications via radio (walkie-talkie).

3. Break down heavy lifts into smaller lifts if at all practical.

4. Hold a coordination meeting for heavy lifts (i.e., over 10), with the crane operator, toolpusher,and Operations Supervisor present and discuss:

• Type of rigging necessary.

• Visual inspection of the rigging.

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• Signaling methods.

• Overall plan for off-loading and placement of lift.

5. Obtain approval from the Operations Superintendent and OIM before performing dual lifts(i.e., use of two or more cranes for a single lift).

6. Plainly mark all lifts over 1 MT at dockside prior to loading onto the workboat.

7. Keep loads vertically below the boom hook to avoid swinging as much as practical.

8. Ensure that crane hook is vertically centered over a lift prior to lifting off of supply vesselspicking up from rig decks.

9. Use tag lines on all lifts.

10. Attach loose slings to any load, which is not pre-slung on the supply vessel before connectingload to the crane hook.

Note: The crane is not to support a sling while connecting the sling to the load.

Note: The only exceptions are the use of pallet bars for off-loading pallets and casing hooksfor off-loading casing.

11. Use a minimum of two (2) deck hands when handling cargo and attaching slings on the supplyvessel.

12. Ensure that all personnel wear Life Vests/Jackets while on the vessel deck while transferringcargo from a supply vessel.

13. Take precautions to avoid binder slap back when removing chain binders on cargo from supplyvessel.

Note: Supply vessels will use chain binders to secure cargo and keep it from shifting duringrough seas conditions.

3.5.5 RIGGING GUIDELINES

Lifting Equipment Policy

Proper equipment is to be used to off-load cargo (i.e., slings and shackles of adequate size,manufactured pallet bars and casing hooks, etc.).

Off-Loading Policy

Pipe bundles are not to be off loaded from a supply vessel under any circumstances if any of thefollowing conditions exists:

• Pipe bundle has slings that have only a single wrap around the pipe bundle,

• Pipe bundle has short slings, which result in a crane hook angle of more than 30 degrees.

MARINE OPERATIONS


• Pipe bundle has slings around the pipe bundle, which is more than 25% of the pipe lengthfrom the end of the pipe bundle.

Sling Rigging Policy

Slings that have a plastic covering are not to be used under any circumstances. Covering may allowcorrosion to occur which can go undetected.

Tubular Off-Loading Guidelines

Dependent on the size of tubular, utilize the following sling arrangements:

• 30" Use only slings attached to shackles, 1 joint per lift maximum

• 20" Use only casing hooks, 1 joint per lift maximum

• 13-3/8" " Use only casing hooks, 2 joints per lift maximum

• 9-5/87" Use only casing hooks, 2 joints per lift maximum

• 5" Use either casing hooks or slings, 4 joints per lift maximum Use pre--slung, reasonable number of joints (or smaller)

Note: Pre-slung bundles are to have two slings, each having two wraps around the pipe with aminimum of five pipe joints per bundle for sizes up to and including 5".

Note: Pre-slung bundles for casing larger than 5" up to 7" casing is to have a minimum offour joints per bundle.

Note: Do not pre-sling casing 7" and larger.

General Rigging Guidelines

1. Use manufactured pallet bars to lift pallets (i.e., not styles made at the rig site.).

2. Lift a maximum of two pallets at a time and do not exceed 6 ft in height (i.e., total for twopallets).

3. Use slings with the same number of legs as the number of straps on the bags to lift big bags.Connect all bag straps individually to the sling legs.

Note: Do not shackle together the bag straps on the same sling leg and do not lift a bag unlessusing all straps on the bag to share the load between straps.

4. Off-load only one bag per lift.

5. Leave bags that have damaged straps on the supply vessel.

6. Use a four-leg sling arrangement for lifting cargo containers and baskets.

7. Shackle each sling leg to the designated lifting padeyes on cargo containers and baskets.

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8. Use slings, chains, and links that are adequate for the particular lift.

9. Use the Tables at the end of this section for additional information and specifications.

• Table No. I - Wire Rope Sling Safe Working Loads

• Table No.2 - Chain Sling Safe Working Loads

• Table No.3 - Master Link Safe Working Loads

• Table No.4 -Installation of Wire Rope Clips

Cargo Transportation Guidelines

1. Ensure cargo containers are the primary method for transporting drums. Drums should beplaced on and secured to pallets inside of a cargo container for forklift capability.

Note: Removing drums from a basket is difficult and hazardous.

Note: In critical or emergency situations and if a cargo container is not available, sling onlyone drum at a time per lift using proper drum hooks.

2. Transport gas bottles (i.e., oxygen, acetylene, nitrogen, etc.) using a proper bottle rack whichhas a single point lifting padeye.

Note: Do not transport loose gas bottles.

3. Only transport radioactive and explosive materials in proper containers that are madespecifically for such material.

Sling Rigging Guidelines

1. Calculate the safe working load of slings by dividing the catalog breaking strength of thelifting gear by a Safety Factor.

2. Use the following to determine which Safety Factor applies.

Operation Safety Factor

Wire Rope Slings 5.0

Chain and rigging tackle 3.5

Personnel baskets 10.0

3. Calculate the load per sling leg by dividing the total vertical load by number of slings thendividing again by the cosine of the lift angle (i.e., angle between slings at crane hook).

4. Ensure that the slings are of sufficient length so that the maximum angle between the slings atthe crane hook is 60 degrees for containers, etc. and a maximum of 30 degrees for bundledpipe (i.e., 50 ft sling lengths for 40 ft pipe bundles and 40 ft sling lengths for 30 ft pipebundles).

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Note: If the sling leg length equals or exceeds the horizontal distance between loadattachment points (i.e., padeyes), the lift angle is 60 degrees or less.

5. Locate each sling leg a distance equal to 15 percent of the bundled pipe length when lifting apipe bundle (i.e., 6 ft. from the end for 40 ft pipe joints).

6. Use wire rope slings.

Note: Wire rope slings break one strand at a time whereas chain slings break with little or nowarning. Also, chains are less resistant to shock loading.

7. Use galvanized wire rope when possible.

8. Ensure that galvanized chain is not used in offshore environments as the strength deterioratesto some unknown value over time.

9. Use wire rope choker hitches that utilize a slip through or reeve eye thimble.

10. Only use sliding choker hooks that are of the safety latch design.

11. Do Not use a safety shackle through a soft-line eye to make a hitch connection.

12. Ensure that sling hooks as well as crane hooks have a fail safe hook latch.

13. Ensure loads engage fully about the throat of the hook and that point loading does not occurfor the sling on the crane hook.

14 Use shackles that are either the screw type or pin-bolt-nut type.

Note: Loads, which have permanently dedicated shackles, are to have a cotter pin outside theshackle nut.

15. Use casing hooks that are self-tightening with a pressure lock and manual release.

Note: If open type hooks are necessary, use an interconnecting pull line longitudinallybetween the hooks.

3.5.6 EQUIPMENT MAINTENANCE

Definition: Good maintenance is frequent inspection, cleaning, and lubrication of riggingequipment.

Equipment Maintenance Guidelines

1. Maintain chains, wire rope, shackles, hooks and all other rigging equipment on a periodicbasis.

2. Inspect all rigging equipment upon operation start-up and every 3 months thereafter. Slingsmust be recertified every 6 months.

MARINE OPERATIONS


3. Destroy any rigging equipment that has corrosion, excessive wear, stranded wires, or is inotherwise suspect condition.

4. Lubricate all rigging equipment during each inspection.

5. Ensure rigging equipment is clean and dry prior to the lubricant application.

6. Apply proper lubricants correctly to rigging equipment.

7. Brush light oils directly on rigging equipment from the oil container.

8. Heat medium to heavy oils prior to applying to rigging equipment.

9. Use lubricants that do not contain metals (i.e., not used crankcase oil).

10. Use lubricants that are water repellent and have a good penetrating ability.

11. Consider a lubricant for slings, shackles, chains, etc. from the following list:

• Rocal Rd 105

• Sea King Sk 620

• Advanced Lubricant Svcs. Esso Surett Fluin 4k

• Rocal Rd 05 Aerosal Esso Rustban 395

• Esso Petroleum il 795 Mobil Oil Mobiltac 81

• British Ropes Britlube IOb/69b

Wire Rope Guidelines

1. Lubricate wire ropes more frequently than just during inspections.

Note: Wire rope is in need of a lubricant when the following characteristics are noted:

• Creaking noise while the rope is spooling.

• Breaking of wires in the valley of the rope without any indication of uniform strandnicking.

Note: The following is an example of the strength reduction in "rust-bound" wire ropeassuming the wire rope diameter remains constant (i.e., no reduction due to corrosion).

• New 7/8", 6 x 36, IWRC wire rope with original lubricationMinimum breaking strength is 34 tons with 4.51 percent stretch.

• Same wire rope in an unused condition but with mild corrosionWill break at approximately 22 tons with only 1.63 percent stretch.

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TABLE NO. 1

WIRE ROPE SLING SAFE WORKING LOADS

Galvanized, BS 6166:1981 Uniform Load Method/Extra Imp. Plow Steel (180 kgf/mm2)

Maximum Lift Angle = 60 Deg. - (All wire rope 6x36 IWRC)

Max. Safe Working Lds (Metric Tons) (Safety Factor = 5) - Max Safe Working Ld (Mt)

Rope Dia. Single-Leg Two-Leg Two-Leg Four-Leg

mm (in) Hitch Double Choker Hitch Hitch

9 (3/8") 1.0 MT 1.1 MT 1.4 MT 2.1 MT

13 (1/2") 2.1 MT 2.2 MT 2.9 MT 4.4 MT

16 (5/8") 3.3 MT 3.4 MT 4.6 MT 6.9 MT

19 (3/4") 4.6 MT 4.8 MT 6.4 MT 9.6 MT

22 (7/8") 6.2 MT 6.5 MT 8.7 MT 13.0 MT

26 (1") 8.6 MT 9.0 MT 12.0 MT 18.0 MT

28 (1-1/8") 10.0 MT 10.5 MT 14.0 MT 21.0 MT

32 (1-1/4") 13.1 MT 13.7 MT 18.3 MT 27.5 MT

38 (1-1/2") 18.5 MT 19.4 MT 25.9 MT 38.8 MT

51 (2") 34.8 MT 36.5 MT 48.7 MT 73.1 MT

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TABLE NO. 2

CHAIN SLING SAFE WORKING LOADS

Heat Treated Alloy Steel (800N/mm2)-BS 6166: 1981 Uniform Load Method

Max. Lift Angle = 60 Deg

Max. Safe Working Loads (Metric Tons) - (Safety Factor = 4)

Chain Dia Single-Leg Two-Leg Two-Leg Four-Leg

mm (in) Hitch Double Choker Hitch Hitch

6 (1/4") 1.5 MT 1.6 MT 2.1 MT 3.1 MT

8 (5/16") 2.0 MT 2.1 MT 2.8 MT 4.2 MT

10 (3/8") 3.2 MT 3.3 MT 4.4 MT 6.7 MT

13 (1/2") 5.4 MT 5.6 MT 7.5 MT 11.3 MT

16 (5/8") 8.0 MT 8.4 MT 11.2 MT 16.8 MT

19 (3/4") 12.5 MT 13.1 MT 17.5 MT 26.3 MT

22 (7/8") 16.0 MT 16.8 MT 22.4 MT 33.6 MT

26 (1") 20.0 MT 21.0 MT 28.0 MT 42.0 MT

32 (1-1/4") 32.0 MT 33.6 MT 44.8 MT 67.2 MT

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TABLE NO. 3

MASTER LINK SAFE WORKING LOADS

Single Master Link Master Link AssemblyStock Diameter (one or two sling legs) (three or four sling legs)

Safety Factor = 6:1 Safety Factor = 3.5:1

13 mm (1/2") 1.8 MT --

16 mm (5/8") 2.5 MT --

19 mm (3/4") 3.9 MT 4.8 MT

26 mm (1") 9.2 MT 8.6 MT

32 mm (1-1/4") 13.3 MT 15.2 MT

38 mm (1-1/2") 18.1 MT 24.0 MT

45 mm (1-3/4") 23.6 MT 34.5 MT

51 mm (2") 36.9 MT 47.2 MT

57 mm (2-1/4") 45.1 MT --

64 mm (2-1/2") 55.7 MT --

70 mm (2-3/4") 67.4 MT --

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TABLE NO. 4

INSTALLATION OF WIRE ROPE CLIPS

Wire Rope Minimum Rope Turn back Torque

Diameter No. Clips From Thimble

6 mm (1/4") 2 121 mm 2 kgm (15 ft-lb)

9 mm (3/8") 2 165 mm 6 kgm (45 ft-lb)

13 mm (1/2") 3 292 mm 9 kgm (65 ft-lb)

16 mm (5/8") 3 305 mm 13 kgm (96 ft-lb)

19 mm (3/4") 4 457 mm 18 kgm (130 ft-lb)

22 mm (7/8") 4 483 mm 31 kgm (225 ft-lb)

25 mm (1") 5 660 mm 31 kgm (225 ft-lb)

29 mm (1-1/8") 6 864 mm 31 kgm (225 ft-lb)

32 mm (1-1/4") 6 940 mm 50 kgm (360 ft-lb)

38 mm (1-1/2") 7 1219 mm 50 kgm (360 ft-lb)

51 mm (2") 8 1803 mm 104 kgm (750 ft-lb)

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3.6 TRANSPORTATION & PERSONNEL TRANSFERS

Transportation & Personnel Transfer Foreword

This section contains guidelines for transporting cargo and personnel to and from offshore sites.For more detailed guidelines when transferring personnel from an offshore facility, refer toEMPC Safety Manual.

Safety of personnel is the primary objective when moving personnel and cargo offshore. Whenthere is doubt about any aspect of personnel safety, transfers must not occur until the hazard(s)causing the doubt are eliminated or effectively managed.

For most operations, helicopters will be the preferred means of transporting personnel betweenShore Base and the rig. Supply vessels may be the primary means on some operations and maybe used on other operations if weather conditions prohibit helicopter flights. Transfers shouldonly be made during calm sea conditions (i.e., 5 feet or less).

3.6.1 CARGO TRANSPORT

Supply Vessels

1. Coordinate the loading and unloading of the supply vessels at the base through theMaterials Supervisor.

2. Notify the Materials Supervisor of the cargo type and the expected arrival time to ensureefficient handling of equipment and tools at the Base.

3. All returned material must be shown on a Material Transfer Cargo Manifest (MTCM)and sent on the supply vessel with the materials showing the following information:

• Description of Item

• Condition of Item (1 -New, 2 -Used, 3 -Needs Repair,4 - Junk)

• Owner of Item (Affiliate or Contractor Name)

• Disposition of Item (return to stock, return to Contractor, repair)

Note: Any hazardous cargo is to be clearly marked as such on both the MTCM and theitem container.

Note: Separate MTCMs should be used for different material owners, i.e., rental tools tobe returned to different Contractors should be shown on separate manifests.

4. All cargo on supply vessel decks departing the base shall be secured.

5. Weather permitting, all cargo on supply vessel decks departing from offshore shall besecured.

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6. Vessels shall have gates across their stem at all times except when handling anchors orsetting out buoys.

7. No individuals shall be allowed on the deck of supply vessels while the vessel isunderway or standing by when there is cargo on deck.

8. Tubulars 5" and smaller shall be pre-slung in appropriate numbers per bundle bothoutbound and inbound.

Helicopters

1. Transport of cargo via helicopters is limited to small lightweight items unless critical tothe operation. Proper approvals must be in place prior to transporting any cargo otherthan small lightweight items. Typically, procedure/equipment used for airlift of heavy,non- standard items will require consultation with Aviation Department contact and FieldDrilling Manager.

2. Potentially hazardous material such as batteries, paints, acidic or corrosive chemicals, etc.are not to be transported via helicopter.

3. An accurate cargo and weight manifest for all helicopter transportation, includingpassengers, must completed prior to boarding (OIMS Manual Element 6).

3.6.2 HELICOPTER OPERATIONS

Helideck

1. Pilots are to lock brakes while on the helideck if the helicopter has wheels.

2. Helideck is to have rope mats or non-skid surface.

Note: Rope mats must be of the proper size to avoid entanglement of helicopterskids/wheels.

3. Rope mats must be securely tied down.

4. Helideck must be marked clearly with landing circle and have the location name clearlyvisible from the air.

Landing & Takeoff

1. Only the Jack-Up helideck shall be used for helicopter operations. Any exception to usethe platform's helideck must be cleared with Operations Superintendent & Production.

2. All cranes are to be shut down 10 minutes prior to landing/takeoff (OIMS ManualElement 6).

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3. Supply boat/standby boat should be off anchor and ready to respond during landing anddeparting.

4. Fire stations are to be manned with a trained fire team ready to respond whenever ahelicopter is landing, refueling, or departing, and during engine startup/shutdown. (OIMSManual Element 6).

5. Helideck is to be cleared of all arriving/departing passengers and/or cargo prior tomoving passengers and/or cargo onto the helideck for boarding.

6. Notify Shore Base of Helicopter arrivals and departures. (OIMS Manual Element 6).

Note: Shore Base is responsible for the "Flight Tracking System". (OIMS ManualElement 6).

7. Trained personnel shall be designated to initially approach helicopters after landing toopen and shut the helicopter's doors and then only after receiving permission from thepilots.

8. An announcement shall be made of all helicopter landing/departure on the rig's publiccommunication system (OIMS Manual Element 6).

Refueling -Emergency Situation Only

1. Shut down the helicopter, clear the helideck of all non-essential personnel and man thehelideck fire fighting equipment during refueling operations. (OIMS Manual Element 6).

2. Only use approved refueling equipment.

3. Pilots are to personally:

• Supervise the refueling operation.

• Test fuel for water and sediment immediately prior to refueling.

• Ground helicopter with an approved ground wire during refueling operations.

4. All refueling equipment is to be maintained in excellent condition.

5. Helideck fire fighting systems will be manned during refueling operations (OIMSManual Element 6).

3.6.3 PERSONNEL TRANSPORT-HELICOPTER

Scheduling & Manifests (OIMS Manual Element 6)

1. A fax will be sent to the Shore Base Dispatcher the day before flights, except inemergencies, listing;

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• Passengers names

• Company Affiliation

• .Weight of Passenger and Baggage

2. Offshore bound fax lists will be sent from the Shore Base and shore bound fax lists willbe sent from the offshore site.

3. Manifests will accompany all flights listing the passengers and their Company; (OIMSManual Element 6)

a. Outbound Flights: Manifest will be prepared by Shore Base Dispatcher and acopy given to the offshore site dispatcher upon arrival of the helicopter.

b. Inbound Flights: Manifest will be prepared by Offshore Site dispatcher and givento the helicopter prior to its departure from offshore.

4. Helicopters are not to be scheduled at night unless a medical emergency exists (somegeographic night flights may be necessary due to limited daylight hours).

Responsibilities

Helicopter Passenger

1. Approach the helicopter from the 3 or 9 o'clock position only after directed by the pilot.

2. Wait for escort at rig/shorebase prior to embarking/disembarking.

3. Walk as close to the nose of the helicopter as possible when crossing in front of thehelicopter paying attention to pivot tubes which may be hot.

4. Never walk under the tail section or around the rear of the helicopter.

5. Wear PFD's or inflatable life jackets while on the helicopter when flying over water.

6. Fasten seat belts before takeoff and keep seat belt on until the helicopter arrives at itsdestination.

7. Never move about the cabin when the helicopter is in flight.

8. Be certain that the helicopter landing is complete before unfastening the seat belt.

9. Do not smoke any time while on or near the helicopter.

Helicopter Pilot

1. All passengers will be given a safety orientation/ditching instructions prior to boardinghelicopters at the shore base location. (OIMS Manual Element 6)

MARINE OPERATIONS


2. Instruct passengers to remain on board until the rotor blade is at a complete stop ifshutting down the helicopter.

3. Load and unload passengers with the rotor blade in motion only after announcing to thepassengers that the helicopter will not shut down and to proceed with caution.

Offshore Installation Manager

1. Ensure passengers sign in and record body weight and luggage.

2. Ensure manifest is complete. (OIMS Manual Element 6)

3. Ensure personnel meeting helicopters (i.e., fire teams and dispatchers) are trainedpersonnel, properly organized, and in position prior to helicopter arrival/departure.

4. Ensure that a public announcement is made prior to all helicopter landing/departures.(OIMS Manual Element 6).

3.6.4 PERSONNEL TRANSPORT -SUPPLY OR STAND-BY BOAT

In general, the preferred method of transport, even in an emergency, is via helicopter. However,when boats are used, a JSA should be prepared and reviewed with all personnel prior toboarding.

3.7 MARINE TRAINING

3.7.1 GENERAL

Marine Drill Objective

The objective of marine drills on a mobile offshore drilling unit is to train all onboard drillingcontractor personnel (i.e., night and day crews) to respond appropriately when faced with anemergency situation. An equally important objective is to train and ensure that all other on-boardpersonnel (typically temporarily or transient to the rig) how to identify emergency signals, howto respond, and how to safely evacuate.

General Marine Training Guidelines

1. Ensure that each drill demonstrates crew's ability to respond to an emergency andcorrectly operate required safety equipment.

2. Schedule drills to allow full participation of crews while minimizing interference withdrilling operations.

3. Plan drills, which simulate realistic emergencies and demonstrate necessary steps tomitigate a real emergency.

MARINE OPERATIONS


4. Ensure that each drill crew member understands their emergency designated assignmentfor drill scenario (i.e., securing well).

5. Walk through drills and coach key personnel as necessary to ensure crew is familiar withtheir designated assignments and that all others know signals, muster points, andevacuation procedures.

6. Utilize announcements over public address system as necessary.

7. Hold a discussion session after completing drill and critique areas for improvement.

8. Each drill, including a group discussion and critique, should take approximately onehour.

3.7.2 REPORTING & DRILL FREQUENCY

Reporting

1. Record all drills on Daily Drilling Report.

2. Record all drills on Daily IADC Report.

3. Forward a Marine Emergency Drill Report Form to the Operations Superintendent.

Note: See the "Blank Form" in this manual (Section 3 -Appendix G-III) for the MarineEmergency Drill Report Form.

Marine Drill Frequency

1. "Fire Drills" -Initial drills as required to plan and organize Fire Fighting Squads andweekly thereafter.

Note: Conduct fire drill during hours of darkness and/or hold drill without priors noticeto crew once every month.

2. "Abandon Rig Drills" -Frequently until all personnel know their stations and theabandonment procedure and muster checks are satisfactory (i.e., all personnel report tomuster points). Conduct the drills weekly thereafter.

Note: Conduct" Abandon Rig Drills" during hours of darkness and/or hold drill withoutprior notice to crew once every month.

3. "Man Overboard Drills" -Initially as required to plan and organize Response Teamsand every two weeks thereafter.

Note: Conduct man overboard drill during hours of darkness and/or hold drill withoutprior notice to crew once every month.

MARINE OPERATIONS


4. "Specialized Drills" -As required to train designated response teams to ensure teammembers are proficient at their assigned duties. This type of training does not in itselfsatisfy the requirement for weekly drills since only part of crew participates. It is,however, valuable in developing a well-trained crew.

Note: Hold Fire Drill and Abandon Rig Drill concurrently as a weekly drill whenpractical.

Note: Conduct training in the use of rescue equipment and assignment of duties in lieuof man overboard drills on days of inclement weather.

3.7.3 MARINE DRILL PROCESS

Marine Drill Process

Plan Drill: Carefully plan drills to focus on training for a particular need.

Conduct Drill: Realistic drills simulate an actual condition and require crews toperform as though an actual emergency situation existed.

Critique Drill: Discussion: session will identify problem areas and help identifyareas for improvement.

Marine Drill Planning Guidelines

1. Design each drill to emphasize a single aspect of responding to an emergency situation.This should increase the chance of this aspect being recalled during an emergency.

2. Emphasize the principal aspects listed in Section 3.7.1 during the drills.

3. Choose appropriate location to emphasize a particular aspect during drill.

4. Write down scenario for the drill and distribute to the various team leaders.

5. Follow through with planned drill trying not to change conditions of the drill

6. Vary day and times of drills to ensure that all crew members are prepared to reactefficiently to a real emergency.

7. When practical, plan safety meeting to follow a drill to encourage discussion of drill.

Marine Drills Guidelines

1. Avoid exposing crew or Jack-Up to situations that may place them in jeopardy.

For example, do not use toxic gases when training crew members in the use of self-contained breathing apparatus nor start fires to test fire fighting system.

MARINE OPERATIONS


2. A void placing crew in high risk situations; however, avoiding all risk should not be thebasis for failing to test some safety equipment.

For example, launching lifeboats in mild seas can entail some risk; however, this risk isacceptable since operating this equipment increases the chance of successful deploymentin a real emergency.

Critiquing Guidelines

Ensure that key supervisory personnel critique drill and lead a discussion, which focuses on theprincipal aspect of drill immediately following all drills. All Jack-Up personnel should beencouraged to participate in the discussion session following a drill.

Critique and discussion sessions should:

• Review the emphasis of drill.

• Discuss problems, which occurred during drill.

• Assess whether drill focused on the particular aspect as planned. Determine if drillwas conducted in realistic manner.

• Discuss situations that could have developed if this had been a real emergencysituation.

• Establish agreed upon areas for improvement that need practice during future drills.

3.7.4 FIRE DRILLS

Purpose of Fire Drill

Prepare Response Teams (i.e., Fire Fighting Squads) for mitigating a fire and rescuing injuredand/or trapped personnel. Also, demonstrate that members of the Fire Fighting Squadsunderstand their designated assignments and perform them in an acceptable manner.

Fire Fighting Squad Members

• One (I) Fire Fighting Squad leader

• Four (4) Fire Fighters

Fire Drill Guidelines

1. A five person Fire Fighting Squad is to be organized for each 12-hr shift.

2. Each member of Fire Fighting Squads must have on the job training.

3. The Fire Fighting Squad Leader must have completed a fire fighting training course.

4. Assign the on-board medic to a Fire Fighting Squad as practical.

MARINE OPERATIONS


5. One member on each Fire Fighting Squad is to be appointed assistant Squad leader.

6. Off-duty personnel should participate in this drill when feasible.

7. Conduct an unannounced fire drill and/or night drill once every month

8. Drills should include a mock injury and/or a rescue situation.

9. Occasionally designate the Squad leader as the injured person during a rescue situation sothat assistant Squad leader is leading the Fire Fighting Squad.

10. Fire locations should be varied.

Fire Drill Procedure

The following steps constitute an effective fire drill:

1. The observer of the fire should sound the alarm and advise the facility of the location ofthe fire.

2. The Person In Charge (PIC) or his delegate should immediately go to the pre-designatedcommand center (e.g., radio room, bridge, control room, etc.).

3. The rig communication equipment and procedures are to be tested by alerting designatedshore base that a "fire drill" is in progress.

4. The Fire Fighting Squads are to muster at the scene of the fire.

5. The Person In Charge (PIC) or his delegate will notify the drill crew to secure the welland activate the Emergency Shut Down (ESD)/Deluge system.

6. Drill crew secures well (i.e., when drilling/tripping, position pipe to well shut-in positionand close BOP except when in open hole).

7. Mobilize a stand-by boat or supply vessel, if available, to a standby position.

8. Communicate reports during each phase of drill to designated "command center"

9. All personnel not involved in fighting the fire or in critical rig operations are to muster attheir designated muster stations.

10. A muster shall be taken to ensure that all personnel are accounted for and the resultsreported to the Person In Charge (PIC).

11. The Fire Fighting Squad response is to include a simulation of actions necessary tomitigate the fire if an actual emergency was in progress.

12. Squad leader is to communicate hazardous material situations to Person In Charge (PIC)or his delegate.

MARINE OPERATIONS


13. Designated personnel are to standby for action necessary to support Fire Fighting Squad.This will include such duties as stretcher bearers, etc.

14. Post a fire watch after fire is out to guard against ignition.

15. Person In Charge (PIC) is responsible for de-watering operations and monitoring standbyvessel throughout fire fighting operations.

16. Squad leader is to prepare a critique after fire drill and hold a discussion session.

17. Complete the Drill Report and forward to the Operations Superintendent.

3.7.5 FIRE DRILL -EXAMPLE

SCENARIO

DATE/TIME: 4-25-84/0030 LEVEL: Serious

LOCATIONS: Cementing Room FIRE: Class B w/heavy smoke

INJURED: No.2 LOCATION: Trapped in space near fire

EMPHASIS: Effective search for missing crew members.

FIRE SCENARIO: Leaking fuel line sprays diesel on manifold causing fire to engulf engine.Two operators seek refuge in office whose only exit is on fire.

CONDUCT

SOUND ALARM - Sound Alarm

- Announce Drill -Fire location.

- Check Communications. Call shore base & boats.

ASSEMBLE - Unassigned crew to muster at assigned areas.

- Call Roll at Jack-Up abandonment stations.

- Notify Person In Charge (PIC) of anyone missing from roll.

- Fire crew to assemble near fire area.

INVESTIGATE - Assigned fire team member to check fire area.

- Brief fire team on fire conditions.

- Call for rescue party -include medic.

MARINE OPERATIONS


RESTRICT - Fire Crew to contain fire to allow rescue of injured.

RESCUE - Rescue crew to move injured to safe area.

- Medic to attend injured personnel.

EXTINGUISH - Deploy fire teams to extinguish fire.

- Extinguish Fire.

CRITIQUE

DISCUSS - Assemble all supervisors and fire fighting squad.

- Discuss objective of drill - was it accomplished?

- Discuss any procedure or equipment problems.

REPORT - Complete Drill Report and send copy to office.

- Document drill in IADC and Daily Drilling Report

- Forward Drill Report to Operations Superintendent.

3.7.6 ABANDON RIG DRILLS

Purpose of Abandon Rig Drill

Ensure that rig personnel can perform their assigned duties and demonstrate operation oflifeboats and associated equipment and that all on-board personnel (especially non-Rigcontractor personnel) know how/when to safely muster and evacuate.

Minimum Life Boat Complement:

• One (I) Boat Commander -Certified as Commander

• One (I) Release Mechanism Operator -Certified as Life Boatman (Coxswain)

• Two (2) other crew members -Certified as Life Boatman (Coxswain)

• One (I) Electrician or Mechanic -Operate the life boat winch

In order to assist in reconnection of lifeboat lowering lines after drill is complete and to assist incorrecting unforeseen mechanical problems, this is the minimum complement required for drilllaunching.

MARINE OPERATIONS


Abandon Rig Drill Guidelines

1. Ensure that rig radio frequencies, rig location, and headings to safe refuges are posted ineach lifeboat.

2. Occasionally hold drill without prior notice to crew.

3. Partially lower (i.e., 10-15 feet) all lifeboats once each week, weather permitting.

4. Launch lifeboats, navigate in open water, and retrieve monthly if possible but at leastonce per quarter.

5. Only launch lifeboats during reasonable weather/sea conditions and when asupply/standby vessel is prepared to rescue if necessary.

6. Conduct an unannounced abandon rig drill and/or night drill once every month, and atleast once per month, the drill should include a mock injury or a rescue situation.

7. Personnel are not required inside lifeboat while partially lowering and raising.

8. Test engine and sprinkler system on lifeboats weekly when water can be supplied.

9. Do not lower a lifeboat into water until engine(s) is running.

10. Ensure that a minimum of four (4) men are in lifeboat when launched.

11. Man lifeboat winches with qualified individual (e.g., rig electrician or mechanic) duringlaunching and recovery of the lifeboats.

12. Simulate securing the well and activating the rig ESD/Deluge system.

The following steps constitute an efficient Abandon Rig drill:

1. Ensure that a supply/stand-by vessel is moved to the vicinity of lifeboat landing area priorto lowering lifeboat if actual launching is to be conducted.

2. Sound designated alarm for abandon rig. The type of alarm is on rig station bills innumerous locations. Announce that this is a drill over public address system.

3. Rig communication equipment and procedures are tested by alerting designated shorebase that a "Lifeboat Launching Drill" is in progress.

4. All personnel are to report promptly to their station bill assignment and collect theirabandonment cards from the card holder unless excused to continue operations. Excusesrequire prior approval of the Operations Supervisor and are by exception only.

5. All personnel are to wear appropriate attire and carry survival gear to drill (i.e., either lifejacket or survival suit depending on environment).

MARINE OPERATIONS


6. Life Boatmen prepare Life Boat for boarding (i.e., attach grips and safety pendants),

7. Personnel enter Life Boat following instructions by Boat Commander and fasten theirseat belts immediately.

8. Persons whose cards remain in the cardholders at the abandonment stations are located.

9. Radio contact is made before launching and maintained at all times on a predeterminedclear frequency between Boat Commander and Person In Charge (PIC) or his delegatewho has overall charge of drill.

10. Engine(s) is started and operated for several minutes.

11. Boat Commander is to explain the operation and lowering procedure.

12. If NOT LAUNCHING the Life Boat, all personnel aboard the Life Boat are to exit in anorderly fashion and muster for drill discussion.

13. If LAUNCHING the Life Boat, all personnel aboard the Life Boat except the "MinimumLife Boat Complement" are to exit in an orderly fashion and muster for drill discussion.

14. Boat commanders are to ensure a clear landing area below lifeboat before lowering.

15. Once lifeboat leaves davits, no one other than the Boat Commander shall do anything toaffect lowering of lifeboat.

16. The order to release lifeboat from lowering lines shall not be given by anyone other thanthe Boat Commander and shall not be given by him until he ensures by visual means thatlifeboat is waterborne.

17. Boat Commander will release and maneuver lifeboat away from rig to a pre- designatedrallying point. As practical, operate all equipment to ensure proper functioning.

18. Boat Commander is to maneuver lifeboat along side of rig, attach lowering line hooks tolifeboat.

19. Raise lifeboat back up to davits and secure before personnel exit lifeboat.

20. Boat Commander is to conduct a verbal critique with his crew upon completing drill.Discussion should focus on areas for improvement and alternate abandonmentprocedures.

21. Person in charge is to critique drill with Boat Commanders.

MARINE OPERATIONS


3.7.7 ABANDON RIG DRILL -EXAMPLE

SCENARIO

DATE/TIME: 4-25-84/0030 LEVEL: MAJOR

LOCATIONS: Aft lifeboats FIRE: None

INJURED: No. 0 LOCATION:

DAMAGE: Forward lifeboat inoperable

EMPHASIS: Orderly abandonment with one lifeboat damaged.

SITUATION: Storm has damaged forward lifeboat and vessel is listing. Abandonmentmust utilize aft lifeboat and two life rafts.

CONDUCT

SOUND ALARM - Sound Alarm.

- Announce forward boat not operable.

- Check Communications. Call shore base/boats.

ASSEMBLE - Muster at aft boat area.

- Board Life Boat shifting fwd crew to rafts.

- Call Roll.

- Search for persons missing from roll.

LAUNCH BOATS - Instruct on Launching Boats.

(Simulate) - Operate All Equipment.

- Start Engine.

- Instruct on Alternate Abandonment.

LAUNCH BOATS - Disembark all personnel except life boat crew (4).

(Actual) - Station Electrician at winch.

- Launch lifeboat.

MARINE OPERATIONS


CRITIOUE

DISCUSS - Assemble all supervisors and lifeboat commanders.

- Discuss objective of drill -was it accomplished?

- Discuss any procedure or equipment problems.

REPORT - Complete Drill Report and send copy of office.

- Document drill in IADC and Daily Drilling Report.

3.7.8 MAN OVERBOARD DRILL

Purpose of Man Overboard Drill

Ensure that rig personnel can perform their assigned duties when someone goes into water.

Rescue Team Members:

• One (I) Rescue team leader

• One (I) Rescue Boat Commander

• One (I) Rescue Boat Release Mechanism Operator (Coxswain)

• Two (2) other crew members who are qualified Coxswains

• One (I) Electrician or Mechanic to operate rescue boat winch

Man Overboard Drill Guidelines

1. Organizes a (6 man) Rescue Team for each crew.

2. As practical, assign the rig medic to one of the Rescue Teams.

3. Plan drills to emphasize key point(s) or areas for improvement.

4. Only launch rescue boat during reasonable weather and sea conditions when asupply/standby vessel is prepared to rescue if necessary.

5. Conduct an unannounced man overboard drill and/or night drill once every month, and atleast once per month, the drill should include a mock injury or a rescue situation.

Man Overboard Procedure

The following steps constitute an efficient Man Overboard drill:

MARINE OPERATIONS


1. To simulate a man overboard, throw buoyant dummy into water that is the approximatesize, shape and weight of a man.

2. Pass the words "Man Overboard" upon throwing dummy overboard.

3. Post a look-out(s) at the best point possible with binoculars whose sole responsibility is tokeep sight of the person overboard, as long as possible, and continually point toward him.

4. Rig communications equipment and procedures are tested by alerting designated shorebase that a "man overboard drill" is in progress.

5. Throw a life ring in the vicinity of man overboard (i.e., buoyant dummy) as soon aspractical. Periodically, use lights and smoke flares to add realism to drill.

6. Person in charge is to muster Rescue Team at rescue boat. The rig medic is to providefirst aid to man overboard.

7. If a supply or stand-by vessel is available, notify vessel for assistance. Vessels are todeploy scramble nets as soon as practical.

8. If retrieval is possible by crane, crane operator is to lower a personnel basket with twocrew members, wearing lifejackets, to retrieve the man overboard.

9. When weather permits, launch rescue boat and retrieve Man Overboard. Ensure that theElectrician or Mechanic is operating the rescue boat winch on the rig. In this scenario,assume individual(s) are not able to assist themselves and determine the suitability ofretrieval tools and techniques to recover an injured or unconscious individual after goingoverboard. Assess suitability of technique if weather conditions were significantly worse.

10. If rescue boat is not launched, retrieve Man Overboard dummy with supply/standbyvessel.

11. Muster entire crew to a pre-designated location. Perform roll call to determine thenumber and names of missing crew member(s). Report results to person in charge.

12. Upon completion of drill, make appropriate log entries including the time required torecover the man overboard.

13. Rescue Team Leader is to prepare a critique and hold discussion session with the RescueTeam and rig Personnel.

3.7.9 SPECIALIZED DRILLS

Purpose of Specialized Drill

Involve response teams and/or small groups of crew in specialized training so that training canfocus on specific skills in areas that need improvement and develop effective response teams.

MARINE OPERATIONS


Some examples of the types of skills suited to this training are:

• Life boat Launching -Small number of the crew launch and operate the boat.

• Rescue Operations -Rescue Teams practice man-overboard drill or rescue or firevictim.

• Helicopter Fires -Fire Fighting Squad tests foam systems for a helicopter fire.

• Ballast Control -React to failed equipment.

• Specialized Fires -Fire Fighting Squad practices mitigating a fire in an enclosed spaceusing breathing equipment.

MARINE OPERATIONS


3.7.10 PRINCIPAL ASPECTS OF DRILLS

Drill scenarios should empathize skills listed below.

Abandon Rig Drills:

Coordinating communication

Abandoning -one lifeboat disabled

Abandoning -escape routes blocked

Operating lifeboats in a sea lane

Muster & personnel accountability

Fire Drills:

Coordinating communication

Coordinating Fire Fighting Squads

Coordinating Rescue Teams

Handling Complex Fire Situations:

• Enclosed spaces

• Limited access

• Combination of the above

• Fighting different fire types

• Injured personnel

Use of Equipment such as:

• Breathing Equipment

• Stretchers

• Fire hoses

• Radios

Man Overboard Drills:

Initial response for man overboard

Using life boats and rescue boat

Administering first aid

Coordinating Communications

Coordination of other craft in the area

Posting and maintaining lookout

3.8 SHIP COLLISION AVOIDANCE

Ship Collision Avoidance Foreword

Drilling Units should not be located near a shipping lane nor between shipping lane boundaries ifpossible. If necessary, directional wells can be drilled to avoid these areas. If a Drilling Unitmust be stationed in such an area, the risk assessment for the operations must include theproximity of the Drilling Unit to ship traffic areas.

MARINE OPERATIONS


All proposed Drilling Unit locations should be researched for shipping lane proximity and trafficin the area and appropriate "Detection Procedures" prepared and risk assessments completed.

The only way to avoid collisions is to spot errant ships early and issue warnings. Procedures andguidelines described below should be followed.

3.8.1 DETECTION

General Detection Guidelines -For MODU in or near shipping lane

All personnel on-board the Drilling Unit are responsible for vigilance in detecting errant shipsapproaching the site. However, the level of formal detection program implementation willdepend on the proximity of the Drilling Unit to shipping lanes and/or heavy ship traffic. Thereare many "unofficial" shipping lanes used by ships as short-cuts and some detection program isalways necessary.

1. Ensure all radar reflector beacon systems are functional at all times.

2. During foggy conditions, post a radar watch on the Drilling Unit.

3. Continuous 24-hour radar watches and/or standby vessels should be used when in thevicinity of high ship traffic and shipping lanes.

4. Radar watch and/or standby vessel watch procedures when operating in close proximityto ship traffic should be completed and approved by the Field Drilling Manager toinclude;

• Action plans for different approach radar and ship course headings. Shipnotification plans

• Abandonment procedures

5. Ensure that all navigational aids (lighting and foghorns) are operational.

6. Advise all Drilling Unit personnel during Safety Meetings to be on the lookout forapproaching ships.

7. Immediately notify the Offshore Installation Manager after spotting questionable ships orvessel approaching

8. A sonar pinger will be installed and operational at all times once the rig is positioned.

3.8.2 RADAR WATCH PROCEDURES

In areas of high risk, i.e., near shipping lanes or heavily traveled routes, radar proceduresdescribed below should be implemented on the drilling unit.

Radar Operation

MARINE OPERATIONS


1. The Drilling Unit's radar installation is to be located:

• In an area providing visual contact with the surrounding outside seas, i.e.,bridge, etc.

• Away from heavily traveled and noisy areas, i.e., not to be located in a radioroom. Near VHF Marine radio.

2. Qualified and trained radar operators are to man the radar station 24 hours per day and berelieved by qualified marine personnel at least every 3 hours for breaks.

3. Radar unit settings shall be maintained as follows:

• Primary scanning set to 12 nm.

• Audio alarm set for 5 nm.

• Inner Guard Ring set for 2 nm.

4. Radar Watch Operator's duties shall include:

• Continuously man the radar station except when relieved for breaks.

• Maintain radar unit settings described above.

• Track all ships within a 12 nautical mile range and determine their courseheading.

• Contact ships reaching 5 nautical mile range of Drilling Unit's position andrequest ships maintain 2 nautical mile separation.

• Maintain logbook of all contacts with ships.

Alert Procedures

1. Ships within the 12 nautical miles primary radar range will be marked with the "EBL" bythe Radar Operator who will track the vessel heading and determine the course heading.

2. Ships reaching the 5 NM range will be contacted by the Radar Operator:

Radio Contact Established

• Verify the vessel crew is aware of the Drilling Unit installation's position.

• Confirm that the vessel is not in mechanical difficulty.

• Request the vessel maintain a 2 nautical mile separation from the DrillingUnit.

MARINE OPERATIONS


Radio Contact Not Established

• Radar Watch Operator will notify the Offshore Installation Manager (OIM).

• OIM will dispatch supply/standby vessel to attract the ship's attention (e.g.,fire hose, ships horn, radio).

3. Ships reaching the 4 NM range and on a course:

Radar Watch Operator

• Notify the OIM.


• Contact the vessel to divert its course and/or determine if ship has mechanicaldifficulty.

• Notify the Operations Supervisor on duty that a collision is possible.

• Notify supply/standby vessel to intercept ship.

4. Ship reaching the 4 NM range and on a collision course which cannot be contactedand/or has mechanical difficulty (engine/steering failure):


• Notify supply/standby vessel to return to rig if ship cannot be intercepted.

• Notify the Operations Supervisor on duty.

• Sound alarm and muster rig personnel at their abandonment stations.

Operations Supervisor

• Notify Drill Crew to secure the well.

• Notify Shore Base that a collision is possible and imminent.

5. Ships reaching the 2 NM range radar guard ring on a collision course:


• Determine need for abandonment.

• Sound the abandonment alarm for the Drilling Unit.

• Broadcast navigational warnings continuously.

MARINE OPERATIONS


• Notify supply/standby vessel to assist in rig abandonment.

• Abandon rig.

MARINE OPERATIONS


SECTION 3 - APPENDIX G-I

MEMORANDUM

ExxonMobil Development Co. DrillingDATE: TO: PRODUCTION AND DRILLING OPT. SUPTSFROM: OFFICE ENGINEERING TEAMSUBJECT: " " Platform Drilling Program SIMOPS/MIRU Meeting

BACKGROUND

The jack-up drilling rig is scheduled to begin operations at the " " Platformon about . On , a SIMOPS meeting was held to evaluate the risksinvolved with simultaneous drilling and production operations at the platform. Following is a summary of thereview of the SIMOPS Move-In/Rig-Up Checklist for Jack-Up Drilling Rigs.

SIMOPS MIRU CHECKLIST REVIEW

1) A mudline survey with divers and/or side scan sonar may be necessary to check for any obstacles ordebris that might be in the immediate area where the rig is to be positioned. Determine if areapipelines need to be buoyed for the planned approach of the rig. At those platforms where a jack-up righas previously operated, the footprint of the rig is to be studied to determine if it can be reused.(NOTE: The side scan sonar is typically performed if a jack-up rig has not been at the location within12 months, or if any substantial construction or workover work has been performed within the lastyear). Note, if any pipelines are within 490 ft of the rig, the MMS requires buoys, unless a waiver isobtained. Global positioning is usually sufficient to obtain a waiver unless the spud cans are very close(~50 ft) to the pipeline.

•2) Evaluate the punch-through potential of the rig legs.

•3) Evaluate the platform leg batter and positioning of dolphins for potential interference with rig legs.

Drilling/Subsurface engineering will provide scale drawings of the rig, spud cans, etc.•

4) Review the location of all pipelines, underwater flare lines, process equipment vent lines, pipelinerisers, etc. and determine if any relocation or protection work is necessary. Active pipelines that areexpected to be located beneath the jack-up barge shall be depressurized during the MOB/DEMOB. Forthose lines to be reactivated following MIRU, a joint decision by Drilling and Production OperationsManagement is made regarding any special precautions necessary to ensure that an appropriate levelof safety is maintained.

•5) Determine if the main deck production processing equipment located beneath the cantilever requires

protection or relocation. (NOTE: There are to be no unprotected pressurized process vessels, such asseparators, glycol contact towers, etc., located beneath the cantilever, nor any gas venting in this area).

•6) Unprotected process equipment located within 10 ft. of the cantilever shall have a fire monitor,

operated from the rig, directed on it.•

7) Locate all fire protection equipment stations on the main deck, and determine if they require relocation.•

8) If the platform has a firewater system, ensure that it is operable and meets the deliverabilityrequirements for that facility.

•

MARINE OPERATIONS


9) Ensure that the location of the rig's designated safe welding area meets all MMS and ExxonMobilregulations (consider distances from existing combustible material or any process equipmentcontaining hydrocarbons).

•10) A scale drawing depicting platform/rig equipment layout shall be developed highlighting the designated

safe welding area, as well as areas in which Hot Work is prohibited.•

11) Inspect all platform deck grating, plating, boards, and handrails, and arrange for repair orreplacement as needed.

•12) Ensure that all aids to navigation are operating properly.

•13) Record all casing pressures on both producing and non-producing wells. This information is

transmitted to the Drilling or Workover Engineer.

• Casing pressures on ALL are as follows:

Well Name Inside Drive Pipe Inside Conductor Inside Surface

Note: NA means that there is no pressure seal & gauge on the annulus.

14) Review with the Field Superintendent the rig move schedule to coordinate Production Operations whilethe rig is being mobilized/demobilized and cantilevered into position over the platform.

•Field Supts: & , x- or

EMDC Drilling Supts: at ( ) -

15) A scale drawing showing the position of the rig and cantilever in relation to the platform processequipment, fire protection equipment, lighting, escape routes, etc. is developed and distributed.

•16) Ensure the contractor crane complies with the inspection requirements of API RP2D. Documentation

of this inspection is required.•

17) An Emergency Evacuation Plan (EEP) data sheet is completed and submitted for approval to the localOfficer in Charge of Marine Inspection of the United States Coast Guard prior to spud. The FieldSuperintendent shall gather the data for the EEP and forward it to the Regulatory Affairs Engineer.

•18) If the rig is located on a platform with production quarters, the rig's emergency alarm system is

connected to the production alarm system and these alarms are to be compatible.•

19) Ensure that sufficient emergency lighting is available at all living quarter exits, along escape routes,and at the escape capsules to provide safe transit to the muster areas.

•

MARINE OPERATIONS


PERSON IN CHARGE (PIC)

• The will be the PIC. The Drilling and FieldSuperintendents will work together to coordinate tying the rig and platform ESD systems together, utilizingthe I&E Technician, per the SIMOP's Manual.

• The PIC and Field Superintendent should communicate each day prior to the 6:00 AM Production safetymeeting regarding safety issues and work status.

APPROVALS

Drilling Ops. Supt. Production Ops. Supt.

SIMOPS Meeting Attendees:

MARINE OPERATIONS



US-EAST SIMULTANEOUS OPERATIONS DEVIATION REQUEST

DATE:LOCATION:ORIGINATOR:FIELD PIC:TYPE OPERATION:TYPE ACTIVITY:REQUIREMENT NO:IDENTIFY TYPE OF REQUIREMENT: MMS MUST SHOULDDURATION OF DEVIATION: FROM TO

DESCRIPTION OF DEVIATION:

SPECIAL PRECAUTIONS TAKEN:

APPROVAL REQUIRED:FIELD SUPERINTENDENT: ORIGINATOR'S OA ID:

SECTION 3 – APPENDIX G III

DRILLING OPERATIONS MANUAL - JACK-UP / PLATFORM / BARGE 1 of 10First Edition - May, 2003

MARINE OPERATIONS


SECTION 3 – APPENDIX G-IV

PRE-STARTUP INSPECTIONS FOR NEW TO FLEET JACKUP DRILLING RIGS

1.0 Purpose

To document current practice of compliance with the Mobile Offshore Unit Marine Safety Sectionof the ExxonMobil Upstream Design Guidance Manual

1.1 Inspection of Critical Marine and Emergency Equipment / Marine Safety Survey

These inspections ensure that the MOU equipment complies with the Upstream Design GuidanceManual, is maintained, and is operational. Additionally, it will address personnel competency andpersonnel performance in critical marine functions and emergency response.

The inspections are performed in accordance with the following guidelines:

1. Upstream Design Guidance Manual Mobile Offshore Unit Marina Safety

2. Offshore Installation Escape, Evacuation, and Rescue Analysis Assessment Guidelines,EPR.61PR.96

3. Exxon Guidelines for Preparing and Conducting Effective Drills on MOUs.

A third party company (ModuSpec) with surveyors trained in these guidelines has been contractedto perform the inspections and report findings.

1.2 Structural Integrity

1.2.1 Assessment

For MOUs or designs that have had a structural integrity assessment in the past. The assessmentconsists of:

1. A review of previous hull and leg inspections including the Classification Society (ABS,D&V, Lloyd's) Special Periodic Survey. Technical assistance in reviewing these documentsis available from Stan Christman in the Drilling Technology Group.

2. A review of previous operating history

3. A review of the specific site environmental conditions.

For new MOU designs a structural and fatigue analysis is required and should be completed withthe technical assistance of the Upstream Research Company.

MARINE OPERATIONS


1.2.2 Inspection

The inspection if required consists of visual and NDT of the following areas: cantilever, cranepedestals, helideck, jacking system, jackhouse structure, spud cans, and legs.

Inspection plans for routine inspections can be developed by Bennett & Associates orModuSpec. The URC should be contacted for inspection plans for unusual jackup applicationssuch as sea ice, high seismicicty, unusual soil conditions, etc.

DRILLING OPERATIONS

______________________________________________________________________________DRILLING OPERATIOS MANUAL - JACK-UP/PLATFORM BARAGE RIG DRILLINGFIRST EDITION - MAY 2003

4.0 DRILLING OPERATION

4.1 Introduction 14.2 General Operations Guidelines 14.3 Pre-Spud Operations 34.4 Structural Drive Pipe 44.5 Conductor and Surface Casing Interval 54.6 Diverter Operations 64.7 Intermediate / Protective Casing Interval 64.8 Production Casing / Liner Interval 74.9 Slot Recovery / Whipstock / Section Mill / Cut & Pull 7 4.10 Wellbore Anti-Collision Guidelines 9 4.10.1 Requirements for "Collision Risk" Wells 9 4.10.2 Requirements for All Directional Wells 104.11 Directional Surveying and Deviation Control 114.12 Drill String Design 124.13 Bottom Hole Assemblies 144.14 Hydrogen Sulfide Considerations 174.15 Hydrogen Sulfide Contingency Plan 19

DRILLING OPERATIONS


4.1 INTRODUCTION

This section provides guidelines for conducting a safe, efficient, and environmentally sound drillingoperation. These guidelines may be modified based on actual well conditions after approval asspecified in OIMS.

Specific requirements for each well will be covered in core drilling procedures designated by eachdrill team for their specific drilling operation. For details on the installation of the various wellheadcomponents, refer to the wellhead manufacturer's operations manual.

Applying proven drilling technology to efficient rig operations is essential to minimizing drillingcost. Since every hole drills differently, the drilling supervisor should remain flexible and exercisegood judgement in requesting permission to make changes to an approved procedure. Extensiveplanning and design criteria has gone into the makeup of an approved drilling procedure. Ifupgrades are required because of onsite learning's or firsthand knowledge, the MOC (Managementof Change) process must be used (see Section 4 – Appendix VII for suggested MOC Form). Thisprocess ensures that all drill team members have had the opportunity for input and are aware of allchanges.

There are a number of factors which contribute to fast, trouble free drilling: 1) consistently followgood practice, 2) complete rig acceptance tests and crew safety training prior to spudding, 3) set upcommunications and reporting systems prior to spudding, 4) have all material and equipmentnecessary for a job on location and checked, 5) have environmental protection systems installed andfunctioning prior to spudding, 6) select the proper bit, 7) properly design bottom hole assemblies, 8)run low solids drilling fluids, 9) optimum hydraulics, 10) drill team members maintain an awarenessof hole conditions, 11) implement and follow stuck pipe prevention practices, and 12) recognizewell control early warning signs immediately.

The intent of this manual is not to give specific recommendations for every situation but to giveguidelines. Drilling personnel must also rely upon their experience and training to supplement thismanual.

4.2 GENERAL OPERATIONS GUIDELINES

1. All depth measurements are to be made from a consistent reference point, the top of the kellydrive bushing. "RKB" when determined on a rig with a top drive system shall mean thesurface of the rotary table. After nippling up the casing head, record on the daily drillingreport the elevation of the spool flange relative to RKB.

2. The slip handles are to be tied together to prevent accidental dropping of the pipe during thefollowing conditions:

• Whenever the BHA is close to or above the wellhead.• Any other time there is a possibility of the elevators hitting the pipe in the slips.

3. During routine drilling in normal pressure zones, WOB and RPM's are to be varied asrequired to maintain maximum performance. When drilling near anticipated abnormalpressure zones, the drilling parameters are to be maintained constant to allow for moreaccurate pressure detection.

DRILLING OPERATIONS


4. Below each string of casing, except conductor, a pressure integrity test is to be conducted after10' of new hole has been drilled to determine the formation integrity. The PIT will normallybe taken to leak-off or jug tested to the pressure specified in the procedure, but will not exceedthe casing test pressure (see Section 11 of this manual).

5. On trips, the blind rams will be closed when the drill string is removed from the wellbore.Caution will be used when the blind rams are opened, due to the potential for trappedpressure. Each rig must have a procedure in place to monitor pressure below the blind ramswhen they are closed.

6. When pipe is out of the hole, a rotary cover will be installed.

7. The locking mechanism to lock the master bushing in the rotary and bowls in the masterbushing must be free and functional for the rotary to be considered operational. The kellybushing shall be locked at all times (or removed) except when procedures specifically requirethem to be temporarily unlocked .

8. While tripping in the hole, fill the drill string frequently. Frequency is to be determined by thedrilling superintendent based on current mud weight, hole conditions, and depth. The trip tankwill be used while running in the hole unless otherwise addressed by the Field DrillingManager. If it is used, pump the trip tank mud across the shale shaker when emptying.

It is preferable to use the maximum acceptable mud level drop in the annulus instead of thenumber of stands run as a drill string fill up guideline while tripping the hole. For example,assume five inch 19 1/2 ppf drill pipe is being run in a hole and the drill pipe float allows nomud to enter the drill string. After running 1,860 feet, the drill pipe float fails allowing themud to U-tube and balance in the drill pipe and annulus. Depending on the hole size, the mudlevel would drop as follows:

Hole Size, inches Mud level drop, feet 8 ½ 52012 ¼ 23817 ½ 11419 ¼ 94

An equation specifically for 5 inch 19 1/2 ppf drill pipe to calculate the fluid level drop for theabove scenario is:

d = L x [ 18.32 / ((D x D) - 6.68) ]where: d is the mud drop in the annulus, in feet

L is the length of 5 inch drill pipe run without filling, in feetD is the hole diameter, in inches

A general equation to calculate the mud drop for a different size string being run in the holeis:

d = (C x L) / (A + C)where: d is the mud drop in the annulus in feet

C is the drill string capacity in bbl/feetL is the length of drill string run without filling in feetA is the annulus capacity in bbl/feet

DRILLING OPERATIONS


The drilling engineer can easily generate a series of tables for a specific well and an optimumfill up schedule based on an acceptable downhole pressure drop which would be based onpore pressure estimates while drilling.

9. The completion or plug and abandonment program should be developed while drillingproceeds. This allows equipment to be procured in a timely manner and completion or P&Aconsiderations, such as casing pup joints run to aid in perforation depth control, to beimplemented during the drilling phase.

10. A non-ported float will be run when drilling through casing set at insufficient depth to allowfor the well to be shut in. After sufficient casing is set to allow the well to be shut in, a portedfloat will be run. Modification to the drill pipe float, including porting, must not be done onthe rig. Field modification of drill pipe floats is not allowed. Either a Model "F" (plunger)or Model "G" (flapper) may be used as a solid float. Only a Model "G" may be used with ahardened port in the flapper. The common sizes of float valves are:

Bit Size 6 inch 8 1/2 inch 12 1/4 inchTool joint 3 1/2 Regular 4 1/2 Regular 6 5/8 RegularFloat valve size 2F-3R 4R 5F-6R

A safety valve (ball open) and inside BOP (plunger locked down) will be on the rig floor. Asafety valve and an inside BOP will be available, on the rig floor, for each size drill pipe thatis currently used. Prior to running or pulling any casing liner or tubing, a cross-over back tothe safety valve and a safety valve must be on the rig floor. The safety valve must be functiontested and the test must be documented on the IADC report and DMR.

11. The Crown-O-Matic will be checked daily and after slipping the drilling line. Results of thisinspection must be recorded daily in accordance with MMS Regulations.

12. Flow check all connections.

13. The fast (hard) shut-in method using the annular preventer to shut-in the well will be used.

14. Do not test a lubricator with perforating guns inside to a higher pressure than the perforatingguns are rated.

15. Casing annulus pressure should be monitored daily on all rigs with surface wellheads. Ifcasing pressure is detected, it should be reported on the Daily Drilling Report. The situationshould be reviewed with the Operations Superintendent to determine if any corrective actionsare warranted, e.g. bleed off, increased monitoring, etc. (OIMS Manual Element 6).

16. Standpipe or mud pump suction screens are preferable to drill pipe screens. Only rundownhole screens when no nuclear source tools are in the BHA. Always discuss use of DP ordownhole screen with Operations Superintendent.

4.3 PRE-SPUD OPERATIONS

1. Develop a waste disposal plan which addresses the following:

• Plastic and Styrofoam

DRILLING OPERATIONS


• Metal (no used casing thread protectors are to be sent to the United States)• Garbage (including ground food waste) in accordance with USCG MARPOL

regulations• Paper and cardboard• Used engine oil - Contractor Responsibility• Mud - Per applicable NPDES Manual• Drill solids (where regulations require) -NPDES Manual• Sewage and effluent - Per NPDES Manual or Discharge Compliance Program (ensure

that the drilling unit's treatment plant is operational)• Well Completion/Workover/Treatment Fluids - per NPDES Manual

2. Hold a pre-spud meeting.

3. Complete rig acceptance prior to picking up the rig and again at frequency specified by theOperations Superintendent. The minimum tests will be those required in the drilling contract.At a minimum all rigs entering the ExxonMobil fleet will be inspected by the OperationsSuperintendent or his designee prior to acceptance.

4. Ensure that the muster list has been completed and all personnel are accounted for.

5. Conduct a general safety meeting, review all of the pertinent Safety Alerts.

6. Ensure that the spud mud has been mixed as per the drilling program.

4.4 STRUCTURAL DRIVE PIPE

The most time effective method of setting drive pipe is to drive it to refusal (usually less than 225blows per foot) with a diesel/hydraulic hammer. Plain-end or quick connect pipe is employed andwelded/made-up as the joints are added to the string. For a height estimate, use 45 feet for thediesel/hydraulic hammer and slings and 42 feet for a joint of drive pipe. Although not essential, useof a pipe bevel machine and two welding machines will greatly speed up the driving process forpipe that must be welded. It is important that driving not stop once started (e.g. an overnight shutdown) as the pipe will probably not start moving again.

Driving pipe with a diesel/hydraulic hammer entails higher than normal risk. The pipe will be liftedby padeyes that probably will not have had the welds inspected. While driving, the drive pipe couldenter a soft zone and drop rapidly. A quick connect type connection allows use of a false rotarytable and elevators, and speeds up the driving time while eliminating field welding.

It is sometimes necessary to wash-out the drivepipe during driving operations if the drive hammerblows per foot reach the recommended maximum prior to achieving planned/adequate drive pipepenetration. Wash-out of drive pipe during driving operations requires risk assessment includingconsideration of shallow hazards, prior MMS approval, and appropriate EMDC and EMPCmanagement approval.

DRILLING OPERATIONS


4.5 CONDUCTOR AND SURFACE CASING INTERVAL

The D&E procedure provides details for the following operations: conductor hole drilling;conductor casing running, cementing & hang-off; diverter procedures; surface hole drilling; surfacecasing running, cementing, hang-off, and wellhead installation.

1. The purpose of the conductor casing is to provide adequate Well Control integrity to allowdrilling to the surface casing point. Conductor casing is typically required when:

• An active drilling program has not been conducted on a specific platform within theprevious 12 months.

• There is significant shallow gas and/or lost returns potential present.• Offset well casing pressures and potential casing leaks present the possibility of

encountering charged formations shallower than the surface casing depth.

2. The purpose of the surface casing is to provide adequate Well Control integrity to allowdrilling to the next casing setting point (protective or production casing depth). Surface casingis the first casing string on which the full 5 preventer BOP stack is nippled-up. Surfacecasing supports the weight of all subsequent strings of casing, tubing and surface equipment(i.e. blowout preventers or the wellhead and tree). The setting depth will range from 2000feet to several thousand feet. Surface casing is cemented to surface either during the primarycement job or after the primary job with a grout job.

Unless otherwise specified in the drilling program, conductor and surface holes will be drilled frombelow the drive pipe shoe to ~20' below the planned shoe depth for the respective casing. Makesure to stop drilling prior to exceeding the maximum permitted depth for the hole interval. Therathole is less critical with a weld-on wellhead as it is probably desirable to set the conductor orsurface pipe on bottom. The conductor and surface holes will generally be drilled with SW-gel-CLS mud systems to total depth.

Where significant shallow gas risk is identified, the conductor or surface hole may be drilledutilizing a pilot hole to facilitate well control operations. The primary means of well control duringpilot hole drilling is a dynamic kill. The annular clearance between drill collars and the wellboreprovides a friction pressure drop, to help increase the effective BHP at high circulating rates in theevent of a well control problem. If the well kicks, circulate drilling mud at maximum rate. The bitshould be within 200 feet of bottom. Spot one ppg heavier mud or barite plug if well flow cannotbe killed with regular mud. Circulating heavier mud around may cause lost circulation.

The following general guidelines are for pilot hole drilling operations:

1. A volume of one ppg heavier than drilling weight kill mud can be mixed and maintained inreserve until the pilot hole has been drilled. The minimum volume of mud to be mixed willbe specified in the drilling program and will generally be the sum of the annulus volumebetween the drill string and the pilot hole from TD to the flowline plus the volume requiredto stop reservoir flow as determined by dynamic kill simulations for the applicable holegeometry and reservoir conditions. In areas where the potential for the presence of shallowgas is low, dynamic kill simulations will not be required. If the dynamic kill calculations aremade, a volume pumped versus pump rate plot will be produced which has a No Kill Regionand Kill Region.

DRILLING OPERATIONS


2. During critical operations (drilling, tripping, etc.) conducted while drilling the pilot hole,either the operations supervisor or the tool pusher should be on or near the rig floor.

3. If the rig is equipped with a top drive, rotating while pulling out of hole will reduce theswabbing effect and reduce the chance of influx. Pumping out of the hole is also an option.

4. Minimizing hole washout, avoiding excessive mud seepage, controlling return mud weight,and directional control/wellbore avoidance are more important than high rate of penetrationfor the conductor and surface hole sections.

4.6 DIVERTER OPERATIONS

A diverter assembly composed of spacer spools, drilling cross, and an annular will be nippled upduring all conductor and surface hole drilling. A kill line will be connected to one of the spooloutlets and the diverter lines will be connected to the two 10" side outlets. The primaryconsideration is to have a straight diverter line with a non-restrictive valve (ball or gate valve). Thediverter line must extend beyond the rig cantilever and must not be directed onto the platform ortoward the drilling rig and should account for prevalent wind direction.

Controls should be sequenced to prevent closing the annular prior to the down wind diverter linevalve opening. Anchor the end of the diverter line. Consider need for installing a flare line remoteignitor.

4.7 INTERMEDIATE / PROTECTIVE CASING INTERVAL

Drilling the Intermediate Hole

Formation pressures in the hole below surface casing define the type of well being drilled - normalor abnormal pressure. In areas where abnormal pressure formations are encountered or holeconditions mandate formation isolation, intermediate or protective casing may be required prior toreaching total depth. Casing seat or TD Hunts may be required. Fracture gradients of theformations encountered should be estimated based on offset drillwells. If there are no applicableoffset wells, estimates from empirical data such as Eaton's curves can be used.

Running and Cementing the Intermediate Casing

A full string of casing will be run and hung off in the wellhead. The casing string will include afloat shoe, float collar, and possibly casing pup joints. The cementing assembly will include topand bottom wiper plugs, and cement head/manifold. The Casing and Cementing Sections of thismanual should be referred to when planning this job.

After tagging cement with the bit and prior to drilling out of the shoe, do well control drills.Review shut in procedure with both crews. Shut in well and circulate well through the chokemanifold. Let drilling crew members work the choke. (Alternately this can be done after displacingthe hole with mud to determine the choke line pressure drop for kick calculations.) A casing testwill usually be mandated by the governing regulatory body prior to drilling out and after landing theBOP stack. Run a pressure integrity test after drilling out below the intermediate casing string.Update kick sheet daily while drilling.

DRILLING OPERATIONS


4.8 PRODUCTION CASING / LINER INTERVAL

Drilling the Production Hole

The same guidelines given in the Drilling the Intermediate Hole section apply when drilling thishole section. If using a top drive, pick up sufficient drill pipe to drill to total depth. A ported drillpipe float will be used below surface casing once the well can be shut in on a kick.

After tagging cement with the bit and prior to drilling out of the shoe, do well control drills.Review shut in procedure with both crews. Shut in well and circulate well through the chokemanifold. Let drilling crew work the choke. (Alternately this can be done after displacing the holewith mud to determine the choke line pressure drop for kick calculations.) The casing/liner will bepressure tested in accordance with applicable Regulatory requirements. Update kick sheet dailywhile drilling.

4.9 SLOT RECOVERY / WHIPSTOCK / SECTION MILL / CUT & PULL

The following discussion deals with methods of drilling new wells or hole sections from in oraround existing wells. Slot recovery allows for new wells from the surface while whipstocks andcasing cut & pulls reuse existing casing to reach new objectives. In general, deep whipstocks willbe less expensive than cut & pulls (C&P), which are generally cheaper than slot recoveries and newdrill wells.

When deciding on whether or not to reuse a wellbore, factors to include are: the direction of theexisting well compared to the desired objective(s), existing casing program vs. hole sizes andcompletion necessary, future life of the existing completion, ability to reach (and others on a multi-well program) and have needed hookload, and others.

If an existing well is to have part of it reused, maximum effort should be taken to confirm thesuitability of the well prior to moving the rig onto location. This includes a thorough researching ofthe well's history (e.g., drilling wear, noted pressure tests, cement records), inspection of thewellhead by a qualified service technician, pressure testing casing as possible, and performing allpossible P&A work. If the cement job for a casing string is questionable, it is sometimes advisableto run a high-quality imaging tool (e.g., Schlumberger's USIT log) to determine cement quality andTOC behind the casing; this can aid in Whipstock placement and help decide if a C&P is possible.

Many times, the various procedures described will be run together (e.g. C&P production casing toallow a Whipstock from the surface casing). It will be important to verify compliance with theappropriate regulatory guidelines and obtain approval for operations.

Slot Recovery

Slot Recovery is a method of opening space on a platform for a new drillwell that has had all of itsconductor slots used by previous wells. This helps avoid costly platform modifications that couldotherwise be required. Diver Divert and Drive Pipe Whipstock are the two types of slot recoveryavailable for use once the subject well has been fully P&A'd (see Section 13 for details on P&Aoperations).

DRILLING OPERATIONS


For a Diver Divert slot recovery, all strings of casing (including drive pipe) are cut and recoveredfrom ~5 feet above the mud line. The new drive pipe is lowered through the platform's conductorguides to below the water line where divers then guide the new drive pipe to the side of the existingcasing stubs. The new drive pipe is then driven to the desired depth and well operations proceed asnormal. It is often desired to have a deviated drive shoe on the bottom of the drive pipe to helpensure separation from the old well as quickly as possible.

For a Drive Pipe Whipstock slot recovery, all strings of casing (including drive pipe) are cut andrecovered ± 60 – 80 feet below the mud line. A whipstock is attached to the bottom of the newdrive pipe and lowered through the platform's conductor guides to the existing casing stubs.Whipstocks are available with either a spear or an overshot and can be oriented to the directiondesired. Once the whipstock is mated to the abandoned conductor, the new drive pipe is sheared offof the whipstock and the drive pipe is driven to the desired depth. Again, operations can nowproceed as normal.

Drive pipe whipstocks are generally the preferred option because there is no requirement for diversto be in the water. Both options require special evaluation of the anticipated drive pipe deflection todetermine if one or more platform conductor guides will have to be removed.

Whipstocks

Casing Whipstocks are mechanical devices set inside of existing casing and are used to exit frompreviously drilled wells. The Whipstocks can be either single-trip or multiple trips. The differencein price between single-trip and multiple-trip should be evaluated for each situation (generally,single-trip systems will be more economical on deeper exits while the multiple-trip are better forshallow exits where trips are fast). The general plan of operations is that the Whipstock is run inhole, oriented, and set (either mechanically or hydraulically). The Whipstock should be oriented tothe direction desired for sidetrack (generally ~30° – 45° from highside). Then, casing mills are usedto exit the casing and make enough new hole to perform a PIT. Once this is complete, new drillingoperations are able to proceed. It is important to never rotate anything across the face of thewhipstock; this will help prevent the whipstock from turning and causing the new hole to be lost.The fluid system should be sufficiently viscous and have ditch magnets in place to help remove themetal shavings from the system.

Section Milling

Section milling is similar to whipstocking in that existing wellbore is exited by milling a hole in thecasing. The main difference is that the means of exiting the casing is not a mechanical tool. ToSection Mill, underreaming-type casing mills are run into the existing casing string and a hole ismilled in the casing (typically, ~100'). A cement plug is then placed across the milled interval andthe well sidetracked off of this cement plug. This method is preferred over Whipstock operationswhen the new hole section will be long, directionally complex, or otherwise cause excessive wearand tear on the whipstock that could cause failure (and thereby lose the new hole).

Casing Cut & Pull

The benefit of casing Cut & Pulls for sidetracking new hole is the increased hole size available byremoving one or more strings of casing. The basic plan for a C&P is to lower a casing cutter(generally hydraulic) into the hole to the desired cutting depth, cut the casing, then attempt to pull

DRILLING OPERATIONS


the old casing from the hole. Based on the depth of the cut, the removal of casing could eitherexpose formation or the previous casing string.

4.10 WELLBORE ANTI-COLLISION GUIDELINES

Wellbore anticollision guidelines in this section are a recommended minimum standard for alloperations. These guidelines should be reviewed on a well by well basis. Any exceptions to thesestandards requires Operations Superintendent approval.

1. The most critical piece of information in the anti-collision arena is data quality. All platformsurveys and RKB's should be reviewed by a qualified individual to ensure the data is correct,reasonable and free of errors. Pay particular attention to azimuth round-off error and RKBdatum height (these have been incorrect in the past).

2. Once a well path has been generated, have the directional contractor run an anti-collisionreport. Review the report and identify the wells that will need to be addressed individually.Obtain the most recent wellbore sketches for every well on the platform and for all wells thatpass near the proposed well (wells may originate from an adjacent platform or an open waterlocation). Pay attention to tubingless wells, producing wells, gas lifted wells, and pluggedwells.

3. In the SIMOPS meeting held between EMDC and EMPC, discuss the status of the previouslyidentified wells. Plan to shut in, bleed off and or set plugs in wells close to the proposed wellpath.

4. During drilling operations near interference issues, survey every stand and use currenttechnology to provide the best information possible (i.e., surface readout gyro). Have thedirectional contractor supply an additional directional driller to run projections and anti-collision reports only. Use a jetting assembly to steer near interference. Minimize Drillstring rotation (DO NOT USE A MOTOR) while near another well. Monitor constantly fortorque, LR, metal cuttings, cement, or any other parameter that could indicate interference.

4.10.1 REQUIREMENTS FOR “COLLISION RISK” WELLS

1. Collision avoidance planning and operating requirements (Items 1-7) will apply to“Collision Risk Wells”. Collision Risk Wells are defined as:

2. Any well drilled from a multi-well pad or structure (includes abandoned wells).

3. Single-well operations, if the planned trajectory is expected to pass within 100m (330 ft) ofthat of an offset well.

4. If SIMOPS or local regulatory collision avoidance requirements are more stringent thanEMDC requirements, the more conservative requirements will be followed.

5. Either Wolff & DeWardt or ISCWSA models may be used to develop collision avoidanceand EOU calculations. The vendor is responsible for selection of tool error factors and theperformance of their proprietary software.

6. The least-distance method will be utilized to calculate the separation between ellipses.

7. Ellipse of uncertainty calculations will be based on 2 standard deviations (2σ).

DRILLING OPERATIONS


8. Offset monitoring and shut-in requirements for Collision Risk Wells are determined by“Separation Distance” or “Separation Factor” requirements, whichever is larger. FDMapproval is required to operate with an EOU Separation Distance < 10ft, or SeparationFactor < 1.5. The FDM may approve exceptions to shut in requirements if risk can bereduced to acceptable levels through operational practices.

SEPARATION DISTANCE

• If the EOU Separation Distance projected to the next survey point is < 10 ft, monitor theapplicable offset annulus continuously.

• If the EOU Separation Distance projected to next survey point is < 5ft, shut in the offsetand set a plug below the estimated intercept depth (or close SSSV if it’s below interceptpoint). Monitor annulus continuously.

SEPARATION FACTOR

• If the EOU Separation Factor projected to the next survey point is < 1.5, monitor theapplicable offset annulus continuously.

• If the EOU Separation Factor projected to next survey point is < 1.2, shut in the offsetand set a plug below the estimated intercept depth (or close SSSV if it’s below interceptpoint). Monitor annulus continuously.

1. As a final planning check, the onsite directional driller is to run an independent collisionavoidance profile for Collision Risk Wells prior to commencing work.

2. Anti-collision plots will be maintained for Collision Risk Wells at the rig site. Updates arerequired following each survey until the potential intercept point is passed.

4.10.2 REQUIREMENTS FOR ALL DIRECTIONAL WELLS

1. Written directional and proximity monitoring plans will be included in the program. Theengineer, first line engineering supervisor, and operations superintendent must endorse theplan prior to field implementation.

2. FDM approval of MOC is required for changes in trajectory after final plan approval thatcreate 1) a “Collision Risk Well”, or 2) a change in the shut in requirements of an offsetwell (per Separation Factor or Separation Distance rules).

3. The drilling program will specify the type of survey tools and minimum frequency ofsurveys in each interval.

4. Critical pre-drill planning data will be summarized and transmitted to the survey anddirectional contractors in writing. The data will include, but not be limited to:• Well Name• Preliminary Reference Elevation• Slot/Well Surface Coordinates• Displacement from Slot to Platform Tie Point• Azimuth Reference Correction (True North, Grid North)• Magnetic Declination• Target description and hard line constraints

DRILLING OPERATIONS


• Survey tool types and frequency, by interval

5. All survey data will be communicated between parties at the rig site in a standardizedformat. Either the contractor or ExxonMobil may develop the format (electronic orwritten).

6. The drilling engineer will review the information in the final well survey for accuracy andinitial it prior to distribution.

7. Geologic targeting requirements will be obtained from the client organization in writing.

8. The survey plan and trajectory will ensure that the wellbore’s two-sigma ellipse ofuncertainty fits fully within the specified geologic target on the planned line of approach. Ifthis cannot be achieved, client management approval is required to drill a trajectory with areduced probability of landing within the target area.

4.11 DIRECTIONAL SURVEYING AND DEVIATION CONTROL

The purpose of the guidelines in this section is to maintain directional control on all wells (verticaland directional) as drilling progresses. Directional control ensures a known bottom hole locationand well trajectory in order to avoid collisions/damage to offset wells and efficiently drill to thegeologic objective(s) and relief well targets if necessary. For relief well purposes, it is important toknow the position of the well to within 50 feet, which is the effective range of noise log andMagRange tools.

For the purpose of applying the following general survey requirements, a vertical well is defined asa well that has less than three degrees of inclination from surface to total depth. The following tablesummarizes the minimum surveying requirements:

Type of Well Requirement Vertical Well (less than 3°) Inclination Survey every 1000'Directional Well during normal Inclination and Azimuth every 500'drillingDirectional Well during planned Inclination and Azimuth every 100'angle changesPrior to setting surface and deeper Inclination and Azimuth 500' from csg shoescasings in both directional and vertical wellsTotal Depth on both directional Inclination and Azimuth 500' from TDand vertical wells

A composite survey from either the drive pipe or conductor shoe to TD must be provided per MMSrequirements.

Surveying Guidelines

1. If well surveys are required beyond the minimum summarized above, they will be specified inthe drilling program.

2. To determine surveying requirements, the following casing definitions will be used:

DRILLING OPERATIONS


Drive, or Structural, - pipe which is driven to support unconsolidated deposits and providehole stability for initial operation (normally 20-30 inch).

Conductor - Set below drive pipe and before surface pipe to mitigate some shallow drillinghazards.

Surface - a blowout preventer stack is nippled-up on top of this string and a pressure integritytest is run after the casing shoe is drilled. Surface casing cannot be used as production casing,without a written exception from the field drilling manager.

3. A gyro deviation survey will be taken at the total depth of the drive pipe hole or shoe.Typically a gyro must be run because the pipe is driven in place.

4. Surveys taken with a MWD tool are definitive, and it is not necessary to confirm MWDsurveys with a single shot survey. Standpipe or mud pump suction screens are preferable todrill pipe screens. Only run downhole screens when no nuclear source logging tools are in theBHA. Always discuss use of drill pipe screens with Operations Superintendent.

5. In cases where bottom hole location is critical, an electronic multi-shot or gyroscopic surveymay be run. EPRCo's Wellpath program or vendor software can be used to estimate theamount of error that results from using various survey tools and aid in the decision to run amulti-shot or gyro survey.

6. The drilling superintendent should be provided directional data on a continual basis. Fordirectional wells, the directional driller and drilling engineer are to maintain a wellboretrajectory record and a current wellbore plot. All directional plots are to be updated, and anysignificant deviation from the planned directional program is to be presented to the operationssuperintendent immediately. The minimum curvature calculation technique should be used.

7. Survey results are to be reported on the survey screen of the daily drilling report and IADCReport. All directional information should be converted to GRID measurements whenreported and plotted.

4.12 DRILL STRING DESIGN

Drill String Guidelines

1. All drill string connections are to be torqued to API recommended values except as identifiedin the appropriate procedures.

Jet-Lube's Kopr-Kote can be used for every connection from bit to kelly/top drive. Kopr-Kote does not contain zinc or lead. Prior to application of Kopr-Kote, the tool joint threadsshould be cleaned to bare metal.

To prevent galling of the non-magnetic components when using Kopr-Kote, connectionsshould be cleaned, inspected, and given a MAG-COAT. Without MAG-COAT, non-magnetic connections will have a higher incidence of galling using Kopr-Kote.

2. Change the drill pipe stand breaks on every trip.

DRILLING OPERATIONS


3. Maintain an accurate strap of the drill pipe on the rig floor. The well depth is determined bythe driller's STM.

4. Use a drilling jar that has a large ID so that it is possible to use a wireline string shot orsevering charge if required.

5. Drill string components should have the same basic connection OD unless a bottleneckedcrossover is used to provide a transition. All drillstring component connection OD's must beexternally fishable for the hole size they are used in. Exceptions must be approved by theOperations Superintendent.

6. If possible, the drill string is to be designed to withstand a minimum of 100,000 lbs. ofoverpull in a straight hole and 150,000 lbs. of overpull in a directional hole.

7. The drill string is to be designed to withstand predicted combined torque and tension loadsusing the FORCAL program (see Directional Drilling BHAs) for difficult directional wellsand/or critical wells.

8. Limit the rotary torque during normal drilling operations to drill pipe connection makeuptorque in order to prevent over-torquing the drill pipe connections. Check the actual makeuptorques used by the Drilling Contractor.

9. If the drill pipe is new or refurbished, inspect tool joints for abrasive hard banding whichcould damage casing.

10. Perform proper break-in procedures for newly cut drill pipe connections.

Drill String Inspections

Drill string components will require periodic inspection based on rotating hours and type of drillingservice (i.e. critical or standard). The following inspection frequency is recommended:

Rotating Hours Between Inspections

WELL SERVICE Drill Pipe Drill Collar/BHA ComponentsCATEGORY 6" and Smaller 6-1/4" and LargerCritical Service 1500 150 200Standard Service 2500 250 300

The above intervals should be adjusted based on experience and failure experience.

The recommended inspection methods for drill string components are to be in accordance withStandard DS-1, Drill Stem Design and Inspection, Second Edition, by T. H. Hill and Associates,March 1998 manual. Inspection service categories, acceptance/rejection criteria, and exceptions toDS-1 are given in the ECIDO Drilling OIMS Manual.

There are several classifications of well categories and OIMS requires that drill string inspectionfrequency as well as casing design be based on well categories.

DRILLING OPERATIONS


The OIMS manual designates well service categories as standard or critical in Element 3 and liststhree conditions which qualify a well as critical.

The top drive should have a magnetic particle examination of the exposed surfaces on all loadbearing components annually to determine the presence of fatigue crack indications.

4.13 BOTTOM HOLE ASSEMBLIES

General

Guidelines in this section address the design, care, and makeup of bottom hole assemblies fordrilling operations to meet the following objectives:

• Control or Induce Changes in Hole Deviation• Improve Bit Performance• Provide Weight on Bit• Ensure a Full Gauge Hole• Reduce the Susceptibility to Differential Sticking and/or Key Seating• Reduce Downhole Vibration• Prevent/Reduce BHA Problems Such as Wash-outs and Twist-offs

BHA Operational Guidelines

1. Three musts for good drill collar performance are:

• Must properly lubricate shoulders and threads• Must use proper torque - Must be measured• Must immediately repair minor damage

2. Never make up drill collars or BHA components by reversing the rotary table. Tighten eachconnection separately. Do not double up to save time.

3. When breaking out drill collars, rotate slowly with a slight upward pull on the blocks. Do notallow threads to jump after the collar is backed out.

4. To avoid galling, a good rig practice is to "walk out" the drill collar joint using chain tongs.

5. Change the stand breaks on the BHA/drill collars on every trip.

6. Optimize jar placement by running jars near most likely stuck point.

7. Keep an accurate drawing of all BHA components including the dimension of eachcomponent (OD's, ID's, lengths, serial numbers, etc.). The dimensions should be measured insuch a way as to contribute toward successful fishing. Outside diameter dimensions should betaken with a caliper that will just slip over the body by its own weight.

8. Gauging the bit after makeup will ensure that it was not pinched by the bit breaker. Refer toSection 5 (Bit Classification and Hydraulics) for gauging guidance.

DRILLING OPERATIONS


9. Maintain stabilizer blade OD, according to the BHA programmed design, by gauging themevery trip and replacing as needed. It is preferable to not change more than one stabilizer pertrip. Follow the gauging guidelines given in the bit section.

10. Lift sub pins should be cleaned, inspected, and lubricated on each trip. If these pins have beendamaged and go unnoticed, they will eventually damage all of the drill collar boxes.

BHA Design

The bottom hole assembly that is to be used in each hole section will be specified in the pertinentdrilling procedure. The following considerations should be included when performing a BHAdesign:

1. HeviWate drill pipe run between the drill collars and drill pipe provides a transition zone aswell as additional available string weight. In deeper wells with increasing angle, minimizingHWDP to assist in optimizing drilling hydraulics is a common practice.

2. Ensure that crossovers from large diameter drill collars to smaller drill collars or drill pipe donot exceed a 2" reduction in size, or that the stiffness ratio does not exceed 5.5 for a non-critical well or 3.5 for a critical well.

3. The acceptable drill collar and BHA tools bending strength ratio is 2.25 to 3.20.

4. These bending strength ratios may not be possible with small drill collar sizes such as 4 3/4inch drill collars with 3 1/2 IF (NC 38) connections. Experience has shown that rotaryshoulder connection failures have rarely occurred using 4 3/4 inch drill collars even withBSRs below 2.0.

5. Select components of the BHA considering lost circulation material requirements andpotential for drill string sticking and subsequent fishing operations (nozzles, motors, MWDs,etc. may plug when pumping LCM).

6. Ensure that all BHA connections have boreback stress relief box connections and stress reliefgrooves on pins.

7. Spiral drill collars are preferred to minimize differential sticking potential.

8. Straight welded blade stabilizers minimize swabbing in gumbo sections. Stabilizers with alonger contact area increase wall support area in soft formations. Stabilizers with a shortercontact area are preferable in hard formations. Consider use of spiral, integral bladestabilizers with adequate bypass area for high angle, directional well hole cleaning.

Directional Drilling BHAs

These guidelines are not intended to be policy or inflexible standards but should serve as afoundation on which to base decisions for well specific designs.

From about 1950 to 1980, drill pipe and HeviWate drill pipe were never run in compression for fearof fatigue failures as a result of buckling. However, inclination of a wellbore was seldom taken intoaccount in calculating the required drill collar weight. As a result most operators did not add collars

DRILLING OPERATIONS


as hole angle increased which undoubtedly caused drill pipe to be run in compression. Fatiguefailures expected for drill pipe run in compression did not occur.

Industry has determined that drill pipe can carry high compressive loads in high angle wells withoutbuckling and fatigue failures. Buckling does lead to accelerated fatigue damage and tool joint wearwhich can be tolerated for short periods of time especially if it would save a trip or reduce thechance of a differentially stuck drill string.

The basis for these conclusions is that a drill string laying on the low side of an inclined hole is veryresistant to buckling since the hole supports and constrains the pipe throughout its length. Animportant benefit of running drill pipe in compression is that the length of HeviWate and drillcollars can be reduced and hydraulics, hole cleaning, and ROP can be improved.

FORCAL permits drill string design based on allowable drill pipe compression for deviated orstraight wellbores. ROB predicts rates of build or drop for rotary bottom hole assemblies.Placement of stabilizers on the bottom of a BHA for directional control can be analyzed as well ashow drill collars will bend between stabilizers. Directional service companies can provide similardrill pipe design software. Be sure to note the limitations of the particular software being used andcheck this against the situation being analyzed (e.g. FORCAL needs modified input when modellingcasing running because it is based on string theory).

The new BHA design methods which take advantage of the reduced BHA buckling tendency indirectional wells have been used since the early 1980s with outstanding results. The short drillcollar lengths required (frequently just MWD/LWD equipment for GOM operations) resulted inreduced torque and drag and reduced frequency of differentially stuck BHAs. The amount of drillpipe, HeviWate drill pipe, and drill collars run in compression is well specific and depends on holesize, mud weight, well angle, desired WOB, and torque and drag constraints. All drilling operationsshould take advantage of design methods which can minimize problems with torque and drag andstuck BHAs.

When differential pressure exceeds about 1,500 psi, take special care to avoid differentially stickingthe drill string. Implement special procedures such as making rotating connections, controlling mudfluid loss and mud cake quality, ensuring effective hole cleaning (i.e., limiting cuttings dune height,etc.), and pumping out of hole on rigs with a top drive system. For differential overbalance pressuregreater than 2,500 psi consider use of the high overbalance, "Seal-While-Drilling" technique.

For wells between 15-35 degrees of angle, apply the following general BHA guidelines. For wellswith >45 degrees of angle special drilling practices may be required.

1. Minimize the number of drill collars and run the maximum amount of drill pipe andHeviWate drill pipe in compression as indicated by the FORCAL program. In most casesonly non-mag collars are required in addition to MWD/LWD collars based on well angle, holesize, desired weight on bit, well angle, mud weight, and torque and drag constraints.

2. Do not run more than one unsupported drill collar above the top stabilizer in directional wells.This can also be eliminated if a non-mag spacer is not required, or if non-mag HWDP isavailable to be run in place of the non-mag collar. At high angles, additional DC's create avery high bending stress in the top stabilizer connection. They also create the potential forstuck pipe if they sag to contact the wall.

DRILLING OPERATIONS


3. The computer program ROB in conjunction with the directional service companysoftware/experience should be used to design stabilizer placement for the BHA. In most area,particularly in areas where differential sticking is a concern, stabilizers should be placed every60 feet.

4. The directional drilling contractor should provide recommended BHAs for evaluation by theDrilling Engineer.

5. Keep up with differential pressure between the mud weight and pore pressure. Take specialprecautions to prevent stuck drill strings anytime differential pressures exceed about 1,500 psiregardless of the type formation drilled.

6. In harder formations, roller reamers are sometimes used in lieu of stabilizers. Roller reamersare often used when significant amounts of reaming is anticipated or rotary torque reductionsare desired. Non-rotating drill pipe protectors or sleeves should be considered when torquereduction is desired.

7. For steerable PDM drilling assemblies, optimize mud motor and LWD tool configuration toanticipated well conditions including: drilling fluid type, flowrate, downhole temperature,anticipated time between trips, bit type, and drilling WOB and torque requirements. ForGOM Directional wells use high performance, extended power section PDMs wheneverpossible.

FORCAL V.5.02 software estimates the torque and drag on a tubular given the wellbore geometry,tubular configuration, direction of movement, and coefficient of friction. The movement can beaxial, rotational, or combined. Two coefficients of friction may be used, one for cased portions ofthe well and the other for the open hole section. Tripping of tubulars into and out of the wellborecan be modelled. Given the measured torque or hookload, FORCAL can calculate the coefficient offriction.

ROB V.5.01 software predicts the build/drop and walk performance of rotary and motor assemblyBHAs. The user can perform sensitivity analysis to predict the effects of various parameters onBHA performance. Geology effects such as bedding planes can also be included and a calibrationmodule allows the user to take advantage of local experience. ROB performs drill ahead and wellextend calculations along with 2-D and 3-D well planning.

POWERPLAN V.3.8 is also utilized and has the capabilities of prediction both torque/dragand build/drop and walk of different BHA's.

Torque and drag surveillance should be monitored for all protective and production holes in excessof 40° with greater than 1500' MD of openhole. An example is included in Section 4 – AppendixVIII.

4.14 HYDROGEN SULFIDE CONSIDERATIONS (OIMS Manual Element 10)

Hydrogen sulfide is an extremely toxic gas. In drilling operations, a wide range of hydrogen sulfideconcentrations may be found. The effects of these concentrations also range widely - from adisagreeable odor or eye irritation at low concentrations to serious illness or even death at higherconcentrations. All personnel working in areas where they may be exposed to hydrogen sulfide

DRILLING OPERATIONS


should be trained to recognize and understand its hazards and to protect themselves from its harmfuleffects (contractor and service company personnel should be H2S certified before coming to therig). Personnel should be trained to rescue victims and administer first aid to those who areovercome, without endangering themselves. All personnel on the rig should have access to anescape pack.

Hydrogen sulfide is an extremely toxic, colorless, heavier than air (1.18 specific gravity) gas. Itburns with a blue flame and produces sulfur dioxide gas which is slightly less toxic than hydrogensulfide, but can cause eye and lung irritation and serious injury. In low concentrations, hydrogensulfide has the odor of rotten eggs. It forms an explosive mixture with air at concentrations between4.3% and 46% by volume. It is soluble in water and oil but becomes less soluble as the fluidtemperature increases.

When there is a potential for encountering hydrogen sulfide, the following must be considered andaddressed:

• Monitoring• Use of breathing apparatus• Positioning of breathing apparatus• Equipment training• Hazardous locations• Material selection - BOP and well control equipment H2S trimmed• Regulations• First aid• Coded air horn or bell alarms• Response at various levels of hydrogen sulfide concentration• Sensors - location, calibration, visual and audible signals, fixed and hand held• Emergency procedures• Periodic drills and safety meetings• Operating guidelines• Wind socks and safe assembly areas• Transportation and evacuation• Part of the Risk Assessment process• MMS or other Regulatory Agency H2S Contingency Plan Development & Approval

API RP 55 can provide guidance on operations involving hydrogen sulfide and contains a table onthe physiological effects of various concentrations.

An example guideline on facial hair and corrective lenses as pertains to respiratory equipment couldbe:

• Clean shaven in the face-piece-sealing area and must not have facial hair that could interferewith the function of the mask.

• Before donning a respirator with a full face piece, any head covering, glasses and foreignitems in the mouth must be removed

• Wearing contact lens with a respirator is not permitted.• Prescription eyeglass wearers who are assigned to areas where full-face respirators may be

required should be provided with a means of attaching the prescription lenses to the face

DRILLING OPERATIONS


mask. Hooded Egress Units allow for the use of prescription eyeglasses during emergencyevacuations.

Guidelines For Drilling

For all operations where H2S is being produced on the platform or where H2S may be encounteredwhile drilling, a contingency plan will be developed and approved by the applicable regulatoryagency as required. Hydrogen sulfide monitoring should be continuous while drilling anywherecovered by the contingency plan. Monitoring should be done with remote sensors which are locatedat a minimum near the bell nipple, on the rig floor, and above the shale shaker. Gas trap gas andvulnerable areas may also be monitored. The approved contingency plan will have details on wheresensors should be placed. Maintenance and logged calibration is important. At the first indicationof H2S, confirmation should be made with a hand held meter.

If drilling in a H2S area, Garrett Gas Train sulfide readings on the mud filtrate will also be required.It is advisable to start five drilling days before entering predicted hydrogen sulfide zones toestablish background concentrations. Draeger has recently changed the scale on their tubes, and thetube factor given in API RP 13B-1 should be carefully checked to ensure the tube factor matchesthe tubes being used.

4.15 HYDROGEN SULFIDE CONTINGENCY PLAN

A typical hydrogen sulfide contingency plan has three phases:

If the measured H2S levels is ten ppm or less, but greater than zero then,

• Continue normal drilling• Sensitize crew with drills and safety meetings• Ensure H2S scavenger (zinc basic carbonate) is on location and discuss its addition to the

mud system• Maintain mud pH at 9.5 or higher• Consider increasing the number of air packs on location• Check calibration of sensors• Limit visitors and unnecessary personnel on location• Check igniter on gasbuster flare line• Driller and mud loggers to keep in communication

If the measured H2S level is twenty ppm or less, but greater than ten ppm then,

• Suspend drilling operations and make an effort to suppress the H2S before proceeding withdrilling.

• Sound H2S alarm and illuminate flashing light• Rig crew immediately dons breathing apparatus and stops circulation to control source of

hydrogen sulfide. Driller is to know if the well is to be shut in. Notify toolpusher and ECIdrilling supervisor

• All non-essential personnel proceed to upwind assembly area. No non-essential personnelwill be allowed in any area with possible H2S exposure.

DRILLING OPERATIONS


• Conduct safety meetings and review plans to return to drilling. Plan response in the eventhydrogen sulfide concentration exceeds twenty ppm. Repeat safety meeting before crewscome on tour.

• All personnel check their safety equipment for proper operation and location. Persons withoutassigned breathing equipment cannot work in the Hazardous area.

• Treat mud with scavenger as necessary• Notify the operations superintendent before returning to drilling• Use the 'Buddy System' – no individual is to be allowed to work in affected areas by

themselves

If the measured H2S levels greater than twenty ppm then,

• Sound H2S alarm• Rig crew dons breathing apparatus and closes in the well• All personnel proceed to upwind safe assembly area• Suspend drilling operations and reassess contingency plan with superintendent

Guidelines For Well Control

In a kick situation, where H2S has previously been detected in the drilling fluid filtrate or by mudlogging gas analysis, all personnel directly involved with the operation are to have readily availableindividual self contained breathing apparatus (SCBA). All other personnel are to be alerted andmade aware of the designated safe briefing area(s) to be used during the well killing operation.

During the kick circulation, the above personnel are to don their SCBA's, as a minimum, 30 minutesprior to the calculated arrival time of the kick fluid and remain in the SCBA's until 30 minutes afterthe kick fluid is vented down the flare line. Attempt to burn the kick gas if conditions allow, andappropriate Regulatory Approvals have been obtained.

During the entire kick circulation, a designated member of the drill crew is to check (with a SCBAon) the shaker area for H2S concentrations. Also, the return drilling fluid is to be monitored forH2S throughout the entire well killing operation.

If at any time during the kick circulation, H2S concentration exceeds 20 ppm or more in theworking atmosphere (air), the well is to be shut in and non-essential personnel are to be moved intothe safe briefing area(s) or evacuated (depending upon the concentration of H2S ).

In the event of any well control situation in which the occurrence of H2S is probable, considerationsare to be made for bullheading the formation fluid back into the formation, rather than circulatingthe kick out and releasing the H2S at the surface.

Guidelines For Coring And Production Testing

Refer to Sections 8 and 12 of this manual for information/guidelines regarding H2S in coring andproduction testing operations. If working on a well with hydrogen sulfide gas, all workers in thearea should mask up while retrieving the back pressure valve.

BIT CLASSFICATION AND HYDRAULICS

______________________________________________________________________________________DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLINGFIRST EDITION - MAY, 2003

5.0 BIT CLASSIFICATION AND HYDRAULICS

5.1 General 15.2 Drill Bits 15.3 IADC Bit Classification System 35.4 IADC Bit Grading System 65.5 Running Procedures for Fixed Cutters 85.6 Hydraulics Program 105.7 Guidelines for Hydraulics Optimization 125.8 Hydraulics Optimization 17

Reference

BIT CLASSIFICATION AND HYDRAULICS

DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE DRILLING 1 of 18First Edition - May, 2003

5.1 GENERAL

The Drilling Program shall specify a recommended bit selection and hydraulics program based onoffset well data and (or) anticipated drilling conditions. The bit and hydraulics programs specifiedin the Drilling Program are to be viewed as guidelines only and adjustments are to be made asnecessary in the field to account for actual drilling conditions.

5.2 DRILL BITS

Bit Operational Guidelines

1. Establish optimum bit parameters early in the bit run. Drill-Off Tests should be used todetermine the point at which ROP begins to decrease with increasing WOB. The �flounderpoint� in the drill-off test is the WOB at which the bit is beginning to ball. It may be possibleto increase the WOB and ROP if bit cleaning is improved. Options for improving bit cleaningare increased hydraulics, reduced blades on PDCs, mud additives (ROP enhancer) if MW < 10ppg, and inhibitive mud. Vary weight on bit (WOB) and rotary speed (RPM) as required tomaintain maximum performance, taking into consideration abnormal pressure detectionrequirements, high drill gas, and the carrying capacity of the mud (ability to remove cuttingsefficiently).

2. When drilling near anticipated abnormal pressure zones, the drilling parameters are to bemaintained constant to allow for more accurate pressure detection.

3. Monitor bit ROP trends to determine when the break even point, based on increasing cost perfoot, has been reached.

Cost Per Foot (CPF) = Bit Cost + Rig Cost (Trip Time + Drilling Time)Footage Drilled

4. Use the automatic Driller, if available, when drilling below surface casing.

5. Grade each bit for wear and damage according to the IADC Dull Bit Grading Systempresented at the end of this section.

Bit Selection

The selection of bits provided to the Drilling Rig should be sufficient to cover a wide range ofdrilling conditions. The following guidelines are given for bit selection:

1. Bit selection will generally call for the most aggressive bit that will stand up to the anticipatedlithology. Soft formation mill tooth bits will generally be the bit of choice for surface holedrilling.

2. Sealed bearing (and possibly journal bearing) tooth bits will generally be recommended fordrilling the soft surface hole sediments in an attempt to drill this section in one bit run.



3. In deeper hole sections, where multiple bit runs are required, bit selection is to be based on bitperformance optimization, unless potential upcoming operations (coring, intermediate logs,casing seat hunt, etc.) dictate otherwise.

BIT SELECTION CHART

FORMATIONS IADC BIT CLASSIFICATION

CHARACTERISTICS TYPE 1st CHARACTER ROCKBITS

1st & 2nd CHARACTERFIXED CUTTERS

TOOTH INSERT PDC DIAMONDSOFT: Sticky, Lowcompressive strength andhigh drillability.

Clay, Marl, Gumbo, RedBeds, UnconsolidatedSands & Shales, Halite

1 4 M(S)1M(S)2M(S)3S(M)4

SOFT TO MEDIUM:Low Compressive strengthinterbeded with hardlayers.

Sand, Shale, Anhydrite,Soft Sandstone and SoftLimestone, ShaleyLimestone

1 5 M(S)1M(S)2M(S)3M(S)4

M6M7

MEDIUM: Hard withmoderate compressivestrength.

Shale, Chalk, Sand,Anhydrite, ShaleyLimestone, SoftLimestone with HardStreaks.

2 6 M(S)2S(M)3M(S)4

M6M7M8

MEDIUM TO HARD:Dense with increasingcompressive strength butnon or semi-abrasive.

Shale, Siltstone, Sand,Lime, Anhydrite,Dolomite, CalcareousSandstone, Sandstonewith Chert & PyriteStreaks

2 6 M2M(S)3M(S)4

M6M7M8

HARD: Hard and densewith high compressivestrength, some abrasivelayers.

Sand, Siltstone,Quartzite, Granite,Dolomite, ChertConglomerates, AbrasiveSandstone & Limestone.

3 7 M3M4

M6M7M8

EXTREMELY HARD:Very hard and abrasive.

Quartz, SandstoneConglomerates,Volcanics such as Basalt,Gabbo, Rholite, Granite.

8 M7M8

The table above correlates formation characteristics against bit type based on the IADC bitclassification system. Although this is fairly straight forward for rock bits, it is more nebulous forfixed cutter bits (in particular, the PDC variety). PDC usage has only come into its own in the lastfew years; compared to rock bits this technology is still in the "toddler stage". Consequently, agood, compressive, clear-cut classification system has not yet been developed. To classify the fixedcutters, the World Oil's 1995 Drill Bit Classification Tables were reviewed to determine which bittypes were recommended by manufactures for a particular formation. The bold characters indicate



The bit classification which appears most often under a particular formation. The relative size issecondary indication of how often a particular bit type is recommended. A comprehensivediscussion of the IADC classification system follows.

5.3 IADC BIT CLASSIFICATION SYSTEM

IADC Bit Classification

The IADC Bit Classification System identifies bits using a numbering system. For roller cone bits,these numbers identify the formation/tooth type, degree of hardness within the basic formation andbearing type. For fixed cutter bits, the characters identify body material, PDC cutter density orDiamond size, PDC size or Diamond type, and bit profile.

The IADC Bit Classification System is described below.

Roller Cone Bits

For example, a typical IADC classification for a roller cone bit is 1-1-1.First Character: Cutting Structure Series (1-8). Refers to formation characteristics. Within the

steel tooth and insert groups, the formations become harder and more abrasiveas the series number increases.

Mill Tooth Bits (1-3)1 - Soft2 - Medium to Medium Hard3 - Hard, Semi-Abrasive / Abrasive

Insert Bits (4-8)4 - Soft5 - Soft to Medium6 - Medium to Hard, Semi-Abrasive7 - Hard, Semi-Abrasive/Abrasive8 - Extremely Hard, Abrasive

Second Character: Cutting Structure Types (1-4). Refers to the degree of hardness within aformation type.

1 - Softest formations => 4 - Hardest formations

Third Character: Type of Bearing / Gage Protection (1-9).1 = Standard Roller Bearing2 = Roller Bearing, Air Cooled3 = Roller Bearing, Gage Protected4 = Sealed Roller Bearing5 = Sealed Roller Bearing, Gage Protected6 = Sealed Friction Bearing7 = Sealed Friction Bearing, Gauge Protected



8 = Directional9 = Other, Reserved For Future Use

Fourth Character: Special Features (Alpha characters). Defines additional features of roller conebits with regard to cutting structures, bearings, seals, hydraulics, and specificapplications.

A = Air Application (Journal bearing with air nozzles)B = Special Bearing SealC = Center JetD = Deviation ControlE = Extended Jets (Full length)G = Extra Gage / Body ProtectionH = Horizontal / Steering ApplicationJ = Jet DeflectionL = Lug PadsM = Motor ApplicationS = Standard Steel Tooth ModelT = Two ConeW = Enhanced Cutting StructureX = Predominantly Chisel Tooth InsertsY = Predominantly Conical InsertsZ = Other Shape Inserts

Fixed Cutter Bits:

New (Current) IADC Classification:

For example, a typical IADC classification for a fixed cutter bit is M-1-2-1.

First Character: Body Material (Alpha Character). Refers to the type of body construction.M = Matrix or S = Steel (only two designations)

Second Character: Cutter Density. For PDC bits this refers to total cutter count, including standardgage cutters. For Diamond bits this refers to diamond size. As with rock bits,the larger the number the more suited for harder more abrasive applications.

PDC Bits (1- 4) Designation of 1 represents a light set while 4 represents a heavy set. Cuttercount is based on 1/2" cutter size, cutter (larger/smaller) sizes are projected as1/2" cutter densities.

1 = 30 or fewer 1/2" cutters2 = 30 to 40, 1/2" cutters3 = 40 to 50, 1/2" cutters4 = 50 or greater 1/2" cutters



Diamond Bits (6 - 8) A designation of 6 represents larger diamonds while 8 represents smallerdiamonds

6 = < 3 stones per carat7 = 3 to 7 stones per carat8 = > 7 stones per caratNote: (0, 5, & 9) are undesignated and reserved for future use.

Special designs using additional gage cutters, such as sidetrack bits, or bits for horizontaldrilling, are not considered for the purpose of classification.

Third Character: Size or Type of Cutter. For PDC bits, the third character refers the size of thecutter while for Diamond bits, it refers to the type diamonds.

PDC Bits (1- 4) Size1 = > 24mm in diameter2 = 14mm to 24mm in diameter3 = 9mm to 13mm in diameter4 = < 8mm in diameter

Diamond Bits (1- 4) Type 1 = Natural Diamonds

2 = TSP (Thermally Stable Polycrystalline) Diamonds3= Combination Cutters (such as natural diamond and TSP)4 = Impregnated Diamond Bit (Applies only the highest density Bits)

Fourth Character Profile or Body Style. Gives an idea of the basic appearance of the bit, based onoverall length of the cutting face of the bit.

PDC Bits (1- 4)1 = Fishtail2 = Flat Face3 = Long bit profiles4 = Increasingly longer bit profiles

Diamond Bits (1- 4) 1 = Flat Face TSP and Natural Diamond

2 = Long3= Longer4 = Increasingly Longer

Old IADC Classification:

For example, a typical IADC classification for a fixed cutter bit is D-2-1-2.

Letter: Cutter Type and Body MaterialD = Natural Diamond M = Matrix Body PDC



S = Steel Body PDC T = Thermally Stable PolycrystallineO = Other (TSP)

First Number: Bit Profile (Gauge Point to Cone)1 = Long Taper, Deep Cone 2 = Long Taper, Medium Cone3 = Long Taper, Shallow Cone 4 = Medium Taper, Deep Cone5 = Medium Taper, Medium Cone 6 = Medium Taper, Shallow Cone7 = Short Taper, Deep Cone 8 = Short Taper, Medium Cone9 = Short Taper, Shallow Cone

Second Number: Hydraulic Design

Type Body Changeable Jets Fixed Ports Open Throat

Bladed 1 2 3Ribbed 4 5 6Open Faced 7 8 9

Alternate designations: R = Radial Flow, X = Cross Flow, O = Other

Third Number: Cutter Size and Density

Cutter Size Light Density Med. Density Heavy Density

Large 1 2 3Medium 4 5 6Small 7 8 9Impregnated 0 0 0

Note Size Distribution Definitions

Small � Greater than 7 stones/carat for natural Diamond.� Less than 3/8" diameter of usable height for PDC bit.

Medium � 3 to 7 stones/carat for natural diamond.� 3/8" to 5/8" diameter of usable height for PDC bit.

Large � Less than 3 stones/carat for natural diamond.� Greater than 5/8" diameter of usable height for PDC bit.

5.4 IADC BIT GRADING SYSTEM

I.A.D.C.DULL BIT GRADING CODES

CUTTING STRUCTURE B G REMARKSINNER ROW OUTER ROW DULL CHAR. LOCATION BEARING SEALS GAUGE 1/16" OTHER CHAR. REASON PULLED

1 2 3 4 5 6 7 8(1) CUTTING STRUCTURE - INNER

Inner 2/3 of bit.(2) CUTTING STRUCTURE - OUTER

Outer 1/3 of bit.



STEEL TOOTH BITS - A linear measure of lostcutting structure due to abrasion or damage.(0 - no loss of cutting structure due to abrasionor damage, 8 - total loss of cutting structure dueto abrasion or damage.

INSERT BITS - A linear measure of lost, wornand/or broken inserts. (0- no loss, worn and/orbroken inserts, 8-all inserts lost, worn and/orbroken.)

DIAMOND, PDC and/or TSP BITS - A linearmeasure of lost, worn and/or broken cutting structure. (0-no loss,worn and/or broken cutting structure, 8-all of thecutting structure is lost, worn, and/or broken.

(3) MAJOR DULLCHARACTERISTIC

(4) LOCATION (5) BEARING/SEALS (6) GAUGE (8) REASON PULLED

(These codes are alsoused for Column 7)

ROLLER CONE DIAMOND CONE # OR #'SROLLER CONE

NON-SEALEDBEARINGS

SEALEDBEARING

* BC - Broken Cone N- Nose RowM - Middle RowG - Gage RowsA - All Rows

C - ConeN - NoseT - TaperS - ShoulderG - GaugeA - All Areas

123

A linear scaleestimated bearinglife used. (0 - nolife used,8 - all life used, i.e.,no bearinglife remaining

E - indicatesseals effectiveF - indicatesseals failedX - indicatesFixed Cutter Bit

I - in gauge1/16 - 1/16" outof gauge2/16 - 1/8" outof gauge10/16 - 10/16"out of gauge

BHA - Change Bottom Hole Assembly

BT - BrokenTeeth/Cutters

DMF - Downhole MotorFailure

BU - Balled Up Bit DTF -Downhole ToolFailure

*CC - Cracked Cone DP - Drill Plug

*CD - Cone Dragged DSF - Drill String Failure

CI - Cone Interference DST - Drill Stern Test

CR - Cored CM - Condition Mud

CT - ChippedTeeth/Cutters

CP - Core Point

ER - Erosion FM - Formation Change

FC - Flat Crested Wear HP - Hole Problems

HC - Heat Checking HR - Hours

JD - Junk Damage LN - Lost Nozzle

*LC - Lost Cone LOG - Run Logs

LN - Lost Nozzle PN - Plugged Nozzle/orFluid Passage

LT - Lost Teeth/Cutters PR - Penetration Rate

OC - Off-Center Wear RP - Pump Pressure

PB - Pinched Bit RR - Rig Repair

PN - Plugged Nozzles/Flow Passage

TD - Total Depth/CSGDepth

RG - Rounded Gauge TW - Twist Off - drill string

RO - Ringed Out TQ - Torque

SD - Shirttail Damage WC - Weather Conditions

SS - Self SharpeningWear

WO - Washed Out - drillstring

TR - TrackingWO - Washed OutWT - Worn Teeth/CuttersNO - No Major/OtherDull Characteristic

* - shown cone # or#'s under location



5.5 RUNNING PROCEDURES FOR FIXED CUTTERS

The following are general guidelines to be used when running fixed cutter (PDC and Diamond) bits.

PREPARING THE HOLE:

• Use PDC drillable float equipment.• Inspect previous bit for junk damage and gage wear.• Make cleanout trip if necessary with junk basket.• MAKE SURE HOLE IS CLEAN.

PREPARING THE BIT:

• Transport bit in box to the rig floor to avoid cutter damage.• Carefully remove bit from the box. Do not set bit directly on steel decking. Use wood or a

rubber mat.• Inspect bit for damage.• Record bit serial number.• Check O-rings, nozzles, and bit gage (not applicable for diamond bits).• Check inside bit for obstructions or foreign matter.

MAKING UP THE BIT:

• Fit bit breaker to bit and engage latch.• Clean and grease pin.• Lower drill string to top of pin and engage threads.• Locate bit and breaker in rotary table and make up to recommended torque.

TRIPPING IN THE HOLE:

• Remove bit breaker and carefully lower bit through the rotary table.• Trip carefully through BOPs, casing shoes, and liner hangers.• Trip slowly through ledges, dog legs, and tight spots.• Wash last three joints to bottom with full flow at 50 - 60 RPM.• Approach bottom observing weight indicator and rotary torque.• Tag bottom gently and pick up 6 - 12 inches off bottom.• Circulate 5 - 10 minutes with full flow at 50 - 60 RPM.

REAMING:

• REAMING UNDERGAGE HOLE IS NOT RECOMMENDED.• Ream tight spots with full flow to keep cutters cool.• Use 2,000 - 4,000 pounds WOB and 50 - 60 RPM.• REAM SLOWLY - AVOID HIGH TORQUE.



BIT BREAK IN:

• Lower bit to bottom with full flow at 60 - 80 RPM. Use of a motor will result in a higherrotation speed.

• Compare expected vs. actual hydraulics.• Record stand-pipe pressure and pump strokes.• Drill a bottom hole pattern with 2,000 - 4,000 pounds WOB.• BREAK BIT IN SLOWLY - DO NOT GET IN A HURRY.• After three feet, add weight in 2,000 pound increments and increase rotary to optimum RPM.

DRILLING AHEAD:

• Determine optimum drilling parameters by changing WOB and RPM within recommendedguidelines.

• Conduct drill-off tests to maximize ROP.• Do not hesitate to adjust drilling parameters.• Rotary torque should approximate that of rock bits at equal ROP and WOB. Faster ROP will

normally result in higher torque values.• If torque or RPM cycling is severe, control with lighter WOB or increased RPM.

MAKING CONNECTIONS:

• After making a connection, lower to bottom slowly with full flow and 50 - 60 RPM.• Check standpipe pressure and pump strokes on and off bottom.• Increase RPM to previous level and add weight slowly.• DO NOT JAM THE BIT BACK ON BOTTOM.

PULLING OUT OF THE HOLE:

• Slow down through tight spots, casing shoes, liner hangers, and BOPs.• Attach bit breaker and break out bit in rotary table.• Avoid cutter damage when removing bit.• Do not place bit directly on rotary table.• Return bit to box after dull evaluation.



5.6 HYDRAULICS PROGRAM

The recommended hydraulics program for each hole section will be specified in the DrillingProgram based on predicted drilling parameters such as mud weight, BHA configuration, pumpcapability, pressure losses, etc. Bit hydraulics are to be recalculated onboard the Drilling Vesselbased on actual parameters. This design has three flow regions based on the critical flow rate QCrit,the flow rate at which the total available horsepower is utilized at the maximum allowable surfacepressure, PSurf.

CASE I: Unlimited surface pressure (conditions not limited by surface pressure constraints).Flow rates are high and surface pressure is low. In this region hydraulic impact ismaximized when 74% of the available pressure is expended at the bit with flow rateabove QCrit. This condition usually occurs at shallow depths in the conductor andsurface casings sections of the hole where the total pressure losses in the system arelow. Often larger liners and/or changes are not justified for the fast top hole, precludingoptimum hydraulics until drilling below surface hole. High flow rates are theparameter to key on.

∆PBit = 0.74 PSurf Flow Rate > QCrit

CASE II: Intermediate between Case I & Case II. Flow rate remains constant while circulatingpressure increases with depth. In this region the circulation rate remains constant atQCrit while surface pressure increases until 48% of the maximum allowable pressure isexpended at the bit. This condition usually occurs in the intermediate/protective casingsection of the hole.

∆PBit = (0.48 to 0.74) PSurf Flow Rate = QCrit

CASE III: Limited surface pressure (conditions are limited by the maximum allowable surfacepressure, Pmax). Surface pressure remains constant while circulating rates are reduced.In this region hydraulic impact is maximized when 48% of the maximum allowablepressure is expended at the bit. This condition usually occurs in the deeper section ofthe hole below surface or protective casing. Often a change in liner size is requiredbelow protective casing.

∆PBit = 0.48 PSurf Flow Rate < QCrit

In the past ExxonMobil generally used the Reed Log-Log Graphical Method to calculate optimumrig hydraulics as described above. A detailed discussion of this method can be found in the EUSADrilling Engineering School Manuals and the old EUSA Drilling Operations Manual (the RedBook). Currently the Reed Hydraulic computer program is utilized.



Hydraulic Equations

HHP = (HP)(Em)(Ev) HHP = (P)(Q) 1714

QCrit = 1714(HHP) VN = 0.32(Q)PSurf A2

∆PN = (MW)(Q)2 FB = (MW)(VN)(Q) 12042(Cd)2A2 1932

AV = 24.5(Q) (DH)2 - (DP)2

Where: A = TFA, total flow area of the nozzles (in2)AV = Annular Velocity (fpm)Cd = Nozzle coefficient = 1.03DH = Diameter of the hole (in)DP = Diameter of pipe in hole (in)Em = Mechanical efficiency of mud pump (%)Ev = Volumetric efficiency of mud pump (%)FB = Hydraulic impact force at the bit (lbs)HP = Input horse power from mud pump performance tables (hp)HHP = Mud pump output hydraulic horse power (hp)MW = Mud weight (ppg)P = Circulating pressure, standpipe pressure (psi)∆PN = ∆PBit, pressure drop across the bit nozzles (psi)PSurf = PMax, maximum allowable circulation pressure (psi)Q = Circulating rate (gpm)QCrit = Circulation rate at which total available horsepower is utilized at

the maximum allowable surface pressure, PSurf (gpm)VN = Nozzle velocity (fps)



5.7 GUIDELINES FOR HYDRAULICS OPTIMIZATION

The following guidelines, recommendations, and rules-of-thumb are intended to provide ameans for monitoring conditions at the rig and to get a feel for how well things are going.They are not "the answer" but flags only, indicating whether further scrutiny is needed or asa starting point for hydraulic program planning

Hole Cleaning

The main symptoms of poor hole cleaning depends largely on hole angle. At low angles (< 20°) thecuttings tend to fall downhole as soon as the pumps are stopped. The best sign of poor cleaning isfill on bottom, either on connections or after tripping. In extreme cases it may be difficult to pull offbottom with the pumps off. At high angles (>50°) the cuttings fall to the low side of the holeforming a stationary cuttings bed. There is typically no fill on bottom and no trouble makingconnections. The main evidence of poor hole cleaning is seen on trips. The string may pull tight orget stuck off bottom while attempting to pull through this cuttings bed. At intermediate angles (40°-60°) the cuttings fall to the low side of the hole forming a cuttings bed. This bed is not stationary;consequently, when circulation is stopped the cuttings bed may begin to slide (avalanche)downhole. Symptoms of poor hole cleaning for the intermediate angle case, will range betweenthose seen for the low angle and high angle wells. In any event, if the drag gets high, RIH 2-3stands, put the top drive on and circulate and rotate at maximum allowable rates until thehole is cleaned up; don't try to pull through tight spots. It may be necessary to pump out orback ream out of the hole in the higher angle wells. Backreaming out of the hole requiresOperations Superintendent approval. Utilizing a bit with a cross sectional area as low a possible, oran open area as high as possible, will provide benefits when tripping through intermediate and highangle hole cuttings beds.

Carrying Capacity Index (CCI)

For low angle and intermediate holes up to 35°, the CCI still appears to be the best indicator of holecleaning. There is no mathematical derivation for CCI; field observations indicate that thenumerical product of K, annular velocity, and mud weight should equal or exceed 400,000 for goodhole cleaning. The carrying capacity of a mud depends upon the difference in density between thecuttings and the drilling fluid, the annular velocity, and the viscosity of the fluid in the annulus. Asany one of these numbers increases, the carrying capacity of the mud increases.

NOTE: The CCI is only meaningful when circulating. A suspension capacity of the drilling fluid isalso needed for making concoctions and immobilizing cuttings in washouts during trips.Adequate gel strengths are needed for trips.

CCI = (MW)(K)(AV) Good hole cleaning occurs when CCI > 1 400,000

K = (511)1-n (PV+YP) Where: MW = Mud Weight (ppg) AV = Annular Velocity (fpm)

n = 3.322 log 2PV+YP PV = Plastic Viscosity (cp) PV+YP YP = Yield Point (lb/100 ft2)



The K is the consistency index which corresponds to the viscosity of the mud at a shear rate of onereciprocal second, and n is the measure of the non-Newtonian flow behavior in the power lawrheological model, SS = K (SR)n.

The following graph provides a graphical solution for the K value utilizing PV and YP of the mud. Graphical Solution for Low Shear Rate Viscosity - K

Hole Cleaning Ratio (HCR)

For intermediate and high angle holes which develop cuttings beds, EMURC has developed aparameter called the Hole Cleaning Ratio (HCR) that is highly correlative with hole cleaningproblems. Because of the many drilling variables and the complicated physical system involved, thesimple "Recommended Annular Velocity" table which appeared in past EPR literature is no longerendorsed. In its place, EMDRC has developed a new tool from fluid mechanics theory, publishedlaboratory data, new experimental data, and field data that provides an optimal combinations ofdrilling variables for efficient hole cleaning. It has been used for planning or well design to predictthe likelihood of encountering hole cleaning problems based on drill string design (bit design, holesize, collars, drill pipe), drill pipe rotating speed, drilling fluid rheology, flow rates, and well profile.EMURC is currently developing a PC program for surveillance in the field.

HCR = H/Hcrit. Good hole cleaning occurs when HCR > 1.1

Where: H = the equilibrium height of the free region over the cuttings bed and is a function of the variables listed in figure 1. below.

Hcrit = the critical height is a primarily a function of bit geometry.



Hole Cleaning Ratio (HCR)

(continued)



Hole Cleaning Operations (Intermediate and High Angle Holes)

Based on this work, the following pump out procedure is recommended for the deviated portion ofthe wellbore where problems due to cuttings bed are suspected.

• Monitor torque and drag using the Torque & Drag Surveillance spreadsheet.

• Circulate and rotate drillpipe at the maximum allowable flow/recommended rate prior tostarting the trip. Experience has shown that 2 to 3 bottoms up volumes may be needed toclean the hole enough for tripping. If sidetracking is possible, move the bit slowly over ashort interval

• Rotate will help stir up and remove cuttings beds especially if lots of sliding is done. Refer toEMDC Technology Group for detailed guidelines.

• In the deviated section, POH slowly as detailed in the drilling procedure (~2-1/2 to 3-1/2minutes per stand).

• If excess drag is indicated, stop pulling, slack off 1 joint, then circulate and rotate at least onebottoms up at the maximum allowable flow rate. Rotating aids significantly to hole cleaningin high angle holes (normal practice is 100-120 rpm).

• Then, if a top drive is available, pump out of the hole at the maximumallowable/recommended flow rates while pulling at 2-1/2-3-1/2 minutes per stand or longer,continue until hole frees-up.

• Once in the lower angle section of the wellbore (preferably inside casing), circulate at leasttwo bottoms up at the maximum allowable flow rate until cuttings returns decrease.

• Once the hole is clean, finish POH without pumping.

• For drilling operations with extended hole sections above 45°, backreaming may benecessary. Operational details will be provided in the applicable drilling procedure. Ensurethat the dangers of backreaming in high-angle holes are thoroughly discussed prior tobeginning the well so that everyone is clear on the strategy to be used.



Rules-of-Thumb

1. Flow rate: Normally offshore drilling flow rates fall between 50 to 70 GPM per inch of bitdiameter. However, flow rates greater than 70 GPM per inch of bit diameter are not unheardof in high angle wells.

• Do not sacrifice flow rate to get more horsepower, jet velocity, or bit pressure drop.

• Too low a flow rate will ball the bit and reduce effective hole cleaning.

• The annulus flow rate is too low to cause erosion. However, nozzle velocities whichare typically 200-400 ft/sec may cause enlargement in low strength rock (<1,500 psi).Limit nozzle velocity to <400 fps in soft rock.

• Fast drilling with low mud weights requires a minimum of 50 GPM per inch of bitdiameter for holes < 20°; higher angle holes may require more.

2. Hydraulic Horsepower: Maintain 2 to 7 hydraulic horsepower per square inch of boreholearea (HHP/in2).

• PDC bits with OBM require less HHP/in2 than with WBM. Total flow rate is moreimportant when drilling with PDC bits and OBM than HHP/in2 .

• Fast drilling generally requires high HHP/in2 ; however, some PDC bits in OBM canget by with as little as 2 HHP/in2.

• Larger bits require more HHP. However, many times in larger hole sizes high HHP isnot possible. In these cases, pump the maximum volume possible.

• Maximum HHP/in2 should be considered only when excess pump horsepower isavailable.

3. Bit Pressure Drop: When operating below QCrit, design hydraulics for 48% to 65%pressure drop across the bit; this is usually the case below surface casing.

• Optimum Hydraulic Impact occurs when 48% of the system pressure loss is at the bitwhile optimum Hydraulic Horsepower occurs with 65% of the loss at the bit.

• If the total of drill string and annulus pressure loss is greater than 52% of the availablepump pressure, smaller nozzles are required. However, do not operate below 30 GPMper inch of bit diameter. Consider using larger drill pipe.

• When running a PDM, it is recommended that the differential pressure across the bitnot exceed 1000 psi to prevent accelerated wear of the rotor / stator assembly.

4. Jet Velocity: Good jet velocities are typically between 350 and 450 feet per second (use lessthan 400 fps in very soft rock to avoid washout).

• Jet velocity will influence chip hold down and ROP.



5.8 Hydraulics Optimization (GOM Drilling for reference)

Except in extremely soft rock, hydraulics don�t literally drill. However, they do clean the bit so thatcuttings build up does not start to carry the WOB that should be on the teeth (balling). Hydraulicsextend the flounder point, which is the point at which the bit starts to ball.

1. In high ROP, directional, the primary hydraulic design criteria is hole cleaning. Optimumhydraulic horsepower at the bit can be utilized to provide effective cleaning of the bit.

2. Hydraulic optimization should be determined by the performance of the rig equipment andthe results of the previous bit run(s).

3. Bit nozzles should be at least 12/32" to avoid plugging for normal drilling operations and ≥14/32" if lost returns are anticipated. MWD equipment and motors may also need to bespecially designed if lost returns are anticipated to prevent plugging the drillstring with LCM.Downhole screens have been used if no nuclear source tools are being run. Use of anydownhole or surface drill pipe screen must be approved by the Operations Superintendent.

4. In soft, unconsolidated formations, limit jet velocity to minimize hole wash-out (<400 fps)

5. In fast drilling and high angle holes, maximize flow rate for better hole cleaning.

6. Carefully analyze ECDs and frac gradients to determine appropriate circulation rates.

7. Frequently in GOM drilling operations, PDC bits are capable of ROPs in excess of our abilityto clean the hole. For these situations, it is critical to optimize RPM and hydraulics toeffectively clean the hole, not necessarily maximize ROP. Utilize HOLECLEAN software toachieve hydraulics design with HCR > 1.1.



5.9 REFERENCE MATERIAL:

Bit Classification

1. World Oil's 1995 Drill Bit Classifier.2. Trinidad's Drilling Operations Manual, Drilling Operations Section, Page 2-7.¹3. Gulf of Mexico's Drilling Operations Manual.4. Hughes Tool Company, Dull Bit Grading Codes chart.5. IADC Drilling Manual, Eleventh Addition, Chapter A, Section 2, Page 2&3; Section 3,

Page 1; Section 4, Page 3&4.6. EPR Drilling Mechanics, Section 4-Roller Cone Bits, Page 34.7. Hycalog's Fixed Cutter Handbook.8. Geology, A Golden Guide, Frank H. T. Rhodes, Classification of Igneous Rocks

Hydraulics

1. EUSA Drilling Engineering School Manual, Hydraulics Section.2. EUSA Drilling Operations Manual (The Red Book) Rig Hydraulics Section.3. EPR Directional Drilling Workshop for ECI, Surveillance and Follow-Up Section.4. IADC/SPE Paper 27464 Hole Cleaning in Large, High-Angle Wellbores, Marco Rasi, EPR5. Drilling Practices Manual, Preston L. Moore, Chapter 10-Hydraulics in Rotary Drilling.6. Randy Smith Drilling School Handbook, TRUE-Well Plan Sec., Hydraulics Planning.7. Reed Tool Company Hydraulics Program Manual.8. Reed Tool Company Hydraulics Slide-Rule and Pump Performance Charts.9. IADC Drilling Manual, Eleventh Addition, Chapter R, Section 13, Page 1.10. Trinidad's Drilling Operations Manual, Drilling Operations Section, Page 2-7. (available

from R. E. Rivers (EMDC)11. Dr. Leon Robinson's Drilled Solids Management Seminar.

DRILLING FLUID SYSTEM

______________________________________________________________________________DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLINGFIRST EDITION MAY, 2003

6.0 DRILLING FLUID SYSTEM

6.1 General 16.2 Solids Control 16.3 Drilling Fluid Treatments 36.4 Drilling Fluid Checks 56.5 High Temperature Drilling 66.6 Stuck Pipe Pills 66.7 Lost Circulation 76.8 Non-Aqueous Fluid Operations 156.9 Rig-Site Dielectric Constant Measurement 336.10 Drilling Fluid System Guidelines 34




6.1 GENERAL

The most efficient drilling fluid system depends on a balance of cost (material and rig time),wellbore stability needs, formation characteristics and environmental issues. An effective drillingfluid system minimizes the number of different chemical components necessary to achieve thedrilling fluid properties specified in the Drilling Program.

Check local requirements for material to keep on hand.

Drilling program development will incorporate an understanding of contingencies based upon theresults of risk analysis in material types and requirements through the numerous stages of a well.

6.2 SOLIDS CONTROL

Maintaining control of the low gravity solids content in any drilling fluid will maximize theperformance of the drilling fluid system. The two common ways to maintain solids control are:(1) solids control equipment and (2) dilution. A balance between the two methods is necessary tomaintain a drilling fluid system in a cost effective manner.

Except when the drilling fluid is unweighted, the most economical method of solids control is to usesolids control equipment. This requires maintaining the solids control equipment in optimumcondition so that it performs in accordance with the manufacturer's specifications. However, solidscontrol equipment is not 100% efficient and some solids control by dilution is always required.

Shale shakers are the most efficient way to remove solids. They see the drilling fluid immediatelyas it comes out of the hole before the cuttings are reduced in size by the surface processingequipment. Use of high quality shakers, with fine screens maintained per the manufacturer'srecommendation, is the most cost effective method of removing solids.

A centrifuge is usually economical in high weight mud (> 14 ppg) or in low weight mud if theliquid phase is expensive (some polymer muds or non-aqueous muds). Dilution is the most costlymethod of solids control when using a weighted drilling fluid (> 11.0 ppg).

Dilution Guidelines

1. Maintain the low gravity solids as specified in the Drilling Program primarily by the use ofsolids control equipment and only dilute when necessary. Some dilution is required on mostmuds.

2. If direct additions of dilution water are made to the active system, be aware that mud additiveswill also be needed to keep mud properties constant.

3. Dilute the active system to the desired solids content in one circulation by partial displacement(discarding a portion of the active mud system prior to diluting with whole mud). Note thatmud discharges are usually regulated by the local governing bodies. Do not exceed maximumhourly mud discharge rate and always ensure that appropriate discharge conditions are metprior to discharge.



4. Dilute the active system prior to weighting up the drilling fluid to avoid dilution of higher costdrilling fluid.

5. Monitoring of the mud's particle size in light or unweighted mud may drive the decision todilute more aggressively.

Dilution - Premixed Drilling Fluid

The advantages of using premixed drilling fluid (whole mud) when diluting the active system are asfollows:

• Easier for Drilling Fluids Engineer to keep up with product concentrations.• Provides a more even concentration of chemicals in the drilling fluid system.• Reduces the need to add bulk materials (salt, barite) to the active system while circulating.

The disadvantages include:

• Adding product that is not needed• Prevents the practice of letting mud property trends drive which materials are used• Ties up mud pit space continuously.

Shale Shaker Guidelines

1. Use shale shakers as the primary means to control the solids content of the drilling fluidsystem.

2. Invest in a generous number of the newest technology shakers available.

3. Use screen sizes that enable the shale shakers to process the entire drilling fluid flow streamwith the flow stream approximately two-thirds to end of screen.

4. Optimize solids removal by evaluating shaker screen sizes continuously and using the smallestscreens possible considering the required pump rate and rate of penetration.

5. Keep shale shakers in good operating condition. Maintain proper screen tension and promptlyreplace torn screens. Corrugated ("Pyramid") style screens have proven effective forincreasing processing capacity. Avoid using corrugated screens on the end panel or on anypanel that is not mostly submerged.

Hydrocyclones Guidelines

1. Use hydrocyclones continuously when circulating an unweighted drilling fluid in mostsituations.

2. Check cones every tour for plugging.

3. Ensure cones are operating in a spray discharge as much as possible.



4. Ensure that loss of drilling fluid from the bottom of the cones is not due to inlet plugging.

5. Feed rates to the hydrocyclones should be about 125% of the downhole pump rate.

6. Ensure cone inlet manifold has head gauge and is operating at 75 ft. of head.

Mud Cleaner Guidelines

1. Use a mud cleaner for weighted or expensive unweighted drilling fluids (high salt, PHPApolymers, etc.) only if high gravity solids to low gravity solids ratio, ppb, is less than 2 in thescreen discharge (i.e. HGS, ppb < 150= 1.5).

LGS 100

2. Check the cones every tour for plugging.

3. Ensure cones are operating in a spray discharge as much as possible.

4. Ensure that loss of drilling fluid from the bottom of the cones is not due to inlet plugging.

5. Wait one or two circulations before operating the mud cleaner when adding large quantities ofbarite to the system.

6. Running the mud cleaner when using screens finer than 180 mesh can result in excessdischarge of barite. Typically, a mud cleaner is uneconomical when using screens over 180mesh in high weight mud (>14 ppg).

Centrifuge Guidelines

1. Feed the centrifuge with drilling fluid from the active system only.

2. Run the centrifuge only as much as necessary to maintain or restore acceptable mud rheologyand filtration properties.

3. Do not exceed the maximum feed rate specified by the manufacturer.

4. Rinse and flush out the centrifuge after use to prevent damage from barite settling.

5. While drilling ahead, a centrifuge will not reduce LGS but will help maintain status quo.

NOTE: Reference URC MANUAL -- Guidelines for the selection, use, and evaluation ofSolids Control Methods.

6.3 DRILLING FLUID TREATMENTS

Drilling Fluid Treatment Guidelines

1. Conduct a minimum of two (2) complete "In" and "Out" checks of the drilling fluid dailyduring drilling operations.



2. Process the drilling fluid returning from the wellbore so that the fluid properties of the drillingfluid going back into the hole are within the range as specified in the Drilling Program.

3. Pilot test any planned significant change to the drilling fluid system prior to making change.

4. Measure and record the drilling fluid weight and funnel viscosity on 15 minute intervals fromthe flow line and the suction pit.

5. Do Not add oil or any additive to the drilling fluid system that is not approved for discharge aslong as fluid discharge is desired.

6. Notify the Driller and Mud Logger of planned changes to the active system volume.

7. Prehydrate all bentonite in fresh water before adding it to the active system in saltwater muds.

8. If available, use a shearing device to maximize yield of gel and polymers when prehydrating.

9. Mix all caustic additions in an enclosed barrel before adding to the active system (not from ahopper).

10. Presolubilizing all polymers in fresh water before adding to a high salt mud system ispreferred.

11. Maximize utilization of all chemicals by pre-hydrating them in fresh water before adding toactive system.

12. Ensure that hoppers are shut off when not in use for mixing.

13. Mud materials (especially bulk materials) should be periodically tested to assure that thequalities of the materials meet API standards, or the standards specified by the contract withthe supplier. (i.e., specific gravity test for barite)

Drilling Fluids Testing Equipment

The Drilling Fluids Engineering Company is to maintain the following testing equipment on the rig:

1. One complete mud testing kit with testing chemicals and API press.

2. Six-speed Fann viscometer complete with heat cup.

3. HTHP filter press if appropriate for the mud type and downhole environment.

4. Digital pH meter and electrode and calibration buffers of pH = 7 and 10.

5. Pilot test kit complete with high speed Waring mixer (Hamilton Beach, Waring Blender orequivalent).

6. Portable roller oven and 2 - 3 heat-age cells.



7. Methylene blue test kit.

8. Pressurized mud balance complete with calibration kit.

9. Garrett Gas Train Kit for measuring carbonates and hydrogen sulfide for either a water mud ornon-aquious fluid (NAF) if appropriate.

Drilling Fluids Report Guidelines

The Drilling Fluids Engineer is to provide a Daily Drilling Fluids Report to the OperationsSupervisor which includes the following:

• Daily and Cumulative Usage of Drilling Fluid Products

• Daily and Cumulative Costs of Drilling Fluid Products Used

• Daily and Cumulative Dilution Volumes

• Daily and Cumulative Drilling Fluid Volumes Lost (Estimated) Over Solids Controlequipment, Lost Circulation, Or Not Accounted For in The Dilution Volumes

• Cumulative Record of All Drilling Fluid Checks Properly Labelled as to Time and Depth ofBit

6.4 DRILLING FLUID CHECKS

The Drilling Fluids Engineer is to make the following measurements for each mud check on awaterbase drilling fluid.

• Drilling Fluid Weight• Funnel Viscosity• PV (Plastic Viscosity) @ 120º F• YP (Yield Point) @ 120º F• Rheometer Readings For 600, 300, 200, 100, 6, and 3 rpm Dial Readings at 120º F• Gel Strengths @ 120º F (10 sec., 10 min., and 30 min.)• API Water Loss at 100 psi and Room Temperature• HTHP Fluid Loss at 500 psi Differential and Temperature Based on ExxonMobil mud

program.• Methylene Blue Test (MBT)• pH Measurement Using a Digital pH Meter• Pf, Mf, and Pm titrated with pH meter• Chloride Content of Rig's Drill Water / Water additions (Barrels)• Chloride Content for mud make-up water• Chlorides and Total Hardness of mud filtrate• Water, Oil and Solids Content (Retort)• Low Gravity Solids Content / Sand Content• KCl (wt%) and Potasium (mg/L) if using a KCl Drilling Fluid System• PHPA (PPB) if using a PHPA Drilling Fluid System



• H2S if Specified in Drilling Program (Garrett Gas Train Measurement of Sulfides.) (mg/L)• Carbonates using Garrett Gas Train (mg/L)• Lime Content

6.5 HIGH TEMPERATURE DRILLING

Hot Roll and Static Age Samples

Drilling muds can potentially have significant gelation problems when exposed to high temperaturesfor long periods. These problems can be especially acute in heavily weighted muds needed to drillabnormally pressured formations. The mud engineer or his assistant is to hot roll and static age mudsamples at anticipated bottom hole temperatures on a frequent basis (minimum 1/week) any timestatic bottom hole temperatures exceed 250 degrees Fahrenheit. Unless otherwise specified in theDrilling Program, samples should be hot rolled for 12 hours and static aged for 24 hours both atestimated bottom hole temperature. Rheology, Gel strengths, pH, and HTHP fluid loss readings ofthe aged / hot rolled samples should be compared to pre-aged readings to evaluate the stability ofthe mud and to help determine if additional treatments are needed.

6.6 STUCK PIPE PILLS

Stuck Pipe Pill Guidelines

1. For differentially stuck pipe, Mix a pill with a volume large enough to cover the BHA,including a 50% excess for hole washout, plus about 25-50 bbls. This volume is enoughfluid to pump 0.5 - 1.0 barrel every 30 minutes for 24 hours.

2. Mix stuck pipe pills that are environmentally acceptable when practical.

3. Ensure that the hydrostatic pressure is not reduced below the pore pressure of the formation when displacing the pill.

4. Mix the pill in the slugging pit or reserve pit.

5. Spot the pill across the BHA as soon as possible using the cement pump.

6. Pump a barrel of spotting fluid every 30 minutes for 24 hours while jarring.

7. If a stuck pipe pill is to be premixed, ensure that it is rolled regularly to help prevent settling.This is especially important in high mud weight and in cold weather conditions.

8. For additional do's and don'ts on spotting fluids, review the "ExxonMobil Stuck PipeSpotting Fluid Guidelines" – available from Drilling Technical Operations Support.



6.7 LOST CIRCULATION

The first priority when encountering lost circulation is to fill the hole as quickly as possible withwater or other light fluid to keep the hole full. It is the responsibility of the driller, mud loggers, andthe mud engineer to be alert for lost circulation. Warning signs are as follows:

1. Loss in Pit Level

2. Complete Loss of Returns

3. Loss of Pump Pressure

A third party data acquisition system with data archiving and alarms should be considered ifmonitoring of lost returns is critical.

Building Integrity

Lost returns occur when the pressure in the wellbore exceeds the resisting stress in the rock. Theintegrity is determined by the closure stress (psi) in the fracture that is created. Closure stress isbuilt by applying pressure to increase the fracture width, which compresses the rock so that itpushes back with greater force. The greater the width achieved, the greater the increase in integrity.However, in order to apply the pressure required to compress the rock, it is first necessary to isolatethe fracture tip which would otherwise continue to grow at a very low pressure. Conventional LCMisolates the tip by becoming an unpumpable mass due to loss of its carrier fluid as it travels downthe permeable fracture face. The LCM also serves to pack the fracture open so that the higherclosure stress is maintained. Even relatively small particles are effective and will become anunpumpable mass if the leakoff is high. High leakoff and high solids concentration are the keyfeatures in the design of pills. Fracture growth is not stopped by blocking with large particles, it isstopped by the loss of carrier fluid and the development of an unpumpable mass.

The pill may have an intrinsically high spurt loss and yet be ineffective if the permeability is low.Hesitation squeezing is critical in low permeability (< 500+ md) because it allows time for thecarrier fluid to leak off. Multiple layers of LCM are eventually built up in the near wellbore regionthat achieve sufficient fracture width and closure stress to allow drilling to continue.

Integrity cannot be built unless a fracture is created and its width increased. If the required increasein closure stress is very low, mud solids alone may achieve the required width when micro-fracturesare just initiating and no loss is observed. If slightly more increase in width is needed, then the wellmay “take a drink” and then drilling may continue. When complete losses occur the most effectiveapproach available should be used on the first attempt. This is justified by the high cost of rig timefor multiple attempts to build integrity. Mix high fluid loss pills, use the highest concentration ofLCM possible, and plan on hesitation squeezing. This may not be the best “first” response in caseswhere the loss zone isn’t a sand over about 100md or underbalanced by greater than 1000psi.



Filling the Hole

If lost returns occurs and the annulus fluid level drops it is essential to fill it immediately. Whenloss is observed:

1. Immediately pick up off bottom a minimum of 15 ft (clear kelly bushing if using a kelly).

2. Shut down the mud pumps.

3. Observe the fluid level in the annulus, (bell nipple) if visible.

4. If it does not stand full, fill initially with 0-20 bbls of drill weight mud to see if the loss isdeclining.

5. If the loss doesn’t decline, fill with water or base oil via the trip tank until losses stop. Theannulus will be stable when the total head equals the fracture closure stress in the loss zone.Measure and record the volume of light fluid required to fill the annulus.

6. Calculate the fracture closure stress (integrity) in the loss zone based on the amount of fill andreport the fill volume and FCS on the daily report.

FCSppg = [(Light Fill Height)(Light Fill Density) + (Mud Height)(MW)]

(Estimated Depth of Loss)

7. Observe the annulus. If the light fill attempts to flow back it is likely that underground flow isoccurring. Shut in immediately to prevent flowback and monitor pressure. Contact theOperations Superintendent immediately.

8. Once the annulus is stabilized, it may continue to drop slowly due to seepage. Begin filling withwhole mud rather than light fill to avoid underbalancing shallow zones with light fill.

Attempting to Establishing Circulation

1. In most cases, it is desirable to pull the pipe into the previous casing shoe.

2. After pulling into the shoe, allow 2-4 hrs before attempting circulation to ensure the fluid in thefracture has leaked off, allowing it to close. Monitor on the trip tank.

3. Work the drill string slowly and use the standpipe choke if necessary when initiating circulationafter waiting on fracture closure.

4. Circulate bottoms up from the casing shoe before tripping back into open hole.

5. Trip in the open hole slowly and break circulation frequently.



Treatment Selection

1. Utilize Figure 6-1 to select the appropriate treatment for severe loss events.

2. Detailed procedures for each treatment type are contained in the EMDC Generic Lost ReturnsProcedure posted on Global Share. This posted document is continuously updated withlearnings in operational practices and pill formulations.



Figure 6-1Lost Returns Treatment Selection Guide

(See EMDC Generic Lost Returns Procedure for details)

Lost Returns Occurs

Does HoleStand Full

Fill Annulus withLight Fluid (water

or base oil)No

Yes

Is FCS > PorePressure

Losses areLikely Vugular

Losses areFracture Propagation

(Most Common)

Yes

WBM

DOB2CProcedure

Cement orFlexPlug

Procedure

Yes No

Is ZonePermeable

ConventionalLCM

Procedure

FlexplugProcedure

YesNo

No

Are Losses Dueto Seepage No

SeepageControl

Yes

WBM

DOB2CProcedure

YesNo



Conventional LCM Treatment for Severe Losses

1. If the well will not circulate, position the bit in the previous casing shoe and prepare forbullhead operations. If the well can be circulated place the bit below the loss zone and circulateLCM entirely out of the bit to position it in the annulus. Pull the bit into the previous shoe toconduct squeezing.

2. If the pill is to be circulated outside, mix the LCM slightly heavier than the mud so that it fallsback to fill the pipe displacement when pulling DP. Use a solid float to prevent backflow intothe BHA. Fill the annulus with whole mud. The string will pull wet.

3. Mix pills by adding water, 15ppb Attapulgite, and LCM. If Attapulgite is not available, use 0.5ppb Xanthan gum as viscosifier. After blending LCM, add barite to achieve required density.

4. Use the highest concentration of LCM that can be pumped through the drill string components.

5. Do not use materials that reduce spurt loss (e.g. fine calcium carbonate, microfibers, starch andbentonite).

6. Do not allow fluid to return from the annulus while squeezing LCM. Shut in prior to startingdisplacement and monitor and record pressures. Any change in annulus pressure is a directmeasure of the change in fracture closure stress (integrity).

7. Hesitation squeezing maximizes fracture closure stress. Place approximately ¼ of LCM intofracture and shut down. Conduct at least two more squeezes with hesitations between each toallow the LCM carrier fluid to leak off. Hesitate for 1-4 hrs between each squeeze. Leave 10-20 bbls of LCM above the loss zone after the final squeeze

8. Hold pressure between squeezes. If backflow is allowed prior to the carrier fluid leaking off, thefracture width and stress will decline.

9. Provide pressure and volume data to the drilling engineer for plotting and archiving in the wellrecord.

10. After holding the final squeeze pressure for a minimum of 4 hrs, bleed off pressure and stagepumps up slowly. Stage the drill string to bottom, breaking circulation at each point andmonitoring the returns for additional gains or losses.

Pill Formulations

Pill formulations continue to improve. Learnings are continually updated and published in theEMDC Generic Lost Returns Procedure, which is posted on Global Share. Contact DrillingTechnical Operations Support for additional assistance in pill design.

The pill should be the most economic design that will successfully build integrity. The ease withwhich integrity is built is dependent on the leakoff (permeability) and the required increase infracture stress (width). If permeability is high or the required increase is small, relatively low



concentrations of medium LCM may be effective (20-40 ppb). In very low permeability andseverely drawn down sands concentrations of over 100 ppb have become standard practice.

The concentration of LCM that can be pumped is limited by particle size and restrictions in drillstring. Medium fibers have been pumped through MWD at 80 ppb. Smaller 400 micron LCM (e.g.,Steel Seal, SweepWate) has been pumped through MWD at concentrations over 300 ppb. Higherconcentrations of smaller particles are more effective than low concentrations of medium material,but it is also more costly. Field experience is required to determine which approach is the morecost effective. Because the spread rate for drilling rigs is high, preference should generally be givento the approach that is more likely to work on the first attempt (high concentrations of 400 micron).

Regardless of particle size or type, the manner in which an LCM is used is more important thanwhat is used. The combination of high fluid loss designs and hesitation squeezing greatly enhancesthe effectiveness of any material.

Ballooning

Ballooning refers to the loss and backflow of mud that is sometimes observed when circulation isbegun and stopped. It is due to the expansion of a lost returns fracture due to the ECD associatedwith circulation, and then the contraction of the fracture when the ECD is removed. It is generallyassociated with soft, low permeability formations. It may occur in higher permeability if low-leakoff mud such as a NAF is in use.

Prevention of Ballooning

Ballooning can be prevented if the mud weight is reduced so that the total ECD is less than thefracture closure stress and the fracture cannot reopen. It may also be possible to stop ballooning bytreating the fracture with Flexplug (NAF) or DOB2C (WBM) to build the closure stress to exceedthe ECD. Cement has also been used successfully, but it creates the potential for sidetracking. Thisis more likely to be successful if the fracture is confined to a discrete sand than if ballooning isoccurring in a shale.

Other Conditions for Lost Returns

1. If the well will not stand full, the LCM pill will be overdisplaced by the hydrostatic head ofdrill-weight mud. Overdisplacement can be controlled by pumping sufficient light fluid at theend to place the drill pipe column underbalanced to the fracture closure stress in the loss zone.The light fill is referred to as a drill pipe “hydrostatic packer”. The calculations for designing ahydrostatic packer are provided in the Generic Lost Returns Procedures.

2. Discuss cutting mud weight with the Operations Superintendent. When returns are lost the BHPfalls to the resisting force in the fracture, which is referred to as the fracture closure stress(FCS). If the annulus remains stable after filling, flow is not occurring with a BHP equal to theFCS. This is an important diagnostic that indicates that the mud weight may be safely cut toequal the calculated FCS without concern for flow.



3. By definition, seepage is the loss of whole mud into the pore throats of the formation (nofracture propagation). Seepage is stopped when fine solids plug the pore throats through whichwhole mud is escaping. In low weight mud (<10 ppb), add fine calcium carbonate at 5-8 ppb forthis purpose (5 micron CaCO3). However, the addition of fine blocking material is questionableat high mud weights where there is already a sufficient volume of barite particles of this size toblock the pore throats. For example, a 13.0 ppg mud has over 100 ppb of particles the same sizeas fine calcium carbonate. Also, do not use “lost returns” LCM for seepage control. Largermaterials such as medium fiber and nut plug do not fit the pore throats well and result in thickercakes. While they slow the loss, they increase the potential for differential sticking.

4. Treatment of the entire mud system with lost returns LCM is discouraged. The detrimentaleffect of medium LCM on mud properties and solids control is significant. System treatment issometimes recommended when very long intervals of lost returns are anticipated that cannot betreated with discrete pills. However, when this occurs it is generally possible to cut the MW anddrill the entire interval prior to conducting a single treatment.

5. If seepage and filtrate control are critical, consider the use of Drill and Seal treatments. Thisprocess is described in detail in the Generic Lost Returns Procedures posted on Global Share.Drill and Seal is used when the filter cake associated with continued low seepage and filtrationlosses may result in differential sticking, torque and drag, or wireline sticking.

6. Conventional LCM does not work if the rock is impermeable and the carrier fluid cannot leakoff (shales). The recommended alternatives for impermeable rock are DOB2C in water basemud or Halliburton’s Flexplug in oil base mud. Neither requires leakoff in order to function.DOB2C is a mixture of oil, bentonite, cement and water that forms a highly viscous slurry thateventually hardens. Flexplug is a proprietary product that forms a rubbery material at down holetemperature. Detailed procedures for each are provided in the Generic Lost Returns Procedureson Global Share.

7. By definition, vugular formations are those with > 1/16” openings. The practical definition isthat they are formations with pore throats that cannot be blocked with conventional LCM (e.g.,carbonates, oyster beds, gravel). The recommended treatment for vugular loss that will notrespond to coarse LCM is cement in oil base mud, or DOB2C in water base mud. Cement mayalso be used in WBM but DOB2C has an advantage in that it can be drilled out without concernfor sidetracking. DOB2C cannot be used in an NAF.

Drilling Without Returns

If cement or LCM pills fail to control the lost circulation, it may be possible, (in short durations) todrill without returns. A cuttings bed build-up in a directional well can result in stuck pipe due toinadequate hole cleaning.

Dry drilling is used in many operating areas as an alternative when major lost returns areencountered.



The drilling fluid is pumped at a reduced rate to:

• Keep the bit lubricated and cool• Keep the bit from plugging• Carry the cuttings into the loss zone to aid in plugging.

Care should be taken when dry drilling, each joint may have to be reamed several times toclean the hole sufficiently, and should only be done with Field Drilling Manager approval.

The reduction in hydrostatic pressure should be considered while dry drilling.

Drilling Bypassing the Shakers

Carrying LCM in the system and bypassing the shakers. This (seal while you drill) method is goodto keep from using the LCM for only one circulation thus reducing the cost, but could compoundthe problem if prolonged. If the shakers are allow to stay by-passed too long, the solids content ofthe mud system will eventually reach a point that the borehole cannot sustain the increased weightor viscosity. The small solids have a tendency to stick, (piggy-back) on the LCM and is circulatedback downhole increasing the solids and thus increasing the mud weight.

There are of course exceptions to both the above, this is not to say they shouldn't be used ifneeded, but experimenting with one or both and experience with them will increase theirusefulness and successfulness.

Cement Plugs

If neat cement is used alone to fight lost returns, a slurry weight of 15.8 ppg has proven to be themost effective. Balanced plugs are to be spotted through open ended drill pipe positioned across thethief zone and the drill pipe pulled into the casing shoe. If the hole does not take any mud afterspotting the cement plug, a gentle bradenhead squeeze may be applied after the drill pipe is in thecasing shoe. Gel cements having lower densities may be necessary with zones that have very littleintegrity or may fracture using neat cement. In mixing this type of cement, the following slurry isrecommended:

13.2 ppg Density 100 sxs Class G Cement 8% Gel 24.3 bbls Fresh Water 1/4 ppb Sodium Carbonate 1/4 ppb Caustic

(The sodium carbonate and caustic are used to remove calcium and magnesium ions.)

Cements such as Cal-Seal (contains gypsum), Thixotropic (containing clays and polymers), andGilsonite (crushed-up limestone) can also be used, though they have not proven to be much moreeffective than regular cement in severe lost return occurrences.

DOB2C



DOB2C is effective in stopping fracture propagation in either low or high permeability rock.However, its primary advantage over conventional LCM is in lower permeability. Becauseconventional LCM requires leakoff of the carrier fluid, it doesn’t perform well in very tightformations or shale. DOB2C can only be used in WBM.

DOB2C achieves integrity through a different process than conventional LCM. Because of itsextremely high viscosity, the wellbore pressure required to squeeze it down an induced lost returnsfracture is high. The high pressure at the wellbore increases the fracture width and fracture closurestress (FCS). The pressure is held while the cement in the DOB2C sets, and the fracture width andincreased closure stress are maintained permanently.

DOB2C is often also preferred to cement in blocking vugular losses because the low-strengthmaterial left in the wellbore is easily drilled out without risk of sidetracking. Another advantage isthat because of its high viscosity it is possible to apply a high squeeze pressure to DOB2C thatensures that the material is forced into all of the vugular openings. Cement may flow freely into thelargest of the openings without developing sufficient back pressure to force additional cement intothe smaller vugs.

Although diesel is most commonly used as the base fluid to carry the bentonite and cement, otherlow-toxicity oils and synthetic based muds have been used successfully.

Flexplug

Halliburton FlexPlug is a blend of latex and other additives that mix with mud to form a rubberymaterial under downhole conditions. Flexplug stops fracture growth by blocking the fracture nearthe wellbore, and then it deforms to maintain the blockage as the fracture widens under squeezepressure. The extrusion pressure of the material is high enough that wellbore pressure is nottransmitted to the fracture tip and fracture growth (lost returns) is prevented. The squeeze pressureis held until the temperature-activated set occurs. Because FlexPlug does not achieve significantcompressive strength (as does DOB2C) there is probably some loss of fracture width and integritywhen the squeeze pressure is released. However, field experience suggests that in many situationsthe sustained stress is adequate.

FlexPlug is a candidate system in 1) NAF, and 2) low permeability, because it does not requireleakoff in order to function, as does conventional LCM. It will also function in high permeability,however conventional LCM is less costly and equally effective I high permeability.

6.8 NON-AQUEOUS FLUID OPERATIONS

General Guidelines

Safety Considerations:

1. Slipping Hazards

Stress cleanliness around the rig: Provide absorbent material to keep the rig floor and catwalk dry.A rig oil mud vacuum, similar to the "Max Vac" system should be installed with outlets connectingto the rig floor, shakers, pump room, BOP deck, etc. to contain mud that accumulates during trips,



when working on pumps, or when spills occur. Rig floor non-skid, studded rotary mats should beused. Frequent use of steam cleaners is recommended.

2. Fire hazards

Provide good ventilation in closed areas, especially on the below-deck pits offshore. The twoperiods of greatest fire risk are when the mud contains formation gas, and when the hole is firstdisplaced and the lighter, more volatile ends of the base oil are being lost to the atmosphere. Noopen flames, cigarettes, welding, etc. should be allowed near oil mud. The rig should be checkedfor electrical shorts and for any equipment or operation which could create sparks; electric motorsshould be explosion-proof. A foam suppression fire fighting system should be considered for the pitroom and shaker area.

3. Air quality

Provide good ventilation in closed spaces, especially over mud pits, shakers and mud mixing areas.Air exchanges of 90 room volumes per hour are usually adequate. Have a room dedicated to mudtesting available; the mud engineer's testing lab must also have good ventilation because volatilesolvents are needed to break the emulsion during many oil mud tests.

4. Skin contact

All contractor and EMDCDO employees who may get oil mud on their skin should be made awarethat it is an irritant and should be removed as quickly as possible. Protective clothing, gloves,rubber boots, and safety glasses should be made available. Water soluble cleansing creams (forremoval of mud from the skin) and barrier protective hand creams should be provided. Crewsshould be told of the health considerations and how to remedy them. This should be consistent withExxonMobil's OSHA (applies to non-US East operations) Hazard Communication Program andcommunicated to the contractor's safety and First Aid leader on the rig.

Protecting the Environment and Minimizing Mud Losses

1. A lower kelly, mud-saver valve should be installed (i.e. Drilco's Mud Check Valve orequivalent).

2. A mud bucket with a drain to the flow line should be used. The pneumatic type Mud Buckethas proved very beneficial when making wet trips or back reaming out of the hole.

3. Both OD and ID drill pipe wipers should be used when making trips unless well controlproblems prevent safe use of ID wiper. ID wiper should have the proper size fishing neck.

4. A drip pan should be used for the pipe rack and catch pans installed where appropriate (e.g.,under centrifugal or transfer pumps).

5. The immediate working area on the rig floor should be combed with 3" flat bar welded onedge, or the equivalent, and drained to the flow line or sand trap with the option of going toa disposal sump.



6. Install oil resistant rubber goods in valving; BOPs (annular element and ram block seals);pump swabs; shaker screen mounts; and flexible hoses. Centrifugal pumps should beinstalled with mechanical seals.

7. Ensure rainwater cannot contaminate mud in exposed pits.

8. Blank off all sources of water around the mud pits. Water is a serious contaminant in oilmud.

9. A pump, supply line, and a nozzle to clean the shaker screens and shaker area are sometimesprovided, but keep in mind the fire hazard generating a fine spray of an oil, particularlydiesel with its low flash point +/- 140-150º F.

10. "No Smoking" signs should be placed in conspicuous locations around the mud pits.

11. A heavy duty explosion proof electric steam cleaner/pressure washer should be available.

12. Rig up a shut-off valve for the base oil supply tank away from the pits.

13. Cuttings removal and disposal systems must be installed. Cuttings boxes or baggingsystems must meet all regulatory requirements.

14. The addition of oil-wetting agent and dilution with base oil should be considered whenbuilding OBM slugs in high-density mud systems. Lower viscosity slugs have proven to bemore effective, especially when utilizing a tapered drill string.

15. A vacuum system provides many benefits.

16. Mud pit drains should be blanked off (skillets installed) to ensure that oil mud can not bedirected overboard.

OIL SPILL PREVENTION MEASURES

Communications

1. There should be a written transfer procedure on the rig and the supply vessel which outlinesthe following (at a minimum):

• product to transfer• sequence of transfer operations• transfer rate• particulars of transferring and receiving systems• emergency procedures• cutting and welding permits are to be returned and put on hold until transfer of OBM

or base oil is complete• spill containment procedures• watch and shift arrangements• transfer shutdown procedure



• spill reporting requirements and procedures

2. A pre-transfer meeting must be conducted on the rig and the supply vessel to review the transfer procedures with all personnel involved.

3. While transferring base oil or OBM from the supply vessel to the rig, a designated crew member will be assigned to observe for leakage from the rig/supply vessel to the sea.

4. Radio communications will be available between the rig control room, rig observer, and thesupply vessel at all times during the operations.

5. A work permit should be issued prior to transferring any hydrocarbon product.

Transfer Hose

1. Hose must be rated for hydrocarbon fluids.

2. Hose design burst rating shall be one of the following, whichever is greater:

a. at least 600 psi, orb. four times the transfer pump's pressure relief valve setting plus fluid hydrostatic, orc. four times the transfer pump's output plus fluid hydrostatic when no relief valve is

installed.

3. Hose working pressure shall be one of the following, whichever is greater:

a. at least 150 psi, orb. the transfer pump's pressure relief valve setting plus the fluid hydrostatic, orc. four times the transfer pump's output plus the fluid hydrostatic when no pressure

relief valve is installed.

4. The hose will be visually inspected for tears, punctures, soft spots, or bulges in the hose exterior, immediately prior to the transfer.

5. It must be verified that the rig and supply vessel connections are mating pair.

6. A ball valve will be installed on supply vessel end of the transfer hose.

7. There will be a positive sealing cap on the end of the transfer hose.

8. The hose length must be sufficient for the supply vessel to move to the outer limits of themooring lines.

9. The hose must be adequately supported to avoid excessive strain on the hose couplings

10. There must be no kinks in the transfer hose when connected to the supply vessel.

11. If the transfer hose is disconnected from the riser pipe, a sealing cap will be installed on theend of the riser.



RIG PREPARATIONS PRIOR TO TAKING ON NAF MUD

1. There should be detailed procedures, with checklists, (refer to NAF/OBM ReadinessChecklist in Section 6 – Appendix G-II) for preparing the rig to take on the oil-base mud.Procedures should heavily emphasize actions that must be undertaken to prevent spilloccurrence prior to loading the product and while it is in use.

2. There should be mud piping schematics available on the facility for the circulating system.This schematic should highlight the location of all dump valves and any other potential spillsource.

3. Consideration should be given to color-coding all dump valve operating handles by paintingthem a distinctive color (e.g., yellow and black stripes). Double valve with a gate valve onthe end and a work permit sign to open valves.

4. Prior to closing each dump valve in the sand traps or mud pits, the seat and the valve O-ringshould be visually inspected to verify that both are clean, free of debris or obstruction, andare not damaged. Each valve shall then be closed while visually observing the seating of thevalve. After full closure, the valve should then be packed with a gel-water paste to furtherenhance the seal.

5. All mud pit and sand trap dump valves should be double-valved, locked in the closedposition, and posted with a sign, printed in English and in the native language, stating "Workpermit required to operate". In some instances, double-valving has been accomplished byinstalling a gate valve downstream of the dump valves in the common discharge line for thesand traps and/or mud pits. NOTE: If a gate valve is not already installed in the dischargeline, installing one will most likely require approval by a regulatory agency such as ABS etc.Another method for deterring OBM from getting overboard is to install a skillet in all dumplines.

6. Consideration should be given to installing a pump-out line between the double-valvedarrangement (i.e., between dump valve and the gate valve) to allow pumping out anypollutant which may leak by a dump valve.

7. Work permit requirements should be in place to operate the dump valves. A work permitshould also be required before OBM can be transferred into any tank or pit that has had adump valve operated, repaired, or resealed.

8. OBM transfers should not be made during hours of darkness, during meal time, or during atour change unless emergency situations dictate or unless prior written policy has beenestablished to effectively deal with the situation.

9. While transferring OBM from the supply vessel to the mud pits, a designated crew membershould be assigned to observe for leakage from the bottom of the rig to the sea.

10. A checklist shall be completed for transfer to/from the rig of hydrocarbons (i.e., Oil BaseMud, Diesel, etc.) and shall include inspection of loading lines, pressure testing of loading



lines, fire protection, verbal communication system between source vessel and destination.Checklists have been included in Section 3 – Appendix G-I.

Frequency Prior to connection of onloading hoses for each transfer cycle (Safety Management Program Section 5.4.1).

11. Rat holes/mouse holes should be sealed with a hose routed to a disposal tank.

12. Pump room drains should be routed to a disposal tank.

13. There should be a drain pan under the rotary table with a return line routed to the flow line.

14. All rig floor drains should be routed to a disposal tank.

15. Slip joint packing and flow line seals should be oil-resistant rubber. Slip joint barrels shouldbe inspected to insure surfaces are smooth and free from scouring.

16. Base oil or OBM should not be stored in a pit longer than is actually required. Holding pitsshould be thoroughly cleaned at the conclusion of each job requiring OBM.

17. Check all BOP and rig valves for rubber and resilient seal compatibility with OBM.

18. Before loading Oil Mud into rig mud tanks, install new rubber products in all low-pressuremud valves and pump suction valves.

19. Stock up on spare rubber products for valves and mud processing equipment.

20. Double-check all valves in the circulating system before loading Oil Mud into rig tanks.

21. Create extra sumps around the pumps and rig substructure to trap oil.

22. Use a vacuum pump to clean out sumps, and to clean out pumps during repair work.

23. Ensure that all mud handling equipment and mixing pumps have drip pans.

24. Add a 2" drain line between the mouse hole and the trip tank (or any tank with the capabilityto pump mud to shakers). With this drain, mud that drains from the kelly can be saved andpumped across the shakers.

25. Double valve all tank lines. If possible, use hard piping (welded Schedule 40) for linesrather than hoses.

26. Install a common overflow between storage tanks to prevent spills during loading andtransferring.



NAF DRILLING FLUIDS

Treatment Guidelines

1. Perform a minimum of two (2) complete (In and Out) checks of the drilling fluid every 24hours during drilling operations.

2. Process the drilling fluid returning from the wellbore so that the fluid properties of thedrilling fluid going back into the wellbore are within the acceptable range per thespecifications in the approved Drilling Program.

3. Pilot test any planned significant change to mud system before making change.

4. When drilling, measure and record at 30-minute intervals the drilling fluid weight and funnelviscosity from the flow line and the pump suction pit.

5. Notify the Driller and Mud Logger of planned changes to the active system volume.

6. Use a shearing device to maximize yield of emulsifiers, gelling agents, and to get a tightoil/water emulsion.

7. Make sure that hoppers are shut-off when not in use for mixing.

Test Equipment

The test equipment listed in Exhibit B of the Mud Materials and Mud Engineering ServicesContract shall be maintained at the rig. See contract for details. Specific items necessary for testingoil-base muds include:

1. Equipment for chemical analysis of oil muds as stated in API RP 13B-2.

2. Reference Manual - API RP 13B-2 "Recommended Practice - Standard Procedure For FieldTesting Oil Based Drilling Fluids", December 1991 Edition or newer.

3. Pressurized Mud Balance with Calibration Kit.

4. Fann 6-speed VG Meter.

5. Thermostatically-controlled viscometer cup.

6. Thermometer (32-220° F).

7. HTHP filter press.

8. 10 or 20 cc mud retort.

9. Electrical stability meter with calibration kit.

10. Electrohygrometer with calibration kit.



Further details on test equipment are given in ExxonMobil Oil and Synthetic Mud TestingGuidelines.

Mud Check Guidelines

Unless otherwise specified in the Drilling Program, the Drilling Fluids Engineer shall make thefollowing measurements for each "Mud Check" on an oil-base drilling fluid.

1. Mud Weight.

2. Funnel Viscosity.

3. Plastic Viscosity (PV) at 120° F.

4. Yield Point (YP) at 120° F.

5. Gel Strengths at 120° F.

6. API Filtration at 100 psi differential.

7. HPHT Filtration at 500 psi differential at temperature specified in the Drilling Program.

8. Alkalinity and Excess Lime.

9. Water Phase Salinity.

10. Calcium.

11. Activity by electrohygrometer.

12. Electrical stability.

13. Water, oil, and solids content (retort).

14. Oil Water Ratio.

Further details on mud checks are given in ExxonMobil Oil and Synthetic Mud TestingGuidelines.

Drilling Fluids Report Guidelines

The Drilling Fluids Engineer is to provide a Daily Drilling Fluids Report to the operationssupervisor daily which includes the following:

• Daily and Cumulative Usage of Drilling Fluid Products• Daily and Cumulative Costs of Drilling Fluid Products Used• Daily and Cumulative Dilution Volumes• Daily and Cumulative Drilling Fluid Volumes Lost (Estimated) Over Solids Control

Equipment, Lost Circulation, Or Not Accounted For in The Dilution Volumes



• Cumulative Record of Drilling Fluid Checks Labelled as to Time and Depth of Bit

Personal Protective Equipment and Facilities

1. Ensure that workers report to work each tour in clean work clothes and that each worker hasextra clean work clothes on site. In general, oil-soaked clothing should be changed as soonas practical.

2. Provide an adequate means of clean-up for workers who have skin contact with oil mud.

3. Provide hand cleaners and barrier creams to remove oil from the skin and to protect the skin.These items should be kept at all eye wash stations.

4. The following personal protective equipment (PPE) should be available for use by personnelworking with oil muds:

• Work gloves (replace when oil-saturated). Chemical resistant gloves worn underneathwork gloves may be used to minimize skin contact. (Latex-type surgical gloves workwell)

• Crew members that work with the mud or mud pumps should wear chemical-resistant(e.g. Neoprene) gloves.

• Safety glasses with side shields.• Hard hat.• Complete slicker suit or chemical apron.• Extra PPE should be kept in dog house for other personnel frequently called to work

on the drill floor.• Rubber boots.• Paper towel dispensers, hand cleaner, barrier cream dispensers, and wash water in mud

pit area. "ZEE" skin cream has worked well in preventing skin irritation.

Industrial Hygiene-Related Training

1. Before beginning an oil mud job, a training program for rig personnel should be conductedto explain health hazards associated with exposure to oil muds.

2. Drilling Contractor must ensure that workers are familiar with MSDS (Materials Safety DataSheets) for base oil and all oil mud additives.

3. Training program should explain proper use of PPE. Requirements regarding use of PPEshould be clearly stated before using an oil mud.

Oil Mud Displacement

Successful displacement of Water-Base Mud by an Oil-Base Mud can be difficult. Unless coveredin the Drilling Program, a Supplemental Procedure that describes the necessary procedures will bewritten by the Drilling Engineer. An example procedure completed using the EMDC US EastDrilling Group Core OBM Displacement Procedure can be found in Section 6 – Appendix S-I.



1. Use a spacer. Consider using dye.

a. Where differential pressure allows, a simple spacer such as a pure base oil oftenworks best.

b. If a weighted spacer is required, oil mud without calcium chloride is best. Incementing operations the spacer must not contain calcium chloride or flash settingcould occur.

2. Spacer Volume recommendations:

a. Use the volume necessary to achieve a spacer height of 200-500 ft in the annulus.Use greater heights for open hole, lesser heights inside casing.

b. WELL CONTROL CAUTION: Calculate effect of spacer on hydrostatic pressures.

3. The displacing fluid should be heavier than the fluid to be displaced. The density of bothfluids should be checked at the same temperature.

4. Condition water mud by deflocculating to lower yield point and gel strengths. Circulatebottoms-up at high pump rate immediately before beginning displacement.

Displacement Procedures

It is very important to plan the displacement carefully. Have thin, freshly circulated water base mudin the hole just before displacement.

1. Circulate and thin the water base mud thoroughly before shutting down to change out thewater mud in the pits with oil mud. On some rigs, the returns can be diverted down a metaltrough (mud ditch) from the shakers to the suction pit; if so, circulation with water mud cancontinue while the remaining pits are drained of water mud and cleaned out.

2. Clean out pits after removing water mud.

3. Put 40-60 mesh screens on shale shakers to handle thick oil mud. Have finer screens readyfor installation after the oil mud has circulated around.

4. Put spacer in slugging pit and fill other pits with oil mud.

5. Zero pump stroke counter after spacer is pumped and before the first good oil mud startsdownhole. Record stroke count when water mud and water mud/oil mud interface has beendisplaced and reasonably good oil mud returns are visible. Start shakers, direct mud to pits.

6. Rotate and reciprocate pipe during displacement.

7. Pump at fast rates during displacement. Reduce rate if pressures increase. Do not stoppumping once the displacement has commenced unless absolutely necessary.

8. Dump water mud or move to storage while pumping.



9. Catch spacer/water mud/oil mud interface and dispose per the approved requirement.

10. Circulate around once, and after determining that the water mud and spacer have come backdivert returns over the shakers and begin remedial oil mud treatments with emulsifier andwetting agents. Typical treatments are in the 0.5-1.0 ppb range for each additive during thenext circulation.

11. Run a check for flow properties, E.S., and HTHP as soon as practical after good mud hascome back (remedial treatments should already have been initiated) and assess the conditionof the mud. Continue treating as necessary, and do not stop circulating until acceptable mudproperties are attained.

12. Change out shaker screens to the smallest mesh possible as soon as the shakers can handle it.

13. Use pump stroke count to estimate the degree of channelling by the oil mud. This will helpdetermine how much water mud was left in the hole.

14. Commence drilling when the oil mud exhibits stable rheology, electrical stability, and showslittle or no water in the HTHP filtrate.

Testing and Conditioning During Displacement

1. Test for water mud/spacer interface every 15-20 minutes until 75% of displacement has beenpumped, then test continuously.

2. Record pump stroke count when reasonably good oil mud returns are visible at the shakers.Use stroke count to calculate how much water mud was left in the hole. If a significantamount of water-base mud was left in the hole, it may have been caused by severely washed-out open hole. Water mud can bleed into an oil mud for several days after the displacement;this mixing can weaken the oil mud emulsion.

3. HANDLING CONTAMINATION: After good oil mud returns are directed over theshakers, emulsifier and wetting agent can be added at the shakers, in the suction, or in bothplaces. Continue to circulate and condition the mud for several circulations and test flowproperties, and Electrical Stability. Check the High Temperature / High Pressure fluid lossfor the presence or absence of water; drilling should not commence until the HTHP is

< 1.0 cc or water free. This process of displacing and then conditioning may take 24 hr ormore and should not be rushed. Ensure the mud is well treated-before drilling ahead.

4. FLUID IDENTIFICATION: To help identify when good oil mud is coming back, runDispersibility and Electrical Stability Tests as follows:

Dispersibility Test

1. Fill one clean glass or plastic container with base oil, the other with water.

2. Place a few drops of the returning fluid in each and observe for signs of dispersibility:



• If the fluid disperses in water and not in the oil, it is water mud. • If the fluid disperses in oil and not in the water, it is oil mud. • If an oil slick forms on the surface of the water or some fraction does not mix, it is a

mixture of water and oil.

Electrical Stability Test

1. Periodically check the E.S. on a sample of the returning fluid.

2. If there is appreciable water mud in the fluid, E.S. will be zero (very conductive).

3. When the amount of water mud declines to about 20-25% in the oil mud, the E.S. meter willbegin giving a low reading (100-200 volts). At this time, slow the pumps and prepare to putthe mud over the shakers.

A. Rig Preparation

1. All welding repairs on pumps, pits, and rig floor should be completed before taking on OilMud.

2. Change swivel packing and blank off all water lines to the pits. Maintain on site a supply of55-gallon disposal drums for oily wastes.

B. Base Oil Storage

1. Bull plug ends of tank lines when not in use.

2. Maintain adequate base oil on location or boat.

3. Use an air-driven wash-down pump for washing shaker screens and other equipment.Ensure that pump suction is protected with a screen.

C. Whole Mud Storage

1. Maintain a minimum of 500 bbl weighted mud in tanks on location.

2. Whole mud storage tanks should be continuously agitated if possible.

3. Monitor gel strengths on stored mud; higher gel strengths are necessary to prevent baritesettling.

D. Solidification

1. Utilize a Drying Shaker to get the drill cuttings as dry as possible and to recycle as much ofthe base oil as possible (e.g. Sweco LM-3 Shaker, Derrick Hi-G Shaker, etc.).

2. Utilize a screw type conveyor(s) or vacuum unit for cuttings gathering, collection anddischarge from the Mixing Unit to the storage area.



OIL BASE UTILIZATION CHECKLIST

Use the OBM checklist in the Safety Management Program

1. EPR - Oil Mud Manual

2. EUSA - Oil Mud Lab Manual / Oil Mud Testing Guidelines

3. NODO - OBM operations Practices Manual

4. NODO Operations & Technical Bulletin No.# 94-21/How to build high-density OBM slugs.

5. Drilling Safety Management Program

LOADING OIL BASE MUD OR BASE OIL FROM SUPPLY VESSEL TO RIG

Responsibility

1. OIM or Barge Engineer/Captain to be in charge of operation.

2. Tool pusher is to be responsible for rig related preparations. Assistant Driller and Derrickman are to assist the Tool pusher.

Preparations

1. OIM or Barge Eng./Captain to hole pre-transfer meeting with involved crew members.

2. Visually inspect transfer hoses for any damage immediately prior to transfer. Transfer hosesmust be rated for hydrocarbon fluids and have a safe working pressure of 150 psi. Verifythat the supply vessel's pumping pressure will not exceed safe working pressure of the hoses.

3. Transfer hoses have a valve on the end, at the supply vessel side, and has been checked fordamage.

4. All others outlets on the load line are sealed off with a blind flange or a valve that is properlyclosed and padlocked (i.e., list specific valves).

5. Valves on sample outlets at each loading stations are closed.

6. Valves on all opposite side loading stations are closed and secured (i.e., padlocked).

7. Tool pusher and ExxonMobil drilling supervisor will verify that all preparations listed here-in have been made before initiating the transfer. Also, the Tool pusher and ExxonMobildrilling supervisor will ensure that the "checklist" is fully completed prior to commencingthe operation. A copy of the completed "checklist" will be provided to the ExxonMobildrilling supervisor.

8. Transfer hoses will be visually checked for damage prior to transfer.



9. Mud pits, shaker pits and shaker box have been emptied and cleaned out per mud engineerapproval. All dump valves have been closed, secured, and tagged.

10. Main mud valve on overboard discharge line is closed and padlocked (specify valves).

11. Trip tank is to be cleaned out. The trip tank dump valves are to be closed and secured.

12. Overboard valves from the rig floor drain are closed and secured. Rig floor drains are linedup to drain tank.

13. Drains in pump room, mud treatment room, shaker room, mud mixing area, and cementroom are sealed.

14. All valves to cement unit are closed. Dump valves from cement unit displacement andmixing tanks are closed and padlocked.

15. Isolation valves in mud pit room between OBM line and drill water line are closed andsecured.

16. Main valve on sea water supply line and all water valves at mud pits, pump room, and shaleshakers are closed and tagged.

17. Main diesel supply line valve has been closed, padlocked and tagged.

18. Transfer pumps are available for use in the event of a spill on the deck or to transfer at thepits.

19. Desander and desilter feed line manifold valves are closed and secured.

20. Valves on possum belly discharge are closed and secured.

21. Water flushing system on shakers screens are closed and secured.

22. Cuttings overboard gate in shale shaker cutting trough is sealed.

23. Cuttings transfer augers are operational.

24. Shaker bypass line to mud pits is closed.

25. Gumbo box bypass line is closed.

26. Gumbo box view hatch is sealed.

27. Cracks in rig floor are sealed with "Builders Foam".

28. Choke manifold discharge line is closed and tagged.

29. Large garbage bags are on rig if needed.



30. Cutting boxes are on rig.

31. Absol is on rig.

32. Vacuum system is operational.

33. Extra personnel on rig for cutting handling as needed.

34. Drillpipe inside and outside wipers are on rig.

Communications

1. All involved rig and supply vessel personnel to have VHF radios.

2. One designated rig crew member to be assigned as lookout during the transfer to observe forleakage from the rig or supply vessel and to monitor transfer hoses.

3. Transferring of oil base mud should be done in daylight hours only, unless ExxonMobiloperations superintendent approves a night transfer. Additional planning steps will benecessary to address problems that could be encountered with a transfer during darkness.

4. OIM, tool pusher, ExxonMobil drilling supervisor, mud engineer, mud logger and controlroom operator will be informed prior to the transfer of OBM.

Transferring

1. OIM or Barge Eng./Captain and the derrick man will double check line up from loadingstation to mud pits.

2. Work permit will be completed prior to the transfer.

2.a Cutting and welding permits are to be returned and put on hold until transfer of OBMor base oil is complete.

3. Connect transfer hose to supply vessel. OIM or Barge Eng./Captain to confirm with supplyvessel captain that transfer hose connection flange is a proper mate to the flange on supplyvessel.

4. Transfer is now ready to be started. The derrick man will monitor volume pumped andchange over as required, opening valves on next pit to be filled before closing valve on pitjust filled. Derrick man and mud loggers will monitor volume received periodicallythroughout the operation and upon completion of fluid transfer.

5. If any difference between volume pumped and volume received should occur, stop thetransfer immediately. The tool pusher and ExxonMobil drilling supervisor are to beinformed of the discrepancy and an investigation will be conducted to find the reason for thedeviation. An acceptable solution to the problem will be implemented prior to continuingthe operation.



6. The mud engineer will perform quality checks of the transferred fluid periodically during theoperation.

7. When transferring is completed, stop transfer pump and close valve on loading line in pitroom. Close the valve at the loading station, the transfer hose must then be bled to thesupply vessel. The valve on the end of the transfer hose at the supply vessel must be closedprior to disconnecting the hose from the flange on the vessel.

8. All mix lines, suction lines and transfer lines to the cement unit and trip tank are to beflushed. All water mud/oil mud interface from the flushing operation must be captured andpumped to a slop tank. After flushing, all valves are to be closed.

DISPLACING WATER BASE MUD FROM THE WELLBORE WITH OIL BASE MUD

Responsibility

1. Tool pusher and ExxonMobil Drilling supervisor to be in charge of displacing operations.

Preparations

1. Tool pusher and Mud Engineer will hold pre displacement meeting with all involved crewmembers.

2. Ensure flowline adapter connections are tightened.

3. Shaker bypass line to mud pits is closed.

4. Shaker bypass line into the gumbo box is inspected, closed, tagged and secured.

5. Gumbo box view hatch is closed and inspected.

6. Dump valves on degasser are inspected, closed, tagged and secured.

7. Trip tank has been emptied and cleaned.

8. Trip tank dump valve is inspected, closed, tagged and padlocked.

9. Rig floor drains are lined up to the slop tank.

10. Valves on overboard lines from the rig floor/slop tank are to be inspected, closed, tagged andpadlocked.

11. Shaker pit and shaker box are cleaned to meet mud engineer approval.

12. Shaker pit dump valves must be inspected, closed, tagged and padlocked.

13. Valves on possum belly discharges are inspected, closed, tagged and secured.

14. Shaker discharge lined up to bypass the sand traps.



15. All drains where OBM could be discharged will be plugged or directed to a slop tank.

16. Air transfer pumps available on rig.

17. Water flushing system valves for shaker screens will be closed and tagged.

18. Cuttings overboard gate in shale shaker cuttings trough is sealed.

19. Hatches on cuttings auger in correct position.

20. Cuttings transfer augers are operational.

21. Drains in shaker, sack, cement and treatment rooms sealed.

22. Desander and desilter feed line manifold valves are inspected, closed, tagged and secured.

23. Overflow tubes and cement unit displacement tank drain lines valves are inspected, closed,tagged and secured.

24. Cracks/openings in rig floor are sealed with "Building foam".

25. Choke manifold discharge line valves are closed and tagged.

26. Air operated mud bucket is on the rig and operational.

27. Drill pipe inside/outside wiper is on the rig.

28. Large bags are on rig if needed.

29. Vacuum system is on rig and is operational.

30. Additional personnel available to handle cuttings auger/cuttings boxes.

31. Plans have been developed to handle the water base mud displaced from the wellbore.

32. A plan is in place to catch the water base mud/OBM interface.

33. Chemicals onboard to treat OBM once displacement is completed.

34. Both mud engineers are on tour.

35. If displacement operations are to be conducted during darkness, ensure adequate lighting isavailable.

Communications

1. All personnel involved in the displacement will have VHF radio access.



2. The tool pusher, ExxonMobil drilling supervisor, mud engineer and mud loggers will beinvolved in the displacement operation.

3. One designated rig crew member will be assigned as a lookout during displacementoperations to observe for leakage.

4. OIM, tool pusher, ExxonMobil drilling supervisor, mud engineer, mud logger and controlroom operator will be informed prior to displacement operations.

Displacing

1. Tool pusher and derrick man will confirm with each other that all valves are lined upproperly prior to starting displacement operations.

2. If any leakage or spills are detected, stop the displacement operations immediately.Implement corrective measures and ensure all involved personnel are notified prior torestarting displacement operations

3. The mud engineers will periodically check the E.S. of the returning mud to determinewhento put the return flow across the shale shakers.

4. After displacement, all mix lines, suctions lines and transfer lines will be flushed and anyinterface will be disposed of in the slop tank.

6.9 RIG-SITE DIELECTRIC CONSTANT MEASUREMENT

General Approach

In general, wellbore stability models are constructed based on cuttings analysis (to determinesurface areas) from several offset wells. The surface areas are then stratigraphically correlated, dataconsistency is evaluated, and a surface area profile is generated.

To apply an offset surface area profile to a prospective well, correlativity of stratigraphy must bedetermined (i.e., How do the offset wells tie to the prospect well?). Typically, simple adjustmentsto stratigraphic tops are made to correlate the surface areas. Sometimes, the depths of offset surfaceareas are "stretched" or "compressed" to accommodate anticipated interval thickening or thinning.This surface area profile is used as input data to a wellbore stability model that is used for wellplanning. Cuttings surface areas can be measured at the rig-site to verify or modify the wellborestability model while drilling. Qualitatively, one can determine if the wellbore should be drillingmore or less stable than the modeled well depending on the comparison of real versus assumedsurface areas. Quantitatively, the real surface areas can be used to revise the model and mud weightschedule.

Measurement Options

Real-time surface area measurements can be made with a portable, on-site DCM kit. The decisionof whether to mobilize on-site surface area measurements should consider the following:



• DCM requires a trained, dedicated mud logger.• A DCM kit costs about $16,000, plus an incremental cost for consumable supplies

Alternatively, cuttings have been shipped from wellsite to EMURCo in Houston or to Σª Labs inAberdeen for analysis. Transportation time (to Houston or Aberdeen) is generally the critical pathitem for off-site analysis. A typical analysis cost is $15-20 per sample. Independent of themeasurement option, approximately 30-50 samples can be analyzed each day. The normal samplefrequency is about once every 30 feet.

Limitations

The purpose of any measurement is to enable some response, if necessary. In some cases, theoptions for acting on rig-site surface area measurements may be limited.

• Certain wells face the difficult situation where the collapse gradient approaches, or evencrosses the fracture gradient. Such a circumstance can be caused by abnormally high orunusually anisotropic tectonic stresses, or when rock strength is very weak compared to evennormal stresses. Due to the conflicting requirements for stabilizing the wellbore (highermud weight) and avoiding lost returns (lower mud weight) the only option is to manage thesymptoms of instability while approaching the fracture gradient as closely as practical.Recent encounters with this situation (see examples below) have motivated current URCresearch on improved leakoff prediction and lost returns mitigation.

• While the EPR shale strength correlation incorporated in the WBSD software is accurate forthe large majority of shales, the strength behavior of certain lower surface area shales hasbeen observed to fall outside the database from which the correlation was delivered. Shalesin Malaysia and the Irish Sea, for example, record surface areas of 100-200 m²/gm whileexhibiting mechanical properties consistent with 400-500 m²/gm. Laboratory work is inprogress to resolve such exceptions to the present database.

Applications

The following summarizes how real-time (on-site) surface area measurements have been or could beused to impact drilling operations:

• Elli: The actual mud weight used took advantage of a 1 ppg "conservatism" (based onNorth Sea experience) in mud weight predictions from the wellbore stability model. Real-time surface area measurements indicated slightly stronger shale than initially assumed,which reinforced confidence in the selected mud weight.

• Bolivia: The pre-drill wellbore stability model was constrained to data from distant near-surface core holes to bracket the expected surface areas. Real-time surface areameasurements were used to qualitatively check shale sensitivity and monitor the inhibitiveeffects of glycol.

6.10 DRILLING FLUID SYSTEM GUIDELINES

On-site measurements of surface areas are recommended when:



• Offset data are sparse.• Correlation with offset wells is suspected, and or• Preliminary modeling indicates operational flexibility to act on wellbore stability model

predictions (i.e., mud weight and/or chemistry can be altered without losing returns).

On-site measurements of surface areas provide useful data, but may not influence operationaldecisions when:

• Mud weight is constrained by the leakoff gradient.• Mud chemistry is constrained by hydrate inhibition requirements, and/or• Shale strength is not consistent with the data base correlation.

If these latter conditions are suspected beforehand, off-sit measurements of surface areas may bemore convenient and cost-effective since the data will be used primarily to:

• Update/calibrate a stability model for future wells, and/or• Conduct a post-mortem analysis for hole problems in the current well.


SECTION 6 - APPENDIX G-I

Prior to the transfer of fluid, all Rig and Boat personnel will meet and review the appropriate JSA's,MSDS Sheets. Fluid Transfer Procedure, and establish two-way communications. Upon thecompletion of the pre-job transfer meeting, all persons involved in the transfer will sign this documentindicating this procedure has been reviewed.

I. TRANSFER FROM MUD COMPANY TO BOAT

A. Prior to Loading Boat Inspect All Hoses, Couplings, and Lines

� Look for cracks and frayed hoses� Ensure connections are tight� Ensure pollution equipment is in place (e.g., 5-gal bucket, drip/catch pans)� Individuals are assigned to monitor transfer (have radios available)� Absorbents pads are available on location

B. Location and Review ESD Operation and Procedure

� Review and formulate (if necessary) ESD Procedure� Ensure ESD works� Individual is assigned to ESD station during transfer

C. Locate and Inspect Fire Fighting Equipment

� Review Fire Fighting procedure� Ensure that the Fire Fighting Equipment is in working order and close at hand

D. Inspect Receiving Vessel

� Open hatches and inspect for cleanliness (if weather permits)� Note if the tank is isolated from sea-chest with a skillet or blank� Inform the Captain and crew that the fluid is not to be rolled or moved during transit

E. Loading the Boat

� Ensure all personnel are at their assigned station (do not leave unless relieved)� Monitor for leaks when the transfer begins - shut down and repair if necessary� verify volume to be transferred� Prior to pumping, a sample will be taken at the Mud Company's storage site� Catch a composite sample on boat while transferring of the first 10%, middle, and

last 10% of the product and split the sample between the boat and Exxonrepresentative

� Verify the Transfer volume at completion


II. TRANSPORTING FLUID

� Stress that fluid is not to be rolled, moved of transferred while transporting to location� If weather permits, periodically sound the tanks to verify no change

III. TRANSFER FROM BOAT TO LOCATION (DRILLING RIG)

A. Hold Pre-Job Safety Meeting and Review JSA, MSDS, and Transfer Policy

� Secure boat to receiving Rig� Look for cracks and frayed hoses� Ensure connections are tight� Ensure pollution equipment is in place (e.g., 5-gal bucket, drip/catch pans)� Individuals are assigned to monitor transfer� Absorbents pads are available on location� Review and be familiar with spill procedure.


� Review and formulate (if necessary) ESD procedure� Ensure ESD works� Individual is assigned to ESD station during transfer


� Review Fire Fighting Procedure� Ensure that Fire Fighting Equipment is in working order and close at hand

D. Receiving Tanks

� Ensure tanks are clean and sealed� Verify volume to be transferred

E. Transferring Mud to Rig

� Catch a sample of mud at the start of the transfer to verify the composition� At the completion of the transfer shut the valve at the rig to prevent siphoning� Drain the transfer hose back to the boat

Signature/Company/Date _________________ Signature/Company/Date ______________________



SECTION 6 - APPENDIX I (continued)

Prior to the transfer of fluid, all Rig and Boat personnel will meet and review the appropriate JSA's,MSDS Sheets. Fluid Transfer Procedure, and establish two-way communications. Upon thecompletion of the pre-job transfer meeting, all persons involved in the transfer will sign this documentindicating this procedure has been reviewed.

IV. TRANSFER FROM RIG TO BOAT

A. Prior to Loading Boat Inspect All Hoses, Couplings, and Lines

� Look for cracks and frayed hoses� Ensure connections are tight� Ensure pollution equipment is in place (e.g., 5-gal bucket, drip/catch pans)� Individuals are assigned to monitor transfer (have radios available)� Absorbents pads are available on location


� Review and formulate (if necessary) ESD Procedure� Ensure ESD works� Individual is assigned to ESD station during transfer


� Review Fire Fighting Procedure� Ensure that the Fire Fighting Equipment is in working order and close at hand

D. Inspect Receiving Vessel

� Open hatches and inspect for cleanliness (if weather permits)� Note if the tank is isolated from sea chest with a skillet or blank� Inform the Captain and crew that the fluid is not to be rolled or moved during transit

E. Loading the Boat

� Ensure all personnel are at their assigned station (do not leave unless relieved)� Monitor for leaks when the transfer begins - shut down and repair if necessary� verify volume to be transferred� Prior to pumping, a sample will be taken at the Mud Company's storage site� Catch a composite sample on boat while transferring of the first 10%, middle, and

last 10% of the product and split the sample between the boat and Exxonrepresentative

� Verify the Transfer volume at completion


V. TRANSPORTING FLUID

� Stress that fluid is not to be rolled, moved of transferred while transporting to location� If weather permits, periodically sound the tanks to verify no change

VI. TRANSFER FROM BOAT TO MUD COMPANY DOCK

A. Hold Pre-Job Safety Meeting and Review JSA, MSDS, and Transfer Policy

� Secure boat to receiving Rig� Look for cracks and frayed hoses� Ensure connections are tight� Ensure pollution equipment is in place (e.g., 5-gal bucket, drip/catch pans)� Individuals are assigned to monitor transfer� Absorbents pads are available on location� Review and be familiar with spill procedure.


� Review and formulate (if necessary) ESD procedure� Ensure ESD works� Individual is assigned to ESD station during transfer


� Review Fire Fighting Procedure� Ensure that Fire Fighting Equipment is in working order and close at hand

D. Receiving Tanks

� Ensure tanks are clean and sealed� Verify volume to be transferred� Catch a sample to verify composition prior to transferring fluid� Catch a composite sample on boat while transferring of the first 10%, middle, and

last 10% of the product and split the sample between the boat and Mud Companyrepresentative





OIL BASE MUD READINESS CHECKLIST Form D-200

Air Quality & Explosions: (areas exposed to oil base mud, i.e., shakers, pits)Adequate ventilation – change-out air every 5 min. or less Y NMud Lab – dedicated to mud testing only Y NMud Lab – explosion Proof Fixtures Y NMud Lab – away from mud pits or Pressurized Y NSigns Posted – “No Smoking & No Hot Work” Y NElectrical equipment explosion proof – motors, lights Y NPersonal Protective Equipment:Mud area – PPE locker stocked with apron, gloves (heavy duty), boots, faceshield, respirator

Y N

Rig floor area – slicker suits (or aprons), work gloves, latex gloves, boots Y NLong pants / long sleeve shirt worn Y NSafety glasses with side shields worn Y NDeluge shower – mud mixing area, rig floor Y NDeluge shower – rig floor Y NEyewash Stations – rig floor, mud mixing area, other areas of potential exposure Y NWash Basins with hand cleaner available – rig floor, mud mixing area, mud pitarea, pipe rack area, other affected areas

Y N

Shipping Hazards: Y NStair steps wrapped with burlap or have non-skid surfaces Y NFloor mats placed at all entrances to living quarters Y NRotary has non skid matting Y NAbsorbent material available for rig floor, other spill areas Y NSteam cleaner or high pressure wash-down unit available Y NDischarges: Y NRatholes/Mouseholes sealed with hose to disposal basin Y NPipe Rack Drains – drained to disposal basin Y NCatch Pan under Rig Floor – drained to disposal basin Y NKick Plates around main deck/pipe rack area Y NKick Plates around the rig floor Y NDump valves double valved, locked, and signs posted with “Work permit requireoperate” Y NDrill pipe wipers used – inside and outside Y NLower kelly mud saver used Y NMud bucket seals in good condition Y NWater Contamination:Open mud pits covered Y NPits cleaned and isolation valves tested Y NBase oil mud lines with hose and nozzles installed – rig floor, mud pit room,shaker area Y NSources of water isolated – rig floor, mud pit room, shaker area, mud mixing area Y NPacking Elements on centrifugal pumps grease cooled, not water cooled – triptank, mixing pumps Y NMedium and coarse non-water absorbing LCM on rig Y N


OIL BASE MUD READINESS CHECKLIST (continued) Form D-200

Deterioration of Rubber goods: Y NBase oil low in aromatic hydrocarbons, i.e. aniline above 145 Deg. F Y NOil Resistant (nitrile) rubber elements, i.e., mud pit valve seals, shaker valveseals, shaker mounts, and hoses

Y N

Oil Resistant (nitrile) elements used in BOP, ram seals, annulars Y NPersonnel and Training:Two mud engineers on location Y NExtra roustabouts for clean up duty Y NWork-hour restrictions scheduled Y NGeneral Safety Meeting – explain OBM hazards and preventative actionsexplained, i.e., clean clothes, deluge showers, hand cleaners

Y N

Use and need for PPE explained Y N

General Comments:

Report By: Position: Date:

Location: Rig: Contractor:

Distribution: Operations SuperintendentRig file

ABNORMAL PRESSURE DETECTION IN CLASTICS

______________________________________________________________________________________DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLINGFIRST EDITION MAY, 2003

7.0 ABNORMAL PRESSURE DETECTION IN CLASTICS

7.1 Background 17.2 Pressure Indicators While Drilling 27.3 Abnormal Pressure Detection Team Responsibilities 107.4 Mud Logging 117.5 Operational Guidelines 15


7.1 BACKGROUND

For all Drilling Operations a casing seat or TD hunt will be prepared in conjunction with theOperations Geologist. Conventional abnormal pressure detection parameters as described inthis chapter generally apply to clastic sequences.

There are no reliable methods to detect the onset of abnormal pressure in carbonate sections.When drilling predominantly carbonate sequences, extreme care must be exercised includingcontrolled drilling, frequent flow-checks, preparedness for lost returns/fractures andconsideration of correlation (whenever possible). Conversely, in clastics, the detectiontechniques contained in this section may be relied upon with a much higher degree of success.

Definitions Normal Pressure - pressure equal to the hydrostatic pressure exerted bya column of water of a specific density extending from the surface tothe depth of the formation. Normal pressure typically refers to 8.5 -9.2 ppg formations that can be drilled safely with 9 - 10 ppg muds.

Abnormal Pressure - any pressure greater than the normal pressure fora given basin.

Hydrostatic Pressure - the pressure exerted by the vertical height of acolumn of fluid.

Transition Pressure - the interval in which the normal fluid pressuregradient changes to an abnormal fluid pressure gradient.

When doesabnormalpressure occur

Abnormally high pressures are found worldwide. Such pressuresoccur when fluid in the pore space begins to support more overburdenthan just fluid weight; i.e., not all of the compressional forces aretransmitted by the rock matrix.

Causes ofabnormalpressure

Many factors can cause abnormally high formation pressures. In someareas, a combination of factors prevails. The most commonlydescribed cause of abnormally pressured or over-pressured sedimentsis under-compaction.Other causes are thought to be:

• Chemical diagenesis• Uplift• Fluid density contrast• Recharged or re-pressured formations, and• Faulting.


Because conditions can vary widely, special care should be taken not toassume that the cause of abnormal pressure established from experiencein a well-known area necessarily is the cause of a similar condition inanother basin which has not yet been adequately tested by drilling.

Documentationof known well-specificabnormalPressure

Ideally, Operations Geology should define well-specific abnormalpressure causes for any well to enhance understanding and operationalplanning to deal with the pressure when it is experienced.

7.2 Pressure Indicators While Drilling

The following tools & parameters, listed in their order of reliability, areused to monitor for abnormal pressure in clastic sections while drilling:

• Rate of Penetration Curves (includes d and dc exponents)• Total Drilled Gases (BGG, CG, TG, etc.)• Mud Properties (chlorides, viscosity, flowline temperature, etc.)• Cuttings Analysis (lithology, shale density)• Paleontology and Paleobathymetry• Borehole Instability (hole fill, torque and drag)• Correlation (Mud log & LWD with offset logs)• Real Time Pore Pressure Plots (LWD Sonic, Density or

Resistivity)

Rate ofPenetration(ROP)Interpretation

An increase in ROP with constant parameters indicates a drill-off trendand generally indicates an increase in pressure. However, maintaininga constant ROP over a long interval may also indicate increasingpressure since the expected bit dulling trend (decrease in ROP) did notoccur.

Depending on bit type, increased ROP in the transition zone hasconsistently been one of the most definitive indicators of entry intooverpressures when other drilling parameters are maintained constant.

FactorsaffectingROP

Successful use of ROP to detect dulling trends and drill-offtrends is dependent on maintaining constant drilling parameters. Thefollowing factors all affect ROP:

• weight on bit


• rotary speed• bit type/size• bit condition• mud viscosity• hydraulics• differential pressure, and• lithology

Reference: See Section III of the Abnormal Pressure Technologymanual for additional information.

Note: The referenced manual should be reviewed before interpretingthese parameters during an abnormal pressure hunt.

ROP plotting Plotting of ROP is used to differentiate pressure-induced drill-offtrends from normally expected bit dulling trends. These trends arebased on the common assumption that when a bit is first run in the holeand begins to rotate, it begins to wear out or dull which results in aslower ROP (dulling trend).

ROP andlithology

It is important to note lithology changes when plotting ROP.Normally, a drill-off (drilling break) will occur in a silty-shale orsandstone. Thus, when looking for drill-off and dulling trends, "clean"shale intervals should be used.

"d" exponentcurve

Another curve used to predict increasing pore pressure is the "d"exponent curve. This drilling exponent is used to normalize ROP dataand changes in bit weight, rotary speed, and hole size to detectincreasing formation pressure.

Reference: See Section III of the Abnormal Pressure Technologymanual for additional information.Note: The referenced manual should be reviewed before interpretingthese parameters during abnormal pressure hunt.

"dc" exponentcurve

Another curve used in the corrected "d" exponent ("dc"). This value isthe "d" value corrected to the gradient of the basin in which the well isdrilled, and for the mud weight.

Reference: See Section III of the Abnormal Pressure Technologymanual for additional information.


Note: The referenced manual should be reviewed before interpretingthese parameters during an abnormal pressure hunt.

Gas units One of the most important surface measurement parameters used toindicate abnormal pressure is the "gas unit". There is no quantitativecorrelation between gas units and pore pressure.

Interpretationof gasreadings

Detection of abnormal pressure, and even the evaluation of a zone ofinterest, is a matter of comparing parameters through the interval inquestion with the previously established trends. The key tointerpretation is not the magnitude of the gas readings but the relativechange in the readings.

Types of gas The different types of gas are as follow:

• Background Gas (BGG), also called Drill Gas• Trip Gas (TG)• Connection Gas (CG)• Circulating Gas (Circ BGG)• Show Gas, and• Shutdown Gas.

BackgroundGas (BGG)aka Drill Gas

Background Gas (BGG), or Drill Gas is the average gas observed whiledrilling, exclusive of shows. Background gas represents the gasliberated from the pores in the rock that is being ground up by the bit.

Effect of drillpipe pullingspeed on tripgas

Pulling pipe can create a swabbing effect, which lowers the effectivebottom hole hydrostatic pressure during tripping. Drill pipe pullingspeeds must be reduced in critical sections of the well to a level whichminimizes swabbing to ensure that trip gas will be a valid parameterreflecting the actual degree of overbalance of the pore pressure by thestatic mud weight.

Trip Gas (TG) Trip GAS (TG) is the maximum gas observed on bottoms up after atrip. Trip gas represents the amount of gas feeding into the hole whenthe pumps are shutdown and the pipe is tripped.


ConnectionGas (CG)

Connection Gas (CG) is the maximum gas observed on bottoms upafter a connection. Connection gas represents the amount of gasfeeding into the hole when the pumps are shutdown while making aconnection. When the pumps are shutdown, the effective mud weight,or equivalent circulating density (ECD) is decreased because of loss ofthe annulus flow friction effect. Some portion of the connection gasmay also be due to swabbing when picking up for the connection.

Connectionconsistency

To be a meaningful parameter, connections should be madeconsistently, requiring the same amount of time and pick-up speed tocomplete each connection. When picking up to make a connection, thepumps should be left on until the tool joint is at the break-out point.When drilling with a top-drive, it is often desirable to simulateconnections to increase the frequency of the connection gas indicator.

Kelly cut gas A phenomenon sometimes associated with connections is kelly cut gas.It results from air getting into the drill string during a connection.When this "void" in the drill pipe is circulated around (bottoms upcapacity plus drill pipe capacity), it sometimes shows a gas peak. Thesephenomena should be distinguished from connection gas.

CirculatingGas(Circ BGG)

Circulating Gas (Circ BGG) is the stabilized level of gas observed afterall of the cuttings have been circulated out of the hole. It representsresidual gas in the mud system after recent cuttings gas has beencirculated out of the well.

Time forcirculating gasto stabilize

Background gas (when drilling) or bottoms-up gas (after tripping)should drop quickly to a stabilized level after circulating out thecuttings or trip gas. If significant time is required to reach thestabilized level, gas could be feeding in because of insufficient mudweight.

Show Gas Show Gas is cuttings gas observed while drilling a potential reservoirinterval (usually associated with a drilling break).

Reactions toshow gas

Mud weight should not be raised solely in response to show gas fromcuttings. When in doubt, circulate out to determine the circulatingbackground gas level. If the excessive gas units drop rapidly to below


drilling background levels, the gas came from drill cuttings. If the gasunits continue to be excessive after circulating out, the well could be ator very near balance conditions.

Shutdown Gas Shutdown Gas is gas resulting from pump shutdown period; i.e., forequipment repair, etc.

Gas reporting The table below describes how to report the various types of gas.

Gas type Report as ExampleBackgroundGas (BGG) akaDrill Gas

BGG (Depth to Depth) BGG 40 units from 7000' to 7500'and 60 units from 7500' to 8000'.

Trip Gas (TG) Maximum gas observed from tripdepth minus background gas priorto trip. Also note the timebetween B/U trip gas peak andreturn to background gas leveland report if more than normal.

Background Gas before trip: 50unitsMaximum gas observed from tripdepth: 150 unitsReport Trip Gas as: 100 units or100 units over BGG

ConnectionGas (CG)

Maximum gas observed fromconnection depth minusbackground gas prior toconnection. Also note the timebetween the B/U gas peak and thereturn to the prior gas level andreport if more than normal.

Background Gas beforeconnection: 50 unitsMaximum gas observed fromconnection depth: 75 unitsReport Connection Gas as: 25units or 25 units over BGG

CirculatingGas (CircBGG)

Stabilized gas units without drillgas or trip gas.

BGG while drilling is 50 units,after picking up off bottom andcirculating out bottoms up, the gaslevel falls to 25 units. Report CircBGG as 25 units or 25 units overBGG.

Show Gas Maximum gas observed from thedrilling break minus backgroundgas.

Background Gas before drillingbreak: 50 unitsMaximum gas observed fromdrilling break: 750 unitsReport Show Gas as: 700 units or700 units over BGG


Shutdown Gas Maximum gas observed fromshutdown period minusbackground gas prior toshutdown.

Background Gas before shutdown:50 unitsMaximum gas observed fromshutdown period: 75 unitsReport Shutdown Gas as: 25 unitsor 25 units over BGG

Mud propertiesto plot

The mud properties to be plotted include:

• mud density• total chlorides (titrated or resistivity)• temperature• ion change (calcium and sodium)• mud viscosity (funnel, plastic, yield point and gels) and• pH factor.

Frequency ofmud propertiescheck

When looking for abnormal pressure, the mud properties should be keptas constant as possible. The mud properties (both in and out samples)should be checked every four (4) hours or more often if the mud is gascut. Bottoms up after each trip should also be checked.

Plotting method The mud properties should be plotted in a graphical or columnar form.

Changes inrheologicalproperties

Any significant change in the rheological properties of the drilling fluid(especially a freshwater mud) when drilling over-pressured formationsmay be an indication of an under-balanced wellbore condition.

Changes inchlorides

An increase in the total chlorides over the average for the normalpressure portion of the hole may indicate a formation water influx andentry into higher pore pressure. An increase of chlorides causesdrilling fluid chemical changes that show up as an increase in:

• funnel viscosity• plastic viscosity, and• yield point.


Oil / water ratio If drilling with an oil based mud , the oil/water ratio may be anindicator of an influx of formation water.

Temperaturegradientchanges

A temperature gradient change as indicated by the temperature of themud returns at the flowline may indicate that over-pressured sedimentsare being drilled. Generally, this change will be an increase in theflowline temperature due to a higher geothermal gradient in the over-pressured zone. However, a change in the temperature gradient mayalso indicate:

• the crossing of a fault• an unconformity, or• a change in lithology.

Factorsaffectingtemperature

When considering circulating mud temperature to detect a transitionzone, it is very important to remember that these temperatures dependupon the following items:

• ambient temperature• circulation rate• system volume (mud tanks, etc.)• time since circulation• solids content in mud• addition of fluids and additives (humidity, heavy rains if pits are

open), and• penetration rate.

Temperatureplottingguidelines

The following guidelines are recommended in order to obtainmeaningful temperature data that can be assimilated into pressureindicator form.

• Monitor and record simultaneously inlet (suction) and outlet(shakers) temperature.

• Plot with other parameters.• Consider lag time to correlate temperature with depth.• Establish gradient for each bit run.• Do not establish the mud temperature gradients until after the

effects of tripping have normalized (usually 30' to 40' ofdrilling).

• Observe sudden increase in the outlet/inlet differential.


Changes inphysicalproperties ofcuttings

Cuttings from the transition zone will have different physical propertiesfrom normally pressured cuttings. Some of the physical changes are:

• Composition• Color• Texture• Size• Shape• Fracture• quantity, and• bulk density.

Color change Color change is often noted from multi-colored green, reddish brown,tan and light gray non-marine shales in normally pressured sedimentsto a darker gray and often dark brown to gray marine shales inabnormally pressured zones.

Texture change Textural change in shale may be from silty and rough to waxy, slick orsoapy.

Shape change A change in shape may occur from semi-flat, rounded cuttings toangular, flat, splintery and often jagged and elongated (propellershaped) concave curved cuttings. Sometimes large cuttings severalinches long, known as spalling shale, are noted when drilling under-balanced.

Quantitychange

Quantity of cuttings often increases when the overpressure becomesgreater than the mud column pressure. This occurs when the formationbegins to implode into the wellbore. Occasionally, there issimultaneously torquing of the drill pipe and the pump pressureincreases. Also, this is generally when you get fill on bottom aftermaking a connection.

Density change A decrease or departure from the normal compaction trend in the saledensity of the cuttings is another indication of drilling overpressuredshales.


7.3 Abnormal Pressure Detection Team Responsibilities

Team make-up When deployed an abnormal pressure detection team should consist ofthe following members:

• Rig Supervisor• Wellsite Geologist• Drilling Engineer (if required)• Paleontologist (if required)• Mudloggers, and MWD personnel• Rig Hands

� Driller, and Shaker hand� Mud Engineer

When shouldteam arrive

All team members should be at the well site ±24 hrs before thetransition zone is expected. This allows time to monitor all theindicators so that a "normal trend" reference line can be established.

Mission of team

Team membersresponsibilities

The table below describes the responsibilities of each member of theteam.

Role ResponsibilitiesRig Supervisor The Rig Supervisor is responsible for the drilling rig and all on-site

activities and is designated as the Team Leader. The supervisor has theultimate onsite authority on when to raise the mud weight, stop drilling,and log based on the advice of the other team members.

WellsiteGeologist

The Wellsite Geologist's duties are to plot and interpret variousgeological abnormal pressure indicators, interpret and correlate logs(MDS/LWD logs, electric wireline logs, mud logs, etc.), and calculateestimated pore pressure from logs and shale density plots.

DrillingEngineer

The Drilling Engineer's duties are to interpret drilling parameters. TheGeologist and Drilling Engineer must maintain close communicationand closely analyze the various indicators as the hole is drilled.

Paleontologist The Paleontologist's duties (if required) are to identify correlativemicrofossil zones, construct paleobathymetric maps, and help the teambetter understand the geology.


MWDEngineer

The MWD Engineer's duties are to maintain QC of LWD logs, andestimate pore pressure changes from log plots.

Mudlogger The Mudlogger's duties are to record all abnormal pressure parameters,make lithologic descriptions of the cuttings, watch for hydrocarbonshows, and maintain a lithology/drilling parameter log plotted up todate continuously as the well is being drilled.

Driller The driller's duty is to maintain the drilling parameters (WOB andRPM) as constant as possible and as specified by the Rig Supervisor.He should immediately notify the Rig Supervisor of any changes.

Mud Engineer The Mud Engineer's duty is to measure the mud weight at intervalsspecified by the Operations Supervisor and keep the other teammembers updated.

Shaker Hand The shaker hand's duties are to assist the mud engineer in monitoringmud properties, monitor cutting size and volume, and monitor for flowwhen pumps are down.

* Most abnormal pressure detection operations are conducted by contract Geologist with noEMDC Geologist or Engineer on site. Proper communication should be made through withthe team members at the rig site and office.

7.4 Mud Logging

Where arespecificationsfound

Mud logging services and interval will be specified in the DrillingProgram.

Abnormalpressureparameters tobe monitored

Abnormal pressure parameters are to be monitored by the mudloggersand may include the following:

• rate of penetration• d/dc• gas detection

� background gas� connection gas� trip gas, etc.

• chromatograph readings• lithologic descriptions• shale density, surface area and description• "In" and "Out" mud properties, and

� weight� temperature� chlorides, etc.

• hole conditions� torque� drag� fill, etc.


Plotting Data While drilling, the Mudloggers will plot the specified data on a mud logon a continuous basis and maintain 24 hour surveillance of thewellbore.

Distribution/frequency ofreports

The Mudloggers will:

• provide the Drilling Supervisor a copy of the mud log and mudlogging report daily, and

• fix a copy to Company personnel as specified by the DrillingSupervisor/Wellsite Geologist.

Note: It may be required to fax the mud log to the office more oftenwhen drilling in or near possible transition zones (typically, aminimum of twice a day to office for Operations Geologist, andSuperintendent's review).

Mud loggingunitspecifications

The mud logging unit should met the following specifications:

• A pressurized logging unit large enough to accommodate therequired personnel should be use. This could include:� Mudloggers� Wellsite Geologist� Pressure engineer (if required), and� other required personnel.

• All instruments in non-pressurized sections of the unit will beintrinsically safe.

• The unit should have an alarm to detect depressurization.

Detailed specifications for the mud logging unit and associatedequipment will be in the mudlogging contract.


Gas detectionequipment

• A Hydrogen Flame Ionization Gas Detector (FID) andHydrogen Flame Ionization Gas Chromatograph system will besupplied on the unit with a second system provided as backup.

• An integrator will be supplied for gas percentage calculationsfrom the chromatograph.

• Gas readings will be calibrated to :� 2% methane balance in air (2% = 100 units), and� 20% methane balance in nitrogen (2% = 1000 units).

• A carbide lag (or in Oil Base Mud some other type of lag) willbe made each 24 hours to check operation of gas detectors andlag time.

Gas trapequipment

• The primary gas trap must be constructed so that mud entersthrough a 1.5" to 2" hole in a bottom plate on the trap. Two (2)opposed, open stirrup (curved or straight) agitator blades shouldbe used. An air motor is preferred.

• A backup gas trap should be available on location at all times.• The secondary gas trap extracts a precise quantity of mud from

the possum belly and automatically extracts gas entrained in themud. It should be self-calibrating and incorporate two (2) FIDsas sensors.

Computerequipment

• A minimum of three (3) monitors are to be installed as indicatedbelow:� one in the Drilling Supervisor's office� one (Div 1, Class 1, intrinsically safe) on the rig floor, and� one in the mud logging unit.

• Computer software and instrumentation capable of measuringand displaying the following data are ideal:� ROP� Torque� pump pressure� total gas� pit levels� Dxc exponent (calculated)� mud resistivity� temperature� RPM� WOB� Pump strokes� flow rate� trip tank levels� rotary torque, and


� mud density

This software and instrumentation should be independent from the rig'sinstrumentation and have alarms with high/low levels.

Lithologydescriptionequipment

• UV light box with tow (2) 3600 angstrom UV lights plus one(1) white light.

• High quality binocular microscope with high intensity light.• Lithology determining chemicals (e.g., HCL, Alizarin Red).• Probes, tweezers, sample trays and sieves.


Guidelines Guidelines for drilling in abnormal pressure areas are:

• The BOP must be tested and functioned, and the drill crewsdetermined to be qualified and competent (via training anddrills) on flowcheck and well shut-in procedures in accordancewith the Well Control Section of this manual.Reference: See the Well Control Section of this manual foradditional information.

• The drilling fluid should be stabilized at the pre-determinedweight.

• Adequate barite must be on the drilling rig to weight up to atleast the expected mud weight (minimum: the higher of 1000sacks or 1 ppg increase over current mud weight).

• Barite needed should be addressed in lost return areas.• The barite quantity on-site must comply with the regulations of

the MMS or State Agency. Check mud company inventory ofbarite at their base and how rapidly it can be mobilized to therig site.

• The PVT and FLO-SHO alarms should be set to the lowestpractical limits.

• The abnormal pressure detection parameters specified in theDrilling Program must be monitored continuously.

• The drilling parameters should be stabilized as soon as possibleduring each bit run and maintained constant to allow for moreaccurate pressure detection.

• If mud weight must be raised in response to abnormal pressureindicators, drilling should cease and the well should becirculated until the system is stabilized at the new mud weight.After consultation with the Operations Superintendent, the mudweight may be increased gradually while drilling if conditionsallow.

• Consideration should be given to using mill tooth bits as theyhave been the most reliable in responding to abnormal pressureindicators. Successful abnormal pressure hunts have beenconducted with insert bits, and PDC bits in areas withsignificant local knowledge and where offset experience exists.

FORMATION EVALUATION


8.0 FORMATION EVALUATION

8.1 General 18.2 Conventional Coring 18.3 Wireline Logging Program 88.4 Sidewall Coring Operations 118.5 Wireline Radioactive Sources 128.6 MWD/LWD Logging 128.7 Mud Logging and Cuttings Samples 14



8.1 GENERAL

Formation evaluation takes many forms and in many respects is the province of the wellsitegeologist. However, operation of the equipment and its effect on well safety, is the responsibility ofthe operations supervisor. Therefore, each major method of formation evaluation will be discussedin view of operational considerations.

8.2 CONVENTIONAL CORING

For all Drilling Operations, a supplemental procedure will be prepared detailing the coringoperations. The objective of coring is to obtain a formation sample for geological or reservoirevaluation, determine permeability, porosity, composition of the rock, and to conduct flow studies.Because of the valuable information, which the cores provide, the drilling objective is to furnish themaximum core recovery, minimal core damage, and minimum operational cost.

In order to do this, planning is the crucial first step to ensure that a core analysis program issuccessful and that the money used to obtain and analyze the core is well spent. Deciding on thecoring objective, mud type, core cutting method, and core handling procedures at the surface are thefirst steps in the planning process.

The most widely used coring method today is the conventional double tube (inner and outer) corebarrel with a PDC or diamond core head. Diamonds cut with a shearing action and thus greatlyreduce the fracturing of the core. This enhances the recovery because a non-fractured core is lesslike to jam the core barrel before a full-length core has been cut.

Standard core catchers are routinely used successfully in areas with consolidated formations. Closedcatcher core systems such as Baker Hughes Inteq's "Hydro-Lift", used almost exclusively in the Gulfof Mexico, are used in coring unconsolidated formations to enhance recovery. In these cases, use ofa face discharge bit (in which the inner core barrel can extend into the bit throat area) isrecommended to minimize erosion of the core as it is cut.

Pre-Coring Meeting

A pre-coring meeting should take place a week or two before coring, and should be attended (ifpossible) by all personnel that will be involved. At the meeting, the coring objectives and the coringplan can be reviewed and minor changes can be made if necessary. The role and responsibilities ofall personnel should also be discussed. This will help everyone realize that coring is a team effort,and that each person's role is vital.

Conventional Coring Equipment

Core Bits

Diamond core bits are available in numerous designs for drilling various types of formations. In



general, for soft formations, large diamonds are spaced relatively far apart, whereas in hardformations, smaller diamonds are set closer together. The cost of the core bit depends on the totalcarat weight of the diamonds plus the setting charge. Used bits are returned for salvage of thediamonds and to receive credit for the reusable stones.

Beside the PDC/diamond placement, the main difference in core head design is the location, size,and number of drilling fluid passages for cleaning and cooling the bit. This design depends on theformation to be cored along with the available pump horsepower. Relatively large fluid coursespermit higher fluid circulation rates for flushing the hole while cutting sticky shales. Smaller,numerous fluid courses provide better cooling of the diamonds while coring hard abrasiveformations.

When coring in soft formations, EMDC may elect to have the coring company manufacture the corebits with their "throats" 1/8" smaller than the inner barrel or liner inside diameter. This clearancewill allow the shales to swell and hopefully prevent the barrel from jamming and resulting in poorrecovery. Face discharge core heads may also reduce erosion due to fluid flow past the core.

In hard formation wellbores, the initial trip in the hole with a core bit should be done with carefulmonitoring for excessive drag, particularly in the lower portion of the last bit run. As a bit drillshard formations, the gauge protection of the bit can wear creating an under gauged hole. As the fullgauge coring assembly enters this part of the hole, the bit and full gauge stabilizers on the core barrelcould stick. If the drag becomes excessive, the assembly should be pulled from the hole and a holeopener or reamer run to open it to full gauge.

Core Barrel

The conventional core barrel for diamond coring consists of an outer barrel which houses a free,non-rotating, inner core barrel that is made of either light weight steel, aluminium, or fiberglass. Inorder to obtain a good core, the inner barrel must not rotate with the outer barrel. This isaccomplished by suspending the inner barrel on a swivel assembly which utilizes a mud lubricatedanti-friction bearing. The core bit is made up on the bottom of the outer barrel while the inner barrelis fitted with a core catcher assembly at its bottom.

Conventional wall thickness barrels are generally available in the following sizes:

Outer Barrel Diameter Core Diameter 4-1/8" 2-1/8" 4-3/4" 2-5/8" 5-3/4" 3-1/2" 6-1/4" 4"

6-3/4” 4" 7" 4-3/8" 8" 5-1/4"



If either barrel becomes bent, the unit should be replaced because the inner tube will probably rotatewith the outer tube. The inner barrel must have a smooth uniform bore to allow passage of the coreand to prevent wedging. The unit should always be checked before starting in the hole. Theassembly can be hung in the derrick and the inner barrel hand-rotated before making up the corehead.

Inner Barrel Plastic Liners

When coring in soft, unconsolidated formations, a plastic liner can be run that will help prevent theinner barrel from jamming, and help protect and preserve the core during removal and transport. Inmedium to hard formations, these liners are normally not run.

There are three types of plastic liners: 1) Polyvinyl chloride (PVC) with temperature limitations upto 150 degrees F, 2) Acrylonitrile Butadiene Styrene (ABS) with temperature limitations up to 180degrees, and 3) Butyrate, a clear plastic liner that has a temperature limitation of 140 degrees F. ThePVC plastic liner is typically run when coring soft formations, though aluminium liners have beenused in hotter holes where the BHT exceeds 180 degrees F.

The use of these plastic liners will reduce the size of core that can be cut, by 3/8" to 1/2" dependingon the size barrel being used.

Fluted Aluminium Inner Barrel

Very high recovery of long cored intervals has been achieved with fluted aluminium inner barrel inNorway. The design is believed to reduce core to inner barrel friction and therefore reducedjamming.

Stabilizers

Full gauge (1/32” under) integral bladed stabilizers near the top and just above the bit will keep thebarrel from wobbling while coring, and should be replaced when worn down more than 1/8". Ifunder gauged stabilizers were used in drilling the section of hole immediately above the core point,these full gauge stabilizers may cause excessive drag while going in the hole that could stick theassembly. An additional trip with a reamer or hole opener may be necessary before coring cancommence.

Safety Joint

A safety joint at the top of the core barrel enables recovery of the inner barrel and core should theouter barrel become stuck. This will leave only the outer barrel and core bit to be fished from thehole.

It should be noted that the safety joint is made with a left-hand thread that only requires 50% of themake-up torque to release. In high angle directional wells it may be impossible to work downenough left hand torque to the safety joint without backing-off the drill string at a higher point.



Pump-Out Sub

A pump-out sub (circulating sub) should be run above the coring assembly that can be opened in theevent that the flow passages around the bit should become plugged during coring operations. A ballis normally dropped and the drill string pressured-up rupturing a disk that opens flow ports in thesub. Various pressure rated disks can be run, normally using those set to rupture at 3500 psi.Circulation can then resume and the hole cleaned prior to pulling out of the hole. The coringcompany provides these pump-out subs.

Coring Jars

Mechanical jars should NOT be run when coring because they can do serious damage to a corebarrel assembly. If the drill string is stuck at the bit, mechanical jars have been known to tear thethroats out of a core bit. A hydraulic jar (such as Bowen or Houston Engineering) is preferred bymost core companies because the jarring blow can be controlled by the overpull from the rig floor.These jars are placed either towards the bottom of the HeviWate drill pipe, or in the upper portion ofthe drill collars.

CONVENTIONAL CORING TECHNIQUES

Preparing to Core

It is very important that the hole be clean of any debris (rock bit teeth, bearings, etc.) to preventdamage to the PDC or diamonds. If necessary, a junk boot basket can be used during the last bit runprior to coring. If there is junk suspected on bottom after the last bit run before coring a boot basketrun is recommended. The drilling engineer should work closely with the core bit manufacturer toselect the best design and type of bit for the type of formation to be cored, anticipated mudproperties, and available hydraulic horsepower.

As with all drilling assemblies, accurate measurement of the core barrel assembly including theBHA should be made before going in the hole. After touching bottom while circulating, the bitshould be held approximately 3 foot off-bottom and circulation continued to wash the hole clean ofany fill that might have accumulated during the bit trip.

Mud Properties

While drilling just prior to PDC/diamond coring, the mud viscosity should be reduced as much aspossible without sacrificing hole cleaning. A low water loss mud will reduce filter cake build-upand minimize the chances of sticking. Low viscosity and low water loss will also help reduce pumppressures.

In studies performed by Conoco in 1986, they found that very good core recovery (100%) wasobtained in their offshore operations when the pressure of the mud column was kept at least 300 psiabove the formation pressure using a Saltwater/New Drill type mud system. Coring runs in holesusing a freshwater lignosulfonate mud were not as successful (the shales became swollen causing



them to become sticky and jamming the core barrel), and in those operations done with very lowdifferential pressures, no core was recovered.

LCM can be pumped through a core barrel, but the material should be restricted to fine materialonly. Limit LCM to a maximum concentration of 15-20 ppb.

Coring Operations Guidelines

Cutting The Core

Prior to dropping the ball to begin coring, circulate bottoms-up. A steel ball is pumped down thedrill string and is seated in the top of the inner barrel. Coring fluid is then diverted between theinner and outer barrels and emerges at the fluid ports of the bit.

For maximum performance, the core barrel should be stabilized as best as possible in the hole. Astabilizer just above the bit will normally give sufficient stabilization if it is not allowed to get morethan 1/8" under the bit diameter.

When starting the core, it is a good practice to cut the first 12 to 18 inches with only 2,000 to 4,000lbs bit weight and with reduced rotary speed. After the stabilizer is buried in the core hole, bitweight and rotary speed may be increased. While coring, the bit weight should be maintainedcontinuously and the weight must never be allowed to drill-off. Allowing the weight to drill-off willproduce pounding on bottom and can result in severe damage to the core head and coring assembly.The rotary speed should remain constant during the coring operation.

Coring Operations Guidelines

WOB, RPMs and pump rate should be in accordance with the core bit manufacturer'srecommendations. General guidelines are as follows:

• For 8-1/2" hole, WOB should generally be between 4,000 and 6,000 lbs. in soft to medium-hardformations and 10,000 to 20,000 lbs. in harder formations

• The maximum circulation should be limited to a rate that will not erode the core bit matrix orundercut the core. Circulation rates of 200 to 500 GPM are most common when cutting a 4"core.

• Rotary speeds should generally be between 50 and 100 rpm. Rotary speeds above 100 rpm coulddamage the core barrel from excessive torque.

• Drilling parameters (pump pressure vs. pump rate, rotating torque vs. rpm, ROP vs. WOB, etc.)should be monitored closely during coring operations. A change in any parameter may besignificant to coring success.



When the core is being cut and begins to enter the inner barrel, the pump pressure will increase from200 to 300 psi and is the result of the pressure drop across the diamond bit. This pressure should bemonitored during the coring operation, an increase or decrease normally indicates that somethingabnormal is occurring and the cause must be determined. Coring operations should cease, the bitshould be picked-up off bottom, and the standpipe pressure observed.

• If the pressure drops but then returns immediately to the abnormally high pressure when the bitis set back on bottom, the bit has probably failed. A ring of diamonds that has been damagedwill allow the formation to cut into the matrix, restricting the watercourses and causing thepressure increase. When this occurs, pull the bit to prevent further damage.

• If the pressure increase remains when the bit is raised off bottom, plugging of the fluid passagesin the bit or circulatory system may be the cause. Continued high pressure may also be anindication of swivel failure resulting in lowering of the inner barrel and closing of the fluidpassages. In either condition pull the bit.

• An abrupt increase in standpipe pressure may be caused by plugging of the core barrel from anaccumulation of foreign particles in the mud system such as rubber, LCM, or pipe scale.

• A pressure decrease while coring may be due to a number of factors, including a leak in thesurface equipment, or a hole in the drill string. If this pressure decrease is accompanied by adecrease in penetration rate AND less torque, a wedged core has probably developed holding thebit off bottom. If this condition continues after picking up and setting down the bit, pull out ofthe hole and recover what core has been cut.

• When pump pressure fluctuates continuously and the ROP is erratic, it is possible that alternatewedging and crushing of the core is occurring. The barrel should be pulled to avoid loss ofrecovery.

Making Connections and Pulling the Core

A complete set of drill pipe pup joints should be available when coring to prevent making an extraconnection. It is a good practice to leave a foot up on the kelly joint before making a connection.If more than a 30 foot core is being attempted and a connection is necessary, stop the rotary tableand pick the core barrel off bottom slowly. A noticeable jump on the indicator will result when thecore breaks. If the core is hard to break, pull 15,000 to 30,000 lbs above the weight of the string, setthe brake and slowly rock the rotary until the core breaks.

After making the connection, return to bottom and rotate slowly until the bit is again cutting and thenew core is entering the inner barrel. This same procedure should be used before pulling the core toavoid leaving a section of core in the hole. It should be noted that not all core barrels have theability to cut more than 30 foot of core.

When coming out of the hole with the core, it is very important that the drill string be pulled slowlyand not rotated to prevent losing the core. Do not pump a slug, and use the trip tank to ensure that



the wellbore takes the proper amount of mud. Killing a well with a coring assembly in the hole willbe difficult and complicated because of the full core barrel in the string.

Core Handling

When the core barrel is pulled to the surface, there are two methods that are commonly used toremove a core. In hard formation areas where a plastic inner liner is not used, the inner barrel can beremoved from the top of the core barrel and laid on the catwalk where the core is recovered. Thecore can also be removed while the barrel is left hanging in the derrick a few inches above the rigfloor.

The core catcher and lower shoe are removed and the core is slid out of the inner barrel and cut into3 foot sections.

In areas where soft, unconsolidated formations are cored, the plastic liner is pushed-out of the innerbarrel and cut into sections as it is removed on the catwalk. These sections are marked withorientation stripes, the well name, and coring depth. Small holes are normally drilled into each 3foot section through the PVC/fiberglass/aluminium liner to vent any trapped gas. These holes arelater taped closed prior to transport.

The core is packed in dry ice to immobilize the formation fluids and prepared for shipment.Freezing the core at the well site and keeping it frozen throughout the shipping and sampling phaseswill minimize sample disturbance. The core can also be stabilized with resin or gypsum.

When pulling the core through the rotary table, Draeger Tube detectors will be used to determine ifthe core contains H2S. If working in an H2S area, all personnel on the rig floor will don a selfcontained breathing apparatus (SCBA) prior to pulling the core through the rotary table.

Coring High Angle Holes

Coring high angle and horizontal wells will necessitate a change in the typical coring assembly.When using downhole rotary drive mechanisms, MWD tools, etc., the conventional ball to seal offthe inner barrel cannot be pumped down. Special inner relief valves must be installed at the surfacebecause it is unlikely that a ball would remain seated in a horizontal well. Do not use MWD ormotors when coring.

Additional thrust and radial bearings must be built into the coring assembly as well to prevent theinner barrel from rotating. Internal stabilization of the inner barrel to minimize its bending insidethe outer barrel may also be needed. It is prudent to run only a 30 foot long core barrel in mostinstances, unless conditions are extremely favorable.

Fiberglass inner barrels should be considered to reduce friction of the core on the bottom side of theinner wall where the core rests as it enters.



A core barrel with high torque threads is recommended for coring in higher angle wells. This type ofbarrel allows coring in more difficult formations, and will allow more torque to be supplied to thecore head. These high torque threads do not alter the strength of the body or decrease the core size.

A detailed core handling procedure will be provided by Geology based on the coring objectives ofthe well and the type of core analysis required.

8.3 WIRELINE LOGGING PROGRAM

A wireline logging program, which specifies the types of logs to be run, the logging intervals, andthe order in which to run the logs will be included in the applicable drilling procedure.

Logging Sequence

To reduce rig time and complete as many logging runs as possible prior to a conditioning trip, theOperations Supervisor and wellsite geologist should thoroughly discuss the various logs and theproper sequence in which they are to be run. If there is any question, the Operations Supervisorshould notify the Operations Superintendent.

A logical running order is, with GR run on each log for depth control, is:

1. IES or IES-Sonic as required;2. GR and /or FDC/CNL as required;3. Conditioning trip if necessary;4. MDT/RFT's as needed;5. Dipmeter as required;6. Velocity survey if required.7. Conditioning trip if necessary;8. Sidewall cores as required;

The correct scales (5" or 1") for each log should be discussed with the logging engineer and checkedto prevent having to re-log the well. The logging engineer should be instructed to report to theOperations Supervisor any drag on successive logging runs and any sticking or spudding with thelogging tools.

Wireline Logging Guidelines

1. Pre-job meetings will be conducted with the logging engineer prior to beginning each loggingjob. The Company technical requirements for logging and the specific logging program shouldbe discussed, along with safety procedures for handling radioactive tools and sidewall coreguns (SWCs).

2. The logging Engineer will record digital logging data and provide the required number of finallog copies in accordance with the logging program and to the satisfaction of the wellsitegeologist.



3. Two thermometers will be present on each logging run.

4. A running cable-head-tension device, if available, to read actual tension on the rope socket("weak point" of system) should be run.

5. A station time limit should be established prior to running an RFT tool taking intoconsideration the hole condition and previous experience in the area. Typically samples shouldbe taken at the deepest zone of interest first and subsequent samples taken as the tool is pulledup the wellbore to reduce the potential for wireline sticking. However, it may be appropriate tovary the sequence, to ensure the highest priority intervals are tested, in the event that adversehole conditions reduce or prevent all desired testings.

6. The periods during which welding and radios must be shut down (when handling explosives,during certain logs, etc.) will be determined. Always shut down radios when these tools are ator above BOP stack.

7. A wiper trip to the casing shoe should normally be made and the hole should be circulated cleanprior to pulling out of the hole for logging. A high viscosity gel sweep to remove any loosecuttings may be necessary during this circulation. A logging pill may be spotted on bottom tohelp suspend any cuttings left in the hole during logging operations. These pills will be detailedin the appropriate drilling procedures.

8. The Drilling Fluids Engineer will take an "Out" sample of the drilling fluid before stoppingcirculation prior to POOH for logging and give samples of the drilling fluid, fluid filtrate, and afilter cake to the Wireline Logging Engineer to record on the log.

9. The trip tank will be used while logging to keep the hole full. The Drill Crew will record triptank levels at scheduled intervals (15-minute maximum). The Mud Loggers will also recordtrip tank levels at the same intervals as a crosscheck. The amount of drilling fluid required tofill the hole will be reported on the Daily Drilling Report.

10. The Operations Supervisor will be notified of any abnormal changes in trip tank level(considering the line volume) when running in/out of the hole during logging operations.

11. Non-essential personnel will keep away from all logging tools, wireline, and related equipmentat all times.

12. Only authorized personnel will enter the logging unit during wireline operations.

13. Loads will not be moved across the wireline cable when logging is in progress.

14. A wireline wiper will be used to clean the cable when it is being removed from the hole. Washdown water will not be used as this will complicate trip tank level readings.



15. Hole caliper information (if available) and bottom hole logging temperatures will be sent to theDrilling Engineer and Geologist as soon as practical during logging operations.

16. All tight spots and ledges in the hole will be noted for possible reaming prior to runningcasing.

17. Only logging company personnel will handle any tool that contains a radioactive source (e.g.,neutron density tool) or explosives. A work permit is required for radioactive/explosive toolhandling.

18. Logging company personnel will wear appropriate radioactive monitoring devices and take thenecessary safety precautions when running logging tools with radioactive sources.

19. All personnel on the rig floor will don a self contained breathing apparatus (SCBA) in H2Sareas before removing samples from sampling tools such as the MDT/RFT (Atlas FMT).

20. Sample containers which may contain H2S gas will be marked as such.

Wireline Company Responsibilities

1. Maintain the Wireline Logging Unit and related equipment onboard the drilling rig as specifiedin the contract.

2. Ensure that sufficient tools (primary and back-up) are onboard the drilling rig as specified inthe contract.

3. Ensure that all tools are in operating order immediately after arriving at the wellsite. Provideservice history of the W.L. detailing environment worked in and last service.

4. Provide the Operations Supervisor with overall dimensions and drawing of each logging toolrun in the hole.

5. Ensure that overshot grapples and cut and strip equipment is available on the drilling rig foreach different size of fishing neck before running the logging tool.

6. Ensure that logging tools are not stationary in the wellbore except when taking asample/pressure using an MDT/RFT tool.

7. Notify the operations supervisor of any hole problems (excessive drag / sticking tendencies).

8. Ensure that the prospect geologist has all of the logs, tapes, and/or film strips, sidewall cores,etc., prior to leaving the location.

9. Ensure that the area surrounding the logging unit is clean of all debris, trash, and traces of anyoil or lubricants prior to leaving the location.



10. Ensure that all equipment is stored properly (radioactive tools in designated storage area,explosives in approved magazine, etc.).

11. Use radioactive and explosive readiness checklists in Safety Management Program.

Stuck Wireline Operations

The basic philosophy for recovery of stuck logging tools is to cut and strip in most cases,particularly in directional wells and for any radioactive source tool. The following guidelines willbe observed when attempting to free stuck tools:

1. A 75% criteria will be used for maximum overpull of stuck tools/wireline (i.e., overpull willnot exceed 75% of the rating of either the rope socket or the wireline). If a cable head tensionsurface read-out is available, surface line tension will be used to determine the pull on thewireline, and the cable head tension surface read-out can be used to determine the amount ofpull on the rope socket. NOTE: If the float equipment has been drilled out with an undersizedbit that results in a core of cement remaining in the shoe joints, watch for line key seating. Ifthe logging tool becomes stuck, refrain from repeated pulls on wireline, to prevent damagingand cutting the line. Even though it is time consuming, a strip-over job has less risk than awireline-fishing job.

2. All personnel will be cleared from the rig floor and from any areas under the wireline whenpulling on stuck wireline.

3. Approval will be obtained from the Operations Superintendent prior to exceeding the 75%overpull criteria.

8.4 SIDEWALL CORING OPERATIONS

The following guidelines will be observed during sidewall coring operations:

1. After the core gun is loaded, the area around the gun (catwalk, etc.) will be cordoned off andflagged as "Hazardous - Explosives In Use" until run in the hole.

2. Radio silence will be maintained on all radios and any welding is to be shut down on thedrilling rig when picking-up, laying-down and tripping in the hole with the sidewall core gunsuntil the guns are well below the mudline.

3. All helicopters and boats in the immediate area will be notified to maintain radio silence untilfurther notice.

4. The shore base will be advised of the radio silence start and end times.



5. All non-essential personnel will be cleared from the rig floor when handling the core gun onthe rig floor.

6. All personnel working below the rig floor (e.g., Texas deck area of the rig and well bay/+15area of a platform) will be alerted and removed from the area when running a sidewall coregun into the wellbore. Once the gun is below the mud line, normal work can continue. Whenpulling the SWC gun from the wellbore and the gun is at or above the mud line the precautionsmentioned above will be taken.

*NOTE: See EMDC Safety Manual for recommended safe working practices in WirelinePerforating and Other Electrically Detonating Operations section.

Wellsite Geologist Responsibility:

1. Select side wall core points in relatively gauge sections of the hole to avoid "shooting offbullets" and leaving debris in the hole.

2. Make a description of the sidewall cores at the Wellsite immediately after unloading the guns.

3. Ensure that the Operations Supervisor has a report on bullet recovery that includes number ofmisfires, number of bullets left in hole, number of cores recovered, any other gun parts left inthe hole, and depths of all shots.

8.5 WIRELINE RADIOACTIVE SOURCES

Refer to Safety Management Program

8.6 MWD/LWD LOGGING

Logging While Drilling (LWD) objectives are:

• Provide real time correlation and pressure detection.

• Obtain information for early operational decisions.

• Use as a replacement or insurance for wireline logs that may be more costly.

• Use to evaluate highly deviated wells where wireline logging is not possible. LWD logs are themost common log in the Gulf of Mexico because of hole angle and directional constraints.

Tool Placement/Stabilization

1. MWD/LWD tools should be placed as close to the bit as practical in order to obtain highquality data prior to hole erosion and invasion, and to facilitate abnormal pressure hunts,casing seats, and core points.



2. MWD/LWD tools with integral blade stabilizers should be used if a near bit stabilizer isnecessary.

Stuck Pipe

MWD/LWD tools should be run near the bit since the inside diameter of the tools will preventwireline access for free-pointing stuck pipe. Several systems allow wireline passage after retrievingthe electronics package. Use of downhole screens just above the MWD to prevent jamming may beused but could eliminate retrieving sources or electronics in the event of a stuck BHA. DP screendecision should be approved by the Operations Superintendent.

Filter Screens & Flow Rates

1. Filter screens on the mud pump's discharge should be sized to remove any debris that maycause a problem within the LWD tool (see Op Tech Bulletins).

2. Do not use a filter screen inside of the drill pipe at each connection. Placing a filter screeninside drill pipe at each connection will prevent the use of wireline tools if the drill pipebecomes stuck or during well control operations. Use of downhole filter screens just above theMWD are permitted, but may prevent retrieval of sources or electronics. Use of downholescreens must be coordinated with the Operations Superintendent.

3. The MWD/LWD power turbine (if not battery operated) should be sized to obtain the range offlow rates needed for drilling the hole section expected to be penetrated on that run (coordinatewith service company personnel). Additionally, MWD/LWD equipment hydraulic pressurerequirements should be modeled and incorporated into drilling hydraulics.

Handling

1. The MWD/LWD transport tray will be used for movement of LWD tools from the supplyvessel and around the drilling rig.

2. Extreme care should be exercised when moving MWD/LWD tools onto the rig floor to preventany unnecessary blows or jars that could cause internal damage. These tools do not have thewall thickness of drill collars and they can bend quite easily. Rough handling can damage theinternal electronic packages of the tools.

3. Only MWD/LWD service personnel will handle the tools as some LWD logs have radioactivematerials.

Lost Circulation Material (LCM)

Lost circulation treatment options are limited with MWD/LWD tools in the hole (check with LWDpersonnel for specific tool details). If severe lost circulation is expected, MWD/LWD tools shouldnot be used. These tools are very expensive and lost circulation can easily result in stuck pipe and



the loss of the tools or damage to the tools. Should lost circulation occur with an MWD/LWD toolin the hole, the following steps should be taken

• If lost returns are expected, size and set-up the MWD/LWD and motor as applicable toaccommodate high concentrations of fine to medium LCM.

• Pull to the casing shoe and let the hole heal sufficiently to POOH and lay down the tools if atall possible.

• If necessary, pump fine or medium grade LCM well mixed. Limit LCM (nutplug) to amaximum concentration of about 30 ppb fine, or 20 ppb medium when pumping through anMWD/LWD tool.

• For specific LCM material or concentrations consult with the service company and refer to theapplicable drilling procedure. Newer generation MWD/LWD tools have a higher tolerance forlost circulation material; service personnel can give a good estimate on the concentration ofmaterial each tool can withstand before plugging. Some tools can be "turned off" by adjustingflow rate. This may reduce the jamming potential when pumping LCM.

Well Control

MWD/LWD tools should have the ability to circulate a minimum flow rate of 1000 GPM when usedin the upper part of the hole where a dynamic kill may be necessary.

8.7 MUD LOGGING AND CUTTINGS SAMPLES

Mud logging services will be specified in the drilling procedure. Mud logging, which is also a partof formation evaluation, has been previously addressed in Section 7 of this manual. Cuttingssamples will also be collected, as specified in the drilling program. Typically, several sets ofwashed and unwashed cuttings samples will be required. These samples will be collected at theintervals specified in the drilling program.

Note: Where mud loggers units have hydrogen gas feeding the Flame Ionization Detector(FID), post warning signs indicating the flammable/explosive characteristics of the gas. Inspectthe hoses (typically Polyflow) every 2-3 months, and replace if it has been pinched, is brittle, oris discolored from the normal clear or white color (OIMS Manual Element 6).

CASING OPERATIONS


9.0 CASING OPERATIONS

9.1 Casing Running 19.2 Casing Connection Make-up 59.3 Casing Checklist 5

CASING & LINER OPERATIONS


9.0 CASING & LINER OPERATIONS

For all drilling operations, a detailed casing or liner running procedure will be prepared. When the rigis ready to have the casing sent to location, the Operations Supervisor is to call out and arrangedelivery from shore base..

Unless otherwise noted in the applicable procedure, the casing operating guidelines in this sectionwill apply. It is the responsibility of the Operations Supervisor to ensure that the casing running orliner running operation is conducted according to the guidelines and requirements in this manualand/or the approved procedure. In cases of conflict between this manual and an approved procedure,the approved procedure shall be followed.

• A Job Safety Analysis (JSA) will be completed prior to all casing/liner operations and allpersonnel involved with the casing/liner running will review the JSA.

OIMS REQUIREMENT: Use an Excel spreadsheet to generate the casing tally report. The originalshould be forwarded to the Drilling Engineer and should be included in the final well report (OIMSManual Section 4). Additionally, OIMS requires a DRS casing tally report where possible.

9.1 CASING RUNNING

Casing Preparation Guidelines

1. Ensure the pipe rack is clean and cleared of debris, tripping hazards, and slick areas.

2. Unload casing using the proper method. Immediately after unloading casing, the number ofjoints will be counted and compared with the cargo manifest. Any discrepancies will be notedand recorded.

3. The weight and grade of each joint of the casing will be checked to ensure that the propercasing was delivered (check casing ID to ensure correct weight casing was delivered).

4. Ensure the casing is racked properly for pick up and running.

5. Thread protectors will be removed and the threads cleaned if necessary. Most of the timeconnections will be "field prepped" and doped with the proper thread compound at the yardprior to sending to location. The casing, threads and couplings will be visually inspected forany signs of damage.• Take special precautions to prevent damaging the seal area on connections when removing

thread protectors, cleaning etc. Review with the rig crews to ensure that all personnelunderstand what areas of the connections are the sealing areas.



6. Casing will be drifted while on the pipe rack to check for and remove any internal debris.Drift OD is typically API drift but may be a special drift (reference applicable procedure).Recommended drift is a 1' bar (a 3' drift bar is typically used in the pipe yard).

7. All casing will be numbered and strapped.

• Strapping buttress threaded casing to the diamond as the threads make up only to thediamond (1-2 inches before the thread run-out on the pin end). This can result in the casingshoe being deeper than anticipated if measurements are made to the thread run-out. Ensurestrap is to correct position on the casing.

• Use thread run-out template for premium connections and measure from end of pin threads.

8. A casing tally report will be prepared for every casing or liner run, showing the number ofjoints, casing description including joint type (weight, grade), joint length, joint depth,connection type, and location of major casing string components (float equipment, pup joints,crossovers, RA tags, centralizers, wellhead attachments, etc.). A copy of the report will bekept on the rig for reference during logging, completion, P&A operations, etc.

9. At least two people will check the casing tally.

10. When running production casing, pup joints should be placed above the tops of possibledesign productive zones in order to facilitate future correlation. RA (Radioactive) Tags mayalso be useful to ensure accurate tie in when drilling high angle directional wells or when apremium casing thread may be difficult to see with a casing collar locator log (e.g. CRAcasing, integral connection). Use of such devices will be specified in the appropriate casingprocedure. If RA tags are used, install at least one tag 50m above the top most pay zone.

11. Sufficient rathole should be left below the casing shoe to allow for fill, extra joint, etc. Thegeneral guideline on rathole is no more than +/- 50' TVD of the permit depth, deep enough toget all LWD information required below the sand bottom, or deep enough so that the floatequipment does not need to be drilled out on production casing. Rathole is more critical formandrel type hangers where the casing is not planned to be cut off.

Cementing Accessory Guidelines

1. Unless specified otherwise in the applicable casing or liner running procedure, two joints ofcasing should be run between the float shoe and the float collar as float joints. Typically onejoint with the float collar made up on the end and thread locked and one joint with the floatshoe made up on the end and thread locked are assembled in the yard and sent to the rig. Aback up set of float equipment is also sent to the rig loose.



2. All connections up to and including two joints above the float collar will be threadlocked.

3. Run centralizers, turbolizers, scratchers, cement baskets, etc. as detailed in the applicableprocedure.

Casing Running Guidelines

NOTE: Complete the questions in Section 9.3 prior to beginning cementing operations.

1. A hole opener run is made after TD of all hole sections prior to running casing if it deemsnecessary.

2. Prior to running casing, a planning meeting will be held with personnel that are directlyinvolved with the casing job to ensure that key personnel understand the job and theirparticular responsibilities. The casing running procedure will be reviewed and it will beverified that job responsibilities and safety precautions are clear to all personnel.

3. If a mandrel type casing hanger is planned, the landing string complete with cement headshould be spaced out if possible, so that the mandrel casing hanger can be run all the waythrough the stack and landed without having to make a connection while the hanger is in theBOP.

4. The casing hanger and wellhead running tools will be carefully inspected and serviced prior torunning. These tools should be made up and stood back in the derrick if possible prior to thewiper trip before running casing.

5. The drill string should be strapped out of the hole after TD of the hole section. If adiscrepancy exists, the pipe should be re-strapped in the hole on the hole opener run.

6. Any tight spots are to be reamed, as necessary, on the wiper trip prior to logging.

7. When pulling out of the hole on the last trip before running casing, then change out top set ofpipe rams to casing rams and test the bonnet seals when out of hole before running casing..(The order in which casing rams are installed may be changed at the Opt. Supt. discretionbased on current well conditions.) Prior to pulling out of the hole on the wiper trip afterlogging, the drilling fluid will be conditioned to ensure that it is virtually free of cuttings andis of uniform density, with acceptable properties. Based on hole conditions, a casing runningpill may be spotted after conditioning the fluid properties and before pulling out of the hole.



8. The primary well control method is fluid weight. The annular preventer will be used as thesecondary means of well control with the casing rams as the third method during casingrunning operations. Before running casing, reduce the regulator pressure on the annularpreventer per manufacturer's specification for the casing size in order to prevent collapse ofthe casing.

9. The wear bushing must be pulled before running casing.

10. Ensure that the rating of all casing tools (spiders, elevators and links) is sufficient for thecasing string weight at total depth plus 200,000 lbs. of overpull.

11. Ensure that the safety valve on the casing-by-drill pipe crossover is a full opening ball valvesuch as a TIW valve.

• Perform a function test of the safety valve on the casing-by-drill pipe crossover and casingswedge before running casing. Record this safety valve function test on the Daily IADCReport and morning report.

12. For heavy liners, the casing load and overpull limitations will be calculated to ensure that thedrill pipe has sufficient tensile strength to allow it to be used as a landing string.

13. The inside of float joints will be checked for trash just prior to making up.

14. The float equipment will be checked for proper operation after running the float collar and onejoint of casing by filling the casing with fluid and picking up to ensure that the fluid drops outof the casing and stays out after running it back in the hole (if Auto-Fill equipment is notbeing used).

15. The casing will be filled on a regular basis while picking up the next joint and the fill is to beconfirmed at regular intervals. The casing should be filled with the drilling fluid used whiledrilling the hole. Stop in cased hole and fill the casing entirely prior to running casing/linerinto the open hole. Once the casing is in the open hole fill the casing as run but do not stop tofill the casing. (Use of fill up tool can aid in casing fill up.)

16. The correct number of sections in slips and clamps will be used for the size casing being run.

17. Safety clamps will be used until there is enough weight to hold the slips down and counteractthe buoyant effect of the casing in the mud (buoyant effect can dislodge the casing from theslips and the casing can fall downhole).

18. Returns will be monitored (watch for indications of the well flowing) and running speedadjusted to minimize drilling fluid losses to the hole. Any limitations on casing running speedwill be specified in the Drilling Program.



9.2 CASING CONNECTION MAKE-UP

1. Make-up torque will be specified in the Drilling Program based on the connection type, millcoating on the threads, and the thread compound to be used. For all offshore wells using APISTC and LTC connections for any string, EMURC Torque-Position values will be used. ForAPI BTC connections, use the EMURC Torque-Position Manual and Torque Position valuesfor casing sizes less than or equal to 7-5/8". For BTC connections in casing sizes greater than7-5/8" use the EMURC Torque-Position Manual 4-T method. For premium connections,connections will be made up per the manufacturer's recommended procedure. (ReferenceOperations Technology Bulletin 98-68 revised 11/9/1998.) Modified API connections withseal rings should be run with care and according to the Torque-Position Manual notes.

2. Thread compounds rated for the service temperature and conforming to API specificationswill be used.

3. Use tong mounted computer to track each connection make-up. The casing company willensure that a hard copy of make-up curves for all joints run is sent to the Drilling Engineer.The Drilling Engineer is to make sure that this report is in the well file in case future casingtroubles are encountered (e.g. casing leak) and the make-up torques need to be reviewed.

9.3 CASING CHECKLIST

Casing

1. Is condition of casing acceptable? Yes/No2. Is size and condition of casing drifts adequate? Yes/No3. Has casing been drifted, strapped, tallied and verified? Yes/No4. Is condition of casing threads acceptable? Yes/No5. Is enough excess casing on board ? Yes/No6. Is numbering of casing joints correct? Yes/No7. Is thread compound type and quantity acceptable? Yes/No

Operations

1. Are theoretical returns and casing fill up volume calculations correct? Yes/No2. Are fill-up and displacement volumes correct? Yes/No3. Is the reduction of the hydrostatic pressure due to spacer volume a problem? Yes/No4. Is as much rig up completed as possible during HO run, and logging operations? Yes/No5. Are drill floor and catwalk clear of non-essential equipment? Yes/No6. Has a safety meeting been held prior to rigging up equipment? Yes/No7. Is hole monitored on trip tank while completing rig up? Yes/No8. Does Driller know proper casing running speed? Yes/No9. Does the Tong hand know the correct make-up speed and torque? Yes/No



Casing Running Equipment

1. Is all casing running equipment onboard and in acceptable condition? Yes/No2. Are casing slips the correct size and in good condition? Yes/No3. Are the ratings of spiders/elevators/links acceptable for the casing job? Yes/No4. Are tong dies the correct size and in good condition? Yes/No5. Are clamp-on protectors the correct size and is the quantity on

board acceptable? Yes/No6. Is the tensile strength of the landing string sufficient? Yes/No7. Does the casing/drill pipe crossover thread match the casing? Yes/No8. Does the circulating swedge thread match the casing? Yes/No9. Has the safety valve been actuated, left in the open position, and recorded

on the IADC/morning report? Yes/No10. Has the stabbing board been inspected and found to be acceptable?

Raise permit for use of stabbingi board & review JSA. Yes/No

Cementing Equipment/Accessories

1. Is cementing head the correct size, threads, and in good condition? Yes/No2. Are casing subs and swedges the correct size, threads, and in good condition? Yes/No3. Is operations supervisor's visual inspection of all other threads complete? Yes/No4. Is float equipment the correct size, weight, and threads? Yes/No5. Are centralizers the correct size, number, with adequate stop rings? Yes/No6. Is there enough Thread-Lok and Threadkote or equivalent for casing job? Yes/No7. Is float shoe and float collar clean and free of debris and the cement

undamaged? Yes/No8. Is the landing joint/cementing head made up? Yes/No9. Have the wiper plugs been inspected and installed correctly in cement head? Yes/No

ExxonMobil Drilling Superintendent to verify proper loading of plugs in head.



REFERENCE MATERIAL

1. API Bul 5 A2, "API Bulletin on Thread Compounds for Casing, Tubing, and Line Pipe,"American Petroleum Institute, Dallas, Texas, Fifth Edition, April 1972.

2. API RP 5C1, "Recommended Practice for Care and Use of Casing and Tubing", AmericanPetroleum Institute, Dallas, Texas, Fifteenth Edition, May 31, 1987.

3. API Spec 5B, "Specification for Threading, Gauging, and Thread Inspection of Casing, Tubing,and Line Pipe," American Petroleum Institute, Dallas, Texas, Thirteenth Edition, May 31,1988.

4. Day, J. B., Moyer, M. C., and Hirshberg, A. J., "New Makeup Method for API Connections,"SPE/IADC 18697, paper presented at the SPE/IADC Drilling Conference, New Orleans, LA,March 1989.

5. ExxonMobil Upstream Research Company, Torque-Position Manual Third Edition December1999, Wells and Materials Division.

6. EUSADO, Operations Technical Bulletin 98-68, revised November 9, 1998.

CEMENTING


10.0 CEMENTING

10.1 General 110.2 Cementing Guidelines 110.3 Primary Cementing 310.4 Remedial Cementing 510.5 Cementing Checklist 610.6 Reference 7

Appendix G-I ExxonMobil Cement Testing Guidelines

CEMENTING

DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFORM/BARGE RIG DRILLING 1 of 7First Edition - May, 2003

10.1 GENERAL

This section provides guidelines and procedures for cementing operations. Whenever possible, acementing recorder chart (pressure, volume, density vs. time) should be used for all operations (i.e.casing cementing, squeeze cementing, pressure testing of lines and equipment, PITs, etc.). Thechart should be annotated with all significant events such as pressure testing, pumping spacers,mixing lead and tail slurries, displacement, bumping the plug, etc.

For all Drilling Operations, a detailed cementing procedure will be written. For other types ofcementing operations a procedure should be written using the guidelines found in this section as areference (e.g. balanced plugs and KO plugs).

10.2 CEMENTING GUIDELINES

Job Planning

1. Prior to the cementing operation, a planning meeting should be held with all personnel that aredirectly involved with the cement job to ensure that key personnel understand the job and theirparticular responsibilities. The cementing procedure should be reviewed and it verified thatjob responsibilities and safety precautions are clear to all personnel.

2. A good communication system between the rig floor and the cement unit is necessary. Rigphones or hand-held radios are acceptable means of communication.

3. Assign one individual (preferably the Operations Supervisor) to coordinate and directoperations between the rig floor and the cementing unit.

4. All lines including the cement manifold should be pressure tested to the pressure specified inthe applicable cementing procedure prior to cementing.

5. All cementing equipment, including the densiometer, should be thoroughly checked to ensureit is in good repair and functions properly.

6. Hole calliper information and bottom hole logging temperatures should be sent to the DrillingEngineer as soon as practical during logging operations in order to finalize cement volumesand confirm cement thickening times. Hole calipers may be backed out of same LWD data andsome wireline logging tools.

Displacement

1. Cement displacement may be performed with either the cement unit or the rig pumps.Displacement volume, overall job time, desired pump rates, and expected pressures areimportant to consider when deciding which pump to use for displacement.

The following are general guidelines:

CEMENTING


• For inner-string cementing, the cementing pump should be used for the entire operation.The stinger should be run to about 60 feet above the float shoe/collar. Cement should bedisplaced to about 20 feet below the stinger.

• For full casing string cementing either the cement unit or rig pumps may be used fordisplacement. As a guideline, use the cement unit for displacements < 200 bbls or wherethe casing will not be drilled out. Use the rig pumps for displacements > 200 bbls or if thestring will be drilled out. Each job should be considered individually based on conditionsat the time of the cement job.

• For liners, the cementing pump should be used until the top plug is launched, then the rigpump may be used, if desired, to complete the displacement and bump the plug. If highpressures (i.e. > 3000 psi) are anticipated it is probably best to continue displacement withthe cementing unit.

2. If cement is to be displaced with the rig pumps, the pumps are to be calibrated using the triptank prior to starting the cement job. As a contingency displacement mud pit to be observedfor fluid loss when pumping with rig pumps.

3. Ensure the cement unit is ready to finish the cement displacement if the rig pumps encounter aproblem and vice versa. Have the ability to switch from the rig pumps to the cement pumps asneeded.

4. Do not over displace the cement by more than 50% of the volume of the float joints. If thecasing is going to be drilled out, do not over displace at all.

5. Two or more independent volume calculations are to be made on displacement.

6. Pressures should be monitored and recorded for the entire cement job. This will requireleaving the line open to the cement unit if the cement is displaced with the rig pump.

Cement Head/Manifold

1. All valves on the cement head/manifold, as well as the releasing mechanisms, should bechecked to ensure they are in proper working order and that safety devices are in place toprevent premature launching of plugs.

2. Use positive displacement to launch plugs (i.e. do not rely on gravity or falling fluid levels).Plug launching is to be witnessed by Company Supervisor or his delegate.

3. Use bails long enough to latch elevators below the cement head to allow reciprocation of thecasing / liner during displacement of the cement.

4. A cement manifold that is designed for a top drive system is to be used, if applicable.

CEMENTING


5. If the casing / liner is to be reciprocated or rotated during the cement job, the top drive cementhead/manifold rating must be adequate to support the casing and landing string weight plus100,000 lbs. of overpull.

Cementing Well Control

1. Test all cement lines and the cement as specified in the applicable Cementing Procedure.

2. When using an unweighted spacer, ensure that reduction of hydrostatic pressure is notsufficient enough to allow an influx to enter anywhere in the entire wellbore.

3. Ensure circulating swedges (Casing x Drill Pipe and Casing x male half of Chiksan Union) areavailable on the floor for the appropriate size and threads casing. Function test these valvesand document on the morning report and on the IADC.

Spacer

1. Spacers will be used on all cement jobs.

2. Water spacers will be used unless specified otherwise in the applicable Cementing Procedure.

3. A pre-flush spacer is used to induce turbulence, to help get good mud displacement, and tohelp prevent channelling. The postflush spacer is used to help prevent cement contamination.

10.3 PRIMARY CEMENTING

Primary Cementing Guidelines

1. Ensure that adequate cement is at the rig along with ample quantities of liquid/dry additives. Ifpractical, there should be 50-100% excess cement and 100% excess liquid/dry additives at therig site.

2. Ensure that the transfer facilities from the P-tanks to the cement unit are operating correctly.Ensure P-tanks have been fluffed with clear air prior to transferring.

3. Ensure that air lines contain no water (moisture or water in the supply lines could causeplugging during the cement transfer).

4. At least two people will calculate the total cement job volumes, including the required volumeto displace the top plug to the float collar.

5. The volume of mix water pumped will be used to calculate the actual volume of cementpumped. Never rely on P-tank volumes.

6. Circulate and condition the hole prior to cementing. The drilling fluid should be conditionedto ensure that it is virtually free of cuttings, that gas is back down to background levels and thatit is of uniform density with acceptable properties.

CEMENTING


7. Ensure that the cement head/manifold releasing mechanisms are working properly and thatpersonnel are familiar with their operation.

8. The Operations Supervisor will witness the cementer load the wiper plugs in the cementinghead/manifold. It is recommended that the cement job be pumped in the following order:bottom plug, preflush spacer, cement lead, cement tail, top plug, postflush spacer.

9. Monitor returns versus volume pumped throughout the cement job. Any suspected lost returnsduring cementing operations should be reported on the daily morning report, noting time ofloss and pressures. Run ECD calculating software tool on cement jobs where lost returns arepossible to fine tune displacement rates.

10. The slurry weight should be kept as consistent as possible to keep from extending or retardingsetting times. Liquid additives are more sensitive to weight fluctuations than dry blended.

11. The weight of the cement slurry should be checked frequently using a pressurized mud balanceto verify the accuracy of density measurement device on the cement unit.

12. Several samples, spaced throughout the job, of lead and tail slurries should be taken duringcementing. A styrofoam/paper coffee cup filled three-fourths full, stored in a protected area isan adequate sampler.

13. After mixing the cement, release the top plug and pump the spacer with the cement unit placinga small volume of cement on top of the wiper plug. If desired, switch to the rig pumps to finishdisplacement.

14. Displace the calculated casing volume or until the plug bumps. Do not over displace unlesstold to do so in the applicable cementing procedure.

15. Bleed casing pressure to zero quickly and check the floats. If floats do not hold, attempt torock them on seat by repressuring the casing string. If flow back continues, shut in and holdpressure on the casing at least until surface samples setup or no backflow occurs.

CEMENTING


10.4 REMEDIAL CEMENTING

Remedial cementing is sometimes necessary to rectify poor leak-off below a casing shoe, repaircasing or liner top leaks, squeeze off perforations, etc. The primary techniques used for theseoperations will follow a procedure similar to those described in the core procedures in Section 10.However, it is recognized that each situation will be different and extensive modification to theseprocedures may be required.

When a squeeze procedure is prepared, two cement slurries should be designed and tested. If a lowinjection rate is all that can be established a low fluid loss cement slurry should be pumped toprevent the cement from being dehydrated as it is squeezed away. If a high injection rate can beestablished, a cement slurry with higher fluid loss (less expensive) should be pumped. Dependingon the type of squeeze required, a low-fluid loss slurry may be followed by a high-fluid loss slurry.

Braden Head Squeeze Procedure

1. RIH with open ended drill pipe (or tubing stinger on drill pipe work string) to the desiredbottom of cement.

2. Circulate and condition the hole prior to cementing. The drilling fluid should be conditionedto ensure that it is virtually free of cuttings, that gas is back down to background levels, andthat it is of uniform density with acceptable properties.

3. Rig up the cementing lines to the drill pipe, with a full opening safety valve installed at the topof the string. Test the cement lines to the pressure specified in the Cementing Procedure.

4. Pump specified preflush spacer (generally water), then spot a balanced cement plug with thetop a minimum of 165' above the casing shoe. Attempt to rotate drill string to improvedisplacement of mud by cement.

5. Pump postflush spacer (generally water) and mud as required for balance.

6. Slowly POOH about 5 stands above the calculated top of cement.

7. Close the BOP and squeeze the volume of cement specified in the Cementing Procedure bypumping mud down the work string:

NOTE: Squeeze pressure must not exceed the casing test pressure.

8. Shut in the well until surface samples have set up or until reaching the desired compressivestrength. Do not continue to pump in, or bleed pressure during the shut in period.

9. Release pressure on the work string, check for backflow and open the BOP.

10. Circulate bottoms up and condition the mud until cement contamination in mud returns isacceptable. POOH.

CEMENTING


10.5 CEMENTING CHECKLIST

Squeeze/Open Hole Plug Work Strings

1. Is there (+/- 700') of stinger (2-7/8" or 3-1/2" tbg, or 3-1/2" DP) at rig? Yes/No2. Are there appropriate handling tools for stinger at rig? Yes/No

Cementing Equipment/Accessories

1. Are wiper plugs correct size for casing and free of cuts and/or defects? Yes/No2. Witness loading of wiper plugs in cementing head/manifold? Yes/No

Cement Supply

1. Is correct type and amount (50-100% excess if practical) of cement at rig? Yes/No2. Are adequate quantities (100 % excess if practical) of additives onboard? Yes/No2. Inspection of cement storage and transfer facilities complete? Yes/No3. Is there an alternate source(s) of cement if a pneumatic line breaks or plugs? Yes/No

Cementing Personnel

1. Do cementer and key personnel agree on all volumes and rates? Yes/No2. Does cementer understand contingency plan/procedures? Yes/No3. Are two individuals assigned to record displacement volumes? Yes/No

Cement Pumping

1. In case of cement pump failure, is rig pump ready to take over? Yes/No2. Is rig pump efficiency known by pumping into a calibrated tank? Yes/No

Cement Mixing

1. Is cement mixing equipment working properly before cementing? Yes/No2. Is calibration of pressurized mud balance complete? Yes/No3. Are densiometers operating correctly before cementing (calibrated)? Yes/No4. Are adequate blended sample containers available? Yes/No

Mix Water/Displacement Fluid

1. Is quality and supply of cement mix water satisfactory? Yes/No2. Is quality and supply of displacement fluid satisfactory? Yes/No

Pressure Testing/Safety

1. Is chiksan line from cement manifold safely chained to hook or bails? Yes/No2. Is testing of cement lines to specified working pressure complete? Yes/No3. Has cement manifold been pressure tested to specified working pressure? Yes/No4. Has safety valve been installed at top of work string. Yes/No

CEMENTING


10.6 REFERENCE

1. EPR, Cement Slurry Design Manual2. EPR, Primary and Remedial Cementing3. Halliburton, Technical Data Cementing Notebook4. Halliburton, Cementing Tables Handbook.

SQUEEZE PROCEDURE EMDC DRILLING

DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLINGVersion 3–April 2003

Page 1 of 18

SECTION 10 - APPENDIX I

EXXONMOBIL DEVELOPMENT COMPANYDRILLING ORGANIZATION

7-5/8" PROTECTIVE CASING SHOE SQUEEZE PROCEDURE

1. GENERAL INFORMATION

Field: FIELDNAME Well: WELLNAME Rig: RIGNAME

1.1 APPROVALS

Drilling Engineer:Office: (____) ______-______ Home: (_____) ________ DATE________

Supervising Engineer:Office: (____) _____-_______ Home: (_____) ________ DATE________

Operations Superintendent:Office: (____) _____-______ Home: (_____) ______ Pager: 1-____-____-______ DATE________

Engineering Directions(This procedure contains extensive hidden text, which provides explanations and suggestions for tailoringthe procedure to specific applications. Comments and hidden text can be viewed by choosing View onthe menu bar and Comments from the drop down menu. The paragraph symbol (¶) on the standard toolbar also turns the hidden text on and off.)

Engineering/Operations Comments Revision JWB/AMK

1.2 PROCEDURE OBJECTIVE AND KEY ISSUESThis procedure provides details for pumping additional cement to ensure pressure integrity at the 7-5/8”protective/production liner top/casing shoe at 7500'. This liner top/casing shoe requires a successfulpressure test of 2500 psi with 12 ppg mud to drill ahead (18.4 ppg EMW) (per MMS requirements).[NOTE]: Additional comments pertaining to key issues as appropriate.

THOROUGHLY READ THIS ENTIRE PROCEDURE AND DISCUSS ANY DETAILS YOU MAY DISAGREE WITH OR WANTCLARIFICATION ON WITH THE ENGINEER AND/OR OPERATIONS SUPERINTENDENT. DISTRIBUTE PROCEDURE TO FIELDPERSONNEL FOR EQUIPMENT AND PROCEDURE VERIFICATION.



Page 2 of 18

SIGNIFICANT CHANGES IN OPERATIONS FROM PROCEDURE REQUIRE EVALUATION AND DOCUMENTATION. DISCUSSWITH APPROPRIATE TEAM MEMBERS AND COMPLETE MOC FORM.

1.3 SAFETYPrior to starting each different type of operation, conduct safety meeting with all personnel involved andreview job plans. Prepare and review JSA's for all critical operations. Rig Superintendent and Toolpushershould review each JSA prior to beginning work for thoroughness, proper hazard identification, and riskmitigation.

1.4 LIST OF APPLICABLE OP-TECH BULLETINS

BULLETINNUMBER TITLE

26 Failure to use recommended set screw w/ EZSV cement retainer results in expensive fishing job.56 Considerations for liner top squeeze cementing in OBM in Directional Hole98 Stuck "Fasdrill" retainer on recent Pecan Island well.

1.5 SERVICE COMPANY INFORMATION

SERVICE COMPANY LOCATION REPRESENTATIVE PHONE NUMBERCementing OperationsLabSales

BJ Services HoumaNew OrleansNew Orleans

DispatcherJohn St. ClergySparky Barkman

(281)(281)(281)

Squeeze tool provider Halliburton HoumaNew OrleansNew Orleans

DispatcherRick DupontMark Richard

(281)(281)(281)

1.6 TABLE OF CONTENTS

1. GENERAL INFORMATION_____________________________________________________1

1.1 APPROVALS _____________________________________________________________________1

1.2 PROCEDURE OBJECTIVE AND KEY ISSUES________________________________________1

1.3 SAFETY _________________________________________________________________________2

1.4 LIST OF APPLICABLE OP-TECH BULLETINS_______________________________________2



Page 3 of 18

1.5 SERVICE COMPANY INFORMATION ______________________________________________2

1.6 TABLE OF CONTENTS____________________________________________________________2

2. DESIGN BASIS _______________________________________________________________4

2.1 GENERAL INFORMATION ________________________________________________________4

2.2 CURRENT STATUS _______________________________________________________________5

2.3 CEMENT DATA SUMMARY _______________________________________________________6

3. PROCEDURE_________________________________________________________________6

3.1 TOP OF LINER SQUEEZE - DRILLABLE PACKER ___________________________________6

3.2 TOP OF LINER SQUEEZE - RETRIEVABLE PACKER ________________________________9

3.3 SHOE SQUEEZE - DRILLABLE PACKER __________________________________________11

3.4 SHOE SQUEEZE - RETRIEVABLE PACKER________________________________________14

4. ENGINEERING FOLLOW-UP _________________________________________________16



Page 4 of 18

2. DESIGN BASIS

2.1 GENERAL INFORMATION

Casing Shoe Squeeze Liner Top Squeeze

After Squeeze After Squeeze

Squeeze Tool@ 8800'

Squeeze Tool@ 9315'

Top of Liner @9150'

Casing shoe@ 9315'

TOC @8950'

TOC @8950'

Before OpeningSqueeze Tool

Before OpeningSqueeze Tool



Page 5 of 18

2.2 CURRENT STATUSPipe Set MD (ft) TVD (ft)

24” Drive Pipe - -20” Conductor Casing - -16” Surface Casing - -9-5/8” Protective Casing - -8.500”: Drift diameter of 9-5/8” casing

Casing in which squeeze tool will be set in: 7-5/8" 39.0# 6.625"IDCasing burst rating w/ (1.375) SF: - psiCasing was successfully tested to - psi or - ppg EMW @ casing shoe/liner topEstimated Pore pressure at casing shoe: - psi or - ppg EMWEstimated Frac pressure at casing shoe: - psi or - ppg EMWDesired PIT or Liner Top Test is - psi or - ppg EMWMaximum angle in wellbore above planned squeeze tool depth: 5 °°°°Maximum dogleg in wellbore above planned squeeze tool depth: 1.5 °°°° per 100'Mud Weight: - ppgMud Type (WBM / OBM ): -

DEPTHS FROM RKBDescription MD (ft) TVD (ft)Depth to Top of Liner/Casing Shoe 9315 9315Planned Depth of Squeeze Packer 8915 8915Planned Height of Cement in Casing 150 200Estimated TOC in casing 9165 9165

CAPACITIES/DISPLACEMENTSCapacity DisplacementSize Weight Nom. ID Drift ID Footage Bpf Bbls

7-5/8" 39# - - 250' X .054375 = 10.703-1/2" IF 13.3# S-135 - - 8915' X .007220 = 64.40

- - - - - X - = 0- - - - - X - =



Page 6 of 18

2.3 CEMENT DATA SUMMARY

Cement Company: Dowell @ 512-456-9874

High injection rate/Low injection pressure slurry

Cementing Slurry Pilot Test Results---- Sacks Class " " ---- Thickening Time---- Additive ---- psi 12 hour compressive strength---- Additive ---- psi 24 hour compressive strength---- Additive ---- cc/30 min water loss---- ppg slurry ---- ml/250ml Free Water---- cf/sk yield---- gal/sk mix water ---- oF BHST---- bbl slurry volume ---- oF BHCT (sqz schedule)---- bbl water volume---- Estimated pump time ---- Pilot Test Requested

Low injection rate/High injection pressure slurry

Cementing Slurry Pilot Test Results---- Sacks Class " " ---- Thickening Time---- Additive ---- psi 12 hour compressive strength---- Additive ---- psi 24 hour compressive strength---- Additive ---- cc/30 min water loss---- Ppg slurry ---- ml/250ml Free Water---- cf/sk yield---- Gal/sk mix water ---- oF BHST---- Bbl slurry volume ---- oF BHCT (sqz schedule)---- Bbl water volume---- Estimated pump time ---- Pilot Test Requested

3. PROCEDURE

3.1 TOP OF LINER SQUEEZE - DRILLABLE PACKER

1. Make a casing scraper run if deemed necessary prior to running in with SQZRETAINER. Work casingscraper thoroughly across the interval of pipe at planned SQZRETAINER setting depth. Circulate bottoms upbelow the SQZRETAINER setting depth. POOH. If it is deemed that a casing scraper run is not necessary,the following are reconcilers for not making the casing scraper run:



Page 7 of 18

• The SQZRETAINER will be set above where cement was tagged when RIH.• A packed BHA was used during the drillout. Stabilizer placement was as follows: 8-1/2" full

gauge near bit stab, 8-1/2" full gauge stab 15' above the bit, and 8-1/2" full gauge stab 45'above the bit.

• After determining that a squeeze was necessary, the BHA was tripped and rotated across thebottom section of casing several times to clean the ID of the casing of any remaining cement.The SQZRETAINER will be set in the interval that was cleaned with the stabilizers.

• The pumps were on while cleaning the casing to remove any cement cuttings. The rigcirculated adequate BU before POOH to ensure all cement cuttings have been removed.

2. Pick up SQZRETAINER for CGOD CGWT casing and TIH to TOOLMD MD (305’ above the liner top). SetSQZRETAINER @ TOOLMD MD (do not set retainer below 10,005’ which is where cement was tagged whenrunning in the hole to clean out). Ensure that the retainer will not be set in a casing collar. Verify settingwith 15 - 20 kips weight down on the SQZRETAINER and 500-1000 psi on the DP by casing annulus.

• 7.75” is the maximum OD of the SQZRETAINER• Maximum differential pressure for the SQZRETAINER = 5,000 psi• Maximum set down weight for the SQZRETAINER = 50,000 lbs

3. Test cement lines and squeezes manifold to 5,000 psi. (Test against TIW valve)

4. Close annular BOP and pressure up on DP by casing annulus to 500-1000 psi. Establish injection rates at1/2, 1, 2, 3, and 4 bpm without exceeding injection pressures of 4,500 psi (Engineer to comment on basis formaximum injection pressure. i.e. To stay within net burst pressure limit (7,927 psi w/ 1.375 SF ) of the 9-5/8”casing assuming 15.7 ppg mud in the wellbore and a 9.0 ppg EMW back-up behind the 9-5/8”). Monitorannulus carefully for pressure response indicative of packer or DP leak.

Note that the CGOD CGWT casing was last tested to 3,825 psi with 15.7 ppg mud, the cement lines havebeen tested to 5,000 psi, and the SQZTOOL is rated for 5,000 psi of differential pressure.

Use the PIT plotting technique to record pressure vs volume pumped. Contact the Operations Superintendentand the Drilling Engineer to discuss results of the injection test (injectivity will dictate if a change is needed inthe cement design or pump volumes).

Do not exceed the liner top test pressure of 3300 psi with 12.7 ppg mud (15.0 ppg EMW) if injection has notyet been established at this point. This could indicate a satisfactory liner top test has been obtained.

5. Bleed pressure off of the annulus, PU out of the SQZRETAINER, and establish reversing pressures at 3 - 6bpm.

6. Mix and displace the following slurries using the cementing unit[EUSADO20]:Note: While displacing cement down the DP while stung out of the retainer, the flowrate may outrunthe pump rate due to U-tube pressure. Take returns through the choke, if necessary, so that backpressure can be applied to prevent cement from circulating around DP before stinging intoSQZRETAINER.



Page 8 of 18

PUMP SCHEDULE BEFORE STINGING INTO THE SQZRETAINERDescription Density Pump Rate30 bbls pre-flush spacer (MCS-3)38 bbls (150 sacks) low FL squeeze slurry (See Cement Data for recipe)38 bbls (200 sacks) high FL (neat) squeeze slurry (See Cement Data for recipe)10 bbls post-flush spacer (MCS-3)38 bbls mud (lead spacer position ~15 bbls inside the DP above the SQZRETAINER)

Positions cement ~25 bbls inside the DP above the SQZRETAINER. (1470' inside the DP above theSQZRETAINER)

5” 19.5# S-135 DP capacity = 0.01701 bpf; 9-5/8” 53.5# casing capacity = 0.0708 bpf.

7. Close the choke and then sting into the SQZRETAINER. Set 15 - 20 kips weight down on the retainer andpressure up 500 - 1,000 psi on the DP by casing annulus. Pump an additional 119 bbls of 15.7 ppg mud at 4bpm followed by 5 bbls of freshwater down the DP. This will leave 2 bbls of cement in the DP above theretainer. Do not overdisplace the cement.

PUMP SCHEDULE AFTER STINGING INTO THE SQZRETAINERDescription Density Pump Rate119 bbls mud 15.75 bbls Fresh Water 8.3

This will leave 2 bbls cement above the SQZRETAINER in the DP. (118' inside the DP above theSQZRETAINER)

Note: Displacement volumes assume a 12 ppg FCS in the G-series sand at 10,000' TVD. 5 bbls of waterdisplacement should provide approximately 200 psi positive pressure.

If the well jugs up or surface pressure rises to 4500 psi during the squeeze operation with cement in the drillpipe, perform the following steps: sting out of retainer, POOH 2 stands, reverse circulate out 2 workstringvolumes at the maximum rate while keeping the pipe moving (do not exceed the casing test pressure of 3520psi while reversing).

8. PU out of the retainer and dump the last 2 bbls of cement on top of the SQZRETAINER (TOC @ ~9,922’ MD.This leaves 28' of cement on top of the SQZRETAINER). PU 2 stands and reverse out at the maximum ratepossible (do not exceed the casing test pressure of 3520 psi while reversing). Reverse out at least 2workstring volumes and keep the pipe moving while reversing.

9. POOH and LD retainer setting tool. PU the 8-1/2” clean out assembly and TIH to 9,750’ MD. (180' aboveexpected TOC).

10. Ensure 18 hours has elapsed since cement was pumped and wash down to TOC. Drillcement/SQZRETAINER and continue drilling down to the LNROD liner top @ 10,255’ MD. Do not rotateexcessively on the liner top to avoid damaging the tie-back receptacle. C&C mud to clean wellbore.



Page 9 of 18

Note: If ratty and/or soft cement is encountered as deep as 90' above the expected TOC, PU 3 stands andcirculate out 1 cycle. Monitor mud condition/properties and dump all badly cement contaminated mud.Contact the Operations Superintendent to discuss WOC time and forward operations if the cement is nothard.

11. Pressure test the LNROD liner top to 2,300 psi with 15.7 ppg mud. Use the PIT technique at 1/2 bpm andrecord pressure vs. volume pumped. Hold test pressure for 30 minutes. After test, record volume of mudbled back. POOH.

12. After successful test, proceed with the deeper drilling procedure.

3.2 TOP OF LINER SQUEEZE - RETRIEVABLE PACKER

1. Make a casing scraper run if deemed necessary prior to running in with SQZTOOL. Work casing scraperthoroughly across the interval of pipe at planned SQZTOOL setting depth. Circulate bottoms up below theSQZTOOL setting depth. POOH. If it is deemed that a casing scraper run is not necessary, the following arereconcilers for not making the casing scraper run:

• The SQZTOOL will be set above where cement was tagged when RIH.• A packed BHA was used during the drillout. Stabilizer placement was as follows: 8-1/2" full


• After determining that a squeeze was necessary, the BHA was tripped and rotated across thebottom section of casing several times to clean the ID of the casing of any remaining cement.The SQZTOOL will be set in the interval that was cleaned with the stabilizers.

• The pumps were on while cleaning the casing to remove any cement cuttings. The rigcirculated adequate BU before POOH to ensure all cement cuttings had been removed.

2. Pick up SQZTOOL for CGOD CGWT casing and TIH to TOOLMD MD (305’ above the liner top). SetSQZTOOL @ TOOLMD MD (do not set squeeze tool below 10,005’ which is where cement was tagged whenrunning in the hole to clean out). Ensure that the squeeze tool will not be set in a casing collar. Verifysetting with 15 - 20 kips weight down on the SQZTOOL and 500-1000 psi on the DP by casing annulus.

• 7.75” is the maximum OD of the SQZTOOL• Maximum differential pressure for the SQZTOOL = 5,000 psi• Maximum set down weight for the SQZTOOL = 50,000 lbs

3. Test the cement lines and the squeeze manifold to 5000 psi. (Test against TIW valve)





Page 10 of 18


Do not exceed the liner top test pressure of 3300 psi with 12.7 ppg mud (15.0 ppg EMW) if injection has notyet been established at this point. This could indicate a satisfactory liner top test has been obtained.

5. Bleed pressure off the annulus, open bypass on SQZTOOL.

6. Mix and displace the following slurries using the cementing unit:Note: While displacing cement down the DP with the bypass open, the flowrate may outrun the pumprate due to U-tube pressure. Take returns through the choke, if necessary, so that back pressure canbe applied to prevent cement from circulating above the SQZTOOL before the bypass is closed.

PUMP SCHEDULE BEFORE CLOSING THE BYPASS ON SQZTOOLDescription Density Pump Rate30 bbls pre-flush spacer (MCS-3)38 bbls (150 sacks) low FL squeeze slurry (See Cement Data for recipe)38 bbls (200 sacks) high FL (neat) squeeze slurry (See Cement Data for recipe)10 bbls post-flush spacer (MCS-3)38 bbls mud (lead spacer position ~15 bbls inside the DP above the SQZTOOL)

Positions cement ~25 bbls inside the DP above the SQZTOOL. (1470' inside the DP above theSQZTOOL)5” 19.5# S-135 DP capacity = 0.01701 bpf; 9-5/8” 53.5# casing capacity = 0.0708 bpf.

7. Close the choke and then the bypass on the SQZTOOL and pressure up 500 - 1,000 psi on the DP by casingannulus. Pump an additional 119 bbls of 15.7 ppg mud at 4 bpm followed by 5 bbls of freshwater down theDP. This should leave TOC 250' below the SQZTOOL, and 250' above the liner top.

PUMP SCHEDULE AFTER CLOSING THE BYPASS ON SQZTOOLDescription Density Pump Rate119 bbls mud 15.75 bbls Fresh Water 8.3

This will leave the TOC 250' below the SQZTOOL, and 250' above the liner top.

Note: Displacement volumes assume a 12 ppg FCS in the G-series sand at 10000' TVD. 5 bbls of waterdisplacement should provide approximately 200 psi positive pressure.

If the well jugs up or surface pressure rises to 4500 psi during the squeeze operation with cement in the drillpipe, perform the following steps: release the squeeze tool, POOH 5 stands, reverse circulate out 2 workstringvolumes at the maximum rate (do not exceed the casing test pressure of 3520 psi while reversing), POOH 1additional stand, set the packer and put 500-1000 psi on the annulus.



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8. Hesitation squeezeStage up to 5.0 bbls of cement into the formation. Pump in 1.0 bbl at 1/4 bpm every 15 minutes for the first3.0 bbls. Afterwards, pump in 1.0 bbl at 1/4 bpm every 60 minutes for the last 2 bbls (total squeeze volume =5.0 bbls). If a pressure break-over is seen prior to finishing each stage, stop pumping immediately and holdwhatever pressure is achieved for required stage time before continuing with next stage. Stop pumping atany point if 1675 psi is reached (21.0 ppg EMW). If pressure limit is reached, discontinue staging processand hold final pressure for WOC time. If 1675 psi is not reached after squeezing 5.0 bbls, stop stagingprocess and hold whatever pressure is present. Estimated TOC after the hesitation squeeze is 185' abovethe liner top.

9. Hold the final squeeze pressure for 12 hours. The drill pipe pressure should increase due to thermalexpansion. Allow the drill pipe pressure to rise as high as 4500 psi (21.0 ppg EMW) before bleeding off anypressure. If the pressure builds to 4500 psi, bleed back to 3500 psi before continuing to hold squeezepressure. If backside pressure increases above 500-1000 psi, it may be indicative of a leak in either thepacker or the DP. (Maximum allowed annulus pressure is 1585 psi base on a 21 EMW casing test.)

10. After waiting 12 hours, pressure up to 500 psi over the final squeeze pressure to make sure cement is set. IfOK, release pressure, unseat SQZTOOL, and circulate out. POOH.

11. TIH with 8-1/2" clean out assembly to where the SQZTOOL was set and wash down to TOC. Drill cementdown to the LNROD liner top @ 10,255’ MD. Do not rotate excessively on the liner top and avoid damagingthe tie-back receptacle. C&C mud to clean wellbore.


12. Pressure test the LNROD liner top to 2,300 psi with 15.7 ppg mud (20 ppg EMW at the liner top). Use thePIT technique at 1/2 bpm and record pressure vs volume pumped. Hold test pressure for 30 minutes. Aftertest, record volume of mud bled back. POOH.

13. After successful test, proceed with drilling operations per the deeper drilling procedure.

3.3 SHOE SQUEEZE - DRILLABLE PACKER

1. Make a casing scraper run if deemed necessary prior to running in with SQZRETAINER. Work casingscraper thoroughly across the interval of pipe at planned SQZRETAINER setting depth. Circulate bottoms upbelow the SQZRETAINER setting depth. POOH. If it is deemed that a casing scraper run is not necessary,the following are reconcilers for not making the casing scraper run:

• The SQZRETAINER will be set above where cement was tagged when RIH.• A packed BHA was used during the drillout. Stabilizer placement was as follows: 8-1/2" full




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• After determining that a squeeze was necessary, the BHA was tripped and rotated across thebottom section of casing several times to clean the ID of the casing of any remaining cement.The SQZRETAINER will be set in the interval that was cleaned with the stabilizers.

• The pumps were on while cleaning the casing to remove any cement cuttings. The rigcirculated adequate BU before TOOH to ensure all cement cuttings had been removed.

2. Pick up SQZRETAINER for CGOD CGWT casing and TIH to TOOLMD MD (305’ above the shoe). SetSQZRETAINER @ TOOLMD MD (do not set retainer below 10,005’ which is where cement was tagged whenrunning in the hole to clean out). Ensure that the retainer will not be set in a casing collar. Verify settingwith 15 - 20 kips weight down on the SQZRETAINER and 500-1000 psi on the DP by casing annulus.

• 7.75” is the maximum OD of the SQZRETAINER• Maximum differential pressure for the SQZRETAINER = 5,000 psi• Maximum set down weight for the SQZRETAINER = 50,000 lbs

3. Test cement lines and squeeze manifold to 5,000 psi. (Test against TIW valve)


Note that the CGOD CGWT was last tested to 3,825 psi with 15.7 ppg mud, the cement lines have beentested to 5,000 psi, and the SQZRETAINER is rated for 5,000 psi of differential pressure.


Do not exceed the PIT test pressure of 3300 psi with 12.7 ppg mud (15.0 ppg EMW) if injection has not yetbeen established at this point. This could indicate a satisfactory PIT has been obtained.

5. Bleed pressure off of the annulus, PU out of the SQZRETAINER, and establish reversing pressures at 3 - 6bpm.

6. Mix and displace the following slurries using the cementing unit:Note: While displacing cement down the DP while stung out of the retainer, the flowrate may outrunthe pump rate due to U-tube pressure. Take returns through the choke, if necessary, so that backpressure can be applied to prevent cement from circulating around DP before stinging intoSQZRETAINER.

PUMP SCHEDULE BEFORE STINGING INTO THE SQZRETAINERDescription Density Pump Rate30 bbls pre-flush spacer (MCS-3)38 bbls (150 sacks) low FL squeeze slurry (See Cement Data for recipe)



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38 bbls (200 sacks) high FL (neat) squeeze slurry (See Cement Data for recipe)10 bbls post-flush spacer (MCS-3)38 bbls mud (lead spacer position ~15 bbls inside the DP above the SQZRETAINER)

Positions cement ~25 bbls inside the DP above the SQZRETAINER. (1470' inside the DP above theSQZRETAINER)


7. Close the choke and then sting into the SQZRETAINER. Set 15 - 20 kips weight down on the retainer andpressure up 500 - 1,000 psi on the DP by casing annulus. Pump an additional 119 bbls of 15.7 ppg mud at 4bpm followed by 5 bbls of freshwater down the DP. This will leave 2 bbls of cement in the DP above theretainer. Do not overdisplace the cement.

PUMP SCHEDULE AFTER STINGING INTO THE SQZRETAINERDescription Density Pump Rate119 bbls mud 15.75 bbls Fresh Water 8.3

This will leave 2 bbls cement above the SQZRETAINER in the DP. (118' inside the DP above theSQZRETAINER)

Note: Displacement volumes assume a 12 ppg FCS in the G-series sand at 10,000' TVD. 5 bbls of waterdisplacement should provide approximately 200 psi positive pressure.

If the well jugs up or surface pressure rises to 4500 psi during the squeeze operation with cement in the drillpipe, perform the following steps: sting out of retainer, POOH 2 stands, reverse circulate out 2 workstringvolumes at the maximum rate while keeping the pipe moving (do not exceed the casing test pressure of 3520psi while reversing).

8. PU out of the retainer and dump the last 2 bbls of cement on top of the SQZRETAINER (TOC @ ~9,922’ MD).PU 2 stands and reverse out at the maximum rate possible (do not exceed the casing test pressure of 3520psi while reversing). Reverse out at least 2 workstring volumes and keep the pipe moving while reversing.

9. POOH and LD retainer setting tool. PU the 8-1/2” drill out assembly and TIH to 9,750’ MD. (180' aboveexpected TOC)

10. After WOC for 18 hours since the cement was pumped, wash down to TOC. Drill cement/SQZRETAINERand continue drilling out cement. Drill 5'-10' of new hole noting any voids or changes in wellbore conditions.If high gas and or lost returns are encountered just below the shoe, contact the Operations Superintendentimmediately.




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11. Perform a PIT to 17.0 ppg EMW (2970 psi at the surface with 11.8 ppg mud at 10,317' TVD). Use the PITtechnique at 1/2 bpm and record pressure vs. volume pumped. Do not test the shoe to higher than 17.0 ppgEMW.


3.4 SHOE SQUEEZE - RETRIEVABLE PACKER

1. Make a casing scraper run if deemed necessary prior to running in with SQZTOOL. Work casing scraperthoroughly across the interval of pipe at planned SQZTOOL setting depth. Circulate bottoms up below theSQZTOOL setting depth. POOH. If it is deemed that a casing scraper run is not necessary, the following arereconcilers for not making the casing scraper run:

• The SQZTOOL will be set above where cement was tagged when RIH.• A packed BHA was used during the drillout. Stabilizer placement was as follows: 8-1/2" full


• After determining that a squeeze was necessary, the BHA was tripped and rotated across thebottom section of casing several times to clean the ID of the casing of any remaining cement.The SQZTOOL will be set in the interval that was cleaned with the stabilizers.

• The pumps were on while cleaning the casing to remove any cement cuttings. The rigcirculated adequate BU before POOH to ensure all cement cuttings had been removed.

2. Pick up SQZTOOL for CGOD CGWT casing and TIH to TOOLMD MD (305’ above the shoe). Set SQZTOOL@ TOOLMD MD (do not set squeeze tool below 10,005’ which is where cement was tagged when running inthe hole to clean out). Ensure that the squeeze tool will not be set in a casing collar. Verify setting with15 - 20 kips weight down on the SQZTOOL and 500-1000 psi on the DP by casing annulus.

• 7.75” is the maximum OD of the SQZTOOL• Maximum differential pressure for the SQZTOOL = 5,000 psi• Maximum set down weight for the SQZTOOL = 50,000 lbs

3. Test the cement lines and the squeeze manifold to 5000 psi. (Test against TIW valve)

4. Close annular BOP and pressure up on DP by casing annulus to 500-1000 psi. Establish injection rates at1/2, 1, 2, 3, and 4 bpm without exceeding injection pressures of 4,500 psi ( Engineer to comment on basis formaximum injection pressure. i.e. To stay within net burst pressure limit (7,927 psi w/ 1.375 SF ) of the 9-5/8”casing assuming 15.7 ppg mud in the wellbore and a 9.0 ppg EMW back-up behind the 9-5/8”). Monitorannulus carefully for pressure response indicative of packer or DP leak.





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Do not exceed the PIT test pressure of 3300 psi with 12.7 ppg mud (15.0 ppg EMW) if injection has not yetbeen established at this point. This could indicate a satisfactory PIT has been obtained.

5. Bleed pressure off the annulus, open bypass on SQZTOOL.

6. Mix and displace the following slurries using the cementing unit:Note: While displacing cement down the DP with the bypass open, the flowrate may outrun the pumprate due to U-tube pressure. Take returns through the choke, if necessary, so that back pressure canbe applied to prevent cement from circulating above the SQZTOOL before the bypass is closed.

PUMP SCHEDULE BEFORE CLOSING THE BYPASS ON SQZTOOLDescription Density Pump Rate30 bbls pre-flush spacer (MCS-3)38 bbls (150 sacks) low FL squeeze slurry (See Cement Data for recipe)38 bbls (200 sacks) high FL (neat) squeeze slurry (See Cement Data for recipe)10 bbls post-flush spacer (MCS-3)38 bbls mud (lead spacer position ~15 bbls inside the DP above the SQZTOOL)

Positions cement ~25 bbls inside the DP above the SQZTOOL. (1470' inside the DP above theSQZTOOL)


7. Close the choke and then the bypass on the SQZTOOL and pressure up 500 - 1,000 psi on the DP by casingannulus. Pump an additional 119 bbls of 15.7 ppg mud at 4 bpm followed by 5 bbls of freshwater down theDP. This should leave TOC 250' below the SQZTOOL, and 250' above the casing shoe.

PUMP SCHEDULE AFTER CLOSING THE BYPASS ON SQZTOOLDescription Density Pump Rate119 bbls mud 15.75 bbls Fresh Water 8.3

This will leave the TOC 250' below the SQZTOOL, and 250' above the casing shoe.

Note: Displacement volumes assume a 12 ppg FCS in the G-series sand at 10000' TVD. 5 bbls of waterdisplacement should provide approximately 200 psi positive pressure.

If the well jugs up or surface pressure rises to 4500 psi during the squeeze operation with cement in the drillpipe, perform the following steps: release the squeeze tool, POOH 3 stands, reverse circulate out 2 workstringvolumes at the maximum rate (do not exceed the casing test pressure of 3520 psi while reversing), POOH 1additional stand, set the packer and put 500-1000 psi on the annulus.

8. Hesitation squeeze.Stage up to 5.0 bbls of cement into the formation. Pump in 1.0 bbl at 1/4 bpm every 15 minutes for the first3.0 bbls. Afterwards, pump in 1.0 bbl at 1/4 bpm every 60 minutes for the last 2 bbls (total squeeze volume =



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5.0 bbls). If a pressure break-over is seen prior to finishing each stage, stop pumping immediately and holdwhatever pressure is achieved for required stage time before continuing with next stage. Stop pumping atany point if 1675 psi is reached (21.0 ppg EMW). If pressure limit is reached, discontinue staging processand hold final pressure for WOC time. If 1675 psi is not reached after squeezing 5.0 bbls, stop stagingprocess and hold whatever pressure is present. Estimated TOC after the hesitation squeeze is 185' abovethe shoe.

9. Hold the final squeeze pressure for 12 hours. The drill pipe pressure should increase due to thermalexpansion. Allow the drill pipe pressure to rise as high as 4500 psi (21.0 ppg EMW) before bleeding off anypressure. If the pressure builds to 4500 psi, bleed back to 3500 psi before continuing to hold squeezepressure. If backside pressure increases above 500-1000 psi, it may be indicative of a leak in either thepacker or the DP. (Maximum allowed annulus pressure is 1585 psi base on a 21 EMW casing test.)

10. After waiting 12 hours, pressure up to 500 psi over the final squeeze pressure to make sure cement is set. IfOK, release pressure and unseat SQZTOOL and circulate out. POOH.

11. TIH with 8-1/2" drill out assembly to where SQZTOOL was set, and wash down to TOC. Drill out cement and5-10' of new formation noting any voids or changes in wellbore conditions. If high gas and/or lost returns areencountered just below the shoe, contact the Operations Superintendent immediately.


12. Perform a PIT to 17.0 ppg EMW (2970 psi at the surface with 11.8 ppg mud at 10,317' TVD). Use the PITtechnique at 1/2 bpm and record pressure vs volume pumped. Do not test the shoe to higher than 17.0 ppgEMW.


5. ENGINEERING FOLLOW-UP

Well Name: WELLNAMESuperintendents: Drilling SuptsEngineer(s): Drilling Engineer

Well engineer is responsible for verbal follow-up with rig supervisor. Engineer is to identify anddocument below sections of the procedure which did not meet the drilling team's needs and describekey learning's to be incorporated into core procedure.



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Return follow-up to core procedure owner:

Recommended Modifications to Procedure:

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Submitted By: ______________________________________________________________

Phone: ( ) DATE___________


SECTION 10 - APPENDIX IIWell Name

Previous casing Rig NameOD= 16

ID= 15.22 Annular Volume PROPOSED CASING DESIGN (bottom to top)

MD= 1000 0.1128 bpf WGHT GRADE/CONN LENGTH MD ID CAP. (bpf) CAP. (bbls) DISPLACE. MISC. ENGINEERING CALCS.

TVD= 1000 1 45.5 K-55,BTC 4900 4900 10.05 0.0982 481.0 0.0166 Pit gain from casing (bbls): 81.2

Excess bbls of cement at 2 0.0000 0.0 0.0000 Pit gain from cementing(bbls) 754.1

surface if gauge hole 341 3 0.0000 0.0 0.0000 EMW after displacment (ppg) 13.0

4 0.0000 0.0 0.0000 U-tube pressure @ floats (psi 930

Req'd height of tail above shoe 500 feet.

SPACERS

Assumed hole size Pre-flush with 20 bbls of 8.7 ppg seawater spacer.

16.5 " Post-flush with 20 bbls of 8.7 ppg seawater spacer.

Setting MW Annular Volume CEMENT

9.2 0.1523 bpf Lead Slurry: Class 'H' with liquid additives Mixed to: 12.6 ppg

Washout = 49% Mixwater: Sea at 13.23 gal/sk Yield: 2.32 cu.ft/sk

Number of sacks: 1525 Volume: 630.1 bbls

Calculated= 1526Bit Size(in) Tail Slurry: Class 'H' with liquid additives Mixed to: 16.2 ppg

13.5 Mixwater: Sea at 4.68 gal/sk Yield: 1.11 cu.ft/sk

Number of sacks: 425 Volume: 84.0 bbls

Calculated= 425Tail is estimated at DISPLACEMENT

4400 ' MD After postflush, displace w/ 453.1 bbls of 9.2 ppg mud.

4400 ' TVD

Which is 500 ' above PUMP TIMES Rate Lead Tail

casing shoe (assumed hole size). Mix Lead Cement 6 105.0 0.0

If gauge then 1175.3 ' above Mix Tail Cement 6 14.0 14.0

shoe. Drop Top Plug 5.0 5.0

Proposed Casing 20 bbl postflush 6 3.3 3.3

10.75 Casing Point 433.1 bbls displacement 6 72.2 72.2

4900 ' MD 20 bbls displacement 2 10.0 10.0

Float Length= 80 4883 ' TVD Contingency 60 60

Float Capacity= 7.9 bbls Estimated Job Time 270 165

EJT (hours) 4.49 2.74

EJT with contingency 5.49 3.74

Bottom hole static temperature 138 degrees F (est. from log temps)

Bottom hole circulating temperature 110 degrees F (from API Spec 10)


Well NamePrevious casing Rig Name

OD= 16 10.75 " SHOE SQUEEZE ID= 15.22 CASING DESIGN (bottom to top)

MD= 1000 WGHT GRADE/CONN LENGTH MD ID CAP. (bpf) CAP. (bbls) DISPLACE.

TVD= 1000 1 45.5 K-55,BTC 4900 4900 10.05 0.0982 481.0 0.0166

2 0 0 0 0 0 0.0000 0.0 0.0000

3 0 0 0 0 0 0.0000 0.0 0.0000

WORKSTRING DESIGN (bottom to top)

OD WEIGHT/CONN LENGTH MD ID CAP. (bpf) CAP. (bbls) DISPLACE.

1 5 19.5 #/NC50/X-95 4400 4400 4.276 0.017268 76.0 0.0078

2 0 0 0 0.000000 0.0 0.0000

3

Displacement MW SPACERS

9.2 Pre-flush with 20 bbls of 8.7 ppg seawater spacer.

Follow cement with 10 bbls of 8.7 ppg seawater spacer.

CEMENT

Lead Slurry: Class 'H' with liquid additives Mixed to: 16 ppg

Casing Mixwater: Sea at 13.23 gal/sk Yield: 1.65 cu.ft/sk

10.75 " Number of sacks: 257 Volume: 75.5 bbls

Desired underdisplacement of pre-flush Calculated= 257when bypass is closed

5 bbl DISPLACEMENT

Close bypass after pumping 71.0 bbls of preflush and cement

Squeeze packer setting depth After spacer, displace w/ 80.5 bbls of 9.2 ppg mud.

4400 ' MD

PUMP TIMES Rate Squeeze Slurry

TOC desired 250 feet above shoe Mix Squeeze Cement 4 18.9

Desired squeeze volume 10 bbl spacer 4 2.5

50 bbl Casing Shoe 80.5 bbl displacement 4 20.1

4900 ' MD 0 bbl other 4 0.0

Length of new hole: 10 ' 4883 ' TVD Contingency 60

Bit size: 9.875 " Estimated Job Time 102

New hole volume: 0.95 bbl EJT (hours) 1.69

EJT with contingency 2.69

Bottom hole static temperature 138 degrees F (est. from log temps)

Bottom hole circulating temperature 110 degrees F (from API Spec 10)

PRESSURE INTEGRITY TESTS

______________________________________________________________________________DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLINGFIRST EDITION MAY, 2003

11.0 PRESSURE INTEGRITY TESTS

11.1 General 111.2 Casing Test 211.3 Leak-Off Test 311.4 Jug Test (Limited PIT) 411.5 Open Hole Leak-Off Test 4


DRILLING OPERATIONAS MANUAL - JACK-UP/PLATFROM/BARGE RIG DRILLING 1 of 6First Edition - May, 2003

11.1 GENERAL

There are three main types of Integrity Tests that are conducted by EMDC drilling. The CasingTest, the Leak Off Test (LOT), and the Jug Test (PIT). A casing test is used to ensure the casingwill not fail in a well control situation or completion operation. The LOT and PIT tests are used inopen hole just below the shoe to determine the equivalent mud weight that can be held, or that willinitiate a fracture and cause leak-off to the formation. One additional type of test that may beperformed during drilling operations is an open hole integrity test. If this test is required theapplicable drilling procedure will detail that test.

Casing tests are to be charted and the chart maintained at the rig and in the office per regulatoryagency requirements. The MMS requirement is to pressure test all casing strings except the drivepipe, to hold the test for 30 minutes (generally for non-MMS regulated operations, 15 minute testsare sufficient) with <10% loss in pressure, and to document the test on the IADC report. For allEMDC wells, document the test on the morning report as well.

The EMDC Integrity Test Workbook will be completed for either the LOT or PIT and will beperformed in accordance with the guidelines specified below (located on the LAN or Global Share).The Excel workbook contains help files with discussion of theory procedures, and testinterpretation. Additional information regarding test procedures and analysis is contained in theEPR publication "Pressure Integrity Test - Field Guide".

The Operations Supervisor is responsible for completing the PIT form and forwarding it to theDrilling Engineer and Operations Superintendent as soon as practical after completing the test.

General Pressure Testing Guidelines

1. Prior to drilling float equipment, a casing test is to be conducted. This test is to be run to theapproved test pressure by the MMS or other governing regulatory agency.

2. Integrity Tests are required below each string of casing except the drive pipe and conductorcasing. Based on geologic conditions or planned setting depths, a test of the conductor casingshoe may be mandated by the governing regulatory agency. A test is to be conducted after 10'of new hole has been drilled to determine the formation integrity. Per MMS or other governingregulatory agency orders, the test is to be conducted after drilling new formation, but must beperformed before drilling 50' of new formation. The test will generally be taken to leak-off,(LOT) but a jug test (PIT) may be requested (see drilling procedure for details). The testsurface pressure will not in any case exceed the casing test pressure or the surface line pressure.

3. All pressure tests should be conducted in the same manner. The same gauges and pressurecharts should be used on each test. Gauges should be sized for the expected pressure range.

4. Pressure tests will be repeated if any doubt exists as to the validity of the test or if the result isless than anticipated.



5. The cement pump will be used for all pressure tests and, prior to conducting any pressure test,all surface lines will be tested to greater than the anticipated surface pressure as specified in theDrilling Procedure.

6. The following pressure test data will be recorded as accurately as possible:

• Pump Rate

• Mud Weight

• Pump Pressure vs. Cumulative Barrels Pumped

• Total Barrels Pumped

• Shut-In Pressure vs. Cumulative Time (Minutes)

• Total Barrels Bled Back

7. The guidelines in the "Integrity Testing Workbook" should be followed for plot interpretation.

8. After completing Integrity Testing Workbook, fax or email to the Drilling Engineer andOperations Superintendent for review and documentation.

11.2 CASING TEST

The Casing Test procedure is as follows:

1. After setting surface casing and all subsequent casing strings, a Casing Test will be conductedusing one of the following methods:

a. After completing the required BOP test, the blind rams will be closed and the casing willbe tested against the blind rams by pumping down the choke/kill line.

b. After finding hard cement or prior to drilling the float collar, the BOP will be closed onthe drill pipe and the casing will be tested by pumping down the drill pipe.

Method "b" is the preferred technique.

2. Pump drilling fluid at 1/4 - 1/2 BPM and record the pressure build up using the cement pumpuntil reaching the casing test pressure specified in the drilling program. Record bbls pumpedto reach the test pressure.

3. Stop pumping and record the shut-in pressure for 30 minutes per MMS requirements or otherregulatory agency requirements (generally, for non-MMS regulated operations, 15-minute testsmay be sufficient).

4. Bleed off the pressure and record the bleed back volume. Record the test data in the IntegrityTest Workbook.

5. Open the BOP.



11.3 LEAK-OFF TEST

Prior to conducting the Leak-Off Test, the EMDC Integrity Test Workbook is to be prepared forplotting pump pressure and shut-in pressure as a function of cumulative bbls pumped and shut-intime. The drill pipe float valve, either solid or ported, can influence the results; take it intoconsideration. The accompanying equations may be helpful in calculating pressures and volumesduring a leak-off test. Additionally, a spreadsheet to calculate the compressibility of Water or Oilbased muds may be found on the LAN or Global Share. The casing test also provides a goodindication of the expected pressure response if the mud type and density have not been changed.

1. Perform the casing test as described above, drill out the casing shoe and 10' of new hole.

2. Circulate bottoms up and condition the drilling fluid to ensure that is virtually free of cuttingsand is of uniform density. Pull bit up inside the casing.

3. Rig up the cement pump and pump down the drill pipe to ensure all lines are full. Test lines togreater than the expected surface pressure as specified in the Drilling Procedure. The testsurface pressure will not in any case exceed the surface line test or casing test pressure.

4. Close the BOP.

5. Pump drilling fluid down the drill pipe or choke/kill line and record the pressure build upversus cumulative barrels pumped. Pump at 1/4 bpm if the wellbore volume is <1000 bbls and1/2 bpm if greater.

6. Enter the data in 1/4 bbl increments as the test proceeds to determine the leak-off point.

7. Continue pumping until reaching the surface pressure, adjusted for mud weight, specified inthe Drilling Procedure, or leak-off plus 3-4 data points, whichever occurs first.

• Do not exceed the casing test pressure.

8. Stop pumping and record the instantaneous shut-in pressure 10 seconds after shut in.

9. Read, record and plot the shut-in pressure at 1 minute intervals. Allow at least 10 minutes forpressure to stabilize. If pressure is continuing to fall rapidly maintain shut in until it stabilizes.

10. Bleed off pressure and record the bleed back volume from the annulus shoe so that the op floatdoes not restrict flow.

11. Review the gradial plot in the Integrity Test Workbook and determint the LOT. Repeat the testif the interoperation is not clear. Repeat the PIT test if unacceptable. If it appears that the PITwas unacceptable due to fluid leaking off into a permeable sand, a seepage spill may be spottedprior to repeating the test. Use 20-30 ppb of 5 micron (fine) CaCO3. Discuss this option withOperations Superintendent prior to pumping the second test.



12. Open the BOP.

13. Attempt to identify the minimum stress (MS) from the shut in data and record it in the resultssection of the Integrity Test Workbook. If a distinct inflexion is not seen at fracture closurerecord the MS as "N/A". Complete the workbook, including the comments section, form andfax or email it to the Drilling Engineer and Operations Superintendent as soon as practical.

14. Leak-off is assumed to be at the true vertical depth of the casing shoe which should be used tocalculate the PIT. PIT (ppg) = [[ MW (ppg) * 0.052 * TVD of casing shoe (feet) ] + Surfacepressure (psi) ] / [ 0.052 * TVD of casing shoe (feet) ].

11.4 PRESSURE INTEGRITY TEST (JUG TEST)

A jug test or PIT of the casing seat is identical to a leak-off test except that it is not taken to leak-offpressure. The test plots are similar in all areas except the top of the pressure build-up curve. In theLOT, the plot bends to the right at the leak-off point. In the jug test, the entire build-up plot shouldbe a straight line because the test is stopped before leak-off pressure is reached.

11.5 OPEN HOLE LEAK-OFF TEST

This Integrity Test determines if there is a significant decrease in the open hole fracture pressure innew formations drilled. Normally this test is necessary after penetrating porous/permeableformations that have the potential for lost returns and/or when the mud weight nears the last leak-offvalue. The same procedure is used as for performing an open hole test after the bit is pulled upinside the casing.

A higher pump rate may probably be needed than was used in the PIT at the casing shoe because ofthe extended open hole section and potential permeability, however the initial attempt should bemade at the same rate used for the shoe test.

This test may be substituted with for a weight up test when a higher mud weight will be needed toTD the hole section.

NOTE: To supplement the compressibility curves the following equations can be used:

Equation 1

Barrels Base Fluid Required = (Test Pressure) (Casing Fluid Volume) (Coefficient of Compressibility – Cf)

Cf Water = 0.000003

Cf Diesel/SBM = 0.000005

Example - Bbls = (1000 psi)(1500 bbls) (0.000003) = 4.5 bbls required



Equation 2 – to adjust Eqn. 1 for Mud Weight

Adjustment for Mud Solids = (Barrels Base Fluid Required) (1- %Solids)

Example – 14.8 ppg Mud Weight Adj = (4.5 bbls) (1-0.24) = 3.4 bbls Adjusted for 24% solids



FIGURE 11-1 (Intergrity.xls output)

EMW = 16.25 ppg

ISIP

0

500

1,000

1,500

2,000

2,500

3,000

0.0 2.0 4.0 6.0 8.0 10.0 12.0

Volume Prior to ISIP (bbl), Time After ISIP (1 min / minor division)

Su

rfac

e P

ress

ure

(p

si)

Casing Test Test 1 Test 2 Test 3

Test and interpretation comments...

Integrity Test Plot

Test Depth (ft) Integ (ppg) Type MS (ppg)

Test 1 11,000 16.2 LOT 15.6Test 2 0Test 3 0

Final Interpretation

WellCsg Size (in)RigRKB (AMSL, ft)Water Depth (ft)FieldCountry

Example Well9.625Example Rig1002,000Example FieldInternational

PRODUCTION TESTING


12.0 PRODUCTION TESTING

12.1 Production Testing Objectives 112.2 Well Test Design 112.3 Test String 312.4 Surface Equipment 412.5 Measurement Equipment 412.6 Safety 512.7 Personnel Responsibilities 612.8 Pre-test Planning and Preparation 912.9 Information Retrieval 1012.10 Well Killing and Zone Abandonment 1112.11 Emergency Procedures 1112.12 Hydrogen Sulfide 1112.13 Hydrates 12

PRODUCTION TESTING


For Development Jack-up, Platform, & Barge Rig Drilling Operations, a production test is notusually performed. The wells drilled in during development are usually completed and brought onproduction by the Production group after the drilling rig has moved off location. In the event that aproduction test is required (e.g. exploratory well), a detailed Well Testing Procedure will bedeveloped by the Well Test Engineer and/or the Drilling Engineer on a well specific basis. Thisprocedure will cover the essential equipment and steps to be utilized during the production test(using industry guidelines and the general information included below). Refer to ExxonMobilProduction and Development Company Safety Manuals for safety guidelines concerning drill stemtesting, well testing equipment (i.e., steam generators, heater treaters, flowlines, gauge tanks, etc.)and H2S contingency requirements. A Risk Assessment will be conducted prior to initiating WellProduction Testing operations.

12.1 PRODUCTION TESTING OBJECTIVES

A production test is a formation evaluation technique which may be designed to provide thefollowing reservoir description data:

• Types and Properties of Formation Fluids From a Particular Zone• Measurements of Reservoir Pressure and Temperature Under Various Flow Conditions• Determination of the Well Flow Efficiency• Existence of Reservoir Heterogeneities or Boundaries

This information will be obtained through either direct physical measurements taken during theproduction test or through analytical methods using the appropriate reservoir description model, inconjunction with information obtained from the well test.

In exploration well testing, the well may be temporarily completed so that reservoir fluids can beflowed to the surface and measurements of pressure and flow rate can be made. Since hydrocarbonssurface during the production test, extreme caution is to be taken by all personnel involved withtesting operations. It is essential to select equipment and adopt test procedures which will ensurethe safety of the drilling rig and its personnel.

12.2 WELL TEST DESIGN

A typical production test consists of four distinct time periods: initial flow, initial build-up, finalflow, and final build-up. The reservoir's pressure response during each of these time periods isshown schematically in Figure 12-1. The length of each time period is dependent on the reservoirproducing capability and the type of fluids produced.

Initial Flow Period

The purpose of the initial flow period is to clean out the casing perforations and to ensure that apressure differential exists from the formation into the wellbore. The initial flow period is usuallyshort in duration (anywhere from 2 minutes to 1 hour). For an oil well test or bottom hole shut-intest, it is generally not necessary to flow formation fluids to surface during the initial flow. For agas well test, all liquids should be completely removed from the wellbore below the first closedvalve to prevent a phase hump in wellbore pressure from forming due to gas rising through liquids

PRODUCTION TESTING


left in the wellbore. For a surface shut-in gas well test, the initial flow period could last severalhours.

Initial Build-Up Period

Following the initial flow period, the well is shut-in in order to measure the initial reservoirpressure. Ideally, the initial build-up period should last until the bottom hole pressure hascompletely stabilized; however, this is not always feasible. The initial build-up period will normallybe two to four times the length of the initial flow period, with lower productivity reservoirsreceiving the higher multiplier. The minimum length for the initial build-up should be 1 hourregardless of the length of the initial flow period.

In tests which utilize surface readout bottom hole pressure gauges, it is possible to monitor thebottomhole pressures and plot the data in real-time on a Horner or superposition plot. The shut-inperiod should, where practical, last until an initial reservoir pressure can be obtained unambiguouslyfrom extrapolation of the buildup pressures.

Final Flow Period

The purpose of the final flow period is to establish stabilized production from the well and to obtainfluid samples for laboratory analysis. The pressure transient introduced into the formation duringthe final flow period will be used to determine the reservoir permeability-thickness product andidentify the existence of reservoir heterogeneities or boundaries.

The length of the flow period is typically between 6 to 12 hours, but should be sufficient to obtaindefinitive flow data. In some cases, flow periods exceeding 12 hours may be required to ensure dataquality. If produced liquids are flowed to storage tanks, then the flow rate and flow time will haveto be adjusted so as not to exceed the capacity of the tank(s).

The fact that stabilized fluid production is necessary for obtaining useful fluid composition data maydictate the actual length of the final flow period. Fluid samples from both the full well stream andthe separator should be taken during the final flow period.

Final Build-Up Period

During the final build-up period, the well will be shut-in so that the reservoir pressure build-upresponse can be measured and recorded. This information will allow the formation permeability,wellbore damage, and indications of reservoir heterogeneities and boundaries to be determined.

The length of the final build-up period should be at least as long as the final flow period. For lowproductivity reservoirs, the build-up period should be 1-1/2 to 2 times the length of the final flowperiod. If bottom hole samples are required, they should be taken following the final build-upperiod.

PRODUCTION TESTING


12.3 TEST STRING

Test String

The test string contains those components necessary for sealing the tubing annulus, shutting in thetubing downhole (if desired), and suspending pressure and temperature gauges. The shut-in methodused will depend on such considerations as types of fluids produced, objectives of the test, andsafety considerations.

The four basic lower test string assemblies are: Surface Shut-in/Permanent Packer; Surface Shut-In/ Retrievable Packer; Bottom Hole Shut-In / Permanent Packer; and Bottom Hole Shut-In /Retrievable Packer. See Figure 12-2 for a typical lower test string assembly with Surface Shut-In /Permanent Packer.

Shut-In Methods

1. Surface Shut-In

The simplest method for shutting in a well is with a surface shut-in. In this method, primary wellcontrol is at the surface test tree. No manipulation of the test string is required while the well is"alive". Unfortunately for reservoir purposes, during surface shut-in the entire wellbore volume isin communication with the formation. This can lead to two detrimental effects, afterflow and phaseredistribution in the wellbore.

Afterflow is defined as flow from the formation into the wellbore after the well is shut-in at thesurface. Formation fluid can flow into the wellbore because of the compressibility of the fluid inthe wellbore. Afterflow is usually not a problem in oil or gas wells having moderate to goodproductivity. In low productivity wells, afterflow can lead to difficulty with analysis of data.

Phase redistribution (separation of gas and liquid) may cause problems with analysis of data fromhigh liquid ratio gas wells and high GOR oil wells. If phase redistribution occurs, it can usually berecognized as a hump in the plot of build-up data. If pressure humping lasts throughout the test, thebuild-up data may be of questionable value for analysis of reservoir properties.

2. Bottom Hole Shut-In

The bottom hole shut-in method is the ideal way to shut-in a well for a build-up test, because iteliminates the effects of afterflow and phase redistribution. However, a bottom hole shut-inrequires a somewhat complex string of downhole tools, which increases the probability of amechanical malfunction. With some test strings, pipe motions are required to operate tools whilethe well is "live" which is considered a disadvantage from the standpoint of safety.

A bottom hole shut-in should be considered if:

• Phase redistribution (pressure humping) or afterflow is expected to dominate the data.• The surface shut-in pressure of the well is expected to exceed safe conditions.

PRODUCTION TESTING


12.4 SURFACE EQUIPMENT

The surface testing equipment is designed to process produced formation fluids from the surface testtree to a point of disposal. Typically, the major components of this system are: data header, chokemanifold, flow lines, heater, separator, test/gauge tank, transfer pump, and burner(s). The surfaceand bottom hole test equipment required for a particular well test will vary depending uponindividual well conditions and specific reservoir requirements and will be specified in the WellTesting Procedure.

12.5 MEASUREMENT EQUIPMENT

Obtaining accurate measurements of bottom hole and surface pressure and temperature is one ofproduction testing's main objectives. Subsurface pressure and temperature gauges can be eithermechanical or electronic downhole recording devices or wireline run electronic gauges whichprovide a surface readout. Surface pressures are normally obtained with either dial gauges or deadweight testers.

Subsurface Measurement Equipment

Subsurface gauges are run into the wellbore to record the reservoir pressure and temperatureresponse during flowing and shut-in periods. Subsurface pressure and temperature gauges caneither be landed in a nipple located below the perforated joint or run in gauge carriers. There aretwo basic types of subsurface pressure gauges available, the subsurface recording gauges and thesurface readout subsurface gauges.

1. Subsurface Recording Gauges

Subsurface recording gauges make a record of pressure and/or temperature versus time. The recordcan be read at the surface when the gauges are retrieved. These gauges are self-contained recordingdevices which do not require a physical link to surface equipment. Subsurface recording gaugeswill either be mechanically or electronically operated.

2. Surface Readout Subsurface Gauges

Surface readout subsurface gauges allow real time bottom hole pressure and temperaturemeasurements to be read at the surface. These gauges transmit their data through a monoconductorcable. Because of the electric cable, these gauges cannot be used with a standard bottom hole shut-in test assembly.

Surface Measurement Equipment

Surface pressure and temperature measuring equipment can be connected to the data header locatedupstream of the choke manifold. Surface pressure can be measured with either dial type gauges, adead weight tester, and/or electronic gauges.

PRODUCTION TESTING


12.6 SAFETY

General Safety Guidelines

1. The drilling supervisor is to hold a safety meeting prior to the initiation of each productiontest. All personnel are to attend this meeting.

2. Do not subject Oilfield Explosives (perforating guns, tubing cutters, string shots, severingcharges, etc.) to pressures higher than the allowable (rated) pressure specified by themanufacturer. This includes pressure testing lubricators that contain electric line conveyedperforating guns, cutters, etc. and also while running explosives into the well (e.g. multipleruns of through tubing perforating guns/ adding perfs on a "live" well). If necessary,substitute an explosive device with a higher pressure rating.

3. Testing of the surface equipment should be addressed in the Risk Assessment. It is alsorecommended that start-up of the production test be initiated during daylight. Extra lightingmay be necessary to insure potential leaks do not go undetected if testing continues afterdaylight hours.

4. The drilling rig is to be equipped with a warning system, which will be activated any time thewell is being tested. During this period, it will be necessary for personnel to followExxonMobil Safety Manual guidelines for welding, cutting, electrical work, sand blasting, orother work which could result in a fire or explosion.

5. Cranes will not be operated over "live" test equipment.

6. Personnel not required for duties in conjunction with the test, or for maintenance duties, are tostay clear of production testing equipment. Smoking is permitted only in designated areas.

7. If H2S is anticipated in formation fluids, H2S detection equipment shall be used to determineif any hydrogen sulfide is present in the produced formation fluids.

8. At the conclusion of testing operations, all flowlines are to be thoroughly flushed with water.

9. Cement unit should be tied to the surface test tree for use in well kill operations, if necessary.

10. The surface tree lower master valve should be manual operated, the upper master valve &wing valve should be hydraulic or pneumatic operated with a remote unit located away fromthe tree.

11. A contractor representative of the tree supplier must be present on the rig floor or near thecontrol unit at all times when the well is "live".

12. If methanol is utilized, ensure that flame and mitigation detection contingencies are in placeand reviewed with all personnel.

PRODUCTION TESTING


12.7 PERSONNEL RESPONSIBILITIES

The overall responsibility for conducting a safe testing operation rests with the OperationsSupervisor. The Operations Supervisor is to work closely with the Drilling/Well Test Engineer, andService Company Personnel to ensure that all test objectives are achieved. Responsibilityguidelines for a typical offshore production test are listed below; refer to Section 2.6 of this manualfor additional information.

Drilling/Well Test Engineer

1. Develop test procedures and determine equipment needs.

2. Ensure that all test equipment is mechanically sound and compatible with adjacentequipment. Ensure that critical spares are available.

3. Witness pressure and function tests of surface and subsurface test equipment. CoordinateThird Party witnessing of equipment inspections and testing prior to sending equipment tolocation.

4. Supervise the make-up of the test string and check clearances. Ensure that string spaceout iscorrect.

5. Ensure that packer, seal assembly, and tail pipe assemblies have the proper OD's, ID's andlengths.

6. Witness perforating operations (if applicable).

7. Ensure that all wireline tools and equipment are available and compatible with durableconditions.

8. Coordinate and gather test data.

9. Evaluate test data on-site for completeness and accuracy.

10. Specify length of flow and build-up periods and size of choke.

11. Supervise surface and bottom hole sampling.

12. Communicate test results to office personnel during and after the test for making tacticaldecisions.

13. Read and analyze bottom hole pressure charts for evaluation of test results.

14. Follow up on test equipment and service company personnel performance.

Wellsite Geologist

1. Determine number of zones to be tested and provide initial information on pressure,temperature, and types of fluids contained in the reservoir.

PRODUCTION TESTING


2. Analyze electric logs to determine perforating interval(s).

3. Witness perforating operations (if applicable).

4. Assist in gathering and analyzing test data.

Subsurface Test Tool Personnel

1. Prepare test tools and subs for make-up on drill floor.

2. Function and pressure test tools on pipe rack.

3. Check nitrogen precharge on annulus pressure operated tools.

4. Oversee make-up and running of bottom hole test assembly.

5. Operate down hole test tools, by directing the drill crew, under the direct supervision of theDrilling/Well Test Engineer.

Production Testing Service Company Personnel

1. Operate surface and downhole test equipment under immediate supervision of the Drilling \Well Test Engineer. These responsibilities will include proper functioning of separator,changing orifice and choke sizes, accurate calibration of gas and liquid meters, operating allvalves, observing separator pressures, and monitoring gas and liquid flow rates, runninggauges, etc.

2. Coordinate separator operation with rig floor for emergency shut-in.

3. Ensure the proper functioning of burner(s) and monitor wind direction. Operate all valvingunder the direction of the separator operator and help monitor wellhead pressures. Coordinateburner operation with rig floor for emergency shut-in.

4. Take oil, gas, and water samples. Ensure proper labeling.

5. Assist with monitoring wellhead pressures with deadweight tester and record wellheadtemperatures.

6. Operate chemical injection of glycol / methanol, as necessary.

7. Coordinate operation of surface test tree and floor choke manifold and be prepared to handlean emergency shut-in.

8. Ensure that the proper wireline tools are available for test string pressure testing.

9. Ensure that the proper testing and maintenance of the surface test tree and floor chokemanifold are carried out.

10. Assist in monitoring casing annulus pressure and production test data.

PRODUCTION TESTING


11. Prepare subsurface recording pressure and temperature gauges. Continuously monitor panelfor surface reading subsurface pressure and temperature gauges.

Mud Logger

1. Take periodic samples of gas at the floor choke manifold during flow periods and analyzesamples with the gas chromatograph.

2. Use gas detectors to determine possible presence of gas on the rig floor and in thewellhead/BOP area.

Drilling Fluids Engineer

1. Ensure the proper maintenance of the drilling fluid in the pits.

2. Catch samples of condensate and/or water being produced and conduct analysis of filtrate andwater properties.

Cementer

1. Perform well killing and cementing operations as required. Have pumping equipment in astate of readiness to kill the well and/or cement at short notice.

2. Maintain adequate number of cement retainers and conversion kits to bridge plugs for casingsize used in production test.

3. Assist drill crew and subsurface test hole personnel in operation testing of downholeequipment.

4. Assist testing personnel in testing surface test equipment.

Rig Toolpusher

1. Ensure that well killing equipment is ready and coordinate the well killing operations.

2. Oversee running of test string and rigging up of surface control equipment.

3. Help coordinate various steps of the production test sequence as pertaining to the rigequipment.

4. Manipulate/operate downhole tools under direction of subsurface test tool personnel.

Driller

1. Ensure pressure integrity of rig floor piping.

2. Coordinate the Assistant Driller and/or floormen to provide constant observation of the casingannulus pressure and production test data.

3. Ensure that production test string is properly made up.

PRODUCTION TESTING


12.8 PRE-TEST PLANNING AND PREPARATION

Good planning and preparation are essential to conducting a safe and complete production test.Prior to the test, a meeting is to be held with all key personnel to discuss the test procedures,personnel responsibilities, and safety considerations. The BOPs are to be fitted with the proper sizerams as necessary to accommodate the test string equipment in the hole. All surface testingequipment is to be pressure and function tested before beginning the test.

Meetings and Drills

The Operations Supervisor is to hold a pre-test meeting prior to the initiation of each productiontest. All personnel are to attend this meeting. During the pre-test meeting, the following items areto be reviewed and discussed:

• Safety Procedures• Spill Prevention• Test Objectives• Test Equipment and Hook-Up• Test Procedures• Personnel Responsibilities• Data Collection

Supervisors must ensure that the responsibilities of all personnel associated with the test are clearlyunderstood.

Surface Equipment Preparation

At an appropriate time, well before the test string is run in the hole, the separator, heater, transferpump, gauge tank and burner(s) are to be inspected and prepared for operation.

The kill line and flowline connections on the surface test tree are to be checked to ensure thatcompatible chiksan or other flexible connections are available. The fail-safe closed valve on thesurface test tree flowline is to be checked for proper operation. The surface test tree, the flowlinechiksans, and the floor choke manifold are to be checked for connection compatibility. The floorchoke manifold is to be rigged up with the proper size chokes for the initial flow. The data header isto be checked and the adapters, if required, for the various gauges and transducers are to be madeup.

Surface Equipment Pressure Testing

Make up the surface test tree and rig floor equipment. Ensure that the data header and allinstrumentation is functioning properly.

Note: Have an OEM (Original Equipment Manufacture) service representative on locationduring installation and pressure testing of all Christmas tree equipment. Place a permanentwarning sign on the valves which have the potential for internally trapped pressure"Warning: This valve has the potential to internally trap pressure".

PRODUCTION TESTING


Note: Whenever a back pressure valve (BPV) is to be removed from a tubing hanger, alubricator shall be installed and anchored. Prior to retrieving the plug, confirmation ofpressure equalization should be made if possible. If working on a well with H2S gas, allworkers in the area should mask up while retrieving the plug.

Pressure test the surface equipment to 200 psi and to the pressures specified in the ProductionTesting Program, using the cementing unit, as follows. The test pressure is to be held stable for atleast 5 minutes on the low pressure test and at least 5 minutes on the high pressure test.

12.9 INFORMATION RETRIEVAL

A primary purpose of the production test is to collect sufficient data for making an accuratereservoir description. To accomplish this objective, it is essential that the data gathering activity begiven high priority both in planning and during testing operations. This can best be accomplishedby ensuring that each individual involved in the test fully understands his responsibilities and theoperation of the equipment he is assigned to oversee.

Persons responsible for actually gathering data must know what data to gather and which data formis required for transcribing the data. During the pre-test meeting, the Drilling/Well Test Engineer isto assign the appropriate form to each of the individuals involved with data collection. Refer to theEMPC Exploration Well Testing Manual for a listing of suggested data requirements and forms.

The rate for data collection will vary according to the test period in progress and the state of the wellduring the period. In general, data entries should be made more frequently during periods whenwell conditions are changing rapidly with time (e.g., immediately following shut-in or flowinitiation) and less frequently during stable conditions. The primary goal is to ensure that data aresmooth and continuous when plotted against time. The actual frequency for collecting data will bespecified by the Drilling/Well Test Engineer, but for most test situations, the following guidelinesapply:

1. All Flow Periods: Readings should be recorded every 30 minutes during stabilized flow conditions and at an increased frequency during initial flow.

2. Final Shut-In Period: Record wellhead (surface) pressures and temperatures with the chartrecorder and pressure recorder as follows- ensure high frequency reading downhole for build-up analysis:

• Each minute for the first 10 minutes (or at an increased frequency, if appropriate).• Every 5 minutes for the next 20 minutes.• Every 15 minutes for the next hour.• Every 30 minutes for the duration of the shut-in period.

3. Subsurface Pressure Chart Reading:

At the conclusion of the final build-up period, the subsurface pressure gauges are to be recoveredand checked for mechanical malfunction and the pressure readings obtained.

PRODUCTION TESTING


Sample Gathering

Samples of gas, oil/condensate and water are to be collected during each production test forlaboratory analysis. Surface and/or bottom hole samples are to be obtained as described in the WellTesting Procedure.

A master sample list is to be maintained. This list should identify each sample and provideinformation necessary to track the sample at a later date. For example, it should identify the samplecontainer by the container serial number and contain all the data specified on the sample label. Thiswill allow the sample to be correctly identified with the sample bottle should the label be destroyed.

All pressurized samples are to be packed in the boxes sent out to the drilling rig specifically for thispurpose. Bottom hole samples may be required by Reservoir Engineering. When bottom holesamples are required, they will generally be taken directly opposite the perforations, if possible, andwith the well flowing through a small choke.

12.10 WELL KILLING AND ZONE ABANDONMENT

Well Killing

At the conclusion of the final build-up period, the well may be flowed at a high rate to heat up thewellbore for the purpose of avoiding formation of hydrates in the test string. Additional downholework, such as pulling the pressure gauges, obtaining bottom hole samples, or performing other finalactions as specified in the Well Testing Procedure, can then be completed and the well can be killed.The killing operation will vary with the specific well test string being used. However, thesignificant point is to ensure that a column of mud, with sufficient weight to ensure that an over-balance exists at the formation, is circulated throughout the wellbore.

12.11 EMERGENCY PROCEDURES

Refer to specific Emergency Procedures developed for rig operations.

12.12 HYDROGEN SULFIDE

Hydrogen sulfide (H2S) is a colorless gas which is both toxic and corrosive. The presence of H2Sin the production stream requires special procedures for conducting the well test and testingequipment that has metallurgical properties compatible with the H2S environment. Due to theextreme toxicity of H2S, self-contained breathing apparatus (SCBAs) must be available during thetest if H2S is expected. If the potential exists for H2S in the formation fluids, an H2S contingencyplan must be developed and implemented prior to initiating well test operations.

H2S Safety Procedures

The following safety procedures are to be observed on all well tests where H2S is known, expected,or contingent. Also refer to the well's H2S Contingency Plan.

1. Prior to beginning the well test, all personnel are to be briefed on the hazards of hydrogensulphide and certified (i.e. Fit Tested, and applicable certification). H2S drills are to beperformed with all personnel on the rig.

PRODUCTION TESTING


2. All surface and downhole equipment which may be exposed to H2S must be designed for usein H2S environments.

3. Every effort must be made to ventilate the rig floor and separator area before the well isopened.

4. Each individual who will be on the rig floor or working with the hydrocarbon processingequipment (separator, burners, etc.) is to have a self-contained breathing apparatus availablein the work area.

5. When the formation fluid surfaces, every effort is to be made to keep the burner(s) operating.

6. When the formation fluid surfaces, and at 15 minute intervals thereafter, the H2S detector willbe used to determine if any hydrogen sulfide is present in the produced fluids.

12.13 HYDRATES

Hydrate Formation

Hydrates are frozen or ice-like chemical compounds formed when certain light hydrocarbonscombine with water. Hydrate formation is associated with gas production and is a function oftemperature and pressure. Figure 12-3 is a hydrate formation conditions chart. The areas aboveeach curve represent the conditions of temperature and pressure under which hydrates can form ifsufficient water is present.

At low water concentrations and high flow rates, the formation of hydrates may not be sufficient tocause blockage of the flow stream. However, upon shutting in the well, hydrates may form ablockage and prevent further well flow.

Even minor hydrate formation can interfere with wireline/slickline operation for setting plugs orretrieving data. A hydrate mitigation plan should be in place if hydrate conditions are possible.

PRODUCTION TESTING


FIGURE 12-1

PRODUCTION TESTING


FIGURE 12-2

Production Casing

Perforations

Wireline Entry Guide

No-Go Landing Nipple

Spacer Tube

Perforated Joint

Production Tubing

Landing Nipple

Locator Seal AssemblyPermanent

Packer

Lower String Asssembly for Surface Shut-in (Permanent Packer)

PRODUCTION TESTING


FIGURE 12-3

PLUG AND ABANDOMENT

______________________________________________________________________________DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLINGFIRST EDETION MAY, 2003

13.0 PLUG AND ABANDONMENT

13.1 General 113.2 Permanent Plug and Abandonment 113.3 Temporary Plug and Abandonment 413.4 Site Clearance Verification 4

PLUG AND ABANDONMENT


13.1 GENERAL

Before performing any Permanent or Temporary Plug and Abandonment work, regulatory approvalmust be obtained from the applicable regulatory agency. The objective of the following generalguidelines is to plug and abandon wells in accordance with the governing regulatory agency andExxonMobil requirements; such that all hydrocarbon zones, abnormally pressured water zones, andfreshwater aquifers, are isolated to permanently prevent their contents from escaping into otherstrata or to the seafloor.

Procedures may be adjusted to fit specific hole conditions but should at least meet the minimumobjectives described in these guidelines (MMS or local regulatory body and ExxonMobilrequirements).

During permanent or temporary plug and abandonment operations, the following general guidelines,consistent with local regulations, shall apply:

1. Critical abandonment plugs which isolate hydrocarbon and injection zones from fresh wateraquifers should be verified by tagging and/or pressure testing. Coordinate any plugs that mustbe tagged with the applicable regulatory agency and EMPC.

2. During each phase of the plug and abandonment operation, a means of performing well controlis to be maintained. This is valid until casing with a non-sealed outer annulus (generally surfaceor conductor casing) is to be cut or perforated.

3. When casing is cut, pressure control is to be maintained by closing the annular preventer aroundthe drill pipe. This is valid until casing with a non-sealed outer annulus (generally surface orconductor casing) is to be cut. If communication from an open formation to the surface via theannulus is found, the flow is to be controlled with kill mud and the annulus squeeze cementedthrough the cut or perforations. The annulus is to be pressure tested after cementing to ensurethat it has been properly sealed.

4. When conducting plug and abandonment operations, all mud returns are to be analyzed by theMud Logging Unit/Mud Engineer in order to detect any formation fluid influx that might occur.

5. Consideration should be made to treat mud left between cement plugs inside the casing with acorrosion inhibitor and/or a bactericide.

6. During each phase of the plug and abandonment operation, the mud left in the hole above acement and/or a mechanical plug is to have a weight sufficient to withstand, together with theplugs, any pressure which may develop in the well.

13.2 PERMANENT PLUG AND ABANDONMENT

The following is a sequence for a permanent plug and abandonment operation in which all casingstrings and well bore annulus are permanently sealed. Well specific procedures may vary and willbe specified in the Plug and Abandonment Program:



1. Isolation of Zones in Open Hole

The following method of isolating open hole intervals is acceptable.

• In uncased portions of the hole, cement plug(s) shall be spaced to extend from 100' belowthe bottom to 100' above the top of the zone(s) to be isolated. Any porous or permeablezone containing hydrocarbons should be isolated. Typically cement volumes in open holeare based on gauge hole plus 10% excess.

• Other methods of abandonment may be more practical. The appropriate regulatory agencyand the operations superintendent must approve these alternate methods.

Note: The placement of a hi-vis pill below cement plugs can be beneficial inpreventing the plug from settling prior to setting up.

2. Isolation of Open Hole from Casing Shoe

The following methods of isolating open hole below casing are acceptable.

• Place a balanced cement plug across (100' above and 100' below) the casing shoe.

• Set a cement retainer in the casing, 50' - 100' above the shoe, squeeze 100' of cement belowthe shoe and place 50' of cement above the retainer.

• If lost returns have been experienced place a permanent type bridge plug <150' above theshoe and place 50' of cement above it.


3. Plugging or Isolating Perforated Intervals

The following methods of isolating perforated intervals are acceptable.

• The perforations may be squeezed.

• A balanced cement plug placed opposite all open perforations, extending 100' above to100' below the bottom of the perforated interval.

• Set a cement retainer 50' - 100' above the top of the perforated interval, squeeze cement to100' below the perforated interval and place 50' of cement above the retainer.

• A permanent type bridge-plug may be set <150' above the top of the perforated intervalwith 50' of cement placed above the bridge-plug.

• A cement plug that is at least 200' long may be set with the bottom of the cement plugwithin the first 100' above the top of the perforated interval.




4. Plugging of Casing Stubs

Cut and pull any casing strings required and isolate all annular spaces by placing a balancedcement plug, 100' above and below, the remaining stub or one of the following methods:

• A cement retainer or a permanent-type bridge plug is set 50' above the stub and 50' ofcement placed on top of it.

• A cement plug, which is at least 200' long, is set with the bottom of the plug within 100' ofthe casing stub.

• If the stub is below larger size casing plugging shall be accomplished as required to isolatezones or open hole as described above.

5. Plugging of Annular Space

Any annular space that communicates with open hole and extending to the mud line will beplugged with at least 200' of cement.

6. Surface Plug

• Set a balanced cement plug at least 150' in length with the top of the plug within 150' belowthe mud line. The plug will be placed in the smallest string of casing that extends to themud line.

7. Testing of Plugs

The condition and location of certain cement plugs shall be verified by one of the followingmethods:

• By tagging the cement plug, cement retainer, or bridge plug with 15 kips while circulatingagainst the plug. Cement placed above a bridge plug or retainer need not be tested.

• By pressure testing the plug with a minimum pump pressure of 1000 psi with no more than a 10% pressure drop in a 15-minute period (MMS). ExxonMobil at least 500 psi in excessof the formation breakdown pressure or within the working limits of the weakest exposedcasing string whichever is less.

Minimum Verification of Abandonment Plugs

• The first plug below the surface plug will be verified by one of the above methods(MMS).



8. Clearance of Location

All wellheads, casing, pilings, and other obstructions shall be removed to a depth of 15' belowthe mud line or to a total depth approved by the applicable regulatory agency.

13.3 TEMPORARY PLUG AND ABANDONMENT

A temporary abandonment differs from a permanent abandonment in that all casing strings andwellhead seals remain intact.

During temporary plug and abandonment operations, the following general guidelines shall apply:

1. No holes may be punched in the casing except as required for production testing. Perforationsare to be properly plugged and isolated.

2. The wellhead seal area is to be protected by installing a corrosion cap or an abandonment tree.For long abandonment periods, the well may be additionally protected by displacing the mud inthe seal area with inhibiting fluid.

3. The well is to be equipped with a location marker and identification.

4. Inspection of the wellhead and protective structure is to be carried out at least once per year.

5. A bridge plug or a 100' long cement plug is to be set at the base of the deepest casing stringunless the casing has not been drilled out.

6. A retrievable or permanent-type bridge plug or cement plug at least 100' in length, shall be setin the casing within the first 200' below the mudline.

7. Exceptions to these guidelines must be approved by the applicable regulatory agency, theoperations superintendent and EMPC.

13.4 SITE CLEARANCE VERIFICATION

Final site clearance after abandonment must be approved by the regulatory agency. Typically one ofthe following methods will be acceptable:

1. Drag a trawl in two directions across the location.

2. Perform a diver search around the wellbore.

3. Scan across the location with a side-scan or on-bottom scanning sonar.

WELL CONTROL

______________________________________________________________________________________DRILLING OPERATIONS MANUAL- JACK-UP/PLATFORM/BARAGE RIG DRILLINGFIRST EDITION MAY, 2003

14.0 WELL CONTROL

14.1 Well Control – General 114.2 Hole Monitoring 514.3 Equipment Testing 814.4 Equipment Specifications 1014.5 Well Control Drills 1614.6 Well Control Procedures 19

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14.1 WELL CONTROL - GENERAL

Well Control operations are performed to mitigate well control incidents by minimizing the severityof the influx, properly shutting-in the well as soon as practical, and surfacing the influx in a safemanner or pumping/bullheading the influx back into the formation (when bringing the influx to thesurface may be too hazardous, like with H2S). Uncontrolled flows into the wellbore must always bekept below the blowout preventer stack.

Safety of all personnel on the rig is the primary consideration when conducting well controloperations. Integrity of the drilling unit and adverse economic impacts are of secondaryimportance.

General step-by-step procedures may vary depending on the BOP configuration on each individualdrilling unit. The Drilling Contractor's specific shut-in procedures for each drilling unit are to bereviewed to determine if they are acceptable for EMDC's operations. For all locations, a sitespecific well control plan is to be in place which includes diverter and well control proceduresspecific to the drilling unit and BOP stack configuration.

General Well Control Guidelines

General well control guidelines are as follows:

1. All well control equipment will be maintained in a ready state while conducting drillingoperations.

2. Conduct drills in accordance with "Well Control Drills" section of this manual.

3. Test well control equipment (i.e., pressure and function test) as specified in "Well ControlEquipment Testing" section of this manual.

4. A current status board of critical drilling parameters will be maintained at the Driller's consolein plain view. Information on this board should consist of the following:

• Tool joint distance above the rig floor for closing the hang-off rams• Most recent BOP test date• BOP stack dimensions of the preventer spacing from the wellhead• BOP stack dimensions of the preventer spacing below the rotary table (as tool joint space

out is typically measured from the rotary table)

5. Laminated copies of rig specific shut-in procedures shall be posted on the rig floor near theDriller's console. Rig specific station bills, listing duties of the crew members, will also beposted on the rig floor and/or bulletin board.

6. Lost Circulation Procedures will be posted on the rig floor.

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7. The Driller will be instructed to shut-in the well using his judgment and indicators such as pitgain, flow after stopping the pumps, or improper fill-up on trips. The Driller does not have tosecure permission from the Operations Supervisor prior to shutting-in the well.

8. The drill string will always include a float valve above the bit and, after setting sufficientcasing to shut in the well, the float valve will be ported, unless a solid float is approved by theOperations Superintendent. Field modification of drill pipe floats is not allowed.

9. At all times, a full opening, ball type, pressure balanced safety valve (TIW or equivalent) fordrill pipe and an inside BOP, with crossover subs for drill collars and casing, will be on the rigfloor and ready for immediate use (i.e., open). These will be available for all drillstring sizesin use. The safety valve(s) must be function tested and the test must be documented on theIADC report and DMR. The safety valve will always be picked up first. A safety valve willbe installed in the string during periods of downtime, such as slipping and cutting drill line,etc.

NOTE: API Spec. 7 (November 2001 edition) has divided safety valves into two classes.Class I valves (standard valves) are rated to working pressure from below only and may notseal from either direction if pressure is applied from above. Class I valves are not APIpressure rated externally and may leak through the stem. Class II valves are designed for ratedworking pressure from below and above the ball and externally to 2000 psi minimum. If thereis a probability that stripping operations will be required, Class II should be utilized at therigsite. Section 8 in the "ExxonMobil Drilling Surface Blowout Prevention and Well ControlEquipment Manual" provides a listing of manufacturers known to be capable of supplyingproven Class II safety valves.

10. Circulate choke and kill lines to ensure lines are clear (frequency will depend on drillingfluid).

11. The choke will be in the open position with the first valve downstream of the choke in theclosed position as well.

12. Maintain a "Well Kill Worksheet" for the current wellbore configuration and update theworksheet (or KIK PC program) at least daily while drilling is in progress, or as holeconditions change.

13. Keep the inner choke and kill valves on the BOP in the closed position while drilling. Keepthe outer choke and kill valves in the open position.

14. Have the choke manifold lined up to take returns to the poor-boy degasser.

15. Have the PVT and FLO-SHO alarms set to the lowest practical limits.

16. Rig up an annulus fill-up line from the rig pumps for quick fill up of the annulus.

17. Use the annular to initially shut-in the wellbore. The on-site Operations Supervisor willdetermine if hanging-off the drill string is necessary based on existing operating conditions.

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18. If an annular is used to circulate out the influx, the closing pressure may be backed off per themanufacturer's recommendations to reduce wear on the element. Sufficient operating pressurewill be maintained to prevent leakage and avoid gas escaping to the rig floor. Closingpressure can be reduced to allow limited pipe movement to avoid sticking the drillstring whilecirculating out an influx. However, tool joints should not be cycled through the annularelement while circulating out an influx.

19. Shut the diverter annular only after opening the diverter line valve(s) to prevent broaching.Assign personnel to monitor for broaching if diverting the well with only shallow casing set.The diverter lines are to be routed overboard and downwind.

20. Utilize mud pumps and/or fire hoses to wet gas exiting from diverter lines.

21. Wind socks should be visible from pertinent areas of the rig.

Pressure Recording Guidelines

Pressure recording guidelines are as follows:

1. Record the shut-in pressures on the drill pipe and casing every minute until shut-in pressuresstabilize. After stabilization, record the shut-in pressure on the drill pipe and casing every 10minutes until well control operations end.

2. Record the pressure necessary to pump open the float valve as the stabilized drill pipepressure when using a non-ported float valve in the drill pipe.

Note: The method to determine when the float valve is opening is the same as determining the break-over limit during a pressure integrity test.

3. Designate specific personnel to record pressures and observations/remarks though out the wellcontrol operation.

4. Shut down the pumps and shut-in the well to check pressures if a problem arises whilecirculating out an influx into the wellbore.

5. Determine a new friction pressure if using a different pump rate when restarting circulationafter shutting in to check pressures.

6. Determine the new friction pressure in the same manner as the original friction pressure.

Note: The maximum pressure at any point in the wellbore during the killing operation willoccur when the top of the influx is at that point or when the influx is on bottom in thecase of short open hole intervals or long bottom hole assemblies and the top of thebubble is above the casing shoe. This is especially true in deep wells.

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Pump Rate Guidelines

1. Ensure that the selection of the circulation rate considers such factors as: a) formationintegrity at the casing shoe, b) rig well control equipment, c) capacity of barite additions to themud system, and d) rig pump oiling limitations at slower rates.

2. Consider the following advantages of a low pump rate. A typical pump rate is in the 1 to 3BPM range:•••• Low pump rates allow the choke operator more time to adjust the choke.•••• Low pump rates minimizes the handling of large gas volumes at the surface•••• Low pump rates reduces the possibility of lost returns.

3. Understand the limitations of the mud gas separator when 100% gas reaches the surface. Beprepared to bypass the mud gas separator and go directly to the flare if the liquid leg is lost.

Well Killing Worksheet

A Well Killing Worksheet is critical to a successful well control operation since it helps Operationsand Engineering personnel communicate clearly during the operation and perform the necessarycalculations.

After the BOP stack is installed, a "Well Killing Worksheet" will be prepared. The worksheet willbe maintained for the current wellbore configuration and update the worksheet at least daily whiledrilling is in progress, or as hole conditions change.

Note: The KIK PC computer program may be used in lieu of the worksheet.

Steps for completion of the "Well Killing Worksheet" are as follows:

1. Calculate the kill mud weight.

• Record the original weight of the drilling fluid.

• Calculate the necessary increases in drilling fluid weight to balance the formation pressure and to provide an overbalance.

• Calculate the kill weight of the drilling fluid.

2. Calculate the maximum allowable surface pressure:

• Record the PIT at the last casing shoe.

• Calculate the maximum surface pressure which will fracture the formation.

• Record the casing burst pressure and safety factor.

• Calculate the allowable surface pressure for each weight and grade of casing.

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• Select the lower of the two calculated values as the maximum allowable surface pressure (to be used for information only).

3. Calculate capacities and total active system volume.

4. Calculate the barite required to weight up the active system and the corresponding volumeincrease.

5. Calculate the circulation rate and the pressure change schedule:

• Enter the circulation rate and initial drill pipe circulating pressure.

• Calculate the change in circulating pressure that will occur due to a heavier fluid weight.

6. Select the circulation method and prepare the drilling fluid weight schedule. If practical,consult with the Operations Superintendent as to which of the following methods to use basedon well pressures involved, pressure integrity of the casing shoe, rig gas handling capability,mud system capabilities, and mud material on location.

• Driller's Method (original mud weight)

• Weight and Wait Method (balance mud weight or kill weight mud)

7. Perform influx height and gradient calculations:

• If the influx gradient is less than 0.2 psi/ft, the influx is probably gas. If the gradient is between 0.2 psi/ft and 0.4 psi/ft, the influx is probably oil. If the gradient is greater than 0.4 psi/ft, the influx is probably salt water.

14.2 HOLE MONITORING

Hole Fill-Up

Hole Fill-Up Guidelines:

When tripping out of the hole, into the hole, or when the drill string is out of the hole (i.e., logging,BHA change out, slip and cutting drill line, etc.) the hole will be continuously monitored for gainsor losses using the trip tank. The following guidelines should be followed to ensure a full columnof mud is maintained in the annulus at all times.

1. The hole will be kept full using the trip tank when not pumping down the drill string. The triptank level will be recorded a minimum of every 15 minutes when pipe is out of the hole. Atrip book will be maintained for each well and at least one person is to be assigned to monitorthe trip tank on a continuous basis while tripping. The trip book log should compare tripsvolumes to both the theoretical volume and the previous trip volumes

WELL CONTROL


2. If the rig is equipped with a top drive system, back-reaming and pumping out the first 10stands of open hole when tripping should be considered. This is especially relevant whiledrilling directional wells or wells with highly reactive formations.

3. The bit will be returned to bottom and the well circulated bottoms-up if observed fill-upvolume is less than calculated or significantly less than fill-up recorded on the previous trip.If the hole does not take the calculated amount of fluid, the Operations Supervisor will beadvised immediately.

• Pit levels will be monitored carefully when circulating bottoms-up to detect any expansion of gas and/or well flow during the circulating operations.

4. Sufficient mud weight will be used that provides at least 200 psi of overbalance beforeattempting to pull or pump out of the hole.

5. A trip tank with a minimum capacity of 40 bbls is preferred. The trip tank will be marked inat least 1/2 barrel increments.

6. A grease type packing is to be used on the centrifugal pump that feeds the trip tank. Waterinjection will not be used.

7. The mud loggers should also closely monitor trip tank volumes while tripping out of the holeand confirm the displacement volumes recorded by the drilling contractor. They should alsomonitor volumes while tripping in the hole if requested by the Operations Supervisor or if it isspecified in the Drilling Program.

8. The maximum amount of drill pipe than can be run in the hole without being filled must bespecified in the Drilling Program and will be based on that particular well plan (casing depths,amount of open hole, potential gas sand location, etc.) Section 4 describes a method tocalculate the maximum length of pipe that can be run without filling the drillstring.

9. When tripping in the hole displacement volumes from the well must be accurately monitoredusing the trip tank. The FDM can provide an exception to using the trip tank when tripping inhole.

Note: Field modification of drill pipe floats is not allowed. There are no exceptions to thispolicy.

Trip Book Guidelines:

Entries in the trip book for trip-to-trip comparison shall be made as follows:

1. The displacement volume for each stand for the first five (5) stands of drill pipe and every five(5) stands of drill pipe thereafter.

2. The displacement volume for every stand of drill collars and HeviWate drill pipe.

3. Entries shall to be made based on the volume accuracy of the trip tank gauge (1/2 bbl or less).

WELL CONTROL


Flow Check Guidelines

Flow checks and 10-10-10's are to be used as the primary indicators of an under balanced situation.Guidelines for conducting flow checks are as follows:

1. The well will be flow checked before making a connection.

2. The well will be flow checked after an indication of a pit gain.

3. The well will be flow checked after an indication of abnormal pressure.

4. The well will be flow checked after a drilling break over 5' on an exploration well or after adrilling break over 5' on a development well if expecting abnormal pressure or hydrocarbonsin the zone.

• A drilling break is generally defined as a doubling of the rate of penetration (ROP), butcan vary depending upon the area.

5. Flow checks will be planned at intervals less than 100' when drilling with a top drive systemin an abnormal pressure zone.

6. It should be stressed to the driller that the Company will support the driller's judgment whenmaking additional flow checks (not included in these guidelines) or when shutting-in the welldue to flow.

Degasser Guidelines

1. The degasser will be operated whenever there is significant gas in the return flow stream, asindicated by a mud weight cut or chromatograph instruments readings in the logging unit.

2. The drilling fluid weight will be checked downstream of the degasser, as well as at the shaker,in order to determine if the degasser is working properly.

3. Dump the degasser suction and discharge tanks as often as practical to maximize utilization.

14.3 EQUIPMENT TESTING

Pressure Tests

The BOPs, choke and kill lines, choke manifold, floor safety valves, inside BOPs, and the top drivesystem/kelly safety valves are to be pressure tested in accordance with the following requirements:

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BOP Pressure Tests

ACTIVITY BOP TESTING REQUIREMENTS

1) Initial BOP acceptance test (when therig comes under contract)

Test with water to 200 psi low and ratedworking pressure of preventer/equipment

2) Initial Installation on Wellhead if NOTfully tested to rated working pressure asper 1) above.

Test with water to 200 psi low and ratedWP of preventer/equipment or thewellhead, whichever is less. At leastonce per well the rams must be tested totheir rated WP when the appropriatewellhead is installed.

3) Initial installation on wellhead if fullytested to rated WP as per 1) above.

Test with water to 200 psi low. Test annular to70% of rated working pressure or rated workingpressure of wellhead, whichever is less.

For 5k psi rams or lower, test rams/equipment torated working pressure. For 10k psi rams orhigher, test rams/equipment to a pressure thatexceeds the maximum anticipated surfacepressure but not less than 5k psi. At least onceper well the rams must be tested to their ratedworking pressure when the appropriate wellheadis installed.

Note: On wells governed by MMS rules, allrams/equipment must be tested to their ratedworking pressure or rated working pressure ofwellhead, whichever is less (unless approvedotherwise by District Supervisor).

4) After setting casing string AND prior todrilling out casing shoes.

Same as 3) above.

5) Subsequent tests not exceeding every 14days.

Same as 3) above. On workovers governed byMMS rules, then test frequency is every 7 daysinstead of 14.

6) After disconnection or repair of anypressure containing seal but limited to theaffected component.

Test with water to 200 psi and rated workingpressure of preventer/equipment or wellhead,whichever is less.

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Notes:

1. Regulatory requirements may require variations from the above and will govern, if morestringent.

2. Pressure tests will be alternated between control stations. After pressure testing from onecontrol station, conduct a complete function test of the BOP at another other station.

3. The test pressures will be in accordance with the above or those specified in the DrillingProgram. The pressures will be held stable for at minimum of 5 minutes on both the lowpressure test and on the high pressure test or as specified in the Drilling Program.

4. The BOP equipment will be pressure tested when initially installed and at least every 14 daysthereafter, as required by OIMS. The high pressure side of the choke manifold is to bepressure tested to the required BOP ram test pressure. The low pressure side of the chokemanifold will be tested to its rated WP (OIMS Manual Section 6).

The results of all BOP tests and any deficiencies and/or repairs will be recorded on the DailyDrilling Report and IADC Report. Detailed test data will also be recorded by the drilling contractoron a BOP test form designed specifically for the drilling rig. This report should be reviewed by theOperations Supervisor to ensure they are satisfied that sufficient data will be recorded to ensureconfidence in the proper operation of the BOP equipment.

The completed BOP test form is to be signed by the OIM and the Cementer and will be provided tothe Operations Supervisor, along with the pressure recording chart supporting the BOP testingoperation. All pressure charts are to be dated and properly labeled as to each component tested. Allrecords pertaining to the BOP tests are to be retained on the drilling rig until completion of the well.The records are then to be forwarded to the Operations Superintendent for inclusion in the well fileupon request.

Function Tests

The diverter system is to be function tested daily and the BOP system is to be function testedweekly. When conducting these tests, all closing and opening times required to function eachcomponent are to be recorded for comparison with previous tests. Do not pull out of the hole just tofunction test the BOPs.

Diverter Tests

Guidelines for testing diverters are as follows:

1. Response times required to open diverter valves and close the diverter bag around the drillpipe will be recorded and reported on the BOP test form.

2. After initial installation, all diverter lines will be pumped through at the maximum ratepossible, to detect leaks, verify correct line up, and inspect for excessive vibration.

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14.4 EQUIPMENT

Equipment specifications for well control equipment are provided below. Deviations for less thanthe guidelines shown should be based on a risk assessment and should have both EMDC andDrilling Contractor management approval.

Diverter Systems

A "Diverter System" will be installed on all casing strings prior to the surface casing.

The diverter system should conform to the following specifications:

Diverter Design:

1. The diverter system shall consist of:

•••• Annular type diverter packer

•••• Diverter lines (2 lines, 10" ID min, 300 psi WP)

• Remote Actuated Ball Valve on each line

• Diverter valve 10" ID in the diverter line

• Kill line inlet below the diverter (3" nominal)

• Valve in the kill line

2. All diverter components (valves, lines, etc.) will be rated for a minimum of 300 psi workingpressure. Valve actuators shall be sized to shut in against a minimum of 300 psi.

3. All diverter Valves shall be full opening (ball valves preferred).

Diverter Closing System

1. Actuation of the diverter must be available from the rig floor and at least one other remotelocation away from the rig floor. All diverter functions must be available from these locations.

2. If hydro-pneumatic regulators are used, a nitrogen back-up is required.

3. Diverter Hydraulic Control unit must provide 1.5 times the usable fluid necessary to open thediverter valves and close the diverter annular and be capable of being operated from the maincontrol panel and remotely from the Driller's console.

BOP System

A BOP stack and closing system shall be installed for all drilling and completion operations withannular and rams capable of shutting in on all drill pipe sizes in use for that hole section inaccordance with the following specifications:

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Note: If Hydrogen Sulfide gas is expected, all BOP components and element seals must becertified for H2S service.

BOP Stack

1. The BOP stack should be arranged as specified in the Surface Blowout Prevention and WellControl Equipment Manual.

2. BOP elements shall be compatible with the mud type in use.

3. Two rams are to be sized for the larger drill pipe and one ram for the smaller drill pipe if a twopipe size and/or tapered strings are used. Variable bore rams can be used to meet this criteria.The bottom ram shall be sized for the larger pipe size. VBRs cannot be used for the masterram. See Section 4.0 of the Surface Blowout Prevention and Well Control Equipment Manualfor details and additional scenarios.

4. All rams, choke/kill lines, and choke/kill valves shall have a working pressure ratingequivalent or greater than the wellhead working pressure rating. Annular shall have workingpressure ratings of at least 50 percent of the ram preventers.

5. Ram and Choke/Kill line outlet placement shall provide the capability to:

• Close in on the drill string and on casing or liner and allow circulation.

• Close and seal on open hole and allow volumetric well control operations.

• Strip the drill string using annular preventer.

• Bullhead below the blind rams.

6. Choke outlets are to be minimum of 3" ID.

7. Use of clamps would require exception approval from the Field Drilling Manager.

8. Side outlets on ram bodies must be sealed with a blind flange (valves are acceptable only ifthey are pressure tested at the same frequency as the rams).

9. Rams must have locking capability (if locks are manual, a crank with a wheel must beavailable on the rig).

10. Rams must be capable of hanging off the maximum anticipated drill string load with the tooljoints in use and maintain a seal against wellbore pressure equivalent to the ram body workingpressure rating. VBRs are not recommended as the hang-off rams. If VBRs are to be used asthe hangoff rams, the manufacturer's specifications will be checked for pipe size and hang-offload rating. Only "hang-off" type ram blocks, with a hardened area around the lip of the ramblock, should be used.

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11. Drilling spools must have at least the ID clearance and working pressure rating as that of theram bodies.

Choke and Kill Lines

The Choke and Kill Lines shall be equipped with and have a working pressure rated at leastequivalent to the BOP ram preventer rating. Other specifications as follows:

1. One hydraulic valve (e.g., fail-safe close) on the choke line adjacent to the BOP drilling spool.

2. One manual valve on the choke line between the hydraulic valve and the choke manifold.

3. One hydraulic valve and one manual valve on the kill line between the standpipe or pumpmanifold and the BOP drilling spool.

4. Choke lines shall have a minimum ID of 3". Kill lines shall have a minimum ID of 2".

Wellhead

1. The "A" section shall have double valves on one outlet with working pressure at leastequivalent to the "A" section top flange.

2. All wellhead sections shall have a flanged valve with a rated working pressure at leastequivalent to the section top flange.

3. A second valve of the same working pressure shall be installed on any wellhead sectionswhere the casing string suspended by the section is not cemented to the surface.

Wellhead

4. All sections above the "A" section shall be equipped with a second outlet that has a blindflange installed on the outlet.

5. A pressure gauge shall be installed on all wellhead sections outside of the valves to facilitatemonitoring of casing annulus pressure.

BOP Control System

BOPs shall be controlled by a Control System meeting the criteria listed below and must meet thefollowing objectives:

• Provide redundant control system.

• Provide emergency back-ups in case of loss of rig air and/or electrical power.

• Allow independent adjustable operating pressures to annular and other BOP functions.

• Close each Ram Preventer within 30 seconds.

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• Close each Annular Preventer < 18-3/4" within 30 seconds and within 45 seconds forpreventers � 18-3/4".

Surface Accumulator Bottles

1. A sufficient number of accumulator bottles will be installed, at a minimum, to meet EMDC'stechnical specifications, API RP 16D (Part I & II), and/or local requirements for accumulatorunit sizing. See Section 5.0 of the Surface Blowout Prevention and Well Control EquipmentManual for details on EMDC requirements.

NOTE: “API RP 16E as referenced in the BOP manual has since been recalled. The correctAPI reference for accumulator design is now API Spec 16D”.

2. The precharge pressure for all accumulator bottles will be verified upon mobilization of thedrilling unit and approximately every 60 days thereafter.

3. Accumulator bottles shall be divided into at least two or more separate banks of generally thesame number of bottles and each bank shall be capable of being separated by isolation valves.

Accumulator Control Unit

1. Back-up pumps, driven by a different power source than the primary pumps (air driven whenprimary are electric drive) will be installed.

2. Each pump is to be capable of being isolated for repairs while the others remain operational.

3. The hydraulic fluid reservoir will be of adequate size to hold twice the required useable fluidcapacity of the accumulator bottles.

4. Hydraulic fluid will be strained through 20 mesh or smaller suction strainers.

5. A double needle valve will be installed to bleed off manifold and accumulators into thereserve tank (needed to perform mini-checks).

6. The charging manifold will have a full opening, valved outlet for an external pump.

7. The manifold will be equipped with a pressure reducing regulator (0 to maximum allowablepressure) plus bypass and isolation valves.

8. Pressure relief valves will be installed upstream and downstream of the manifold regulator.

9. The entire system should be in an area which is readily accessible to rig personnel andprotected from damage from other rig sources.

10. Check for type of alarm system installed. See required alarms below.

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Regulators

1. The control system will have surface regulators for manifold pressure.

2. A pneumatic back-up supply, independent of the rig air system, will be available for thesurface regulators, unless the regulators are of the worm gear type or equivalent, to avoidlosing supply pressure in the event of rig air failure.

3. The annular and manifold regulators will be set to a minimum of 1500 psi for normal shut-in.Refer to the manufacturers operating manual for information on additional closing pressurerequirements for high expected shut-in pressures and annular pressures for larger sizes of pipeand casing.

BOP Operating Panels

1. Two operating panels will be available, containing all BOP functions, one of which will belocated at the accumulator control unit and the other on the drill floor.

2. All functions shall be kept in the power position and not in the block position.

• Blind Ram function is to have a safety guard installed at all panels and at the accumulatorunit control station to prevent inadvertent operation. The guard at the accumulator unit isnot to interfere with remote operating capabilities.

3. If an electrical relay system is used, emergency generator power or a battery back-up systemwill be available to operate the remote panels for the accumulator unit.

4. If rig air is used, a back-up air supply will be available to operate the remote panels.

5. All functions on all operating panels will be clearly marked as to their purpose and position.

6. Unless a common alarm can be heard in both areas, the drill floor panel and the accumulatorcontrol unit will have alarms for:

•••• Low accumulator pressure

•••• Low fluid level in reservoir tanks

•••• Loss of air supply

Choke & Kill Manifold

The choke and kill lines will be tied into a choke manifold and should conform to the followingspecifications:

1. The choke manifold will have the capability of taking returns through one of at least two (2)adjustable chokes of which one must be a hydraulic choke.

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2. A minimum of two (2) valves will be upstream of each choke and one (1) valve between anyother outlets on the manifold such as the standpipe manifold, trip tank bleed line, and thecement unit.

3. Chokes and gauges are to be equipped with and provide the following:

• A manual back-up method of some type (e.g., back-up bottle of nitrogen, manual pump,etc.) will be available to power the hydraulic choke in case of rig air failure.

• A control panel for the hydraulic choke(s) that has gauges to read the drill pipe pressureand casing pressure immediately upstream from the choke in operation. If the controlpanel has dual chokes, a casing pressure gauge will be available to monitor pressureupstream of each choke.

• A choke panel which contains a gauge indicating choke position, gauges to read pumprate and cumulative pump strokes, and a control to zero the cumulative pump strokecounter.

• A selection of calibrated gauges of various ranges that can help determine shut-in drillpipe and casing pressure accurately.

4. Adequate pressure sensors will be installed on the choke manifold and standpipe manifold tomonitor the annulus and drill pipe pressure from all choke locations.

5. The pressure rating of all components (flexible hoses, valves, lines, pressure sensors, etc.)between the BOP and the high pressure valve downstream of the choke will have a workingpressure rating equivalent to or exceeding the BOP ram preventer rating.

6. All turns in the choke and kill lines from the BOP to the choke manifold, within the choke andkill manifold, and lines downstream of the choke manifold will have targeted tees installed.

7. Manifold outlets will be configured such that well control fluids can be directed from thechoke manifold to the following areas:

• Mud Gas Separator

• Shakers

• Trip Tank

• Directly overboard or to reserve pit bypassing the Mud Gas Separator

Mud Gas Separator

A mud gas separator will be installed and should conform to the following specifications:

1. Capable of venting gas to a downwind safe area and salvaging the drilling fluid whencirculating through the choke manifold during a well control operation.

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2. Provide a sufficient head to force gas out the vent line as well as separate gas from the drillingfluid.

• See Surface Blowout Prevention and Well Control Equipment Manual (page 8-19 and 8-20 for details).

3. Vent line from the mud gas separator will have a minimum diameter of 8" and contain aminimum number of turns to reduce the gas friction pressure.

4. An inspection port will be available on the mud gas separator for visual inspection of theseparator. During mobilization and after each use for well control, the separator should bedrained, washed and visually inspected.

5. A by-pass valve will be installed which vents gas out a direct vent line and isolates the shaleshaker room when the liquid leg is lost at the mud gas separator. The location of the by-passvalve should be upstream of the mud gas separator line to the shakers.

14.5 WELL CONTROL DRILLS

General BOP Drill Guidelines

Well control drills shall be conducted in accordance with the guidelines in this section to ensure thatdrilling personnel can detect and shut-in the well in the shortest time possible.

Blowout preventer drills will be conducted until the procedure for shutting-in the well both whiledrilling and tripping is automatic. The drill crew members must detect a simulated well flow andreact in the proper manner within the time limit required. A schematic of the BOP will be posted onthe drill floor showing distances from RKB to the various BOP components. The Driller mustknow at all times the position of the drill string tool joint in relation to the BOP stack.

The well will initially be closed-in using the Annular Preventer. To allow for a "fast shut-in", thefirst valve downstream of the hydraulic choke should be in the open position with the choke closedas well.

Drills should be announced or unannounced to the drill crew and simulated by changing pit levels,trip tank levels, etc. However, the drilling contractor toolpusher on duty should be made aware ofthe drill prior to changing pit levels to avoid overreaction by the drill crews he is supervising.

Trip Drill

The purpose of this drill is to reduce the time required for the Driller to detect and react to an influxwhile making a trip. After the BOP is installed, this drill must be held with each crew until they arethoroughly familiar with the procedure and thereafter with each crew at a frequency specified byOIMS.

While tripping and after the drill string has been pulled into the casing, without prior notice, theapparent trip tank level is to be gradually increased by manually raising the mud pit level float orverbally notifying the Driller from the Trip Tank Hand or the Mud Logging unit (if being used) that

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an increase in trip tank level has occurred. The Driller, Drill Crew, and Mud Loggers shouldrecognize a 10 bbl trip tank gain within 1 minute and shut in the well within an additional 1minute by performing the following:

1. Detect the kick and sound the alarm.

2. Record the time to detect the trip tank gain (goal is 1 minute or less).

3. Set the slips with a tool joint at the rotary table.

4. Shut down the trip tank pump and check for flow back into the trip tank.

5. Make up (hand tight) an open safety valve on the drill pipe. Close valve.

6. Check the well for flow.

7. Shut-in the well by opening the HCV valve and closing the anular BOP in one motion, torque-up safety valve. Make sure the choke manifold valve downstream of the power choke isclosed.

8. Immediately notify ExxonMobil Drilling Supervisor and Toolpusher. Record the time to shut-in the well after flow is detected (goal is 1 minute or less to minimize influx volume).

9. Install and make-up Inside BOP. Close the nside BOP. Open Safety Valve. (For strippingoperations).

10. Record casing pressure and gain in trip tank. Check accumulator pressures. Check BOPsystem components and choke manifold for correct position. Check for leaks and/or flow.

11. Prepare to extinguish sources of ignition. Alert any boat standing by at the drilling rig.

12. Have crane operator standby for possible personnel evacuation.

13. Assess and review proficiency of drill with crew members. Log drill and reaction time on theDaily Drilling Report and IADC Report.

Note: A typical drill would stop at Step #10, although the documentation under Step #13would still be performed. Steps #11 - #12 may be performed for additional trainingand extended drills.

Pit Drill

The purpose of this drill is to reduce the time required for the Driller to detect and react to a changein the pit level. After the BOP is installed, this drill will be held with each crew until they arethoroughly familiar with the procedure and thereafter with each crew at a frequency specified byOIMS.

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While drilling on bottom, without prior notice, the apparent pit level is to be gradually increased bymanually raising the mud pit level float or by pumping mud from the trip tank to the active system.The Driller, Drill Crew, and Mud Loggers should recognize a 10 bbl pit gain within 1 minute andshut in the well within an additional 1 minute by performing the following:

1. Detect the kick and sound the alarm.

2. Record the time to detect the pit level gain (goal is 1 minute or less).

3. Pick up the drill string until tool joint clears rotary table. Make sure tool joint is not in BOP.

4. Shut down the mud pump(s) and check the well for flow. (Use trip tank if in doubt about thewell flowing).

5. If flowing, shut in the well by opening the BOP choke line valve (HCV) and closing theannular.

6. Report the pit gain and flow check results to the Operations Supervisor and Toolpusher.

7. Record drill pipe and casing pressures. Weigh mud in suction pit. Check accumulatorpressures. Check BOP system components and choke manifold for correct position. Checkfor leaks and/or flow.

8. Complete the Well Killing Worksheet. Determine materials needed to circulate out the kick.

9. Prepare to extinguish sources of ignition. Alert any boat standing by at the drilling unit and/orhave security block off the area if on a land rig.

11. Have crane operator standby for possible personnel evacuation if on a jack-up.

12. Assess and review proficiency of drill with crew members. Log drill and reaction time on theDaily Drilling Report and IADC Report.

Note: A typical drill would stop at Step #6, although the documentation under Step #12would still be performed. Steps #7 – #11 may be performed for additional trainingand extended drills.

Power Choke Drill

Crews are encouraged to conduct power choke drills prior to drilling-out after setting of each casingstring. The drill provides practice for the Drilling Supervisor, Toolpusher, and crew members inoperating the power choke. If done from a floating rig, it is an opportune time to measure the chokeline and kill line friction pressures at various kill rates. The drill should be performed as follows:

1. Circulate the well clean.

2. Conduct a Pit Drill and close in the well using the Annular BOP.

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3. Take slow circulation rates at 20, 30, and 40 spm down the drill pipe and out the choke linewith the hydraulic power choke fully open (optional step if already accomplished).

4. Conduct crew training using the power choke. Bring the pump on lie while keeping the casingpressure constant to desired pump speed. The casing pressure can be varied to illustrate thetime required for the pressure pulse to travel down the annulus and back up the drill pipepressure gauge.

5. Assess drill and use of hydraulic choke with crew members.

6. Record the drill, slow pump rates/pressures, and mud weights used on the IADC and DailyDrilling Report.

14.6 WELL CONTROL PROCEDURES

Laminated copies of rig specific shut-in procedures shall be posted on the rig floor near theDriller's console. Rig specific station bills, listing duties of the crew members, will also beposted on the drill floor and/or bulletin board.

During all well control operations, the following rules will be strictly observed.

1. Smoking will be limited to the quarters area. Violators will be subject to immediate dismissal.

2. Welders will not perform any work without specific instruction and direct supervision by theSenior Drilling Contractor toolpusher and such work must be cleared with the OperationsSupervisor in advance.

3. All grinders, needle guns, etc., will be shut down.

4. Off-duty and personnel that are not required will remain in the quarters area or at a designatedmuster area.

5. If any of the following occur, the rig site is to be immediately abandoned:

• Gas surfaces uncontrolled at the rig floor

• Well fluids broach around the casing

• Well flow is detected with no diverter or no BOP installed.

6. A pre-job safety meeting will be held with all involved personnel prior to attempting a wellkill operation.

Diverter Installed

Successfully diverting a well flow before gas surfaces and without broaching requires that allsurface equipment be ready to close the diverter bag immediately yet have a relief path for the wellfluids to prevent broaching.

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While drilling with a Diverter System using a Remote Operated Ball Valve, the valve open functionshould be plumbed into the diverter close line such that the valve will open prior to the annularclosing.

Mud should be pumped through the diverter lines every tour to ensure the line and relief path are notplugged.

If flow is detected, the following procedure should be followed to divert the flow:

1. Shut down the mud pumps if drilling.

2. Pick up to clear the kelly or tool joint above the diverter bag.

3. Check for flow if uncertain well is flowing.

4. Close the diverter annular.

5. Evacuate personnel to a safe area.

6. Notify the Operations Superintendent.

7. If conditions allow, attempt a dynamic kill by pumping all available mud from the pitsfollowed by water from the water pit if the mud does not kill the well. Pumping will alsokeep the gas flow wet and reduce the fire hazard.

Note: If tripping, running casing, or out of the hole, it may be necessary to strip back tobottom prior to attempting the dynamic kill.

8. Personnel should be posted around the site to detect any signs of broaching.

BOP Operations

The well control procedures in this section are applicable when drilling below surface casing with acompetent shoe and a BOP stack installed.

The Operations Supervisor shall make sure the following is in place:

• Flowcharts are posted on the rig floor and other appropriate locations for "Shut-In Proceduresfor Drilling, Tripping, & Running Casing" and the "Station Bill during Well ControlOperations"

• The Choke Manifold is lined up to take returns through the "Mud Gas Separator"

• The valve downstream of the hydraulic choke is in the closed position during drillingoperations.

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Flowcheck Procedure - Drilling

1. The well is to be checked for flow if any of the following occur at anytime during drilling orcirculating operations:

• Increase in Rate of Penetration.

• Increase in Mud Return Flow.

• Gain in Pits.

• Decrease in Pump Pressure and/or Gain in Pump Strokes.

• High Gas Units.

• Sudden Increase in Torque.

• Increase in mud chlorides.

• Decrease in mud chlorides.

2. The following procedure is to be used to check for flow:

• Pick up the drill string and position a tool joint at the pre-determined shut-in position.

• Shut down the mud pump(s)

• Check the well for flow. Use trip tank if in doubt about the well flowing.

Shut-In Procedure - Drilling

Whenever flow is detected, the Driller is to shut-in the well on his own initiative without any furtherapproval in the following manner:

1. Open the remote choke line valves on the Choke line.

2. Close the annular preventer.

3. Make sure that the Choke Manifold is closed downstream of the power choke.

4. Record the shut-in drill pipe and casing pressures, and pit level gain.

5. Notify Operations Supervisor and Toolpusher as soon as practical.

6. Check accumulator pressures. Check BOP system components and confirm that the chokemanifold is lined up properly. Check for leaks and/or flow.

7. Record drill pipe and casing pressure every minute until the pressures stabilize then every 10minutes thereafter.

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8. Complete the 'Well Killing Worksheet'. Select kill method and determine materials needed tocirculate out the kick.

9. Adjust regulator pressure on annular preventer. Reciprocate pipe, if possible, to avoidsticking.

10. Prepare to extinguish sources of ignition.

Flowcheck Procedure - Tripping

1. The well is to be checked for flow if any of the following occur at anytime during trippingoperations:

• Hole not taking the correct amount of fluid.

• Gain in trip tank.

2. The following procedure is to be used to check for flow:

• Set the slips with a tool joint at the rotary table.

• Make up an open safety valve on the drill pipe. Close valve.

Note: When drilling with a TDS, do not make up the top drive into the drill string.Removing the lower valve in the top drive is time consuming and requires a 6-5/8 Reg box x 4-1/2" IF box crossover.

3. Observe the well for flow. If there is any question as to whether the well is flowing, it shouldbe shut-in and checked.

Shut-In Procedure - Tripping

Whenever flow is detected, the Driller is to shut-in the well on his own initiative, without anyfurther approval, in the following manner:

1. Shut down the trip tank pump.

2. Open the remote choke valve in the choke line.

3. Close the annular preventer around the drill pipe or drill collars.

4. Install and make up inside BOP on top of the safety valve.

5. Open the drill pipe safety valve.

6. Notify Operations Supervisor and contractor toolpusher as soon as practical.

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7. Record shut-in casing pressure. Record trip tank and/or pit gain. Check accumulator pressures.Check accumulator pressures. Check BOP system components and choke manifold forcorrect position. Check for leaks and/or flow.

8. Adjust the annular closing pressure and reciprocate drill pipe to prevent pipe from sticking.

Note: If the casing has pressure and/or the well will flow through the drill pipe, it will benecessary to strip the drill pipe back to bottom before circulating out the influx. SeeStripping Guidelines and Procedure for additional information.

Shut-In Procedure (Drill Collars across BOP stack)

1. Install a crossover and make up a safety valve if drill collars are above the rotary table.

2. Initiate shutting-in the well using the same procedures as for drill pipe.

3. Increase annular closing pressure if necessary to obtain a seal around spiral drill collars orspiral HeviWate drill pipe.

Shut-In Procedure (Drill String Out Of Hole)

1. Close the blind rams if the well begins to flow while the drill string is out of the hole.

2. Open choke line valves on first outlet below the blind rams. Monitoring will not be possiblethrough the choke line on BOP stack configurations where the blind ram is located below thechoke and kill line. This would require monitoring pressure through the annulus valves.

3. Record shut-in casing pressure and gain in trip tank.

4. Notify Operation Supervisor and Contractor toolpusher.

5. Prepare to strip into the hole using the annular. See Stripping Guidelines and Procedures.

Flowcheck Procedure - Running Casing

1. Check the well for flow should one of the following occur at anytime during casing runningoperations:

• Annulus flowing.

• Gain in pits greater than casing/pipe displacement.

2. Stop casing running operation.

3. Check for flow.

Shut-In Procedure - Running Casing

1. Open the remote choke valve in the choke line.

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2. Close the annular preventer.

• The annular closing pressure should have been adjusted for the larger OD pipe prior tostarting to run casing.

3. Install a crossover and make up a safety valve.

Note: If the casing float equipment leaks, it may be necessary to open the annulartemporarily to relieve flow form the casing while install the safety valve.

Well Killing Options - Running Casing

There are several possibilities for killing the well, dependent upon the amount of casing run, amountof well flow, condition of the float equipment, and the annulus pressure. The option selected shouldbe based on actual wellbore conditions, after consulting with the Operations Superintendent.Options include the following:

1. Strip casing out of hole.

2. Kill the well at the present casing depth.

3. Strip casing into the hole on drill pipe.

Fluid Weight/Circulating Rate

Fluid Weight

1. The fluid weight for circulating out influxes and killing wells is to be selected after consultingwith the Operation Superintendent, when practical, as to which of the following methods touse based on actual wellbore conditions:

• Drillers Method - Circulate out the influx using the original weight fluid, then circulate killweight fluid around. The major advantages of this method are relative speed and simplicity.However, this method will result in a higher maximum surface pressure. If insufficient bariteis on hand to weight up the fluid, this method should generally be used rather than suspendingoperations until barite becomes available.

•••• Weight and Wait Method - Circulate out the influx in one circulation using a balanced fluidweight. This method generally results in the lowest surface pressure and minimizes the timelost by returning to normal drilling operations as soon as possible if a sufficient volume ofheavier fluid is available on the Drilling rig and ready to pump. In some instances, the timenecessary to weight up the fluid can be excessive.

2. Mixing rate capabilities of the drilling rig are to be considered. Generally, incremental mudweight increases should be 1.0 ppg or less.

3. The final kill weight fluid is to have a minimum trip margin of about 200 psi depending on thewell. Higher trip margins may be necessary for wells with swabbing problems, etc.

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Circulating Rate Selection:

1. The circulating rates for the well kill operations are to be selected after consulting theOperations Superintendent, when practical. A pump rate in the 1 to 3 BPM range shouldtypically be used for circulating out an influx. The advantages of such a low pump rate are:

• Allows More Time for the Choke Operator to Adjust the Choke.

• Minimizes the Handling of Large Volumes of Gas at the Surface.

• Reduces the Possibility of Lost Returns.

2. Factors such as formation integrity at the casing shoe and rig well control equipment (e.g.,limitations of the mud gas separator) are to be considered when selecting a circulating rate.

3. The pump rate should be reduced, if necessary, when gas reaches the surface to prevent loss ofthe liquid leg in the mud gas separator.

4. When necessary to change circulating rates, the well is to be shut-in and a new frictionpressure determined.

Constant Bottom Hole Pressure Method

Well Kill Procedure

The objective of circulating out influxes is to maintain a constant bottom-hole pressure sufficient toprevent further influxes while minimizing lost circulation at the casing shoe. Following are steps toachieve this goal.

1. With hydraulic choke closed, open the valve downstream of the choke to allow returns to betaken from the choke line through the choke manifold and into the Mud Gas Separator.

2. Bring the pump up to speed slowly to the planned circulation rate. Use the hydraulic choke tohold a constant casing pressure on the annulus equal to the original shut-in pressure on thecasing plus a 25 to 50 psi safety margin.

3. Read and record drill pipe pressure after the pump reaches the desired constant speed andafter casing pressure stabilizes to the desired value.

Note: The drill pipe pressure at this point is the pressure necessary to maintain a constantbottom-hole pressure when circulating at that particular pump speed only. Thedifference between the initial shut-in pressure on the drill pipe and the pumpingpressure on the drill pipe is the friction pressure necessary to circulate drilling fluidat that particular pump speed only.

4. Maintain the desired drill pipe pressure at the constant pump rate while circulating out theinflux by manipulating the hydraulic choke taking returns from the annulus.

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• Changes in pressure due to choke manipulation require approximately 2 seconds per1000' of drill string to register on the stand pipe gauge; however, this lag in response timecan be longer if a large gas kick is present.

• If original mud weight is used, the drill pipe pressure will be held constant at its reaches the bit.

• Be prepared at all times to divert the flow overboard or to the flare as the poor-boy degasser may not be able to safely handle 100% gas.

5. Circulate using the desired fluid weight increments until kill weight mud is circulated aroundand it is verified that the well is dead. Use caution at all times since additional influxes couldenter the wellbore.

Stripping Operations

This section is applicable after making the decision to strip in the hole in order to perform a killoperation during a well control incident.

Stripping Preparation Guidelines:

1. A pre-job meeting is to be conducted with members of the stripping team.

2. Job assignments are to be reviewed and responsibilities designated with each individual on thestripping team.

3. The stripping procedure is to be reviewed and calculations are to be performed for thecapacity and displacement of the drill string for the stripping operations.

4. Ensure that an easy-to-read and accurate pressure gauge is installed on the choke manifold.

5. Ensure that a visual communication system between the person operating the choke and theperson monitoring the trip tank has been established.

6. Ensure that everything is ready to take returns from the choke manifold through the mud gasseparator and into the trip tank. Do not bleed returns into cementing displacement tanks.

General Stripping Guidelines:

1. Only strip in the hole if the buoyed weight of the drill string is greater than the upward forcefrom the wellbore when the drill string is across the BOP stack.

2. Utilize lubrication techniques if the buoyed weight of the drill string is less than the upwardforce from the wellbore.

3. Monitor well bore pressures and control the surface pressures using the bubble migrationtechnique/procedures while rigging up to strip in the hole.

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4. Install a non-ported float valve in the bit sub if the drill string is completely out of the hole.

5. Make up additional drill collars, if necessary, for weight to strip in the hole.

6. Install an inside BOP between any drill collars and the drill pipe or above the bit sub if notusing drill collars.

Note: It is only possible to run wireline tools down to the top of the inside BOP.

7. If out of the hole, trip in the hole and position the bit between the annular BOP and the closedblind rams.

8. Bullhead a higher weight drilling fluid down the choke and kill lines to lower the shut-incasing pressure and reduce the upward force from the wellbore if necessary.

9. Close the annular preventer and pressure up the drill string with the cementing unit to theequivalent casing pressure.

10. Open the blind rams.

11. Bleed off the drill pipe pressure to ensure that the inside BOP is holding.

12. Reciprocate the drill string slowly if in open hole in order to prevent the pipe from stickingwhile rigging up to strip.

13. Reduce the closing pressure on the annular preventer as necessary in order to minimize wearon the element while reciprocating the drill string.

14. Rig up to the safety valve and obtain the drill pipe pressure prior to stripping if the drill stringhas a ported float valve.

Note: Ensure the drill pipe safety valve is opened prior to stripping in the hole.

15. Always use the safety valve on the rig floor and not the top drive when shutting in the well ona trip. After installation of the safety valve, ensure that a backup valve is on the rig floorbefore stripping operations begin.

Stripping Procedure:

1. Record the shut in casing pressure.

2. Install the inside BOP and open the safety valve.

Note: Do not forget to open the safety valve.

3. Fill the drill pipe with a gel pill above the inside BOP to prevent trash in the drill string fromplugging the valve.

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4. Make up a stand of drill pipe and slowly trip in the hole.

5. Apply pipe dope to each tool joint body to ease passage through the annular preventer.

6. Use minimum closing pressure on the annular preventer during the stripping operation.

7. Monitor the flow line for any leakage from the annular preventer while stripping in the hole.

Note: Some leakage from the annular preventer is desirable to increase lubrication betweenthe annular rubber and the drill pipe.

8. Read and record the casing pressure before starting to lower each stand of drill pipe.

9. Slowly bleed returns from the wellbore using the hand adjustable choke in order to maintainthe following, whichever occurs first:

• A returns volume which is equal to the capacity and displacement of the pipe beingstripped into the hole, OR:

• A casing pressure which is equal to the pressure recorded prior to stripping the stand inthe hole, OR:

• Gas is returned at the choke.

Note: Fluid is sometimes lost to the formation resulting in reaching a casing pressurethat is equal to the recorded pressure at the start of the stand, before a returnsvolume equal to the capacity and displacement of the pipe can be bleed.

Note: Do not bleed off gas.

10. When gas reaches the surface, maintain the casing pressure constant and continue to strip intothe hole until the bit is back on bottom.

11. Kill the well using the Constant Bottom Hole Method.

Note: It may not be necessary to increase the weight of the drilling fluid to kill the well ifthe influx to due to swabbing unless the trip margin is insufficient for safetripping.

Well Control for Wireline Operations

Procedures and requirements for additional equipment for well control during wireline operationsare usually generated by the affiliate drilling team, unless local regulatory specifications are ineffect.

In many cases the well is completely stable with the mud weight in use at the time loggingoperations occur and no lubricator system is required. Since the annular preventer may not totallyclose off the wellbore with wireline in the hole, wirecutters should be available to cut the wire, if

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required. Each operational team should plan for this possibility, including securing the surface cutsection of wire, if possible, to prevent wire run away after the cut.

Lubricator systems should be considered where well flows might occur during the logging runs.Areas with open productive zones (particularly high-pressure gas wells), environmentally sensitiveareas, and areas with significant H2S concentrations could be considered for the use of lubricators,that can cover the entire logging tool string. The lubricator is usually made up to a pump-in sub andriser assembly that is anchored across a closed element of the annular preventer or flanged to the topof the annular preventer. If the well starts to flow while the logging tool is in the hole, the toolstring is pulled into the lubricator and the blind rams are shut to isolate the wellbore. Pressure isthen bled off the lubricator and wireline equipment safely rigged down.

Barite Plugs

In most cases, the goal of using a barite slurry is to kill the well using a hydrostatic pressure greaterthan the formation pressure.

The following three characteristics of barite plugs are the result of an analysis of industry experienceand laboratory studies:

1. High density and good pump ability are the most important parameters to consider whendesigning a heavy kill slurry.

2. The settling of barite from a barite plug is a slow process that is usually of little value in mostwell control incidents.

3. Lignosulfonate is the best deflocculant to use when designing the slurry for barite to settle.

Barite Plug Preparation Guidelines:

1. Plan in advance for use of a barite plug as part of the drilling operation.

2. Ensure that the necessary materials are available during the planning phase to help minimizeconfusion during the plug setting operation.

3. Ensure that each cementing operator is familiar with the problems of mixing and pumping abarite plug.

4. Design a tentative plan for mixing, pumping, and displacement of the barite slurry.

5. Utilize drilling Contractor personnel's expertise during the planning phase as necessary.

6. Ensure that there is a removable crossover line in place to ship barite from the bulk tanks tothe cement unit if plugging occurs.

7. Ensure that a barite deliverability test to the cementing unit is performed prior to attempting toset a barite plug.

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Barite Plug Mixing Guidelines:

1. Use either the "Settling Recipe" or "Non-Settling Recipe" shown below when mixing a bariteplug.

SETTLING RECIPE

1 bbl Water (fresh or seawater)15 lb. Lignosulfonate2 lb. Caustic; pH = 10.5 - 11.5

NON-SETTLING RECIPE

1 bbl Water (fresh or seawater)15 lb. Lignosulfonate2 lb. Caustic; pH = 10.5 - 11.51 lb. XC PolymerAs requiredDefoamer

These recipes are for one barrel of mix water.

2. Consider using the "Non-Settling Recipe" for large kill operations.

3. Prepare the mix water prior to adding the barite. The mix water requirement is 54 % of thefinal slurry volume.

4. Prepare a 21 ppg barite slurry by mixing 700 lbs of barite with 0.54 bbl of mix water. Mix thenon-settling recipe by recirculating it through the mixing hopper several times if necessary.

Barite Plug Pumping Procedure:

1. If possible, the same Drill Crew is to be used during mixing or displacing of a barite plug (donot change the Drill Crew until operations are complete).

2. A chiksan swivel is to be installed on the drill pipe safety valve and sufficient chiksans are tobe rigged up to reach the cementing manifold. Do not pump through a kelly or top drivesystem (TDS) when using the "Settling Recipe" for a barite plug.

3. A bypass line is to be installed in order to discard the initial barite slurry.

4. All connections are to be pressure tested from the mixing pump to the drill pipe safety valve.

5. The manifold valves are to be lined up as necessary in order to use the rig pumps fordisplacement of the plug in case the cementing pump fails or the line plugs.

• It is necessary to keep the barite plug moving at all times while in the drill pipe to prevent plugging.

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6. The valves on the cementing unit fill up line are to be tested for leaks and to ensure theyfunction properly.

7. Ensure that a pressurized mud balance is used to weigh the slurry.

8. The safety valve on the drill pipe is to be closed and the bypass line opened in order to discardthe barite slurry, until obtaining the correct weight.

9. Begin mixing and pumping the barite slurry to the bypass line.

10. Close the bypass line and open the safety valve after measuring the correct slurry weight at thebypass line.

11. Zero the barrel counter and continue mixing the slurry using the cementing unit and cementdisplacement tanks.

12. Displace the barite plug without shutting down.

Note: Actual displacement volume depends on whether it is possible to pull out of the plugor if the pipe is stuck.

13. Displace the barite slurry at a rate fast enough to get pumping pressure at the stand pipe. Theheavier barite in the drill pipe will tend to fall, and it is desirable to keep up with it bypumping at a fast enough rate to produce pump pressure at the stand pipe.

14. Pull the drill pipe out of the barite plug after the barite plug is in place. The chance ofsuccessfully pulling out of a barite plug using the "Settling Recipe" is small.

Pulling Pipe Procedure - Barite Plug:

1. The Drill Crew is to be in position to immediately pull out of the barite plug as soon as thedisplacement is complete.

2. Do not take the time to break out the safety valve and swivel before pulling out of the plug.Ensure that another safety valve is available on the rig floor.

3. Pull as fast as possible, consistent with the amount of drag, and rotate the pipe in the slipswhile standing back each stand.

4. Pull the pipe at least 10 stands above the calculated barite plug top.

5. Circulate bottom up the "long way" after pipe is above the plug at least 10 stands.

6. Wait approximately 8-10 hours before tripping back in the hole and tagging the top of thebarite plug in order to be certain that plug is in place.

WELL CONTROL


ExxonMobil Development CompanyDrilling

CREW STATION BILL AND RESPONSIBILITIESDURING WELL CONTROL OPERATIONS

DRILLER1) Detect wellbore influx and sound alarm.2) Pick up drill pipe to proper space out position.3) Shut down mud pump(s).4) Check or verify that the well is flowing.5) Open lower choke valve. Close annular.6) Notify Operations Supervisor and Toolpusher.7) Check accumulator pressure. Ensure that the well is

properly shut-in.

ASSISTANT DRILLER (if applicable)1) Ensure hydraulic choke is closed.2) Check that the first manual valve downstream of

choke is closed.3) Check remainder of choke manifold for proper

alignment.4) Report to Driller.5) Begin recording drill pipe and casing pressures.6) Standby for further instructions from Driller.

DERRICK MAN1) Record pit level and gain.2) Mark new pit level.3) Weigh drilling fluid in pits.4) Check relief valve(s) on mud pump(s) for flow back

from the well.5) Report Drilling fluid weight and active pit gain to

Driller.6) Prepare to weight up mud system.7) Standby for instructions from Driller.

SHAKER HAND1) Check well for flow at shakers.2) Report to Driller.3) Check drilling fluid weight at shakers.4) Monitor return line from choke manifold and flowline.5) Standby for instructions from Driller.

FLOOR HANDS1) Standby rotary to mark pipe for proper space out.2) Standby for further instructions from Driller.3) Install safety valve (as required) and close same.

DRILLING OPERATIONS SUPERVISOR1) Check to assure well is properly shut-in.2) Check well pressures and pit gain.3) Develop well kill plan.4) Call Drilling Operations Superintendent.

TOOLPUSHER1) Supervise Driller after well is shut-in.2) Check to assure well is properly shut-in.3) Monitor drill pipe and casing pressures.4) Notify Chief Mechanic, Electrician, and Crane

Operator.5) Prepare equipment for well kill operations.

CRANE OPERATOR1) Assemble roustabout crew.2) Standby to assist in well control operations.3) Coordinate barite material movement.

MUD ENGINEER1) Check pit volumes, verify mud weight, and report to

Derrick Man.2) Determine barite necessary to increase mud weight.3) Standby to assist Derrick Man.

MECHANIC/ELECTRICIAN1) Check closing unit.2) Check accumulator pressure.

MUD LOGGERS1) Monitor pump strokes, gas units, and pit levels.2) Work up kill sheet.

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