Exon-Mobile Drilling Guide

Development

Drilling STANDARD OPERATIONS MANUAL for JACK-UP / PLATFORM / BARGE DRILLING Click here for Table of Contents

First Edition May 2003

FOR COMPANY USE ONLY

Houston, Texas U.S.A.

ExxonMobil Development Company P.O. Box 4876 Houston, TX 77210-4876

Development 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 for Jack-Up/Platform/Barge Drilling. This manual replaces the Transition Version 1 manual dated October 1999. Many changes and upgrades have been made to this manual based on comments from the Drill Teams and Drilling Support Groups. The preface of the manual describes 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 barge rigs, 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 for planning 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 Operations Superintendent and/or Field Drilling Manager. Also, the guidelines in the manual must be appropriately interfaced with those established by the Drilling Contractor and conflicts addressed by the Operations Superintendent. Special appendices are included in each section of the manual for drill teams to customize the manual for their operating area. The tabs for these appendices are labeled “G” for general information and forms/documents that are used company wide and “S” for specific information and forms/documents that are unique to individual drill teams. We appreciate the time and effort by the Drill Teams and Drilling Support Groups in reviewing and 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 local practices, sections in the draft manual that were removed, general comments with no suggested changes, items not applicable to this manual, and a very few number of items not agreed to. In order to close the loop, Drill Teams that suggested changes not agreed to will receive feedback. This manual will be revised and upgraded in accordance with the revision process in the OIMS manual. In general, this process will involve review of comments received from the Drill Teams, 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

D. R. Anglin Operations Manager

Signature on file

J. W. Kiker Operations Manager

Signature on file____

C. W. Sandlin Operations Manager An ExxonMobil Subsidiary

PREFACE

The ExxonMobil Development Company, Standard Operations Manual for Jack-Up/Platform/Barge Drilling has been prepared to provide guidelines for conducting drilling operations using jack-up, platform and barge rigs in ExxonMobil Drilling's realm of activities. This manual, used in conjunction with well-specific Drilling and Completion Programs and other procedural manuals, including the Drilling OIMS Manual and the Safety Management Program Manual, will provide the basic framework and principles required for the Operations Supervisors and Drilling Engineers for planning and conducting drilling operations. Because of the numerous possible variables and conditions which can occur, this manual cannot replace the knowledge and good judgment of key drilling personnel on the drilling rig or in the office. The guidelines contained within this manual are the logical sequence of steps necessary to efficiently conduct drilling operations in a safe and environmentally sound manner on a global scale 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, some remain as examples and may be valuable for international operations. The guidelines contained herein shall be reviewed and understood by all involved drilling personnel. In accordance with the OIMS "Management of Change" element, significant changes (any change that increases health, safety, public, environmental or financial risk) from these guidelines are not to be undertaken 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 the Drilling Contractor and contained in the Drilling Contractor's operations manuals. Identified procedural conflicts shall be addressed by the Operations Superintendent and any resulting resolutions shall be provided to the Operations Supervisors. Special appendices are included in each section of the manual for drill teams to customize the manual for their operating area. The tabs for these appendices are labeled “G” for general information and forms/documents that are used company wide and “S” for specific information and forms/documents that are unique to individual drill teams. The manual shall be kept current by including recommended improvements/changes in accordance with the change process described in the EMDC Drilling OIMS Manual. In general, this process will involve review of 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 regulatory changes. 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 the information needed to drill and complete drill wells in all situations. Good sound judgement should always be exercised in any task and should never be discarded just to follow an outlined step in any process or procedure DRILLING OPERATIONS MANUAL – JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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SAFETY CREDO We, the Management and Employees of ExxonMobil Development Company: • Will relentlessly pursue our ultimate objective of an injury and illness free work place • Will not compromise our focus on safety in order to achieve any other business objective

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 of others -- both on and off the job • All injuries and illnesses can be avoided when we practice safe behaviors

STANDARD OPERATIONS MANUAL JACK-UP/PLATFORM/BARGE RIG DRILLING TABLE OF CONTENTS

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GENERAL INFORMATION 1.1 Drilling Operations Manual 1.2 Organization 1.3 EMDC Reports 1.4 Drilling Contractor Reports 1.5 Third Party Service Contractor Reports

GENERAL OPERATIONS 2.1 Contracts Administration 2.2 Prespud Meeting 2.3 Security 2.4 EMDC Drilling Operations Personnel Responsibilities 2.5 Drilling Contractor Personnel Responsibilities 2.6 Third Party Service Contractor Personnel Responsibilities 2.7 Special Operations Precautions 2.7.1 Helicopter Operations 2.7.2 Mooring Vessel Operations 2.7.3 Casing pressure Monitoring 2.7.4 Back Pressure Valves 2.7.5 Rotary Table Insert Bushing Locks 2.7.6 Christmas Tree Equipment 2.7.7 Mud Logging Units

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Appendix G-I EMDC-DO Risk Assessment Form Appendix G-II Risk Assessment Package (example) Appendix G-III EMDC-DO BOPE Exception Form Appendix G-IV Drilling Environmental Performance Indicators Report Form 3.0

MARINE OPERATIONS 3.1 Site Survey / Bottom Sweep / SIMOPs review 3.2 Moving 3.2.1 Moving Jack-up Rigs 3.2.2 Moving Platform Rigs 3.2.3 Moving Barge Rigs 3.3 Moving And Positioning 3.4 Pre-Loading (Jack-up Only) 3.5 Cargo Transfers 3.5.1 Precautions 3.5.2 Weather Limits 3.5.3 Heavy Lifts (Jack-Up Lifts in Excess of 10 MT) 3.5.4 Lifting Operations 3.5.5 Rigging Guidelines 3.5.6 Equipment Maintenance 3.6 Transportation & Personnel Transfers 3.6.1 Cargo Transport 3.6.2 Helicopter Operations 3.6.3 Personnel Transport-Helicopter

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

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STANDARD OPERATIONS MANUAL JACK-UP/PLATFORM/BARGE RIG DRILLING TABLE OF CONTENTS 3.7

3.8

3.6.4 Personnel Transport-Supply or Stand-By Boat Marine Training 3.7.1 General 3.7.2 Reporting & Drill Frequency 3.7.3 Marine Drill Process 3.7.4 Fire Drills 3.7.5 Fire Drill-Example 3.7.6 Abandon Rig Drills 3.7.7 Abandon Rig Drill-Example 3.7.8 Man Overboard Drill 3.7.9 Specialized Drills 3.7.10 Principal Aspects of Drills Ship Collision Avoidance 3.8.1 Detection 3.8.2 Radar Watch Procedures Appendix G-I Appendix G-II Appendix G-III Appendix G-IV

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SIMOPs Checklist Memo SIMOPs Deviation Form Study of Pile Interaction with Jack-Up Rig Operations Pre-Startup Inspections for New to Fleet Jackup Drilling Rigs

DRILLING OPERATION 4.1 Introduction 4.2 General Operations Guidelines 4.3 Pre-Spud Operations 4.4 Structural Drive Pipe 4.5 Conductor and Surface Casing Interval 4.6 Diverter Operations 4.7 Intermediate / Protective Casing Interval 4.8 Production Casing / Liner Interval 4.9 Slot Recovery / Whipstock / Section Mill / Cutt & Pull 4.10 Wellbore Anti-Collision Guidelines 4.10.1 Requirements for "Collision Risk" Wells 4.10.2 Requirements for All Directional Wells 4.11 Directional Surveying and Deviation Control 4.12 Drill String Design 4.13 Bottom Hole Assemblies 4.14 Hydrogen Sulfide Considerations 4.15 Hydrogen Sulfide Contingency Plan

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BIT CLASSIFICATION AND HYDRAULICS 5.1 General 5.2 Drill Bits 5.3 IADC Bit Classification System 5.4 IADC Bit Grading System 5.5 Running Procedures for Fixed Cutters 5.6 Hydraulics Program 5.7 Guidelines for Hydraulics Optimization 5.8 Hydraulics Optimization 5.9 Reference Material

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DRILLING FLUID SYSTEM 6.1 General 6.2 Solids Control 6.3 Drilling Fluid Treatments 6.4 Drilling Fluid Checks 6.5 High Temperature Drilling 6.6 Stuck Pipe Pills 6.7 Lost Circulation 6.8 Non-Aqueous Fluid Operations 6.9 Rig-Site Dielectric Constant Measurement 6.10 Drilling Fluid System Guidelines Appendix G-I Appendix G-II

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Fluid Transfer Checklists NAF/Oil Base Mud Readiness Checklist

ABNORMAL PRESSURE DETECTION IN CLASTICS 7.1 Background 7.2 Pressure Indicators While Drilling 7.3 Abnormal Pressure Detection Team Responsibilities 7.4 Mud Logging 7.5 Operational Guidelines

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FORMATION EVALUATION 8.1 General 8.2 Conventional Coring 8.3 Wireline Logging Program 8.4 Sidewall Coring Operations 8.5 Wireline Radioactive Sources 8.6 MWD/LWD Logging 8.7 Mud Logging and Cuttings Samples

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CASING OPERATIONS 9.1 Casing Running 9.2 Casing Connection Make-Up 9.3 Casing Checklist

10.0 CEMENTING 10.1 10.2 10.3 10.4 10.5 10.6

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General Cementing Guidelines Primary Cementing Remedial Cementing Cementing Checklist Reference

Appendix G-I

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Exxonmobil Cement Testing Guidelines

11.0 PRESSURE INTEGRITY TESTS 11.1 General 11.2 Casing Test 11.3 Leak-Off Test 11.4 Jug Test (Limited PIT) 11.5 Open Hole Leak-Off Test DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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STANDARD OPERATIONS MANUAL JACK-UP/PLATFORM/BARGE RIG DRILLING TABLE OF CONTENTS 12.0 PRODUCTION TESTING 12.1 Production Testing Objectives 12.2 Well Test Design 12.3 Test String 12.4 Surface Equipment 12.5 Measurement Equipment 12.6 Safety 12.7 Personnel Responsibilities 12.8 Pre-test Planning and Preparation 12.9 Information Retrieval 12.10 Well Killing and Zone Abandonment 12.11 Emergency Procedures 12.12 Hydrogen Sulfide 12.13 Hydrates

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13.0 PLUG AND ABANDONMENT 13.1 General 13.2 Permanent Plug and Abandonment 13.3 Temporary Plug and Abandonment 13.4 Site Clearance Verificationa 14.0 WELL CONTROL 14.1 Well Control – General 14.2 Hole Monitoring 14.3 Equipment Testing 14.4 Equipment Specifications 14.5 Well Control Drills 14.6 Well Control Procedures


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STANDARD OPERATIONS MANUAL JACK-UP/PLATFORM/BARGE RIG DRILLING TABLE OF CONTENTS

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GENERAL INFORMATION 1.1 Drilling Operations Manual 1.2 Organization 1.3 EMDC Reports 1.4 Drilling Contractor Reports 1.5 Third Party Service Contractor Reports

GENERAL OPERATIONS 2.1 Contracts Administration 2.2 Prespud Meeting 2.3 Security 2.4 EMDC Drilling Operations Personnel Responsibilities 2.5 Drilling Contractor Personnel Responsibilities 2.6 Third Party Service Contractor Personnel Responsibilities 2.7 Special Operations Precautions 2.7.1 Helicopter Operations 2.7.2 Mooring Vessel Operations 2.7.3 Casing pressure Monitoring 2.7.4 Back Pressure Valves 2.7.5 Rotary Table Insert Bushing Locks 2.7.6 Christmas Tree Equipment 2.7.7 Mud Logging Units

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Appendix G-I EMDC-DO Risk Assessment Form Appendix G-II Risk Assessment Package (example) Appendix G-III EMDC-DO BOPE Exception Form Appendix G-IV Drilling Environmental Performance Indicators Report Form 3.0

MARINE OPERATIONS 3.1 Site Survey / Bottom Sweep / SIMOPs review 3.2 Moving 3.2.1 Moving Jack-up Rigs 3.2.2 Moving Platform Rigs 3.2.3 Moving Barge Rigs 3.3 Moving And Positioning 3.4 Pre-Loading (Jack-up Only) 3.5 Cargo Transfers 3.5.1 Precautions 3.5.2 Weather Limits 3.5.3 Heavy Lifts (Jack-Up Lifts in Excess of 10 MT) 3.5.4 Lifting Operations 3.5.5 Rigging Guidelines 3.5.6 Equipment Maintenance 3.6 Transportation & Personnel Transfers 3.6.1 Cargo Transport 3.6.2 Helicopter Operations 3.6.3 Personnel Transport-Helicopter


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3.6.4 Personnel Transport-Supply or Stand-By Boat Marine Training 3.7.1 General 3.7.2 Reporting & Drill Frequency 3.7.3 Marine Drill Process 3.7.4 Fire Drills 3.7.5 Fire Drill-Example 3.7.6 Abandon Rig Drills 3.7.7 Abandon Rig Drill-Example 3.7.8 Man Overboard Drill 3.7.9 Specialized Drills 3.7.10 Principal Aspects of Drills Ship Collision Avoidance 3.8.1 Detection 3.8.2 Radar Watch Procedures Appendix G-I Appendix G-II Appendix G-III Appendix G-IV

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DRILLING OPERATION 4.1 Introduction 4.2 General Operations Guidelines 4.3 Pre-Spud Operations 4.4 Structural Drive Pipe 4.5 Conductor and Surface Casing Interval 4.6 Diverter Operations 4.7 Intermediate / Protective Casing Interval 4.8 Production Casing / Liner Interval 4.9 Slot Recovery / Whipstock / Section Mill / Cutt & Pull 4.10 Wellbore Anti-Collision Guidelines 4.10.1 Requirements for "Collision Risk" Wells 4.10.2 Requirements for All Directional Wells 4.11 Directional Surveying and Deviation Control 4.12 Drill String Design 4.13 Bottom Hole Assemblies 4.14 Hydrogen Sulfide Considerations 4.15 Hydrogen Sulfide Contingency Plan

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BIT CLASSIFICATION AND HYDRAULICS 5.1 General 5.2 Drill Bits 5.3 IADC Bit Classification System 5.4 IADC Bit Grading System 5.5 Running Procedures for Fixed Cutters 5.6 Hydraulics Program 5.7 Guidelines for Hydraulics Optimization 5.8 Hydraulics Optimization 5.9 Reference Material

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DRILLING FLUID SYSTEM 6.1 General 6.2 Solids Control 6.3 Drilling Fluid Treatments 6.4 Drilling Fluid Checks 6.5 High Temperature Drilling 6.6 Stuck Pipe Pills 6.7 Lost Circulation 6.8 Non-Aqueous Fluid Operations 6.9 Rig-Site Dielectric Constant Measurement 6.10 Drilling Fluid System Guidelines Appendix G-I Appendix G-II

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Fluid Transfer Checklists NAF/Oil Base Mud Readiness Checklist

ABNORMAL PRESSURE DETECTION IN CLASTICS 7.1 Background 7.2 Pressure Indicators While Drilling 7.3 Abnormal Pressure Detection Team Responsibilities 7.4 Mud Logging 7.5 Operational Guidelines

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FORMATION EVALUATION 8.1 General 8.2 Conventional Coring 8.3 Wireline Logging Program 8.4 Sidewall Coring Operations 8.5 Wireline Radioactive Sources 8.6 MWD/LWD Logging 8.7 Mud Logging and Cuttings Samples

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CASING OPERATIONS 9.1 Casing Running 9.2 Casing Connection Make-Up 9.3 Casing Checklist

10.0 CEMENTING 10.1 10.2 10.3 10.4 10.5 10.6

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General Cementing Guidelines Primary Cementing Remedial Cementing Cementing Checklist Reference

Appendix G-I

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Exxonmobil Cement Testing Guidelines

11.0 PRESSURE INTEGRITY TESTS 11.1 General 11.2 Casing Test 11.3 Leak-Off Test 11.4 Jug Test (Limited PIT) 11.5 Open Hole Leak-Off Test DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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STANDARD OPERATIONS MANUAL JACK-UP/PLATFORM/BARGE RIG DRILLING TABLE OF CONTENTS 12.0 PRODUCTION TESTING 12.1 Production Testing Objectives 12.2 Well Test Design 12.3 Test String 12.4 Surface Equipment 12.5 Measurement Equipment 12.6 Safety 12.7 Personnel Responsibilities 12.8 Pre-test Planning and Preparation 12.9 Information Retrieval 12.10 Well Killing and Zone Abandonment 12.11 Emergency Procedures 12.12 Hydrogen Sulfide 12.13 Hydrates

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13.0 PLUG AND ABANDONMENT 13.1 General 13.2 Permanent Plug and Abandonment 13.3 Temporary Plug and Abandonment 13.4 Site Clearance Verificationa 14.0 WELL CONTROL 14.1 Well Control – General 14.2 Hole Monitoring 14.3 Equipment Testing 14.4 Equipment Specifications 14.5 Well Control Drills 14.6 Well Control Procedures


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GENERAL INFORMATION

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GENERAL INFORMATION

1.1 1.2 1.3 1.4 1.5

Drilling Operations Manual Organization EMDC Reports Drilling Contractor Reports Third Party Service Contractor Reports

______________________________________________________________________________ DRILLING OPERATIONS MANUAL-JACK-UP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION-MAY 2003

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GENERAL INFORMATION 1.1 DRILLING OPERATIONS MANUAL

The EMDC Jack-Up/Platform/Barge Rig Drilling Standard Operations Manual is applicable to production and exploration wells. The drilling guidelines, principles, and procedures contained in this manual represent drilling 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 each section, one subsection is devoted to operations specific Drill Team operations. Appendices that apply to general drilling operations regardless of area of operation are denoted by a "G" before the appendix number. Appendices relating to a specific drill team are denoted by an "S" prefix before the appendix number. Where applicable, this manual will reference other company and industry documents that contain additional information to supplement the guidelines contained here-in. This manual will present drilling practices common to numerous drilling operations, irrespective of rig type.


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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 planning and preparation of drilling engineering work, and the direct supervision of drilling operations. The Drilling Organization shall prepare guidelines and procedures, as necessary, so that operations are conducted in a safe 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 the satisfaction of the Operations Supervisor on location. The drilling contractor is also responsible for operating and maintaining the drilling rig in safe working condition and in full compliance with EMDC technical specifications and local regulatory requirements, including those requirements as specified in the drilling contract. Other critical third party service contractors are independent contractors that will assist in executing the drilling program. These contractors are responsible for operating and maintaining their equipment in full compliance with EMDC technical specifications and/or contract requirements, and local regulatory requirements. The drilling contractor and other critical third party service contractors provide services where inadequate performance could result in a Level 1, 2, or 3 incident (OIMS Element 9). These contractors must meet or 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


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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 executing the drilling program to the satisfaction of the Operations Supervisor on the drilling rig. These contractors are also responsible for operating and maintaining their equipment in full compliance with EMDC technical specifications 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 documented in the standard reports developed by EMDC and its contractors. This manual describes the preparation and distribution of these reports. Daily Drilling Report The Operations Supervisor will record drilling activities on the DRS and transmit it, usually via the LAN or telephone 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 operation requires 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 the drilling operation cannot be effected without input from the entire drilling organization, and the daily drilling report is the base document from which most information is drawn. The following are guidelines on some aspects 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.


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GENERAL INFORMATION Daily Cost Report The Operations Supervisor should complete the DRS Daily Cost Report and transmit it to the DIMC each morning. The Daily Cost Report should capture all substantial drilling costs including services utilized, rental equipment, and consumed materials. Where exact costs are not known, reasonable estimates should be made and included in the Daily Cost Report. Some contractor costs will not be known exactly until the end of a month. The rig should not attempt to estimate what the discounted charge will be; the rig is to enter the ticket charge on the cost screen. The Drilling Engineer is responsible for monitoring discounted materials and services costs and communicating any adjustments to the Operations Supervisor for modification of cost sheets. It is the Drilling Engineer's responsibility to include the cost of all materials and services in appropriate procedures for Operations Supervisor use in completing the Daily Cost Report. The Drilling Engineer is also 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 over the 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 the Operations 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 kept on the drilling vessel for reference during logging, production testing, completion, plug and abandonment operations, etc. The Operations Supervisor is responsible for completing the casing run tally report and forwarding it to the Drilling Engineer after each casing string is run. While it is not necessary to transmit the off-load tally from the rig, it is necessary to create a DRS off-load tally to be able to complete the casing description part of the 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 complete the Environmental Performance Indicators (EPI) Report for inclusion in the Final Well Report. This form contains four sections; Well Information, Emissions Data, Environmental Regulatory Compliance Data, and Waste Data. Drilling Reporting System (DRS) When the DRS system is in place, the following DRS reports will be maintained and transmitted from the rig daily or when pertinent, 1) Daily Drilling Report, 2) Casing Report, 3) Cementing Report, 4) Lithology,


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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 significant economic impact or failures which could have safety implications. The equipment failure report should adequately describe the nature of the failure, identify the cause of the failure, document the associated downtime 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 Operations Superintendent. 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 rotational schedule) and Operations Supervisors prior to their respective crew changes. The purpose of these notes is to document all situations and/or activities that will require follow-up by the relieving personnel, as well as to 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 by the 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 the container number in which it is stored. Material transfers are prepared for EMDC material and will usually list the commodity number. Hazardous material should be identified on the manifest. Under no circumstances should used casing thread protectors be sent to the United States in a container unless all thread compound is removed. There will be venture specific materials procedures. Once completed, the manifest should be signed by the originator and forwarded to the receiver of the goods by the most expedient means (usually via fax). A copy of the manifest should be given to the captain of the transferring vessel. The Operations Supervisor should sign the manifest for the goods received at the rig. Rental tools should be tracked, preferably in a rental tool log book or in a clipboard maintained on the rig. Pressure Integrity Test Record Pressure Integrity Tests are covered in Section 11 of this manual. The pressure integrity test (PIT) form will be prepared for all tests conducted. Additional information regarding PIT procedures and analysis is contained in the EPRCo publication "Pressure Integrity Test - Field Guide".


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GENERAL INFORMATION The Operations Supervisor is responsible for completing the PIT form and forwarding it to the Operations Superintendent 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 incident reporting. A Reportable Safety Incident is defined by OIMS as being a Lost Time Incident, Restricted Work Incident, 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 Operations Superintendent. Safety Meeting Record The Operations Supervisor should record the issues addressed/discussed at the general safety meeting, as well as the topics of the drill crew pre-tour safety meeting and any critical operations safety meeting in DIMS and the IADC report. The minutes of the general safety meeting can be hand written and do not have to be duplicated on the DIMS report. Forward copies of the contractor's safety meeting minutes to the Operation Superintendent. Well Killing Worksheet After the BOP stack is installed, the Well Killing Worksheet will be prepared in accordance with the guidelines specified in Section 14 of this manual. The worksheet will be maintained for the current wellbore configuration and updated at least daily (or as well conditions change) while drilling is in progress or maintain the KIK PC program data up to date. The Operations Supervisor is responsible for completing the worksheet. There are multiple acceptable formats 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 Manual and 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 and IADC Report. Detailed test data will also be recorded by the Drilling Contractor on a BOP test form designed specifically for the drilling rig. This report should include the information specified in Section 14 of this manual. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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GENERAL INFORMATION The completed BOP test form, signed by the test pump operator, tool pusher/OIM, and Operation Supervisor, will be provided to the Operation Supervisor. All pressure test charts will be dated, and properly labeled as to each component tested in accordance with applicable EMDC and regulatory requirements. All records pertaining to the BOP tests should be retained on the drilling rig until completion of the well. The records should then be forwarded to the nearest production facility or host platform for retention in accordance with applicable regulatory requirements or forwarded to Operations Superintendent 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 elevation and 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 a designated 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 available to be faxed to the Operations Superintendent when needed. A copy of the current POB list will be maintained on the drilling rig. Drilling Recorder Chart The Drilling Contractor should annotate all major drilling activities (drilling, tripping, circulating, running casing, cementing, etc.) on the continuous recording strip chart which records depth, time, hookload, pump pressure, rotary torque, and weight-on-bit, as a minimum. The strip chart should also be annotated by the Drilling 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 Operations Superintendent when requested. IADC Reports The IADC Report will be prepared daily by the Drilling Contractor and signed by both the drilling contractor's senior drilling representative and the Operations Supervisor. The IADC Report will detail the events 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 clearly separated. 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 Superintendent weekly. 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. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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GENERAL INFORMATION The Operation Superintendent will forward the original to the accounting department and retain the pink copy in the drilling office files. Safety Incident Reports Refer to the Drilling Safety Management Program for a description of reports required from the contractors. The Drilling Contractor will prepare an incident report for all lost time incidents, fatalities, restricted work incidents, medical treatment incidents, first aid treatments, regional illness events, near misses, and significant near misses onboard the drilling rig. The incident report will, as a minimum, describe the nature of the incident, list the names of all persons involved (both witnesses and victims), describe the contributing circumstances, 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 any outstanding safety items and provide a list of all meeting attendees. A handwritten report is acceptable. A copy of the report will be provided to the Operations Supervisor for forwarding to the Operations Superintendent. Trip Book The primary monitoring of the volume of mud added to the hole to replace the drill string displacement on trips is the responsibility of the drilling crew. When full service mud logging is available, the mud loggers shall provide a backup trip book log. The trip tank will be used for all trips unless otherwise addressed by the field drilling manager. The trip book must compare measured volume with theoretical volume as well as previous 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 crew well control competency. This checklist is in Section 6 of the OIMS Manual and guidelines are in Section 14 of this manual.


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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 casing cementing, equipment pressure testing, PITs, etc. The chart will be annotated with all significant events such as pumping spacers, pumping lead and tail cements, bumping the plug, etc. (as required by local affiliate and regulatory agencies). The chart will be provided to the Operations Supervisor for forwarding to the Operations Superintendent and 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 guidelines specified in Section 6 of this manual. Unless otherwise specified by the Operations Supervisor, a minimum of 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 each morning. Directional Data For directional wells, the Directional Drillers will prepare a bottom hole assembly sheet and BHA checklist for all BHAs run in the well in accordance with the guidelines specified in Section 4 of this manual. The directional driller will also maintain a wellbore trajectory record and current wellbore plot in the Operations Supervisor's office. The Directional Driller and Operations Supervisor should collaborate to complete and sign the directional drilling pre-job survey data sheet (PJSDS) and forward to the directional drillers coordinator as well as to the Drilling Engineer. A pre-job checklist for directional wells should be used to verify that all operational concerns have been addressed. Both the above items are OIMS required documents. Anticollision/well interference calculation should be updated at each survey point and a minimum of two directional contractor representatives should be onboard when wellbore interference issues exist. The minimum curvature calculation technique should be used. A copy of the wellbore trajectory record will be provided to the Operations Supervisor for forwarding to the Drilling Engineer each morning. Mud Logger's Reports The Mud Loggers will prepare a Mud Log and Daily Mud Logging Report in accordance with the abnormal pressure detection guidelines specified in Section 7 of this manual.


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GENERAL INFORMATION A copy of the log/report will be provided to the Operations Supervisor and wellsite geologist for forwarding 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 company contracted 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 use radioactive 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 Base Manager/Materials Coordinator on a weekly (or other timely) basis.


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GENERAL OPERATIONS

2.0 GENERAL OPERATIONS

2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.7.1 2.7.2 2.7.3 2.7.4 2.7.5 2.7.6 2.7.7

Contracts Administration Prespud Meeting Security EMDC Drilling Operations Personnel Responsibilities Drilling Contractor Personnel Responsibilities Third Party Service Contractor Personnel Responsibilities Special Operations Precautions Helicopter Operations Mooring Vessel Operations Casing pressure Monitoring Back Pressure Valves Rotary Table Insert Bushing Locks Christmas Tree Equipment Mud Logging Units

Appendix G-I Appendix G-II Appendix G-III Appendix G-IV

EMDC-DO Risk Assessment Form Risk Assessment Package (example) EMDC-DO BOPE Exception Form Drilling Environmental Performance Indicators Report Form

____________________________________________________________________________________________________________ DRILLING OPERATIONS MANUAL - JACKUP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION - MAY 2003

1 2 3 3 8 9 14 14 14 14 14 14 14 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 the following responsibilities:

Operations Superintendent 1.

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

2.

Copies of applicable contracts are maintained by the EMGSC procurement group for various drilling operations.

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 terms of 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 with the contract terms.

4.

Conduct a safety/operational ("prespud") meeting prior to the start-up of drilling operations with the appropriate 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 field well file. Note any special problems addressed and/or discussed at these meetings in a memo to the Operations Superintendent.

Critical Service Contractor's Responsibilities 1.

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

2.

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

3.

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


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GENERAL OPERATIONS

4.

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

5.

It is desirable to have acceptance inspection checklist for the following third party services: mud logging, production testing equipment, waste transportation, storage, disposal, self-contained breathing 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 of contractor waste.

4.

Ensure that both EMDC-Drilling and contractor's personnel clearly understand the chain of command and 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 party contractor 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


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GENERAL OPERATIONS

All personnel (EMDC-Drilling and contractors) must obtain, maintain, and retain well data, especially information relating to depths, operational problems, and formation evaluation according to their job requirements and release such information to others on a strictly "need-to-know" basis. All personnel will 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: • • • •

2.

Provide communications, as necessary, between the Operations Supervisor on the Drilling Rig and 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

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 Programs and 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 guidelines or procedures in the Drilling Operations Manual.


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GENERAL OPERATIONS

•

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

Note: • • • •

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

Solicit change(s) to the Drilling Operations Manual from the Operations Supervisors according to the 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.

• • 4.

Compliance with ExxonMobil and Government Regulations: • • • • • •

5.

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

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 regulatory bodies. Request any regulatory exceptions either from the necessary regulatory agency or the appropriate regulatory contact within ExxonMobil. Report incidents of non-compliance. Maintain current knowledge of authority guides.

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

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GENERAL OPERATIONS

1.

Supervise Operations at Drill Site: • • • • • • •

2.

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 and Procedures 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 Production Testing Programs and Procedures. Ensure compliance of Drilling Contractor and Third Party Contractors with terms of appropriate contracts. 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 from the drilling rig as necessary. Ensure Contractors are maintaining the required equipment and conducting efficient operations in a safe and environmentally sound manner.

Ensure Compliance with OIMS and the Drilling Safety Management Program • • • • • • •

Communicate ExxonMobil requirements and expectations regarding safety and performance to all rig site personnel. Assist Drilling Contractor with implementing the Safety Program in accordance with the Drilling Safety 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 the exceptions on DIMS and maintain a record of all significant changes on the rig. Monitor daily operations to ensure Regulatory compliance. Report any incidents of noncompliance. Ensure that all required reports and records are accurate and complete and issued in a timely manner.

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.


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GENERAL OPERATIONS

• •

2.

Prepare Standards and Procedures: • • • •

3.

Prepare a site specific Emergency Response/SIMOPS (if applicable) attachment for the Operations 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

Coordinate a Risk Assessment for all drillwells: • • •

•

• 4.

Prepare the Drilling, Completion, and Production Testing Programs and Procedures based on all available geologic and drilling information from nearby offset wells in the area. This Drilling and Evaluation Program shall include the best available technology for drilling operations. Be knowledgeable of the operating and construction characteristics of all components in the drilling system to be used and be knowledgeable about alternative systems and procedures that might be implemented to improve operational efficiency. Ensure operations staff understands the fundamentals behind successfully implementing the new technology.

Organize meetings with the Operations Supervisor, Operations Superintendent, Field Drilling Manager, Production personnel, Third Party Contractors, and others (as required) to assess and mitigate the particular hazards associated with the planned operations. During the course of the Risk Assessment process, the Drilling Engineer is to ensure that the Risk Assessment Form /Action Status Report (Section 2 – G-I) is completed and routed for endorsement. EMDC-DO has compiled a list of base case failure event scenarios that are common to most of our activities. This list should be reviewed during the Risk Assessment and if any additional risk scenarios are identified, these should be documented using the format supplied and routed for endorsement with the RAF. A cover memo is used to concisely communicate the results of the Risk 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 the Surface Blowout Prevention And Well Control Equipment Manual. The Blowout Preventer Equipment Exception form (Section 2 – Appendix G-III) is to be completed and routed with the RAF. Any requested exceptions regarding the rig's BOP configuration will be approved through endorsement of this form. All follow-up items will be documented in the Risk Assessment package.

Provide Engineering Support: •

Provide surveillance of day-to-day drilling progress to ensure that the Drilling and Evaluation program is conducted to apply the best available technology and propose modifications, as necessary.


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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 equipment based on the results of this analysis. Develop and write supplemental procedures for all major drilling and completion operations. If applicable use the Standard or Core Procedure templates found in this Operations Manual. Prepare cost estimates for the selection of optimum procedural alternatives and equipment modifications. Counsel the Operations Superintendent and Operations Supervisor on critical activities and problems such as equipment failures, mud and hole problems (including tectonics and wellbore stability), etc. Provide rig site technical assistance in abnormal pressure detection, running and cementing critical casing 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.


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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 the Operations Supervisor on the Drilling Rig.

2.

Operate and maintain the Drilling Rig in a safe working condition and in full compliance with EMDCDrilling technical specifications and local regulatory requirements, including those requirements as specified in the drilling contract.

3.

Develop and use safe working procedures. Ensure that the following programs and/or systems are in place and functioning properly (Drilling OIMS Manual Element 8, Section E and Safety Management Program): • • • • • • • •

4.

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

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

Offshore Installation Manager (OIM) Representative 1.

Represent the Drilling Contractor as the person in charge and responsible for the overall operation and 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.


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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 a safe and efficient manner.

6.

Conduct drills, safety meetings, and training.

7.

Ensure that Drilling Contractor personnel document drilling operations properly and that all reports are 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 the satisfaction of the Operations Supervisor onboard the Drilling Rig.

2.

Operate and maintain service equipment in full compliance with EMDC-Drilling technical specifications 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 and environmentally sound manner. Comply with contractual personnel requirements and Short Service Employee (SSE) program requirements.

5.

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

6.

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


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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 drilling operations.

3.

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

4.

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

5.

Take an "Out" sample of the circulating drilling fluid prior to pulling out of the hole (POOH) for logging and give to the Wireline Logging Engineer along with, a fluid filtrate sample, and the associated filter 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 of the hole.

7.

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

8.

Ensure that Drilling Contractor personnel are recording drilling fluid weight and funnel viscosity on 1530 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 flow line 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 maintain the 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 fluid treatments.


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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 drilling rig. Directional Driller Responsibilities 1.

Recommend Bottom Hole Assemblies (BHAs) to the Operations Supervisor for each hole section of a 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 operations supervisor.

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 drilling parameters 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 azimuth and inclination of the wellbore from surveys.

8.

Maintain a current wellbore plot in the Operations Supervisor's office using the wellbore trajectory record.

9.

Provide a daily cost to the Operations Supervisor for directional equipment/tools and services provided 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.


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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 azimuth and inclination of the wellbore from MWD surveys. Ensure that survey correction factors are understood and endorsed by Drilling Engineer, Operations Supervisor, and Directional Driller.

6.

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

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 to ExxonMobil personnel as directed by the Operations Supervisor/Wellsite Geologist.

9.

Protect personnel from exposure to radioactive sources if such sources are present on location for LWD 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 and shape or any parameter that may indicate an increase in pore pressure or the presence of hydrocarbons.

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 the wellbore.

8.

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

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


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GENERAL OPERATIONS

10. Ensure that a Material Safety Data Sheet (MSDS) is available for each mudlogging product on the drilling 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. Inspect the hoses (typically polyflow) every 2-3 months, and replace if it has been pinched, is brittle, 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 as specified in the Drilling Program.

4.

Verify cement volume calculations with the Operation Supervisor prior to starting the cementing operation.

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 additive system 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 recording equipment (chart recorders, densiometers, etc.) and provide the Operations Supervisor with properly documented charts. 11. Ensure that a Material Safety Data Sheet (MSDS) is available for each cement product on the drilling rig.

2.7.

SPECIAL OPERATING PRECAUTIONS 2.7.1

Helicopter Operations Provide accurate cargo and weight manifests for all helicopter transportation.


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GENERAL OPERATIONS

Lower and secure all crane booms before helicopter landing/departure. (Crane operator must step 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. If casing pressure is detected, it shall be reported on the Daily Drilling Report. The situation shall 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 lubricator shall be installed and anchored. Prior to retrieving the plug, confirmation of pressure equalization shall be made, if possible. If working on a well with H2S gas, all workers in the area 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 when procedures specifically require them to be temporarily unlocked. A means of visually determining locked status shall be provided.

2.7.6

Christmas Tree Equipment Have an OEM (Original Equipment Manufacturer) service representative on location during installation and pressure testing of all christmas tree equipment. All wellhead and christmas tree equipment has the potential to trap unexpectedly deadly pressure between seals, in gate valve cavities, under pipe plugs, lockdown screws, grease fittings and in small porting which has become plugged. Some models of gate valves are especially prone to trapping pressure in the gate valve cavities. Trapped pressure most commonly occurs in the split gate style valves and especially the WKM models. Any valve that has service fittings, which access the valve body, should have a permanent warning sign stating "WARNING: This valve has the potential to internally trap pressure!"


14 of 15

GENERAL OPERATIONS

2.7.7

Mud Logging Units Where mud logging units have hydrogen gas feeding the Flame Ionization Detector (FID) post warning 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 is discolored from normal clear or white color. Responsibility: Operations Supervisor Approval Authority for exceptions: Operations Superintendent.


15 of 15

GENERAL INFORMATION SECTION 2 - APPENDIX G-I EMDC-DO RISK ASSESSMENT FORM

REVISED 06/23/99 (EDO_RAF.DOC)

ROUTING & APPROVAL APPROVED DATE

GENERAL WELL:

FIELD:

DEPTH: TOTAL DAYS

RIG: PRESPUD MEETING HELD q YES q NO

COUNTY:

ENGR. SUPV. ENGR. OPER. SUPT. DRLG. ENGR. MANAGER FIELD DRILLING MANAGER

STATE:

WELL TYPE (CHECK ALL THAT APPLY) q DRILLWELL q W/O q P&A q COMPLETION

WELL CATEGORY

RETURN TO ENGR.

q I+ q I q II q III

SECRETARY (COPY /DISTR.)

CATEGORY ASSESSMENT - KEY WELL CHARACTERISTICS CATEGORY 1+ q OFFSHORE DRILLING OPERATIONS FROM PLATFORM OR MODU

CATEGORY II q REQUIRES AN ABNORMAL PRESSURE DETECTION TEAM TO DETERMINE TD

q LIVE/HORIZONTAL DRILLING q EXTREMELY SENSITIVE ENVIRONMENT q 250 ppm ROE OF H2S THAT INCLUDES OCCUPIED STRUCTURES, HEAVILY TRAVELED ROAD, RAILROAD, BUSY WATERWAY OR AIRPORT

q SUSPECTED SHALLOW GAS OR CHARGED SANDS ABOVE THE SURFACE CASING SETTING DEPTH q MAY ENCOUNTER SEVERE LOST RETURNS, SLOUGHING SHALE, OR OTHER SEVERE HOLE PROBLEMS RESULTING IN RELATIVELY HIGH COST q WELL IS LOCATED WITHIN 500' OF AN OCCUPIED RESIDENCE, LAKE, STREAM OR HEAVILY TRAVELED ROAD, RAILROAD, AIRPORT OR PLANT/TREATING FACILITY

CATEGORY 1 q REQUIRES AN ON-SITE PRESSURE DETECTION TEAM FOR SETTING PROTECTIVE CASING INTO ABNORMAL PRESSURE TRANSITION ZONE q REQUIRES > 13 PPG MUD TO DRILL FORMATIONS SUSPECTED OF CONTAINING HYDROCARBONS q EXTREMELY REMOTE SITE THAT IS A CONSIDERABLE DISTANCE FROM SERVICE COMPANIES THAT WOULD BE REQUIRED DURING WELL CONTROL PROBLEMS

q OVERBALANCED / HORIZONTAL DRILLING q 250 ppm ROE OR H2S THAT IS LESS THAN 300 FEET q EXCEPTION FOR OFFSITE AND/OR MULTIPLE RIG SUPERVISION REQUESTED

q WELL IS CAPABLE OF FLOWING HYDROCARBONS AND IS LOCATED WITHIN 2000' OF A DENSELY POPULATED AREA OR HEAVILY TRAVELED ROAD, RAILROAD, WATERWAY, OR AIRPORT q AREA OF ANTICIPATED LOST RETURNS AND KNOWN SHALLOW GAS SANDS CAPABLE OF FLOWING TO SURFACE PRIOR TO SETTIN G SURFACE CASING q 250 ppm ROE OF H2S THAT EXTENDS OUT GREATER THAN 300 FEET

CATEGORY III q LOW RISK, FIELD DEVELOPMENT WELL WITH GOOD OFFSET DATA, MINIMAL PUBLIC AND ENVIRONMENTAL EXPOSURE, MODERATE COSTS, AND NORMAL MUD WEIGHTS

OIMS RISK ASSESSMENT: REQUIRED ON ALL 1+ WELLS AND ANY WELL WITH A BOLD ITALIC KEY WELL CHARACTERISTIC OIMS RISK ASSESSMENT REQUIRED? q YES q NO BASE CASE RISK ASSESSMENT REVIEWED? q YES q NO (IF YES, ATTACH OIMS RISK ASSESSMENT REPORT) ADDITIONAL FAILURE EVENT SCENARIOS IDENTIFIED q YES q NO (IF YES, INCLUDE SCENARIOS IN REPORT) NUMBER OF ADDITIONAL SCENARIOS: NAMES OF PERSON(S) INVOLVED IN BASE CASE REVIEW AND ADDITIONAL SCENARIO ASSESSMENTS :

OIMS DRILLING MANAGEMENT REVIEW MEETING HELD? q YES q NO DATE HELD: MEETING ATTENDEES:

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) q OIL q GAS q INJECTOR q CONDENSATE SHALLOWEST GAS OR OIL @: ppm H2S:

MAX ANTICIPATED SITP 250 ppm ROE:

ANTICIPATED WATER BOARD RULING / EXCEPTION REQUIRED / APPLIED FOR: q YES q NO q YES q NO q N/A MUD TYPE (CHECK ALL THAT APPLY) q FW MUD q SW MUD q OIL (q ESCAID q DIESEL) q BRINE WTR q ________

q YES HYDROCARBON ZONES WILL FLOW IF q NO INSUFFICIENT HYDROSTATIC HEAD HOUSE WITHIN 500': DRILL STEM TEST: q YES q NO q YES q NO q STRAIGHT DIRECTIONAL PLAN: q DIRECTIONAL: MAX MW LINE RESERVE PIT q YES q NO q N/A

ADDITIONAL INFORMATION (IF REQUIRED)

ATTACHMENTS q WELL PLAN / POWER PT. DIAGRAM q MAP OF OFFSET WELLS q DIRECTIONAL WELL PLATS q SUMMARY OF DRILLING HAZARDS q MAP OF GENERAL WELL LOCATION

* REQUIRED FOR ALL WELLS. ORIGINAL: WELL FILE

q BOPE & EXCEPTION(S) FORM* q BOPE SKETCHES q WELLBORE & WELLHEAD SKETCHES q OFFSET WELL PRESSURE CHECKLIST q CIVIL ENGR. DRILL SITE REPORT

q q q q q

DAYS/DEPTH CURVE RIG POSITION ON LOCATION FORM. TOPS/PRESSURES/CONTENT GEOL. X SECTION & STICK CHARTS OIMS RISK ASSESSMENT REPORT

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/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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SECTION 2 - APPENDIX G-II

MEMORANDUM EMDC 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” for the upcoming GI 16 OCSG 031 R-22 ST#1 "Sandberg" drillwell. Enclosed please find the scenario worksheets for the four incidents identified as potential hazards by the team. Please note that these four scenarios addressed in the attached worksheets are unique to this location and are not covered by the existing EMDC Base Case Risk Assessment. The EMDC Base Case Failure Event Scenario List is included for your reference. If you should have any questions regarding this assessment, please do not hesitate to contact any member of the team for clarification.

xc:

H. J. Longwell, III Ensco 99 Drilling Superintendents Element 2 Risk Assessment Custodian

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

1 of 9

ELEMENT 2 RISK ASSESSMENT FAILURE 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/jetting operations.

X

X

X

X

Surface blow-out while conducting completion operations in clear fluids with open 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 is prohibited by weather.

X

X

X

X

Severe weather impacts drilling operations.

X

X

X

X

Drilling regulatory noncompliance or infraction.

X

X

X

X

Derrick barge lift accident/mishap.

X

Jack-up rig punch-through.

X

Barge rig capsizing during sinking/refloating operation.

X

Marine vessel collision with rig/platform.

X

Lifeboat launch failure.

X

X

X

X

Worker incident on rig.

X

X

X

X

Fire/explosion on rig.

X

X

X

X

Person overboard.

X

X

X

X

X

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


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

Barge

Land

Platform

Jack-up **

Oil Based Drilling Fluid Annular Injection Accident/Mishap

X

Oil Based Drilling Fluid Spill

X

Oil Based Drilling Fluid Fire in Pits

X

Well Control Incident Due to Striking Offset Well.

X

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


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GENERAL OPERATIONS

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

EMDC RISK MATRIX A

B

C

D

HYPOTHETICAL FAILURE EVENT SCENARIO:

I

Unplanned Shallow Gas Problems during Conductor-less Drilling

II

E

III

P

E H F

IV

LOCATION: Jack-up Drilling Rig DESCRIPTION: Unexpected shallow gas is found when drilling surface hole without conductor.

CONSEQUENCES:

HEALTH/SAFETY

PUBLIC DISRUPTION

ENVIRONMENTAL IMPACT

FINANCIAL IMPACT

I

III

II

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 prevent lost returns and (2) preparation of a Lost Returns plan.


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GENERAL OPERATIONS

3. A thorough review of the well logs near surface indicated no presence of shallow hydrocarbon-bearing sands. Both the original B-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 bled to 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 in parallel to depths near 5000', and (b) directional driller will drill vertically to ~4,500' MD , which is below the surface casing setting 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 were established: 1) The PIC is the EMDCDO Drilling Superintendent. 2) Emergency shutdown links are established by NOPO field operations. 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 conduit to the surface.


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GENERAL OPERATIONS

RISK WORKSHEET #1 EMDC RISK MATRIX HYPOTHETICAL FAILURE EVENT SCENARIO: Oil Based Drilling Fluid Annular Injection Accident/Mishap

A

B

C

D

I

LOCATION: GI 16 R-Platform and Ensco 99 DESCRIPTION: Mishandling, mechanical failure results in exposure of personnel to Oil Based Drilling Fluid and to potential additives.

II III

H

IV

CONSEQUENCES:

E

P,E,F

ENVIRONMENTAL

FINANCIAL

HEALTH/SAFETY

PUBLIC DISRUPTION

IMPACT

IMPACT

III

IV

IV

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 cost increases 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 all injection 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.


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GENERAL OPERATIONS

RISK WORKSHEET #2 EMDC RISK MATRIX

HYPOTHETICAL FAILURE EVENT SCENARIO: Oil Based Drilling Fluid Spill A

LOCATION: GI 16 R Platform and Ensco 99 DESCRIPTION: Oil spill in water during any oil transfer operation due to mechanical failure and/or human error.

B

C

D

I II III

E,F E,F

P

IV

CONSEQUENCES:

H

ENVIRONMENTAL

FINANCIAL

HEALTH/SAFETY

PUBLIC DISRUPTION

IMPACT

IMPACT

IV

III(a)

II(b),III(b)

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 target objectives) PREVENTATIVE MEASURES: Oil transfer Policies & Procedures. Ensco 99 will be in "Zero Discharge Operation". Oil based drilling fluid disposal company personnel on board. Recent vibrator hose upgrades. Equipment to be checked and tested for leaks prior to first shipment of OBM. Transfer hoses shall have appropriate certification and testing records prior to first shipment of OBM. Transfer hoses shall be checked periodically and shall be replaced if any deficiencies are noted. An exercise will be conducted with all transfer personnel prior to first shipment of OBM. All appropriate personnel will be in constant communication during OBM transfers, especially with boat captain, and no activity associated with OBM movement will be unsupervised. Weather conditions shall be favorable for any transfer from vessel and mooring lines shall be checked periodically. Fire protection equipment will be located in strategic positions to protect personnel inside of the change room and offices. JSAs for all activities will be prepared and thoroughly reviewed prior to any activity associated with OBM. Proper PPE will be utilized when handling OBM. MITIGATION PLANS: Oil Spill Contingency Plan for water locations, emergency response drills.


E

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GENERAL OPERATIONS


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

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.

B

C

I

III

H H

IV

E, F E,F,P

ENVIRONMENTAL

FINANCIAL

HEALTH/SAFETY

PUBLIC DISRUPTION

IMPACT

IMPACT

I, II, III

IV(a)

III,IV

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 drilling operations. PREVENTATIVE MEASURES: Pits and shakers have a Skelton Foam Deluge System. Foam Deludge System: Test procedure will be reviewed, complete water test the system & review of foam deluge shut down & startup procedure. Exxon Safety Manual, JSAs. Proper venting and purging of enclosed spaces. Specification of safe welding areas and electrical classification areas (see API RP 500). Good housekeeping practices. Gas and fire detection systems. Independent electrical inspection of rig. Contractor preventive maintenance program. 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. Fire drills. Escaid 110 invert emulsion oil mud typically has flashpoint > 220° F


E H

II

CONSEQUENCES:

D

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GENERAL OPERATIONS


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

A

B

C

D

E

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 lost returns during well control operations causes a blowout and spill at the surface. COMMENT: Only one live wellbore on the R platform, R-21.

I

H

II

F

III

PE

IV

CONSEQUENCES:

ENVIRONMENTAL

FINANCIAL

HEALTH/SAFETY

PUBLIC DISRUPTION

IMPACT

IMPACT

I

III (a)

III

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 course when 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 use Op Tech Bulletin #99-111 as a guide to avoid wellbore collision. EMDC well control practices and policies. Technically and operationally sound drilling practices. EMDC BOP testing guidelines and EMDC BOP function testing standards. Casing design specifications, casing inspection programs, casing connection make up procedures, casing pressure tests, wellhead QA/QC program. Rig supervisor well control training, NODO technical and operational personnel staffing requirements. Ensco personnel well control training, drilling crew tour proficiency drills, drilling rig critical alarms and instrumentation. NODO critical valve "soft-lock" program. Adequate offset well drilling and formation pressure information. MITIGATION PLANS: Onsite medic. Oil spill response plan. Critical operations and curtailment plan. Fail-safe surface and subsurface ESD systems. Fire fighting equipment/training. Joint drilling/production evacuation drills.


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GENERAL INFORMATION SECTION 2 - APPENDIX G-III ExxonMobil Development Company – Drilling Organization BOPE EXCEPTIONS Well Name: Field/Prospect: County, State

Risk Category: Depth: ppm H2S:

Engineer Engr. Supv. Opt. Supt.

Rig:

250 ppm H2S ROE:

Drlg. Engr. Mgr. Field Drlg. Mgr.

Casing Size

Depth

Drilled Interval

Max. MW Required to Balance Pore Pressure

Exception 1.

Flexible hoses for BOP opening & closing lines not consistent with API RP 16D.

2.

Flexible hoses for choke and kill lines not consistent with API 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 with Type R flat bottom grooves. (Flange bolt tightening check required, BOP WP ≤ 3,000 psi). c) Low carbon steel ring gaskets allowed in gas or sour oil environments (BOP WP ≤ 3,000 psi). d) Only one outlet valve required on each wellhead section (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 on the 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 require straight-through line (BOP WP ≤ 3,000 psi).

9.

Casing rams not required.

HC Exposed? Y/N Type

Exception Requested

MASP PSI

BOP Type

Flowline Type

Choke Type

Choke Min. WP

Justification for Exception

10. Drilling spool not required. 11. SA BOP will not require double valves on each outlet for 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.


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GENERAL INFORMATION SECTION 2 - APPENDIX G-IV ExxonMobil 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. Exceedances

No. to Land

No. Fines

Other

Fines Amount ($US)

Total Exceedances Oil Spills* > 1 bbl.

Chemical Spills* > 100 kg.

No. to land

Vol. to land

bbls.

No. to water

Vol. to water

bbls.

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 Cuttings

Use gauge hole volume

Hazardous Waste (classified as Hazardous Waste by regulatory authorities) Net Generated External Recycled (lbs.) (lbs.) Ongoing (lbs.) Periodic (lbs.) Engineer:

Eng. Manager:

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


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MARINE OPERATIONS 3.0 MARINE OPERATIONS

3.1 Site Survey / Bottom Sweep / SIMOPs review 3.2 Moving 3.2.1 Moving Jack-up Rigs 3.2.2 Moving Platform Rigs 3.2.3 Moving Barge Rigs 3.3 Moving and Positioning 3.4 Pre-Loading (Jack-up Only) 3.5 Cargo Transfers 3.5.1 Precautions 3.5.2 Weather Limits 3.5.3 Heavy Lifts (Jack-Up Lifts in Excess of 10 MT) 3.5.4 Lifting Operations 3.5.5 Rigging Guidelines 3.5.6 Equipment Maintenance 3.6 Transportation & Personnel Transfers 3.6.1 Cargo Transport 3.6.2 Helicopter Operations 3.6.3 Personnel Transport-Helicopter 3.6.4 Personnel Transport-Supply or Stand-By Boat 3.7 Marine Training 3.7.1 General 3.7.2 Reporting & Drill Frequency 3.7.3 Marine Drill Process 3.7.4 Fire Drills 3.7.5 Fire Drill-Example 3.7.6 Abandon Rig Drills 3.7.7 Abandon Rig Drill-Example 3.7.8 Man Overboard Drill 3.7.9 Specialized Drills 3.7.10 Principal Aspects of Drills 3.8 Ship Collision Avoidance 3.8.1 Detection 3.8.2 Radar Watch Procedures Appendix G-I Appendix G-II Appendix G-III Appendix G-IV


______________________________________________________________________________ DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION - MAY, 2003

1 2 3 4 5 6 7 8 9 9 9 10 11 15 20 20 21 22 24 24 24 25 26 27 29 30 33 34 35 37 37 38 38

MARINE OPERATIONS 3.1

SITE SURVEY/BOTTOM SWEEP/SIMOPS REVIEW

For applicable marine operations, a site specific operability study can be conducted by the EMDC Technology 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. Additional inspections 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 the proposed location. The assessment should include a review of existing information for any evidence of shallow hazards. Sources may include the following: •

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

•

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

•

Up-to-date drawings of production platform and facilities to assess interference potential and identify SIMOPs requirements associated with conducting Jack-Up Drilling Operations over production platforms.

•

Diagrams of Production Platform support piling positions and driven depths to assess JUR spud can and platform pile interference potential (be sure to account for production platform leg batter). Section 3 -Appendix G-IV (" Amoco/McClelland Study "Jack-Up Rig Soil Disturbance") is the subject of a memo written by E. J. Henkhaus. The Drilling Engineer is to reconcile all MIRU plans with this memo (and ExxonMobil's Civil Technology 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 survey may include: •

Bathymetry Profile via Echo Sounder

•

Sub-bottom profiler

•

2-D high resolution multifold seismic

•

Side Scan Sonar

•

Magnetometer

•

Soil Boring (100' -150')


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MARINE OPERATIONS For JU rigs, adequacy of JUR leg length must be considered. This will include spud can penetration based 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 preload experience 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 platform shall 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 the seafloor (generally, this is within 500' of the platform).

•

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

•

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

•

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

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

If the decision is made to make any deviations from the guidelines set out in the SIMOPs manual, this may be accomplished by routing a SIMOPs deviation for approval by Production. 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 a representative 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 of local 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 and identify 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, and State O&G Boards’ “Plans for Exploitation” should also be available.


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MARINE OPERATIONS The following general operational guidelines apply to the Jack-Up barge during preparation for and execution of transit operations. 1.

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

2.

Towing arrangements will be made well in advance.

3.

Size and number of tow vessels required considering:

4.

•

Government regulations

•

Contractor’s insurance requirement

•

Expected currents and weather

•

Distance of tow

•

Positioning requirements at the mobilization location and final drilling site.

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 will be 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:

10.

•

Pre-determined safe shelter location or locations along route.

•

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

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


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MARINE OPERATIONS 3.2.2 MOVING – PLATFORM RIGS Prior to commencement of any marine movement operations it is imperative that a review of local 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 identify mitigating options. Valid discharge and drilling permits, from state and or federal agencies, must be posted at the rig prior to spud. Other permits DOCD, APD, MMS, and State O&G Boards’ “Plans for Exploitation”. The following general operational guidelines apply to the platform during preparation for and execution of transit operations. 1. A marine procedure must be documented in accordance with the drilling contractor’s Marine Operation Manual. 2. A person designated by the project team conducts an onsite inspection to determine the preferred placement of all rig packages in relationship to pipelines, facility process equipment, drain systems, blowdown vent lines, and any other equipment that may be affected. 3. Towing arrangements will be made well in advance. 4. Crane barge arrangements will be made well in advance. 5. Check platform loading as it relates to the rig package equipment and secure Structural Engineering’s concurrence with the rig mobilization plan. 6. Review the proposed locations of living quarters, escape routes, diesel storage tanks, etc. and determine 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 the platform 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 to the rigs fire main, and that piping pressure design is compatible. Ensure that the platform’s firewater 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 any drains 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 the designated 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 require during the MIRU and drilling phase. 12. Ensure that a communication link is established between the barge and platform, particularly between the barge crane operator and those persons spotting equipment on the main deck of the platform. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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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 special considerations in regards to emergency situations. 15. Review all electrical classifications applicable to the planned locations of the living quarters and rig components. 16. Inspect the platform’s diesel storage tanks, potable water storage, and various transfer pumps to determine 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 the rig'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 platform rigs, and assess whether they can be reused. 18. Size and number of tow vessels required considering: •


•


•

Expected currents and weather

•

Distance of tow

•


19. Description and or map of tow route. 20. A contingency procedure will be in place for heavy weather including: •


•

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 of local 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 identify mitigating options. Valid discharge and drilling permits, from state and or federal agencies, must be posted at the rig prior to spud. Other permits DOCD, APD, MMS, and State O&G Boards’ “Plans for Exploitation”. The following general operational guidelines apply to the barge during preparation for and execution of transit operations.


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MARINE OPERATIONS 1. A marine procedure must be documented in accordance with the drilling contractor’s Marine Operation Manual. 2. If historical data is absent, a soil bore sample may be analyzed in order to facilitate design/building of a rockpad. 3. Surveying and dredging arrangements will be made well in advance. 4. Towing arrangements will be made well in advance. 5. Size and number of tow vessels required considering: •


•


•

Expected weather

•

Distance of tow

•


6. All equipment onboard must be properly secured prior to rig moves. Particular attention will be given to the BOP stack and tubular goods. 7. Description and or map of tow route and location of pipeline crossings and other facilities that could impact rig move. 8. A contingency procedure will be in place for heavy weather including: •


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


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MARINE OPERATIONS 3.

Attending tow vessels are to be attached by towing wires to the Jack-Up prior to the final jackdown. 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 EMDC and EMPC management through the SIMOPs checklist/review process and appropriate waivers/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 calculated number to ensure stability calculations are correct.

5.

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

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 more than 2 hours continuous without a break.

Positioning A surface positioning system will be utilized to monitor the drilling rig's position as it is navigated onto the proposed location. The specific navigation procedure will be dependent upon the well location and will be specified in the Move-In Rig-Up Procedure. The final position of the drilling rig is to be verified after the legs have been pinned. The drilling rig's exact location, determined after an adequate number of satellites passes, is to be within the stated tolerance as specified in the MIRU procedure. For a rig cantilevered over an existing platform, the position will be deemed acceptable if the 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 or supplemental procedure. This will generally be determined by cantilever/rotary table accessibility of the desired well conductor slot on the production platform and the direction of the prominent winds and wave forces for the proposed location and time of year. Engineer will specify the maximum cantilever loads that will be available in the skidded- out position in the Move-in Rig-Up Procedure and confirm that these will meet maximum well design loads both before and after final JUR positioning. In a multi-well drilling program, the hookloads for all wells and positions must be acceptable. Factors such as crane position, workboat logistics, etc. may also affect the programmed heading of the rig. Note: Anchors will not be used to hold the Jack-Up barge on location prior to pinning the legs. Any use of anchors will require use of a detailed procedure and will necessitate an exception to the standard (approval of the Field Drilling Manager).


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MARINE OPERATIONS 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 out to ensure that pipelines, shipwrecks, spent armaments, and other debris are not present. This inspection 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, preloading must be conducted consistent with the rig contractors and rig manufacturer's standard operating 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 3-5 feet above the wave action line. Once the hull of the barge touches the wave action line during pre-loading, all of the ballast water is discharged and the Jack-Up barge can subsequently be jacked 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-load will 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 Standard Operating 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- Up rig positions at the same production platform, and, if significantly different, additional sea bed cores should be considered to determine the reason for the discrepancy and the actual sea bed integrity.

4.

During jacking operations, the sea water tower must operational at all times, with the normal supply 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 more hazardous undertakings in the offshore environment. A Back-Down Buoy when servicing a Jack-Up rig is recommended, especially during strong current/wind conditions. When setting a Back-Down Buoy, ensure that it is not set on a pipeline or other subsea hazard. Do not use a production platform to store drilling equipment without involving EMPC to ensure the structure can handle the planned load with acceptable safety factors. Guidelines in this section cover some of the major transferring operations. While there is no substitute for good common sense, Marine and Jack-Up rig personnel are to use these guidelines and good judgment to conduct transferring operations in a safe manner. A JSA (Job Safety Analysis) is required prior 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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MARINE OPERATIONS

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 termination and 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, walkietalkie, 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 transferring heavy cargo in heavy weather.

3.

Only transfer small pieces of equipment, necessary to avoid suspension of operations, from a supply vessel in heavy weather conditions and only if the boat captain, DIM, and Operations Supervisor 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 to the cargo can be attached to the crane hook. Shackling slings to cargo when the sling is attached 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 Contractor OIM 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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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 (JSA Mandatory). Note: Crane Operator and the relay personnel are to have visual contact with each other and communications 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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MARINE OPERATIONS •

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 vessels picking 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 connecting load 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 hooks for off-loading casing.

11.

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

12.

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

13.

Take precautions to avoid binder slap back when removing chain binders on cargo from supply vessel. Note: Supply vessels will use chain binders to secure cargo and keep it from shifting during rough 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 the following 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.


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Pipe bundle has slings around the pipe bundle, which is more than 25% of the pipe length from 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 allow corrosion 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 a minimum 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 of four 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 two pallets).

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 unless using 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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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 be placed 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 only one 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 which has a single point lifting padeye. Note: Do not transport loose gas bottles.

3.

Only transport radioactive and explosive materials in proper containers that are made specifically for such material.

Sling Rigging Guidelines 1.

Calculate the safe working load of slings by dividing the catalog breaking strength of the lifting 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 then dividing 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 at the crane hook is 60 degrees for containers, etc. and a maximum of 30 degrees for bundled pipe (i.e., 50 ft sling lengths for 40 ft pipe bundles and 40 ft sling lengths for 30 ft pipe bundles).


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MARINE OPERATIONS Note: If the sling leg length equals or exceeds the horizontal distance between load attachment points (i.e., padeyes), the lift angle is 60 degrees or less. 5. 6.

Locate each sling leg a distance equal to 15 percent of the bundled pipe length when lifting a pipe bundle (i.e., 6 ft. from the end for 40 ft pipe joints). Use wire rope slings. Note: Wire rope slings break one strand at a time whereas chain slings break with little or no warning. 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 deteriorates to 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 occur for 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 the shackle 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 longitudinally between the hooks.

3.5.6

EQUIPMENT MAINTENANCE

Definition:

Good maintenance is frequent inspection, cleaning, and lubrication of rigging equipment.

Equipment Maintenance Guidelines 1.

Maintain chains, wire rope, shackles, hooks and all other rigging equipment on a periodic basis.

2.

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


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Destroy any rigging equipment that has corrosion, excessive wear, stranded wires, or is in otherwise 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 strand nicking.

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

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

•

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


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MARINE OPERATIONS

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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MARINE OPERATIONS

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

mm (in)

Hitch

6 (1/4")

Two-Leg

Two-Leg

Four-Leg

Double Choker

Hitch

Hitch

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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MARINE OPERATIONS

TABLE NO. 3 MASTER LINK SAFE WORKING LOADS

Stock Diameter

Single Master Link (one or two sling legs) Safety Factor = 6:1

Master Link Assembly (three or four sling legs) 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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MARINE OPERATIONS

TABLE NO. 4 INSTALLATION OF WIRE ROPE CLIPS

Wire Rope

Minimum

Rope Turn back

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)


Torque

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MARINE OPERATIONS

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 to EMPC Safety Manual. Safety of personnel is the primary objective when moving personnel and cargo offshore. When there 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 between Shore Base and the rig. Supply vessels may be the primary means on some operations and may be used on other operations if weather conditions prohibit helicopter flights. Transfers should only 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 the Materials Supervisor.

2.

Notify the Materials Supervisor of the cargo type and the expected arrival time to ensure efficient 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 the item container. Note: Separate MTCMs should be used for different material owners, i.e., rental tools to be 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 be secured.


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

7.

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

8.

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

Helicopters 1.

Transport of cargo via helicopters is limited to small lightweight items unless critical to the operation. Proper approvals must be in place prior to transporting any cargo other than small lightweight items. Typically, procedure/equipment used for airlift of heavy, non- standard items will require consultation with Aviation Department contact and Field Drilling 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, including passengers, 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 helicopter skids/wheels.

3.

Rope mats must be securely tied down.

4.

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

Landing & Takeoff 1.

Only the Jack-Up helideck shall be used for helicopter operations. Any exception to use the 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 Manual Element 6).


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

4.

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

5.

Helideck is to be cleared of all arriving/departing passengers and/or cargo prior to moving 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 Manual Element 6).

7.

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

8.

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

Refueling -Emergency Situation Only 1.

Shut down the helicopter, clear the helideck of all non-essential personnel and man the helideck 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 (OIMS Manual 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 in emergencies, 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 will be sent from the offshore site.

3.

Manifests will accompany all flights listing the passengers and their Company; (OIMS Manual Element 6)

4.

a.

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

b.

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

Helicopters are not to be scheduled at night unless a medical emergency exists (some geographic 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 the helicopter 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 its destination.

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 boarding helicopters at the shore base location. (OIMS Manual Element 6)


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

3.

Load and unload passengers with the rotor blade in motion only after announcing to the passengers 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 trained personnel, 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 to boarding. 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 drilling contractor personnel (i.e., night and day crews) to respond appropriately when faced with an emergency situation. An equally important objective is to train and ensure that all other on-board personnel (typically temporarily or transient to the rig) how to identify emergency signals, how to respond, and how to safely evacuate. General Marine Training Guidelines 1.

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

2.

Schedule drills to allow full participation of crews while minimizing interference with drilling operations.

3.

Plan drills, which simulate realistic emergencies and demonstrate necessary steps to mitigate a real emergency.


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

5.

Walk through drills and coach key personnel as necessary to ensure crew is familiar with their designated assignments and that all others know signals, muster points, and evacuation 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 one hour.

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 Marine Emergency Drill Report Form.

Marine Drill Frequency 1.

"Fire Drills" -Initial drills as required to plan and organize Fire Fighting Squads and weekly thereafter. Note: Conduct fire drill during hours of darkness and/or hold drill without priors notice to crew once every month.

2.

"Abandon Rig Drills" -Frequently until all personnel know their stations and the abandonment procedure and muster checks are satisfactory (i.e., all personnel report to muster points). Conduct the drills weekly thereafter. Note: Conduct" Abandon Rig Drills" during hours of darkness and/or hold drill without prior notice to crew once every month.

3.

"Man Overboard Drills" -Initially as required to plan and organize Response Teams and every two weeks thereafter. Note: Conduct man overboard drill during hours of darkness and/or hold drill without prior notice to crew once every month.


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"Specialized Drills" -As required to train designated response teams to ensure team members are proficient at their assigned duties. This type of training does not in itself satisfy 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 when practical. Note: Conduct training in the use of rescue equipment and assignment of duties in lieu of 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 to perform as though an actual emergency situation existed.

Critique Drill:

Discussion: session will identify problem areas and help identify areas 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 react efficiently 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 selfcontained breathing apparatus nor start fires to test fire fighting system.


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A void placing crew in high risk situations; however, avoiding all risk should not be the basis for failing to test some safety equipment. For example, launching lifeboats in mild seas can entail some risk; however, this risk is acceptable since operating this equipment increases the chance of successful deployment in a real emergency.

Critiquing Guidelines Ensure that key supervisory personnel critique drill and lead a discussion, which focuses on the principal aspect of drill immediately following all drills. All Jack-Up personnel should be encouraged to participate in the discussion session following a drill. Critique and discussion sessions should:

3.7.4

•

Review the emphasis of drill.

•

Discuss problems, which occurred during drill.

•

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

•

Discuss situations that could have developed if this had been a real emergency situation.

•

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

FIRE DRILLS

Purpose of Fire Drill Prepare Response Teams (i.e., Fire Fighting Squads) for mitigating a fire and rescuing injured and/or trapped personnel. Also, demonstrate that members of the Fire Fighting Squads understand 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.


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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 so that 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 of the fire.

2.

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

3.

The rig communication equipment and procedures are to be tested by alerting designated shore 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 well and activate the Emergency Shut Down (ESD)/Deluge system.

6.

Drill crew secures well (i.e., when drilling/tripping, position pipe to well shut-in position and 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 at their designated muster stations.

10.

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

11.

The Fire Fighting Squad response is to include a simulation of actions necessary to mitigate 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.


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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 standby vessel 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.


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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 of lifeboats and associated equipment and that all on-board personnel (especially non-Rig contractor 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 in correcting unforeseen mechanical problems, this is the minimum complement required for drill launching.


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MARINE OPERATIONS Abandon Rig Drill Guidelines 1.

Ensure that rig radio frequencies, rig location, and headings to safe refuges are posted in each 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 least once per quarter.

5.

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

6.

Conduct an unannounced abandon rig drill and/or night drill once every month, and at least 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) during launching 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 prior to 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 in numerous locations. Announce that this is a drill over public address system.

3.

Rig communication equipment and procedures are tested by alerting designated shore base that a "Lifeboat Launching Drill" is in progress.

4.

All personnel are to report promptly to their station bill assignment and collect their abandonment cards from the card holder unless excused to continue operations. Excuses require 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 life jacket or survival suit depending on environment).


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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 their seat 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 predetermined clear frequency between Boat Commander and Person In Charge (PIC) or his delegate who 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 an orderly fashion and muster for drill discussion.

13.

If LAUNCHING the Life Boat, all personnel aboard the Life Boat except the "Minimum Life 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 to affect lowering of lifeboat.

16.

The order to release lifeboat from lowering lines shall not be given by anyone other than the Boat Commander and shall not be given by him until he ensures by visual means that lifeboat is waterborne.

17.

Boat Commander will release and maneuver lifeboat away from rig to a pre- designated rallying 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 to lifeboat.

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 abandonment procedures.

21.

Person in charge is to critique drill with Boat Commanders.


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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. Abandonment must 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.


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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 a supply/standby vessel is prepared to rescue if necessary.

5.

Conduct an unannounced man overboard drill and/or night drill once every month, and at least 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:


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To simulate a man overboard, throw buoyant dummy into water that is the approximate size, 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 to keep 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 shore base 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 as practical. 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 provide first aid to man overboard.

7.

If a supply or stand-by vessel is available, notify vessel for assistance. Vessels are to deploy scramble nets as soon as practical.

8.

If retrieval is possible by crane, crane operator is to lower a personnel basket with two crew members, wearing lifejackets, to retrieve the man overboard.

9.

When weather permits, launch rescue boat and retrieve Man Overboard. Ensure that the Electrician 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 of retrieval tools and techniques to recover an injured or unconscious individual after going overboard. Assess suitability of technique if weather conditions were significantly worse.

10.

If rescue boat is not launched, retrieve Man Overboard dummy with supply/standby vessel.

11.

Muster entire crew to a pre-designated location. Perform roll call to determine the number 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 to recover the man overboard.

13.

Rescue Team Leader is to prepare a critique and hold discussion session with the Rescue Team 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 can focus on specific skills in areas that need improvement and develop effective response teams.


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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 fire victim.

•

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 space using breathing equipment.


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MARINE OPERATIONS 3.7.10 PRINCIPAL ASPECTS OF DRILLS Drill scenarios should empathize skills listed below. Fire Drills:

Abandon Rig Drills:

Coordinating communication

Coordinating communication

Coordinating Fire Fighting Squads

Abandoning -one lifeboat disabled

Coordinating Rescue Teams

Abandoning -escape routes blocked

Handling Complex Fire Situations:

Operating lifeboats in a sea lane

•

Enclosed spaces

Muster & personnel accountability

•

Limited access

Man Overboard Drills:

•

Combination of the above

•

Fighting different fire types

Initial response for man overboard

•

Injured personnel

Using life boats and rescue boat

Use of Equipment such as:

Administering first aid

•

Breathing Equipment

Coordinating Communications

•

Stretchers

Coordination of other craft in the area

•

Fire hoses

•

Radios

3.8

Posting and maintaining lookout

SHIP COLLISION AVOIDANCE

Ship Collision Avoidance Foreword Drilling Units should not be located near a shipping lane nor between shipping lane boundaries if possible. If necessary, directional wells can be drilled to avoid these areas. If a Drilling Unit must be stationed in such an area, the risk assessment for the operations must include the proximity of the Drilling Unit to ship traffic areas.


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MARINE OPERATIONS All proposed Drilling Unit locations should be researched for shipping lane proximity and traffic in 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 and guidelines 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 ships approaching the site. However, the level of formal detection program implementation will depend on the proximity of the Drilling Unit to shipping lanes and/or heavy ship traffic. There are many "unofficial" shipping lanes used by ships as short-cuts and some detection program is always 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 the vicinity of high ship traffic and shipping lanes.

4.

Radar watch and/or standby vessel watch procedures when operating in close proximity to ship traffic should be completed and approved by the Field Drilling Manager to include; •

Action plans for different approach radar and ship course headings. Ship notification 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 for approaching ships.

7.

Immediately notify the Offshore Installation Manager after spotting questionable ships or vessel 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 procedures described below should be implemented on the drilling unit. Radar Operation


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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 radio room. Near VHF Marine radio.

2.

Qualified and trained radar operators are to man the radar station 24 hours per day and be relieved by qualified marine personnel at least every 3 hours for breaks.

3.

Radar unit settings shall be maintained as follows:

4.

•

Primary scanning set to 12 nm.

•

Audio alarm set for 5 nm.

•

Inner Guard Ring set for 2 nm.

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 course heading.

•

Contact ships reaching 5 nautical mile range of Drilling Unit's position and request 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" by the 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 Drilling Unit.


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MARINE OPERATIONS Radio Contact Not Established

3.

•

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).

Ships reaching the 4 NM range and on a course: Radar Watch Operator •

Notify the OIM.

Offshore Installation Manager

4.

•

Contact the vessel to divert its course and/or determine if ship has mechanical difficulty.

•

Notify the Operations Supervisor on duty that a collision is possible.

•

Notify supply/standby vessel to intercept ship.

Ship reaching the 4 NM range and on a collision course which cannot be contacted and/or has mechanical difficulty (engine/steering failure): Offshore Installation Manager •

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

5.

•

Notify Drill Crew to secure the well.

•

Notify Shore Base that a collision is possible and imminent.

Ships reaching the 2 NM range radar guard ring on a collision course:

Offshore Installation Manager •

Determine need for abandonment.

•

Sound the abandonment alarm for the Drilling Unit.

•

Broadcast navigational warnings continuously.


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Notify supply/standby vessel to assist in rig abandonment.

•

Abandon rig.


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MARINE OPERATIONS SECTION 3 - APPENDIX G-I MEMORANDUM ExxonMobil Development Co. Drilling DATE: TO: FROM: SUBJECT:

PRODUCTION AND DRILLING OPT. SUPTS OFFICE ENGINEERING TEAM " " Platform Drilling Program SIMOPS/MIRU Meeting

BACKGROUND " " Platform The jack-up drilling rig is scheduled to begin operations at the on about . On , a SIMOPS meeting was held to evaluate the risks involved with simultaneous drilling and production operations at the platform. Following is a summary of the review 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 or debris that might be in the immediate area where the rig is to be positioned. Determine if area pipelines need to be buoyed for the planned approach of the rig. At those platforms where a jack-up rig has 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 within 12 months, or if any substantial construction or workover work has been performed within the last year). Note, if any pipelines are within 490 ft of the rig, the MMS requires buoys, unless a waiver is obtained. 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, pipeline risers, etc. and determine if any relocation or protection work is necessary. Active pipelines that are expected to be located beneath the jack-up barge shall be depressurized during the MOB/DEMOB. For those lines to be reactivated following MIRU, a joint decision by Drilling and Production Operations Management is made regarding any special precautions necessary to ensure that an appropriate level of 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 as separators, 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 deliverability requirements for that facility. •

DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING

First Edition - May, 2003

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MARINE OPERATIONS 9) Ensure that the location of the rig's designated safe welding area meets all MMS and ExxonMobil regulations (consider distances from existing combustible material or any process equipment containing 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 or replacement 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 while the 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 process equipment, 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 local Officer in Charge of Marine Inspection of the United States Coast Guard prior to spud. The Field Superintendent 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. •



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MARINE OPERATIONS

PERSON IN CHARGE (PIC) • The will be the PIC. The Drilling and Field Superintendents will work together to coordinate tying the rig and platform ESD systems together, utilizing the I&E Technician, per the SIMOP's Manual. • The PIC and Field Superintendent should communicate each day prior to the 6:00 AM Production safety meeting regarding safety issues and work status. APPROVALS

Drilling Ops. Supt.

Production Ops. Supt.

SIMOPS Meeting Attendees:



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MARINE OPERATIONS SECTION 3 - APPENDIX G-II US-EAST SIMULTANEOUS OPERATIONS DEVIATION REQUEST DATE: LOCATION: ORIGINATOR: FIELD PIC: TYPE OPERATION: TYPE ACTIVITY: REQUIREMENT NO: IDENTIFY TYPE OF REQUIREMENT: MMS DURATION OF DEVIATION: FROM

MUST SHOULD TO

DESCRIPTION OF DEVIATION:

SPECIAL PRECAUTIONS TAKEN:

APPROVAL REQUIRED: FIELD SUPERINTENDENT: ORIGINATOR'S OA ID:


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SECTION 3 – APPENDIX G III

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

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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 Section of 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 Guidance Manual, is maintained, and is operational. Additionally, it will address personnel competency and personnel 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 contracted to 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 assessment consists 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 documents is 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 with the technical assistance of the Upstream Research Company.


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MARINE OPERATIONS

1.2.2 Inspection The inspection if required consists of visual and NDT of the following areas: cantilever, crane pedestals, helideck, jacking system, jackhouse structure, spud cans, and legs. Inspection plans for routine inspections can be developed by Bennett & Associates or ModuSpec. The URC should be contacted for inspection plans for unusual jackup applications such as sea ice, high seismicicty, unusual soil conditions, etc.


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DRILLING OPERATIONS

4.0 DRILLING OPERATION

4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 4.9 4.10 4.10.1 4.10.2 4.11 4.12 4.13 4.14 4.15

Introduction General Operations Guidelines Pre-Spud Operations Structural Drive Pipe Conductor and Surface Casing Interval Diverter Operations Intermediate / Protective Casing Interval Production Casing / Liner Interval Slot Recovery / Whipstock / Section Mill / Cut & Pull Wellbore Anti-Collision Guidelines Requirements for "Collision Risk" Wells Requirements for All Directional Wells Directional Surveying and Deviation Control Drill String Design Bottom Hole Assemblies Hydrogen Sulfide Considerations Hydrogen Sulfide Contingency Plan

______________________________________________________________________________ DRILLING OPERATIOS MANUAL - JACK-UP/PLATFORM BARAGE RIG DRILLING FIRST EDITION - MAY 2003

1 1 3 4 5 6 6 7 7 9 9 10 11 12 14 17 19

DRILLING OPERATIONS 4.1

INTRODUCTION

This section provides guidelines for conducting a safe, efficient, and environmentally sound drilling operation. These guidelines may be modified based on actual well conditions after approval as specified in OIMS. Specific requirements for each well will be covered in core drilling procedures designated by each drill team for their specific drilling operation. For details on the installation of the various wellhead components, refer to the wellhead manufacturer's operations manual. Applying proven drilling technology to efficient rig operations is essential to minimizing drilling cost. Since every hole drills differently, the drilling supervisor should remain flexible and exercise good judgement in requesting permission to make changes to an approved procedure. Extensive planning and design criteria has gone into the makeup of an approved drilling procedure. If upgrades are required because of onsite learning's or firsthand knowledge, the MOC (Management of Change) process must be used (see Section 4 – Appendix VII for suggested MOC Form). This process ensures that all drill team members have had the opportunity for input and are aware of all changes. There are a number of factors which contribute to fast, trouble free drilling: 1) consistently follow good practice, 2) complete rig acceptance tests and crew safety training prior to spudding, 3) set up communications and reporting systems prior to spudding, 4) have all material and equipment necessary for a job on location and checked, 5) have environmental protection systems installed and functioning 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 awareness of hole conditions, 11) implement and follow stuck pipe prevention practices, and 12) recognize well control early warning signs immediately. The intent of this manual is not to give specific recommendations for every situation but to give guidelines. Drilling personnel must also rely upon their experience and training to supplement this manual. 4.2

GENERAL OPERATIONS GUIDELINES

1.

All depth measurements are to be made from a consistent reference point, the top of the kelly drive bushing. "RKB" when determined on a rig with a top drive system shall mean the surface of the rotary table. After nippling up the casing head, record on the daily drilling report 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 the following conditions: • •

3.

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.

During routine drilling in normal pressure zones, WOB and RPM's are to be varied as required to maintain maximum performance. When drilling near anticipated abnormal pressure zones, the drilling parameters are to be maintained constant to allow for more accurate pressure detection.


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DRILLING OPERATIONS 4.

Below each string of casing, except conductor, a pressure integrity test is to be conducted after 10' of new hole has been drilled to determine the formation integrity. The PIT will normally be taken to leak-off or jug tested to the pressure specified in the procedure, but will not exceed the 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 trapped pressure. Each rig must have a procedure in place to monitor pressure below the blind rams when 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 master bushing must be free and functional for the rotary to be considered operational. The kelly bushing shall be locked at all times (or removed) except when procedures specifically require them to be temporarily unlocked .

8.

While tripping in the hole, fill the drill string frequently. Frequency is to be determined by the drilling superintendent based on current mud weight, hole conditions, and depth. The trip tank will be used while running in the hole unless otherwise addressed by the Field Drilling Manager. 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 the number 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 no mud to enter the drill string. After running 1,860 feet, the drill pipe float fails allowing the mud to U-tube and balance in the drill pipe and annulus. Depending on the hole size, the mud level would drop as follows: Hole Size, inches 8½ 12 ¼ 17 ½ 19 ¼

Mud level drop, feet 520 238 114 94

An equation specifically for 5 inch 19 1/2 ppf drill pipe to calculate the fluid level drop for the above 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 feet D is the hole diameter, in inches A general equation to calculate the mud drop for a different size string being run in the hole is: 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/feet L is the length of drill string run without filling in feet A is the annulus capacity in bbl/feet DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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DRILLING OPERATIONS The drilling engineer can easily generate a series of tables for a specific well and an optimum fill up schedule based on an acceptable downhole pressure drop which would be based on pore pressure estimates while drilling. 9.

The completion or plug and abandonment program should be developed while drilling proceeds. This allows equipment to be procured in a timely manner and completion or P&A considerations, such as casing pup joints run to aid in perforation depth control, to be implemented during the drilling phase.

10.

A non-ported float will be run when drilling through casing set at insufficient depth to allow for the well to be shut in. After sufficient casing is set to allow the well to be shut in, a ported float will be run. Modification to the drill pipe float, including porting, must not be done on the 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 a hardened port in the flapper. The common sizes of float valves are: Bit Size Tool joint Float valve size

6 inch 3 1/2 Regular 2F-3R

8 1/2 inch 4 1/2 Regular 4R

12 1/4 inch 6 5/8 Regular 5F-6R

A safety valve (ball open) and inside BOP (plunger locked down) will be on the rig floor. A safety valve and an inside BOP will be available, on the rig floor, for each size drill pipe that is currently used. Prior to running or pulling any casing liner or tubing, a cross-over back to the safety valve and a safety valve must be on the rig floor. The safety valve must be function tested 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 this inspection 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 perforating guns are rated.

15.

Casing annulus pressure should be monitored daily on all rigs with surface wellheads. If casing pressure is detected, it should be reported on the Daily Drilling Report. The situation should be reviewed with the Operations Superintendent to determine if any corrective actions are 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 run downhole screens when no nuclear source tools are in the BHA. Always discuss use of DP or downhole screen with Operations Superintendent.

4.3

PRE-SPUD OPERATIONS

1.

Develop a waste disposal plan which addresses the following: •

Plastic and Styrofoam


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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 the Operations 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 Operations Superintendent 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 225 blows per foot) with a diesel/hydraulic hammer. Plain-end or quick connect pipe is employed and welded/made-up as the joints are added to the string. For a height estimate, use 45 feet for the diesel/hydraulic hammer and slings and 42 feet for a joint of drive pipe. Although not essential, use of a pipe bevel machine and two welding machines will greatly speed up the driving process for pipe that must be welded. It is important that driving not stop once started (e.g. an overnight shut down) 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 lifted by padeyes that probably will not have had the welds inspected. While driving, the drive pipe could enter a soft zone and drop rapidly. A quick connect type connection allows use of a false rotary table 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 hammer blows per foot reach the recommended maximum prior to achieving planned/adequate drive pipe penetration. Wash-out of drive pipe during driving operations requires risk assessment including consideration of shallow hazards, prior MMS approval, and appropriate EMDC and EMPC management approval.


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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; surface casing running, cementing, hang-off, and wellhead installation. 1.

The purpose of the conductor casing is to provide adequate Well Control integrity to allow drilling to the surface casing point. Conductor casing is typically required when: • • •

2.

An active drilling program has not been conducted on a specific platform within the previous 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.

The purpose of the surface casing is to provide adequate Well Control integrity to allow drilling to the next casing setting point (protective or production casing depth). Surface casing is the first casing string on which the full 5 preventer BOP stack is nippled-up. Surface casing 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 2000 feet to several thousand feet. Surface casing is cemented to surface either during the primary cement job or after the primary job with a grout job.

Unless otherwise specified in the drilling program, conductor and surface holes will be drilled from below the drive pipe shoe to ~20' below the planned shoe depth for the respective casing. Make sure to stop drilling prior to exceeding the maximum permitted depth for the hole interval. The rathole is less critical with a weld-on wellhead as it is probably desirable to set the conductor or surface pipe on bottom. The conductor and surface holes will generally be drilled with SW-gelCLS mud systems to total depth. Where significant shallow gas risk is identified, the conductor or surface hole may be drilled utilizing a pilot hole to facilitate well control operations. The primary means of well control during pilot hole drilling is a dynamic kill. The annular clearance between drill collars and the wellbore provides a friction pressure drop, to help increase the effective BHP at high circulating rates in the event of a well control problem. If the well kicks, circulate drilling mud at maximum rate. The bit should be within 200 feet of bottom. Spot one ppg heavier mud or barite plug if well flow cannot be 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 in reserve until the pilot hole has been drilled. The minimum volume of mud to be mixed will be specified in the drilling program and will generally be the sum of the annulus volume between the drill string and the pilot hole from TD to the flowline plus the volume required to stop reservoir flow as determined by dynamic kill simulations for the applicable hole geometry and reservoir conditions. In areas where the potential for the presence of shallow gas is low, dynamic kill simulations will not be required. If the dynamic kill calculations are made, a volume pumped versus pump rate plot will be produced which has a No Kill Region and Kill Region.


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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 the swabbing 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 penetration for 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 up during all conductor and surface hole drilling. A kill line will be connected to one of the spool outlets and the diverter lines will be connected to the two 10" side outlets. The primary consideration is to have a straight diverter line with a non-restrictive valve (ball or gate valve). The diverter line must extend beyond the rig cantilever and must not be directed onto the platform or toward 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 line valve opening. Anchor the end of the diverter line. Consider need for installing a flare line remote ignitor. 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 - normal or abnormal pressure. In areas where abnormal pressure formations are encountered or hole conditions mandate formation isolation, intermediate or protective casing may be required prior to reaching total depth. Casing seat or TD Hunts may be required. Fracture gradients of the formations encountered should be estimated based on offset drillwells. If there are no applicable offset 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 a float shoe, float collar, and possibly casing pup joints. The cementing assembly will include top and bottom wiper plugs, and cement head/manifold. The Casing and Cementing Sections of this manual 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 choke manifold. Let drilling crew members work the choke. (Alternately this can be done after displacing the hole with mud to determine the choke line pressure drop for kick calculations.) A casing test will usually be mandated by the governing regulatory body prior to drilling out and after landing the BOP stack. Run a pressure integrity test after drilling out below the intermediate casing string. Update kick sheet daily while drilling.


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PRODUCTION CASING / LINER INTERVAL

Drilling the Production Hole The same guidelines given in the Drilling the Intermediate Hole section apply when drilling this hole section. If using a top drive, pick up sufficient drill pipe to drill to total depth. A ported drill pipe 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 choke manifold. Let drilling crew work the choke. (Alternately this can be done after displacing the hole with mud to determine the choke line pressure drop for kick calculations.) The casing/liner will be pressure tested in accordance with applicable Regulatory requirements. Update kick sheet daily while 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 or around existing wells. Slot recovery allows for new wells from the surface while whipstocks and casing cut & pulls reuse existing casing to reach new objectives. In general, deep whipstocks will be less expensive than cut & pulls (C&P), which are generally cheaper than slot recoveries and new drill wells. When deciding on whether or not to reuse a wellbore, factors to include are: the direction of the existing well compared to the desired objective(s), existing casing program vs. hole sizes and completion necessary, future life of the existing completion, ability to reach (and others on a multiwell 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 the suitability of the well prior to moving the rig onto location. This includes a thorough researching of the well's history (e.g., drilling wear, noted pressure tests, cement records), inspection of the wellhead by a qualified service technician, pressure testing casing as possible, and performing all possible P&A work. If the cement job for a casing string is questionable, it is sometimes advisable to run a high-quality imaging tool (e.g., Schlumberger's USIT log) to determine cement quality and TOC 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 to allow a Whipstock from the surface casing). It will be important to verify compliance with the appropriate 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 its conductor slots used by previous wells. This helps avoid costly platform modifications that could otherwise be required. Diver Divert and Drive Pipe Whipstock are the two types of slot recovery available for use once the subject well has been fully P&A'd (see Section 13 for details on P&A operations).


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DRILLING OPERATIONS For a Diver Divert slot recovery, all strings of casing (including drive pipe) are cut and recovered from ~5 feet above the mud line. The new drive pipe is lowered through the platform's conductor guides to below the water line where divers then guide the new drive pipe to the side of the existing casing stubs. The new drive pipe is then driven to the desired depth and well operations proceed as normal. It is often desired to have a deviated drive shoe on the bottom of the drive pipe to help ensure 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 and recovered ± 60 – 80 feet below the mud line. A whipstock is attached to the bottom of the new drive 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 direction desired. Once the whipstock is mated to the abandoned conductor, the new drive pipe is sheared off of the whipstock and the drive pipe is driven to the desired depth. Again, operations can now proceed as normal. Drive pipe whipstocks are generally the preferred option because there is no requirement for divers to be in the water. Both options require special evaluation of the anticipated drive pipe deflection to determine 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 from previously drilled wells. The Whipstocks can be either single-trip or multiple trips. The difference in 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 for shallow exits where trips are fast). The general plan of operations is that the Whipstock is run in hole, oriented, and set (either mechanically or hydraulically). The Whipstock should be oriented to the direction desired for sidetrack (generally ~30° – 45° from highside). Then, casing mills are used to exit the casing and make enough new hole to perform a PIT. Once this is complete, new drilling operations are able to proceed. It is important to never rotate anything across the face of the whipstock; 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 the metal shavings from the system. Section Milling Section milling is similar to whipstocking in that existing wellbore is exited by milling a hole in the casing. The main difference is that the means of exiting the casing is not a mechanical tool. To Section Mill, underreaming-type casing mills are run into the existing casing string and a hole is milled in the casing (typically, ~100'). A cement plug is then placed across the milled interval and the well sidetracked off of this cement plug. This method is preferred over Whipstock operations when the new hole section will be long, directionally complex, or otherwise cause excessive wear and 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 by removing 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 MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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DRILLING OPERATIONS the old casing from the hole. Based on the depth of the cut, the removal of casing could either expose formation or the previous casing string. 4.10 WELLBORE ANTI-COLLISION GUIDELINES Wellbore anticollision guidelines in this section are a recommended minimum standard for all operations. These guidelines should be reviewed on a well by well basis. Any exceptions to these standards requires Operations Superintendent approval. 1.

The most critical piece of information in the anti-collision arena is data quality. All platform surveys 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 RKB datum height (these have been incorrect in the past).

2.

Once a well path has been generated, have the directional contractor run an anti-collision report. 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 that pass near the proposed well (wells may originate from an adjacent platform or an open water location). Pay attention to tubingless wells, producing wells, gas lifted wells, and plugged wells.

3.

In the SIMOPS meeting held between EMDC and EMPC, discuss the status of the previously identified wells. Plan to shut in, bleed off and or set plugs in wells close to the proposed well path.

4.

During drilling operations near interference issues, survey every stand and use current technology to provide the best information possible (i.e., surface readout gyro). Have the directional contractor supply an additional directional driller to run projections and anticollision reports only. Use a jetting assembly to steer near interference. Minimize Drill string rotation (DO NOT USE A MOTOR) while near another well. Monitor constantly for torque, 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) of that of an offset well. 4. If SIMOPS or local regulatory collision avoidance requirements are more stringent than EMDC requirements, the more conservative requirements will be followed. 5. Either Wolff & DeWardt or ISCWSA models may be used to develop collision avoidance and EOU calculations. The vendor is responsible for selection of tool error factors and the performance 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 MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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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. FDM approval is required to operate with an EOU Separation Distance < 10ft, or Separation Factor < 1.5. The FDM may approve exceptions to shut in requirements if risk can be reduced to acceptable levels through operational practices. SEPARATION DISTANCE •

If the EOU Separation Distance projected to the next survey point is < 10 ft, monitor the applicable offset annulus continuously.

•

If the EOU Separation Distance projected to next survey point is < 5ft, shut in the offset and set a plug below the estimated intercept depth (or close SSSV if it’s below intercept point). Monitor annulus continuously. SEPARATION FACTOR

•

If the EOU Separation Factor projected to the next survey point is < 1.5, monitor the applicable offset annulus continuously.

•

If the EOU Separation Factor projected to next survey point is < 1.2, shut in the offset and set a plug below the estimated intercept depth (or close SSSV if it’s below intercept point). Monitor annulus continuously.

1. As a final planning check, the onsite directional driller is to run an independent collision avoidance 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 are required 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. The engineer, first line engineering supervisor, and operations superintendent must endorse the plan prior to field implementation. 2. FDM approval of MOC is required for changes in trajectory after final plan approval that create 1) a “Collision Risk Well”, or 2) a change in the shut in requirements of an offset well (per Separation Factor or Separation Distance rules). 3. The drilling program will specify the type of survey tools and minimum frequency of surveys in each interval. 4. Critical pre-drill planning data will be summarized and transmitted to the survey and directional 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 MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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DRILLING OPERATIONS •

Survey tool types and frequency, by interval

5. All survey data will be communicated between parties at the rig site in a standardized format. Either the contractor or ExxonMobil may develop the format (electronic or written). 6. The drilling engineer will review the information in the final well survey for accuracy and initial 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 of uncertainty fits fully within the specified geologic target on the planned line of approach. If this cannot be achieved, client management approval is required to drill a trajectory with a reduced 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 (vertical and directional) as drilling progresses. Directional control ensures a known bottom hole location and well trajectory in order to avoid collisions/damage to offset wells and efficiently drill to the geologic objective(s) and relief well targets if necessary. For relief well purposes, it is important to know the position of the well to within 50 feet, which is the effective range of noise log and MagRange tools. For the purpose of applying the following general survey requirements, a vertical well is defined as a well that has less than three degrees of inclination from surface to total depth. The following table summarizes the minimum surveying requirements: Type of Well Vertical Well (less than 3°) Directional Well during normal drilling Directional Well during planned angle changes Prior to setting surface and deeper casings in both directional and vertical wells Total Depth on both directional and vertical wells

Requirement Inclination Survey every 1000' Inclination and Azimuth every 500' Inclination and Azimuth every 100' Inclination and Azimuth 500' from csg shoes

Inclination and Azimuth 500' from TD

A composite survey from either the drive pipe or conductor shoe to TD must be provided per MMS requirements. Surveying Guidelines 1.

If well surveys are required beyond the minimum summarized above, they will be specified in the drilling program.

2.

To determine surveying requirements, the following casing definitions will be used:


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DRILLING OPERATIONS Drive, or Structural, - pipe which is driven to support unconsolidated deposits and provide hole stability for initial operation (normally 20-30 inch). Conductor - Set below drive pipe and before surface pipe to mitigate some shallow drilling hazards. Surface - a blowout preventer stack is nippled-up on top of this string and a pressure integrity test 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 MWD surveys with a single shot survey. Standpipe or mud pump suction screens are preferable to drill pipe screens. Only run downhole screens when no nuclear source logging tools are in the BHA. 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 survey may be run. EPRCo's Wellpath program or vendor software can be used to estimate the amount of error that results from using various survey tools and aid in the decision to run a multi-shot or gyro survey.

6.

The drilling superintendent should be provided directional data on a continual basis. For directional wells, the directional driller and drilling engineer are to maintain a wellbore trajectory record and a current wellbore plot. All directional plots are to be updated, and any significant deviation from the planned directional program is to be presented to the operations superintendent 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 IADC Report. All directional information should be converted to GRID measurements when reported 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 identified in the appropriate procedures. Jet-Lube's Kopr-Kote can be used for every connection from bit to kelly/top drive. KoprKote does not contain zinc or lead. Prior to application of Kopr-Kote, the tool joint threads should be cleaned to bare metal. To prevent galling of the non-magnetic components when using Kopr-Kote, connections should be cleaned, inspected, and given a MAG-COAT. Without MAG-COAT, nonmagnetic connections will have a higher incidence of galling using Kopr-Kote.

2.

Change the drill pipe stand breaks on every trip.


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Maintain an accurate strap of the drill pipe on the rig floor. The well depth is determined by the driller's STM.

4.

Use a drilling jar that has a large ID so that it is possible to use a wireline string shot or severing charge if required.

5.

Drill string components should have the same basic connection OD unless a bottlenecked crossover is used to provide a transition. All drillstring component connection OD's must be externally fishable for the hole size they are used in. Exceptions must be approved by the Operations Superintendent.

6.

If possible, the drill string is to be designed to withstand a minimum of 100,000 lbs. of overpull 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 loads using the FORCAL program (see Directional Drilling BHAs) for difficult directional wells and/or critical wells.

8.

Limit the rotary torque during normal drilling operations to drill pipe connection makeup torque in order to prevent over-torquing the drill pipe connections. Check the actual makeup torques used by the Drilling Contractor.

9.

If the drill pipe is new or refurbished, inspect tool joints for abrasive hard banding which could 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 drilling service (i.e. critical or standard). The following inspection frequency is recommended: Rotating Hours Between Inspections WELL SERVICE CATEGORY Critical Service Standard Service

Drill Pipe 1500 2500

Drill Collar/BHA Components 6" and Smaller 6-1/4" and Larger 150 200 250 300

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 with Standard 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 to DS-1 are given in the ECIDO Drilling OIMS Manual. There are several classifications of well categories and OIMS requires that drill string inspection frequency as well as casing design be based on well categories. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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DRILLING OPERATIONS The OIMS manual designates well service categories as standard or critical in Element 3 and lists three conditions which qualify a well as critical. The top drive should have a magnetic particle examination of the exposed surfaces on all load bearing 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 for drilling 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 each connection 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 not allow 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 each component (OD's, ID's, lengths, serial numbers, etc.). The dimensions should be measured in such a way as to contribute toward successful fishing. Outside diameter dimensions should be taken 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 to Section 5 (Bit Classification and Hydraulics) for gauging guidance.


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Maintain stabilizer blade OD, according to the BHA programmed design, by gauging them every trip and replacing as needed. It is preferable to not change more than one stabilizer per trip. 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 been damaged 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 pertinent drilling procedure. The following considerations should be included when performing a BHA design: 1.

HeviWate drill pipe run between the drill collars and drill pipe provides a transition zone as well as additional available string weight. In deeper wells with increasing angle, minimizing HWDP 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 do not exceed a 2" reduction in size, or that the stiffness ratio does not exceed 5.5 for a noncritical 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 3/4 inch drill collars with 3 1/2 IF (NC 38) connections. Experience has shown that rotary shoulder connection failures have rarely occurred using 4 3/4 inch drill collars even with BSRs below 2.0.

5.

Select components of the BHA considering lost circulation material requirements and potential 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 relief grooves 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 a longer contact area increase wall support area in soft formations. Stabilizers with a shorter contact area are preferable in hard formations. Consider use of spiral, integral blade stabilizers 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 a foundation 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 fear of fatigue failures as a result of buckling. However, inclination of a wellbore was seldom taken into account in calculating the required drill collar weight. As a result most operators did not add collars DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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DRILLING OPERATIONS as hole angle increased which undoubtedly caused drill pipe to be run in compression. Fatigue failures 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 without buckling and fatigue failures. Buckling does lead to accelerated fatigue damage and tool joint wear which can be tolerated for short periods of time especially if it would save a trip or reduce the chance 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 very resistant to buckling since the hole supports and constrains the pipe throughout its length. An important benefit of running drill pipe in compression is that the length of HeviWate and drill collars 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 or straight 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 as how drill collars will bend between stabilizers. Directional service companies can provide similar drill pipe design software. Be sure to note the limitations of the particular software being used and check this against the situation being analyzed (e.g. FORCAL needs modified input when modelling casing running because it is based on string theory). The new BHA design methods which take advantage of the reduced BHA buckling tendency in directional wells have been used since the early 1980s with outstanding results. The short drill collar lengths required (frequently just MWD/LWD equipment for GOM operations) resulted in reduced torque and drag and reduced frequency of differentially stuck BHAs. The amount of drill pipe, HeviWate drill pipe, and drill collars run in compression is well specific and depends on hole size, mud weight, well angle, desired WOB, and torque and drag constraints. All drilling operations should take advantage of design methods which can minimize problems with torque and drag and stuck BHAs. When differential pressure exceeds about 1,500 psi, take special care to avoid differentially sticking the drill string. Implement special procedures such as making rotating connections, controlling mud fluid 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 pressure greater 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 wells with >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 and HeviWate drill pipe in compression as indicated by the FORCAL program. In most cases only non-mag collars are required in addition to MWD/LWD collars based on well angle, hole size, 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 is available to be run in place of the non-mag collar. At high angles, additional DC's create a very high bending stress in the top stabilizer connection. They also create the potential for stuck pipe if they sag to contact the wall.


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The computer program ROB in conjunction with the directional service company software/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 every 60 feet.

4.

The directional drilling contractor should provide recommended BHAs for evaluation by the Drilling Engineer.

5.

Keep up with differential pressure between the mud weight and pore pressure. Take special precautions to prevent stuck drill strings anytime differential pressures exceed about 1,500 psi regardless of the type formation drilled.

6.

In harder formations, roller reamers are sometimes used in lieu of stabilizers. Roller reamers are often used when significant amounts of reaming is anticipated or rotary torque reductions are desired. Non-rotating drill pipe protectors or sleeves should be considered when torque reduction is desired.

7.

For steerable PDM drilling assemblies, optimize mud motor and LWD tool configuration to anticipated well conditions including: drilling fluid type, flowrate, downhole temperature, anticipated time between trips, bit type, and drilling WOB and torque requirements. For GOM Directional wells use high performance, extended power section PDMs whenever possible.

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 be axial, rotational, or combined. Two coefficients of friction may be used, one for cased portions of the well and the other for the open hole section. Tripping of tubulars into and out of the wellbore can be modelled. Given the measured torque or hookload, FORCAL can calculate the coefficient of friction. ROB V.5.01 software predicts the build/drop and walk performance of rotary and motor assembly BHAs. The user can perform sensitivity analysis to predict the effects of various parameters on BHA performance. Geology effects such as bedding planes can also be included and a calibration module allows the user to take advantage of local experience. ROB performs drill ahead and well extend 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/drag and build/drop and walk of different BHA's. Torque and drag surveillance should be monitored for all protective and production holes in excess of 40° with greater than 1500' MD of openhole. An example is included in Section 4 – Appendix VIII. 4.14 HYDROGEN SULFIDE CONSIDERATIONS (OIMS Manual Element 10) Hydrogen sulfide is an extremely toxic gas. In drilling operations, a wide range of hydrogen sulfide concentrations may be found. The effects of these concentrations also range widely - from a disagreeable odor or eye irritation at low concentrations to serious illness or even death at higher concentrations. All personnel working in areas where they may be exposed to hydrogen sulfide DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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DRILLING OPERATIONS should be trained to recognize and understand its hazards and to protect themselves from its harmful effects (contractor and service company personnel should be H2S certified before coming to the rig). Personnel should be trained to rescue victims and administer first aid to those who are overcome, without endangering themselves. All personnel on the rig should have access to an escape pack. Hydrogen sulfide is an extremely toxic, colorless, heavier than air (1.18 specific gravity) gas. It burns with a blue flame and produces sulfur dioxide gas which is slightly less toxic than hydrogen sulfide, but can cause eye and lung irritation and serious injury. In low concentrations, hydrogen sulfide has the odor of rotten eggs. It forms an explosive mixture with air at concentrations between 4.3% and 46% by volume. It is soluble in water and oil but becomes less soluble as the fluid temperature increases. When there is a potential for encountering hydrogen sulfide, the following must be considered and addressed: • • • • • • • • • • • • • • • • • •

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 on the physiological effects of various concentrations. An example guideline on facial hair and corrective lenses as pertains to respiratory equipment could be: • • • •

Clean shaven in the face-piece-sealing area and must not have facial hair that could interfere with the function of the mask. Before donning a respirator with a full face piece, any head covering, glasses and foreign items 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


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DRILLING OPERATIONS mask. Hooded Egress Units allow for the use of prescription eyeglasses during emergency evacuations. Guidelines For Drilling For all operations where H2S is being produced on the platform or where H2S may be encountered while drilling, a contingency plan will be developed and approved by the applicable regulatory agency as required. Hydrogen sulfide monitoring should be continuous while drilling anywhere covered by the contingency plan. Monitoring should be done with remote sensors which are located at a minimum near the bell nipple, on the rig floor, and above the shale shaker. Gas trap gas and vulnerable areas may also be monitored. The approved contingency plan will have details on where sensors should be placed. Maintenance and logged calibration is important. At the first indication of 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 to establish background concentrations. Draeger has recently changed the scale on their tubes, and the tube factor given in API RP 13B-1 should be carefully checked to ensure the tube factor matches the 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 with drilling. 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 ECI drilling supervisor All non-essential personnel proceed to upwind assembly area. No non-essential personnel will be allowed in any area with possible H2S exposure.


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DRILLING OPERATIONS •

• • • •

Conduct safety meetings and review plans to return to drilling. Plan response in the event hydrogen sulfide concentration exceeds twenty ppm. Repeat safety meeting before crews come on tour. All personnel check their safety equipment for proper operation and location. Persons without assigned 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 mud logging gas analysis, all personnel directly involved with the operation are to have readily available individual self contained breathing apparatus (SCBA). All other personnel are to be alerted and made 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 minutes prior to the calculated arrival time of the kick fluid and remain in the SCBA's until 30 minutes after the kick fluid is vented down the flare line. Attempt to burn the kick gas if conditions allow, and appropriate Regulatory Approvals have been obtained. During the entire kick circulation, a designated member of the drill crew is to check (with a SCBA on) the shaker area for H2S concentrations. Also, the return drilling fluid is to be monitored for H2S throughout the entire well killing operation. If at any time during the kick circulation, H2S concentration exceeds 20 ppm or more in the working atmosphere (air), the well is to be shut in and non-essential personnel are to be moved into the 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, considerations are to be made for bullheading the formation fluid back into the formation, rather than circulating the 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 and production testing operations. If working on a well with hydrogen sulfide gas, all workers in the area should mask up while retrieving the back pressure valve.


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BIT CLASSFICATION AND HYDRAULICS

5.0 BIT CLASSIFICATION AND HYDRAULICS

5.1 5.2 5.3 5.4 5.5 5.6 5.7 5.8 Reference

General Drill Bits IADC Bit Classification System IADC Bit Grading System Running Procedures for Fixed Cutters Hydraulics Program Guidelines for Hydraulics Optimization Hydraulics Optimization

______________________________________________________________________________________ DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION - MAY, 2003

1 1 3 6 8 10 12 17

BIT CLASSIFICATION AND HYDRAULICS 5.1

GENERAL

The Drilling Program shall specify a recommended bit selection and hydraulics program based on offset well data and (or) anticipated drilling conditions. The bit and hydraulics programs specified in the Drilling Program are to be viewed as guidelines only and adjustments are to be made as necessary 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 to determine the point at which ROP begins to decrease with increasing WOB. The “flounder point” in the drill-off test is the WOB at which the bit is beginning to ball. It may be possible to increase the WOB and ROP if bit cleaning is improved. Options for improving bit cleaning are increased hydraulics, reduced blades on PDCs, mud additives (ROP enhancer) if MW < 10 ppg, and inhibitive mud. Vary weight on bit (WOB) and rotary speed (RPM) as required to maintain maximum performance, taking into consideration abnormal pressure detection requirements, high drill gas, and the carrying capacity of the mud (ability to remove cuttings efficiently).

2.

When drilling near anticipated abnormal pressure zones, the drilling parameters are to be maintained constant to allow for more accurate pressure detection.

3.

Monitor bit ROP trends to determine when the break even point, based on increasing cost per foot, 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 System presented 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 of drilling 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 anticipated lithology. Soft formation mill tooth bits will generally be the bit of choice for surface hole drilling.

2.

Sealed bearing (and possibly journal bearing) tooth bits will generally be recommended for drilling the soft surface hole sediments in an attempt to drill this section in one bit run.

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

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BIT CLASSIFICATION AND HYDRAULICS 3.

In deeper hole sections, where multiple bit runs are required, bit selection is to be based on bit performance optimization, unless potential upcoming operations (coring, intermediate logs, casing seat hunt, etc.) dictate otherwise.

BIT SELECTION CHART FORMATIONS CHARACTERISTICS

IADC BIT CLASSIFICATION TYPE

Sand, Shale, Anhydrite, Soft Sandstone and Soft Limestone, Shaley Limestone

1

5

Shale, Chalk, Sand, Anhydrite, Shaley Limestone, Soft Limestone with Hard Streaks. Shale, Siltstone, Sand, Lime, Anhydrite, Dolomite, Calcareous Sandstone, Sandstone with Chert & Pyrite Streaks Sand, Siltstone, Quartzite, Granite, Dolomite, Chert Conglomerates, Abrasive Sandstone & Limestone. Quartz, Sandstone Conglomerates, Volcanics such as Basalt, Gabbo, Rholite, Granite.

2

SOFT TO MEDIUM: Low Compressive strength interbeded with hard layers. MEDIUM: Hard with moderate compressive strength.

EXTREMELY HARD: Very hard and abrasive.

FIXED CUTTERS INSERT 4

Clay, Marl, Gumbo, Red Beds, Unconsolidated Sands & Shales, Halite

HARD: Hard and dense with high compressive strength, some abrasive layers.

1st & 2nd CHARACTER

TOOTH 1

SOFT: Sticky, Low compressive strength and high drillability.

MEDIUM TO HARD: Dense with increasing compressive strength but non or semi-abrasive.

1st CHARACTER ROCK

BITS

PDC M(S)1 M(S)2 M(S)3 S(M)4

DIAMOND

M(S)1

M6 M7

M(S)2 M(S)3 M(S)4

6

M(S)2

S(M)3 M(S)4

2

6

M2

M(S)3

M(S)4

3

7

8

M6 M7 M8

M6 M7 M8

M3

M6

M4

M7 M8

M7 M8

The table above correlates formation characteristics against bit type based on the IADC bit classification system. Although this is fairly straight forward for rock bits, it is more nebulous for fixed cutter bits (in particular, the PDC variety). PDC usage has only come into its own in the last few years; compared to rock bits this technology is still in the "toddler stage". Consequently, a good, compressive, clear-cut classification system has not yet been developed. To classify the fixed cutters, the World Oil's 1995 Drill Bit Classification Tables were reviewed to determine which bit types were recommended by manufactures for a particular formation. The bold characters indicate DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE DRILLING First Edition - May, 2003

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BIT CLASSIFICATION AND HYDRAULICS

The bit classification which appears most often under a particular formation. The relative size is secondary indication of how often a particular bit type is recommended. A comprehensive discussion 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 and bearing type. For fixed cutter bits, the characters identify body material, PDC cutter density or Diamond 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 abrasive as the series number increases. Mill Tooth Bits (1-3) 1 - Soft 2 - Medium to Medium Hard 3 - Hard, Semi-Abrasive / Abrasive Insert Bits (4-8) 4 - Soft 5 - Soft to Medium 6 - Medium to Hard, Semi-Abrasive 7 - Hard, Semi-Abrasive/Abrasive 8 - Extremely Hard, Abrasive Second Character: Cutting Structure Types (1-4). Refers to the degree of hardness within a formation type. 1 - Softest formations => 4 - Hardest formations Third Character: Type of Bearing / Gage Protection (1-9). 1 = Standard Roller Bearing 2 = Roller Bearing, Air Cooled 3 = Roller Bearing, Gage Protected 4 = Sealed Roller Bearing 5 = Sealed Roller Bearing, Gage Protected 6 = Sealed Friction Bearing 7 = Sealed Friction Bearing, Gauge Protected DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE DRILLING First Edition - May, 2003

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BIT CLASSIFICATION AND HYDRAULICS 8 = Directional 9 = Other, Reserved For Future Use Fourth Character:

Special Features (Alpha characters). Defines additional features of roller cone bits with regard to cutting structures, bearings, seals, hydraulics, and specific applications.

A = Air Application (Journal bearing with air nozzles) B = Special Bearing Seal C = Center Jet D = Deviation Control E = Extended Jets (Full length) G = Extra Gage / Body Protection H = Horizontal / Steering Application J = Jet Deflection L = Lug Pads M = Motor Application S = Standard Steel Tooth Model T = Two Cone W = Enhanced Cutting Structure X = Predominantly Chisel Tooth Inserts Y = Predominantly Conical Inserts Z = 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 standard gage 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. Cutter count is based on 1/2" cutter size, cutter (larger/smaller) sizes are projected as 1/2" cutter densities. 1= 2= 3= 4=

30 or fewer 1/2" cutters 30 to 40, 1/2" cutters 40 to 50, 1/2" cutters 50 or greater 1/2" cutters


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BIT CLASSIFICATION AND HYDRAULICS Diamond Bits (6 - 8) A designation of 6 represents larger diamonds while 8 represents smaller diamonds 6 = < 3 stones per carat 7 = 3 to 7 stones per carat 8 = > 7 stones per carat Note: (0, 5, & 9) are undesignated and reserved for future use. Special designs using additional gage cutters, such as sidetrack bits, or bits for horizontal drilling, 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 the cutter while for Diamond bits, it refers to the type diamonds. PDC Bits (1- 4) Size 1 = > 24mm in diameter 2 = 14mm to 24mm in diameter 3= 9mm to 13mm in diameter 4 = < 8mm in diameter Diamond Bits (1- 4) Type 1 = Natural Diamonds 2 = TSP (Thermally Stable Polycrystalline) Diamonds 3= 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 on overall length of the cutting face of the bit. PDC Bits (1- 4) 1 = Fishtail 2 = Flat Face 3 = Long bit profiles 4 = Increasingly longer bit profiles Diamond Bits (1- 4) 1 = Flat Face TSP and Natural Diamond 2 = Long 3= Longer 4 = 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 Material D = Natural Diamond

M = Matrix Body PDC


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BIT CLASSIFICATION AND HYDRAULICS S = Steel Body PDC O = Other (TSP)

T = Thermally Stable Polycrystalline

First Number: Bit Profile (Gauge Point to Cone) 1 = Long Taper, Deep Cone 3 = Long Taper, Shallow Cone 5 = Medium Taper, Medium Cone 7 = Short Taper, Deep Cone 9 = Short Taper, Shallow Cone

2= 4= 6= 8=

Long Taper, Medium Cone Medium Taper, Deep Cone Medium Taper, Shallow Cone Short Taper, Medium Cone

Second Number: Hydraulic Design Type Body

Changeable Jets

Bladed Ribbed Open Faced

1 4 7

Fixed Ports

Open Throat

2 5 8

3 6 9

Alternate designations: R = Radial Flow, X = Cross Flow, O = Other Third Number: Cutter Size and Density Cutter Size Large Medium Small Impregnated

Light Density

Med. Density

1 4 7 0

Heavy Density

2 5 8 0

3 6 9 0

Note Size Distribution Definitions Small

Þ Þ

Greater than 7 stones/carat for natural Diamond. Less than 3/8" diameter of usable height for PDC bit.

Medium

Þ Þ

3 to 7 stones/carat for natural diamond. 3/8" to 5/8" diameter of usable height for PDC bit.

Large

Þ Þ

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 INNER ROW 1

CUTTING STRUCTURE OUTER ROW DULL CHAR. 2 3 (1) CUTTING STRUCTURE - INNER Inner 2/3 of bit.

LOCATION 4

B BEARING SEALS 5


G REMARKS GAUGE 1/16" OTHER CHAR. REASON PULLED 6 7 8 (2) CUTTING STRUCTURE - OUTER Outer 1/3 of bit.

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BIT CLASSIFICATION AND HYDRAULICS STEEL TOOTH BITS - A linear measure of lost cutting structure due to abrasion or damage. (0 - no loss of cutting structure due to abrasion or damage, 8 - total loss of cutting structure due to abrasion or damage. (3) MAJOR DULL CHARACTERISTIC (These codes are also ROLLER CONE used for Column 7) * BC - Broken Cone N- Nose Row M - Middle Row G - Gage Rows A - All Rows

INSERT BITS - A linear measure of lost, worn and/or broken inserts. (0- no loss, worn and/or broken inserts, 8-all inserts lost, worn and/or broken.) (4) LOCATION DIAMOND C - Cone N - Nose T - Taper S - Shoulder G - Gauge A - All Areas

DIAMOND, PDC and/or TSP BITS - A linear measure of lost, worn and/or broken cutting structure. (0-no loss, worn and/or broken cutting structure, 8-all of the cutting structure is lost, worn, and/or broken.

(5) BEARING/SEALS CONE # OR #'S ROLLER CONE 1 2 3

NON-SEALED BEARINGS A linear scale estimated bearing life used. (0 - no life used, 8 - all life used, i.e., no bearing life remaining

BT - Broken Teeth/Cutters BU - Balled Up Bit

SEALED BEARING E - indicates seals effective F - indicates seals failed X - indicates Fixed Cutter Bit

(6) GAUGE

I - in gauge 1/16 - 1/16" out of gauge 2/16 - 1/8" out of gauge 10/16 - 10/16" out of gauge

(8) REASON PULLED

BHA - Change Bottom Hole Assembly

*CC - Cracked Cone

DMF - Downhole Motor Failure DTF -Downhole Tool Failure DP - Drill Plug

*CD - Cone Dragged

DSF - Drill String Failure

CI - Cone Interference

DST - Drill Stern Test

CR - Cored

CM - Condition Mud

CT - Chipped Teeth/Cutters ER - Erosion

CP - Core Point

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 LT - Lost Teeth/Cutters

PN - Plugged Nozzle/or Fluid Passage PR - Penetration Rate

OC - Off-Center Wear

RP - Pump Pressure

PB - Pinched Bit

RR - Rig Repair

PN - Plugged Nozzles/ Flow Passage RG - Rounded Gauge

TD - Total Depth/CSG Depth TW - Twist Off - drill string

RO - Ringed Out

TQ - Torque

SD - Shirttail Damage

WC - Weather Conditions

SS - Self Sharpening Wear TR - Tracking WO - Washed Out WT - Worn Teeth/Cutters NO - No Major/Other Dull Characteristic

WO - Washed Out - drill string

FM - Formation Change

* - shown cone # or #'s under location


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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.


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BIT CLASSIFICATION AND HYDRAULICS BIT BREAK IN: • • • • • •

Lower bit to bottom with full flow at 60 - 80 RPM. Use of a motor will result in a higher rotation 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 recommended guidelines. 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.


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HYDRAULICS PROGRAM

The recommended hydraulics program for each hole section will be specified in the Drilling Program based on predicted drilling parameters such as mud weight, BHA configuration, pump capability, pressure losses, etc. Bit hydraulics are to be recalculated onboard the Drilling Vessel based 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 surface pressure, 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 is maximized when 74% of the available pressure is expended at the bit with flow rate above QCrit. This condition usually occurs at shallow depths in the conductor and surface casings sections of the hole where the total pressure losses in the system are low. Often larger liners and/or changes are not justified for the fast top hole, precluding optimum hydraulics until drilling below surface hole. High flow rates are the parameter to key on. ∆PBit = 0.74 PSurf

CASE II:

Flow Rate > QCrit

Intermediate between Case I & Case II. Flow rate remains constant while circulating pressure increases with depth. In this region the circulation rate remains constant at QCrit while surface pressure increases until 48% of the maximum allowable pressure is expended at the bit. This condition usually occurs in the intermediate/protective casing section 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 surface pressure, Pmax). Surface pressure remains constant while circulating rates are reduced. In this region hydraulic impact is maximized when 48% of the maximum allowable pressure is expended at the bit. This condition usually occurs in the deeper section of the hole below surface or protective casing. Often a change in liner size is required below protective casing. ∆PBit = 0.48 PSurf

Flow Rate < QCrit

In the past ExxonMobil generally used the Reed Log-Log Graphical Method to calculate optimum rig hydraulics as described above. A detailed discussion of this method can be found in the EUSA Drilling Engineering School Manuals and the old EUSA Drilling Operations Manual (the Red Book). Currently the Reed Hydraulic computer program is utilized.


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BIT CLASSIFICATION AND HYDRAULICS Hydraulic Equations HHP = (HP)(Em)(Ev)

HHP = (P)(Q) 1714

QCrit = 1714(HHP) PSurf

VN

= 0.32(Q) A2

∆PN =

(MW)(Q)2 12042(Cd)2A2

FB

= (MW)(VN)(Q) 1932

AV

24.5(Q) (DH)2 - (DP)2

=

Where: A AV Cd DH DP Em Ev FB HP HHP MW P ∆PN PSurf Q QCrit VN

= = = = = = = = = = = = = = = = =

TFA, total flow area of the nozzles (in2) Annular Velocity (fpm) Nozzle coefficient = 1.03 Diameter of the hole (in) Diameter of pipe in hole (in) Mechanical efficiency of mud pump (%) Volumetric efficiency of mud pump (%) Hydraulic impact force at the bit (lbs) Input horse power from mud pump performance tables (hp) Mud pump output hydraulic horse power (hp) Mud weight (ppg) Circulating pressure, standpipe pressure (psi) ∆PBit, pressure drop across the bit nozzles (psi) PMax, maximum allowable circulation pressure (psi) Circulating rate (gpm) Circulation rate at which total available horsepower is utilized at the maximum allowable surface pressure, PSurf (gpm) Nozzle velocity (fps)


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GUIDELINES FOR HYDRAULICS OPTIMIZATION

The following guidelines, recommendations, and rules-of-thumb are intended to provide a means 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 as a starting point for hydraulic program planning Hole Cleaning The main symptoms of poor hole cleaning depends largely on hole angle. At low angles (< 20°) the cuttings tend to fall downhole as soon as the pumps are stopped. The best sign of poor cleaning is fill on bottom, either on connections or after tripping. In extreme cases it may be difficult to pull off bottom with the pumps off. At high angles (>50°) the cuttings fall to the low side of the hole forming a stationary cuttings bed. There is typically no fill on bottom and no trouble making connections. The main evidence of poor hole cleaning is seen on trips. The string may pull tight or get 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 between those seen for the low angle and high angle wells. In any event, if the drag gets high, RIH 2-3 stands, put the top drive on and circulate and rotate at maximum allowable rates until the hole is cleaned up; don't try to pull through tight spots. It may be necessary to pump out or back ream out of the hole in the higher angle wells. Backreaming out of the hole requires Operations Superintendent approval. Utilizing a bit with a cross sectional area as low a possible, or an open area as high as possible, will provide benefits when tripping through intermediate and high angle 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 hole cleaning. There is no mathematical derivation for CCI; field observations indicate that the numerical product of K, annular velocity, and mud weight should equal or exceed 400,000 for good hole cleaning. The carrying capacity of a mud depends upon the difference in density between the cuttings and the drilling fluid, the annular velocity, and the viscosity of the fluid in the annulus. As any 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 is also needed for making concoctions and immobilizing cuttings in washouts during trips. Adequate gel strengths are needed for trips. CCI = (MW)(K)(AV) 400,000

Good hole cleaning occurs when CCI > 1

K = (511)1-n (PV+YP)

Where: MW = Mud Weight (ppg) AV = Annular Velocity (fpm) PV = Plastic Viscosity (cp) YP = Yield Point (lb/100 ft2)

n = 3.322 log 2PV+YP PV+YP


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The K is the consistency index which corresponds to the viscosity of the mud at a shear rate of one reciprocal second, and n is the measure of the non-Newtonian flow behavior in the power law rheological 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 a parameter called the Hole Cleaning Ratio (HCR) that is highly correlative with hole cleaning problems. Because of the many drilling variables and the complicated physical system involved, the simple "Recommended Annular Velocity" table which appeared in past EPR literature is no longer endorsed. In its place, EMDRC has developed a new tool from fluid mechanics theory, published laboratory data, new experimental data, and field data that provides an optimal combinations of drilling variables for efficient hole cleaning. It has been used for planning or well design to predict the likelihood of encountering hole cleaning problems based on drill string design (bit design, hole size, 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. Where:

Good hole cleaning occurs when HCR > 1.1

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.


13 of 18

BIT CLASSIFICATION AND HYDRAULICS Hole Cleaning Ratio (HCR)

(continued)


14 of 18

BIT CLASSIFICATION AND HYDRAULICS Hole Cleaning Operations (Intermediate and High Angle Holes) Based on this work, the following pump out procedure is recommended for the deviated portion of the 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 to starting the trip. Experience has shown that 2 to 3 bottoms up volumes may be needed to clean the hole enough for tripping. If sidetracking is possible, move the bit slowly over a short interval

•

Rotate will help stir up and remove cuttings beds especially if lots of sliding is done. Refer to EMDC Technology Group for detailed guidelines.

•

In the deviated section, POH slowly as detailed in the drilling procedure (~2-1/2 to 3-1/2 minutes per stand).

•

If excess drag is indicated, stop pulling, slack off 1 joint, then circulate and rotate at least one bottoms up at the maximum allowable flow rate. Rotating aids significantly to hole cleaning in high angle holes (normal practice is 100-120 rpm).

•

Then, if a top drive is available, pump out of the hole at the maximum allowable/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 least two 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 be necessary. Operational details will be provided in the applicable drilling procedure. Ensure that the dangers of backreaming in high-angle holes are thoroughly discussed prior to beginning the well so that everyone is clear on the strategy to be used.


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Rules-of-Thumb 1.

2.

3.

4.

Flow rate: Normally offshore drilling flow rates fall between 50 to 70 GPM per inch of bit diameter. However, flow rates greater than 70 GPM per inch of bit diameter are not unheard of 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 which are 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 bit diameter for holes < 20°; higher angle holes may require more.

Hydraulic Horsepower: area (HHP/in2).

Maintain 2 to 7 hydraulic horsepower per square inch of borehole

•

PDC bits with OBM require less HHP/in2 than with WBM. Total flow rate is more important when drilling with PDC bits and OBM than HHP/in2 .

•

Fast drilling generally requires high HHP/in2 ; however, some PDC bits in OBM can get by with as little as 2 HHP/in2.

•

Larger bits require more HHP. However, many times in larger hole sizes high HHP is not possible. In these cases, pump the maximum volume possible.

•

Maximum HHP/in2 should be considered only when excess pump horsepower is available.

Bit Pressure Drop: When operating below QCrit, design hydraulics for 48% pressure drop across the bit; this is usually the case below surface casing.

to 65%

•

Optimum Hydraulic Impact occurs when 48% of the system pressure loss is at the bit while 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 available pump pressure, smaller nozzles are required. However, do not operate below 30 GPM per inch of bit diameter. Consider using larger drill pipe.

•

When running a PDM, it is recommended that the differential pressure across the bit not exceed 1000 psi to prevent accelerated wear of the rotor / stator assembly.

Jet Velocity: Good jet velocities are typically between 350 and 450 feet per second (use less than 400 fps in very soft rock to avoid washout). •

Jet velocity will influence chip hold down and ROP.


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Hydraulics Optimization (GOM Drilling for reference)

Except in extremely soft rock, hydraulics don’t literally drill. However, they do clean the bit so that cuttings build up does not start to carry the WOB that should be on the teeth (balling). Hydraulics extend 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. Optimum hydraulic 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 and the 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 be specially 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 any downhole 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 ability to clean the hole. For these situations, it is critical to optimize RPM and hydraulics to effectively clean the hole, not necessarily maximize ROP. Utilize HOLECLEAN software to achieve hydraulics design with HCR > 1.1.


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5.9

REFERENCE MATERIAL:

Bit Classification 1. 2. 3. 4. 5.

World Oil's 1995 Drill Bit Classifier. Trinidad's Drilling Operations Manual, Drilling Operations Section, Page 2-7.¹ Gulf of Mexico's Drilling Operations Manual. Hughes Tool Company, Dull Bit Grading Codes chart. 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, EPR 5. 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.


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DRILLING FLUID SYSTEM

6.0 DRILLING FLUID SYSTEM

6.1 6.2 6.3 6.4 6.5 6.6 6.7 6.8 6.9 6.10

General Solids Control Drilling Fluid Treatments Drilling Fluid Checks High Temperature Drilling Stuck Pipe Pills Lost Circulation Non-Aqueous Fluid Operations Rig-Site Dielectric Constant Measurement Drilling Fluid System Guidelines Appendix G-I Fluid Transfer Checklists Appendix G-II NAF/Oil Base Mud Readiness Checklist

______________________________________________________________________________ DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION MAY, 2003

1 1 3 5 6 6 7 15 33 34

DRILLING FLUID SYSTEM 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 drilling fluid system minimizes the number of different chemical components necessary to achieve the drilling 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 the results 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 the performance 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 to maintain 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 use solids control equipment. This requires maintaining the solids control equipment in optimum condition so that it performs in accordance with the manufacturer's specifications. However, solids control 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 immediately as it comes out of the hole before the cuttings are reduced in size by the surface processing equipment. Use of high quality shakers, with fine screens maintained per the manufacturer's recommendation, 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 the liquid phase is expensive (some polymer muds or non-aqueous muds). Dilution is the most costly method 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 of solids control equipment and only dilute when necessary. Some dilution is required on most muds.

2.

If direct additions of dilution water are made to the active system, be aware that mud additives will 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 that mud discharges are usually regulated by the local governing bodies. Do not exceed maximum hourly mud discharge rate and always ensure that appropriate discharge conditions are met prior to discharge.


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DRILLING FLUID SYSTEM 4.

Dilute the active system prior to weighting up the drilling fluid to avoid dilution of higher cost drilling fluid.

5.

Monitoring of the mud's particle size in light or unweighted mud may drive the decision to dilute more aggressively.

Dilution - Premixed Drilling Fluid The advantages of using premixed drilling fluid (whole mud) when diluting the active system are as follows: • • •

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 fluid system.

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 stream with the flow stream approximately two-thirds to end of screen.

4.

Optimize solids removal by evaluating shaker screen sizes continuously and using the smallest screens possible considering the required pump rate and rate of penetration.

5.

Keep shale shakers in good operating condition. Maintain proper screen tension and promptly replace torn screens. Corrugated ("Pyramid") style screens have proven effective for increasing processing capacity. Avoid using corrugated screens on the end panel or on any panel that is not mostly submerged.

Hydrocyclones Guidelines 1.

Use hydrocyclones continuously when circulating an unweighted drilling fluid in most situations.

2.

Check cones every tour for plugging.

3.

Ensure cones are operating in a spray discharge as much as possible.


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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, PHPA polymers, etc.) only if high gravity solids to low gravity solids ratio, ppb, is less than 2 in the screen 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 of barite to the system.

6.

Running the mud cleaner when using screens finer than 180 mesh can result in excess discharge of barite. Typically, a mud cleaner is uneconomical when using screens over 180 mesh 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 rheology and 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 of Solids 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 daily during drilling operations.


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Process the drilling fluid returning from the wellbore so that the fluid properties of the drilling fluid 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 from the 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 as long 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 a hopper).

10.

Presolubilizing all polymers in fresh water before adding to a high salt mud system is preferred.

11.

Maximize utilization of all chemicals by pre-hydrating them in fresh water before adding to active 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 the qualities of the materials meet API standards, or the standards specified by the contract with the 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 or equivalent).

6.

Portable roller oven and 2 - 3 heat-age cells.


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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 or non-aquious fluid (NAF) if appropriate.

Drilling Fluids Report Guidelines The Drilling Fluids Engineer is to provide a Daily Drilling Fluids Report to the Operations Supervisor 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 All Drilling Fluid Checks Properly Labelled as to Time and Depth of Bit

6.4

DRILLING FLUID CHECKS

The Drilling Fluids Engineer is to make the following measurements for each mud check on a waterbase 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


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DRILLING FLUID SYSTEM • • •

6.5

H2S if Specified in Drilling Program (Garrett Gas Train Measurement of Sulfides.) (mg/L) Carbonates using Garrett Gas Train (mg/L) Lime Content HIGH TEMPERATURE DRILLING

Hot Roll and Static Age Samples Drilling muds can potentially have significant gelation problems when exposed to high temperatures for long periods. These problems can be especially acute in heavily weighted muds needed to drill abnormally pressured formations. The mud engineer or his assistant is to hot roll and static age mud samples at anticipated bottom hole temperatures on a frequent basis (minimum 1/week) any time static bottom hole temperatures exceed 250 degrees Fahrenheit. Unless otherwise specified in the Drilling Program, samples should be hot rolled for 12 hours and static aged for 24 hours both at estimated bottom hole temperature. Rheology, Gel strengths, pH, and HTHP fluid loss readings of the aged / hot rolled samples should be compared to pre-aged readings to evaluate the stability of the 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 enough fluid 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 Pipe Spotting Fluid Guidelines" – available from Drilling Technical Operations Support.


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DRILLING FLUID SYSTEM 6.7

LOST CIRCULATION

The first priority when encountering lost circulation is to fill the hole as quickly as possible with water or other light fluid to keep the hole full. It is the responsibility of the driller, mud loggers, and the 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 if monitoring of lost returns is critical. Building Integrity Lost returns occur when the pressure in the wellbore exceeds the resisting stress in the rock. The integrity is determined by the closure stress (psi) in the fracture that is created. Closure stress is built by applying pressure to increase the fracture width, which compresses the rock so that it pushes 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 isolate the fracture tip which would otherwise continue to grow at a very low pressure. Conventional LCM isolates the tip by becoming an unpumpable mass due to loss of its carrier fluid as it travels down the permeable fracture face. The LCM also serves to pack the fracture open so that the higher closure stress is maintained. Even relatively small particles are effective and will become an unpumpable mass if the leakoff is high. High leakoff and high solids concentration are the key features in the design of pills. Fracture growth is not stopped by blocking with large particles, it is stopped 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 the carrier fluid to leak off. Multiple layers of LCM are eventually built up in the near wellbore region that 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 increase in closure stress is very low, mud solids alone may achieve the required width when micro-fractures are just initiating and no loss is observed. If slightly more increase in width is needed, then the well may “take a drink” and then drilling may continue. When complete losses occur the most effective approach available should be used on the first attempt. This is justified by the high cost of rig time for multiple attempts to build integrity. Mix high fluid loss pills, use the highest concentration of LCM possible, and plan on hesitation squeezing. This may not be the best “first” response in cases where the loss zone isn’t a sand over about 100md or underbalanced by greater than 1000psi.


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DRILLING FLUID SYSTEM Filling the Hole If lost returns occurs and the annulus fluid level drops it is essential to fill it immediately. When loss 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 is declining. 5. If the loss doesn’t decline, fill with water or base oil via the trip tank until losses stop. The annulus 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 and report 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 is occurring. Shut in immediately to prevent flowback and monitor pressure. Contact the Operations Superintendent immediately. 8. Once the annulus is stabilized, it may continue to drop slowly due to seepage. Begin filling with whole 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 the fracture 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 circulation after 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.


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DRILLING FLUID SYSTEM 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 Returns Procedure posted on Global Share. This posted document is continuously updated with learnings in operational practices and pill formulations.


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DRILLING FLUID SYSTEM

Figure 6-1

Lost Returns Treatment Selection Guide (See EMDC Generic Lost Returns Procedure for details)

Lost Returns Occurs

Are Losses Due to Seepage

No

Does Hole Stand Full

Fill Annulus with Light Fluid (water or base oil)

No

Yes Yes Is FCS > Pore Pressure

No

Seepage Control

Yes

Losses are Likely Vugular

Losses are Fracture Propagation (Most Common)

WBM

Is Zone Permeable

Yes

No

Yes

DOB2C Procedure

Cement or FlexPlug Procedure

Conventional LCM Procedure


No

WBM No

Yes

Flexplug Procedure

DOB2C Procedure

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DRILLING FLUID SYSTEM Conventional LCM Treatment for Severe Losses 1. If the well will not circulate, position the bit in the previous casing shoe and prepare for bullhead operations. If the well can be circulated place the bit below the loss zone and circulate LCM entirely out of the bit to position it in the annulus. Pull the bit into the previous shoe to conduct squeezing. 2. If the pill is to be circulated outside, mix the LCM slightly heavier than the mud so that it falls back to fill the pipe displacement when pulling DP. Use a solid float to prevent backflow into the 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 0.5 ppb 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 and bentonite). 6. Do not allow fluid to return from the annulus while squeezing LCM. Shut in prior to starting displacement and monitor and record pressures. Any change in annulus pressure is a direct measure of the change in fracture closure stress (integrity). 7. Hesitation squeezing maximizes fracture closure stress. Place approximately ¼ of LCM into fracture and shut down. Conduct at least two more squeezes with hesitations between each to allow the LCM carrier fluid to leak off. Hesitate for 1-4 hrs between each squeeze. Leave 1020 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, the fracture width and stress will decline. 9. Provide pressure and volume data to the drilling engineer for plotting and archiving in the well record. 10. After holding the final squeeze pressure for a minimum of 4 hrs, bleed off pressure and stage pumps up slowly. Stage the drill string to bottom, breaking circulation at each point and monitoring the returns for additional gains or losses. Pill Formulations Pill formulations continue to improve. Learnings are continually updated and published in the EMDC Generic Lost Returns Procedure, which is posted on Global Share. Contact Drilling Technical Operations Support for additional assistance in pill design. The pill should be the most economic design that will successfully build integrity. The ease with which integrity is built is dependent on the leakoff (permeability) and the required increase in fracture stress (width). If permeability is high or the required increase is small, relatively low


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DRILLING FLUID SYSTEM concentrations of medium LCM may be effective (20-40 ppb). In very low permeability and severely 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 drill string. 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. Higher concentrations 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 more cost effective. Because the spread rate for drilling rigs is high, preference should generally be given to 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 than what is used. The combination of high fluid loss designs and hesitation squeezing greatly enhances the effectiveness of any material. Ballooning Ballooning refers to the loss and backflow of mud that is sometimes observed when circulation is begun and stopped. It is due to the expansion of a lost returns fracture due to the ECD associated with circulation, and then the contraction of the fracture when the ECD is removed. It is generally associated with soft, low permeability formations. It may occur in higher permeability if lowleakoff 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 the fracture closure stress and the fracture cannot reopen. It may also be possible to stop ballooning by treating the fracture with Flexplug (NAF) or DOB2C (WBM) to build the closure stress to exceed the ECD. Cement has also been used successfully, but it creates the potential for sidetracking. This is more likely to be successful if the fracture is confined to a discrete sand than if ballooning is occurring 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 of drill-weight mud. Overdisplacement can be controlled by pumping sufficient light fluid at the end 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 a hydrostatic packer are provided in the Generic Lost Returns Procedures. 2. Discuss cutting mud weight with the Operations Superintendent. When returns are lost the BHP falls 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 the FCS. This is an important diagnostic that indicates that the mud weight may be safely cut to equal the calculated FCS without concern for flow.


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DRILLING FLUID SYSTEM 3. By definition, seepage is the loss of whole mud into the pore throats of the formation (no fracture propagation). Seepage is stopped when fine solids plug the pore throats through which whole mud is escaping. In low weight mud (<10 ppb), add fine calcium carbonate at 5-8 ppb for this purpose (5 micron CaCO3). However, the addition of fine blocking material is questionable at high mud weights where there is already a sufficient volume of barite particles of this size to block the pore throats. For example, a 13.0 ppg mud has over 100 ppb of particles the same size as fine calcium carbonate. Also, do not use “lost returns” LCM for seepage control. Larger materials such as medium fiber and nut plug do not fit the pore throats well and result in thicker cakes. 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 detrimental effect of medium LCM on mud properties and solids control is significant. System treatment is sometimes recommended when very long intervals of lost returns are anticipated that cannot be treated with discrete pills. However, when this occurs it is generally possible to cut the MW and drill 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. This process 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 filtration losses 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 leak off (shales). The recommended alternatives for impermeable rock are DOB2C in water base mud 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 that eventually hardens. Flexplug is a proprietary product that forms a rubbery material at down hole temperature. Detailed procedures for each are provided in the Generic Lost Returns Procedures on Global Share. 7. By definition, vugular formations are those with > 1/16” openings. The practical definition is that 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 not respond to coarse LCM is cement in oil base mud, or DOB2C in water base mud. Cement may also be used in WBM but DOB2C has an advantage in that it can be drilled out without concern for 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) to drill without returns. A cuttings bed build-up in a directional well can result in stuck pipe due to inadequate hole cleaning. Dry drilling is used in many operating areas as an alternative when major lost returns are encountered.


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DRILLING FLUID SYSTEM 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 to clean 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 good to keep from using the LCM for only one circulation thus reducing the cost, but could compound the problem if prolonged. If the shakers are allow to stay by-passed too long, the solids content of the mud system will eventually reach a point that the borehole cannot sustain the increased weight or viscosity. The small solids have a tendency to stick, (piggy-back) on the LCM and is circulated back 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 if needed, but experimenting with one or both and experience with them will increase their usefulness 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 the most effective. Balanced plugs are to be spotted through open ended drill pipe positioned across the thief zone and the drill pipe pulled into the casing shoe. If the hole does not take any mud after spotting the cement plug, a gentle bradenhead squeeze may be applied after the drill pipe is in the casing shoe. Gel cements having lower densities may be necessary with zones that have very little integrity or may fracture using neat cement. In mixing this type of cement, the following slurry is recommended: 13.2 ppg 100 sxs 8% 24.3 bbls 1/4 ppb 1/4 ppb

Density Class G Cement Gel Fresh Water Sodium Carbonate 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), and Gilsonite (crushed-up limestone) can also be used, though they have not proven to be much more effective than regular cement in severe lost return occurrences. DOB2C DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE DRILLING First Edition - May, 2003

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DRILLING FLUID SYSTEM 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. Because conventional LCM requires leakoff of the carrier fluid, it doesn’t perform well in very tight formations or shale. DOB2C can only be used in WBM. DOB2C achieves integrity through a different process than conventional LCM. Because of its extremely high viscosity, the wellbore pressure required to squeeze it down an induced lost returns fracture is high. The high pressure at the wellbore increases the fracture width and fracture closure stress (FCS). The pressure is held while the cement in the DOB2C sets, and the fracture width and increased closure stress are maintained permanently. DOB2C is often also preferred to cement in blocking vugular losses because the low-strength material left in the wellbore is easily drilled out without risk of sidetracking. Another advantage is that because of its high viscosity it is possible to apply a high squeeze pressure to DOB2C that ensures that the material is forced into all of the vugular openings. Cement may flow freely into the largest of the openings without developing sufficient back pressure to force additional cement into the smaller vugs. Although diesel is most commonly used as the base fluid to carry the bentonite and cement, other low-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 rubbery material under downhole conditions. Flexplug stops fracture growth by blocking the fracture near the wellbore, and then it deforms to maintain the blockage as the fracture widens under squeeze pressure. The extrusion pressure of the material is high enough that wellbore pressure is not transmitted to the fracture tip and fracture growth (lost returns) is prevented. The squeeze pressure is held until the temperature-activated set occurs. Because FlexPlug does not achieve significant compressive strength (as does DOB2C) there is probably some loss of fracture width and integrity when the squeeze pressure is released. However, field experience suggests that in many situations the sustained stress is adequate. FlexPlug is a candidate system in 1) NAF, and 2) low permeability, because it does not require leakoff 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 connecting to the rig floor, shakers, pump room, BOP deck, etc. to contain mud that accumulates during trips, DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE DRILLING First Edition - May, 2003

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DRILLING FLUID SYSTEM when working on pumps, or when spills occur. Rig floor non-skid, studded rotary mats should be used. Frequent use of steam cleaners is recommended. 2.

Fire hazards

Provide good ventilation in closed areas, especially on the below-deck pits offshore. The two periods of greatest fire risk are when the mud contains formation gas, and when the hole is first displaced and the lighter, more volatile ends of the base oil are being lost to the atmosphere. No open flames, cigarettes, welding, etc. should be allowed near oil mud. The rig should be checked for electrical shorts and for any equipment or operation which could create sparks; electric motors should be explosion-proof. A foam suppression fire fighting system should be considered for the pit room 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 mud testing available; the mud engineer's testing lab must also have good ventilation because volatile solvents 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 aware that 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 (for removal of mud from the skin) and barrier protective hand creams should be provided. Crews should be told of the health considerations and how to remedy them. This should be consistent with ExxonMobil's OSHA (applies to non-US East operations) Hazard Communication Program and communicated 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 or equivalent).

2.

A mud bucket with a drain to the flow line should be used. The pneumatic type Mud Bucket has 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 control problems 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 on edge, or the equivalent, and drained to the flow line or sand trap with the option of going to a disposal sump.


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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 be installed 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 oil mud.

9.

A pump, supply line, and a nozzle to clean the shaker screens and shaker area are sometimes provided, but keep in mind the fire hazard generating a fine spray of an oil, particularly diesel 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. systems must meet all regulatory requirements.

14.

The addition of oil-wetting agent and dilution with base oil should be considered when building OBM slugs in high-density mud systems. Lower viscosity slugs have proven to be more 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 be directed overboard.

Cuttings boxes or bagging

OIL SPILL PREVENTION MEASURES Communications 1.

There should be a written transfer procedure on the rig and the supply vessel which outlines the 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


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DRILLING FLUID SYSTEM •

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 the supply 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. b. c.

3.

at least 600 psi, or four times the transfer pump's pressure relief valve setting plus fluid hydrostatic, or four times the transfer pump's output plus fluid hydrostatic when no relief valve is installed.

Hose working pressure shall be one of the following, whichever is greater: a. b. c.

at least 150 psi, or the transfer pump's pressure relief valve setting plus the fluid hydrostatic, or 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 the mooring 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 the end of the riser.


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DRILLING FLUID SYSTEM RIG PREPARATIONS PRIOR TO TAKING ON NAF MUD 1.

There should be detailed procedures, with checklists, (refer to NAF/OBM Readiness Checklist 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 spill occurrence 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 spill source.

3.

Consideration should be given to color-coding all dump valve operating handles by painting them a distinctive color (e.g., yellow and black stripes). Double valve with a gate valve on the 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-ring should be visually inspected to verify that both are clean, free of debris or obstruction, and are not damaged. Each valve shall then be closed while visually observing the seating of the valve. After full closure, the valve should then be packed with a gel-water paste to further enhance the seal.

5.

All mud pit and sand trap dump valves should be double-valved, locked in the closed position, and posted with a sign, printed in English and in the native language, stating "Work permit required to operate". In some instances, double-valving has been accomplished by installing a gate valve downstream of the dump valves in the common discharge line for the sand traps and/or mud pits. NOTE: If a gate valve is not already installed in the discharge line, 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 dump lines.

6.

Consideration should be given to installing a pump-out line between the double-valved arrangement (i.e., between dump valve and the gate valve) to allow pumping out any pollutant which may leak by a dump valve.

7.

Work permit requirements should be in place to operate the dump valves. A work permit should also be required before OBM can be transferred into any tank or pit that has had a dump valve operated, repaired, or resealed.

8.

OBM transfers should not be made during hours of darkness, during meal time, or during a tour change unless emergency situations dictate or unless prior written policy has been established to effectively deal with the situation.

9.

While transferring OBM from the supply vessel to the mud pits, a designated crew member should 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 Base Mud, Diesel, etc.) and shall include inspection of loading lines, pressure testing of loading


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DRILLING FLUID SYSTEM 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 should be 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 pits should 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-pressure mud 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 capability to pump mud to shakers). With this drain, mud that drains from the kelly can be saved and pumped across the shakers.

25.

Double valve all tank lines. If possible, use hard piping (welded Schedule 40) for lines rather than hoses.

26.

Install a common overflow between storage tanks to prevent spills during loading and transferring.


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DRILLING FLUID SYSTEM NAF DRILLING FLUIDS Treatment Guidelines 1.

Perform a minimum of two (2) complete (In and Out) checks of the drilling fluid every 24 hours during drilling operations.

2.

Process the drilling fluid returning from the wellbore so that the fluid properties of the drilling fluid going back into the wellbore are within the acceptable range per the specifications 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 funnel viscosity 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 tight oil/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 Services Contract shall be maintained at the rig. See contract for details. Specific items necessary for testing oil-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 Field Testing 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.


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DRILLING FLUID SYSTEM Further details on test equipment are given in ExxonMobil Oil and Synthetic Mud Testing Guidelines. Mud Check Guidelines Unless otherwise specified in the Drilling Program, the Drilling Fluids Engineer shall make the following 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 Testing Guidelines. Drilling Fluids Report Guidelines The Drilling Fluids Engineer is to provide a Daily Drilling Fluids Report to the operations supervisor 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


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DRILLING FLUID SYSTEM •

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 has extra clean work clothes on site. In general, oil-soaked clothing should be changed as soon as 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 personnel working with oil muds: •

• • • • • • •

Work gloves (replace when oil-saturated). Chemical resistant gloves worn underneath work gloves may be used to minimize skin contact. (Latex-type surgical gloves work well) 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 conducted to explain health hazards associated with exposure to oil muds.

2.

Drilling Contractor must ensure that workers are familiar with MSDS (Materials Safety Data Sheets) for base oil and all oil mud additives.

3.

Training program should explain proper use of PPE. Requirements regarding use of PPE should 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 covered in the Drilling Program, a Supplemental Procedure that describes the necessary procedures will be written by the Drilling Engineer. An example procedure completed using the EMDC US East Drilling Group Core OBM Displacement Procedure can be found in Section 6 – Appendix S-I.


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Use a spacer. Consider using dye. a. b.

2.

Where differential pressure allows, a simple spacer such as a pure base oil often works best. If a weighted spacer is required, oil mud without calcium chloride is best. In cementing operations the spacer must not contain calcium chloride or flash setting could occur.

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 both fluids should be checked at the same temperature.

4.

Condition water mud by deflocculating to lower yield point and gel strengths. Circulate bottoms-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 mud in the hole just before displacement. 1.

Circulate and thin the water base mud thoroughly before shutting down to change out the water mud in the pits with oil mud. On some rigs, the returns can be diverted down a metal trough (mud ditch) from the shakers to the suction pit; if so, circulation with water mud can continue 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 ready for 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 starts downhole. Record stroke count when water mud and water mud/oil mud interface has been displaced 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 stop pumping once the displacement has commenced unless absolutely necessary.

8.

Dump water mud or move to storage while pumping.


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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 back divert returns over the shakers and begin remedial oil mud treatments with emulsifier and wetting agents. Typical treatments are in the 0.5-1.0 ppb range for each additive during the next circulation.

11.

Run a check for flow properties, E.S., and HTHP as soon as practical after good mud has come back (remedial treatments should already have been initiated) and assess the condition of the mud. Continue treating as necessary, and do not stop circulating until acceptable mud properties 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 help determine how much water mud was left in the hole.

14.

Commence drilling when the oil mud exhibits stable rheology, electrical stability, and shows little 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 been pumped, 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 significant amount of water-base mud was left in the hole, it may have been caused by severely washedout 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 the shakers, emulsifier and wetting agent can be added at the shakers, in the suction, or in both places. Continue to circulate and condition the mud for several circulations and test flow properties, and Electrical Stability. Check the High Temperature / High Pressure fluid loss for 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 or more 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, run Dispersibility 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:


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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 will begin giving a low reading (100-200 volts). At this time, slow the pumps and prepare to put the mud over the shakers.

A.

Rig Preparation

1.

All welding repairs on pumps, pits, and rig floor should be completed before taking on Oil Mud.

2.

Change swivel packing and blank off all water lines to the pits. Maintain on site a supply of 55-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 barite settling.

D.

Solidification

1.

Utilize a Drying Shaker to get the drill cuttings as dry as possible and to recycle as much of the 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 and discharge from the Mixing Unit to the storage area.


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DRILLING FLUID SYSTEM 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 Derrick man 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 hoses must be rated for hydrocarbon fluids and have a safe working pressure of 150 psi. Verify that 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 for damage.

4.

All others outlets on the load line are sealed off with a blind flange or a valve that is properly closed 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 herein have been made before initiating the transfer. Also, the Tool pusher and ExxonMobil drilling supervisor will ensure that the "checklist" is fully completed prior to commencing the operation. A copy of the completed "checklist" will be provided to the ExxonMobil drilling supervisor.

8.

Transfer hoses will be visually checked for damage prior to transfer.


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Mud pits, shaker pits and shaker box have been emptied and cleaned out per mud engineer approval. 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 lined up to drain tank.

13.

Drains in pump room, mud treatment room, shaker room, mud mixing area, and cement room are sealed.

14.

All valves to cement unit are closed. Dump valves from cement unit displacement and mixing tanks are closed and padlocked.

15.

Isolation valves in mud pit room between OBM line and drill water line are closed and secured.

16.

Main valve on sea water supply line and all water valves at mud pits, pump room, and shale shakers 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 the pits.

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.


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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 for leakage 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 ExxonMobil operations superintendent approves a night transfer. Additional planning steps will be necessary to address problems that could be encountered with a transfer during darkness.

4.

OIM, tool pusher, ExxonMobil drilling supervisor, mud engineer, mud logger and control room 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 loading station 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 OBM or base oil is complete.

3.

Connect transfer hose to supply vessel. OIM or Barge Eng./Captain to confirm with supply vessel captain that transfer hose connection flange is a proper mate to the flange on supply vessel.

4.

Transfer is now ready to be started. The derrick man will monitor volume pumped and change over as required, opening valves on next pit to be filled before closing valve on pit just filled. Derrick man and mud loggers will monitor volume received periodically throughout the operation and upon completion of fluid transfer.

5.

If any difference between volume pumped and volume received should occur, stop the transfer immediately. The tool pusher and ExxonMobil drilling supervisor are to be informed of the discrepancy and an investigation will be conducted to find the reason for the deviation. An acceptable solution to the problem will be implemented prior to continuing the operation.


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The mud engineer will perform quality checks of the transferred fluid periodically during the operation.

7.

When transferring is completed, stop transfer pump and close valve on loading line in pit room. Close the valve at the loading station, the transfer hose must then be bled to the supply vessel. The valve on the end of the transfer hose at the supply vessel must be closed prior 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 be flushed. All water mud/oil mud interface from the flushing operation must be captured and pumped 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 crew members.

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 and padlocked.

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.


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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 is available.

Communications 1.

All personnel involved in the displacement will have VHF radio access.


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The tool pusher, ExxonMobil drilling supervisor, mud engineer and mud loggers will be involved in the displacement operation.

3.

One designated rig crew member will be assigned as a lookout during displacement operations to observe for leakage.

4.

OIM, tool pusher, ExxonMobil drilling supervisor, mud engineer, mud logger and control room 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 up properly 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 to restarting displacement operations

3.

The mud engineers will periodically check the E.S. of the returning mud to determine whento put the return flow across the shale shakers.

4.

After displacement, all mix lines, suctions lines and transfer lines will be flushed and any interface 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 determine surface areas) from several offset wells. The surface areas are then stratigraphically correlated, data consistency is evaluated, and a surface area profile is generated. To apply an offset surface area profile to a prospective well, correlativity of stratigraphy must be determined (i.e., How do the offset wells tie to the prospect well?). Typically, simple adjustments to stratigraphic tops are made to correlate the surface areas. Sometimes, the depths of offset surface areas 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 well planning. Cuttings surface areas can be measured at the rig-site to verify or modify the wellbore stability model while drilling. Qualitatively, one can determine if the wellbore should be drilling more or less stable than the modeled well depending on the comparison of real versus assumed surface areas. Quantitatively, the real surface areas can be used to revise the model and mud weight schedule. Measurement Options Real-time surface area measurements can be made with a portable, on-site DCM kit. The decision of whether to mobilize on-site surface area measurements should consider the following:


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DRILLING FLUID SYSTEM • •

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 in Aberdeen for analysis. Transportation time (to Houston or Aberdeen) is generally the critical path item for off-site analysis. A typical analysis cost is $15-20 per sample. Independent of the measurement option, approximately 30-50 samples can be analyzed each day. The normal sample frequency is about once every 30 feet. Limitations The purpose of any measurement is to enable some response, if necessary. In some cases, the options for acting on rig-site surface area measurements may be limited. •

•

Certain wells face the difficult situation where the collapse gradient approaches, or even crosses the fracture gradient. Such a circumstance can be caused by abnormally high or unusually anisotropic tectonic stresses, or when rock strength is very weak compared to even normal stresses. Due to the conflicting requirements for stabilizing the wellbore (higher mud weight) and avoiding lost returns (lower mud weight) the only option is to manage the symptoms of instability while approaching the fracture gradient as closely as practical. Recent encounters with this situation (see examples below) have motivated current URC research on improved leakoff prediction and lost returns mitigation. While the EPR shale strength correlation incorporated in the WBSD software is accurate for the large majority of shales, the strength behavior of certain lower surface area shales has been observed to fall outside the database from which the correlation was delivered. Shales in Malaysia and the Irish Sea, for example, record surface areas of 100-200 m²/gm while exhibiting mechanical properties consistent with 400-500 m²/gm. Laboratory work is in progress to resolve such exceptions to the present database.

Applications The following summarizes how real-time (on-site) surface area measurements have been or could be used to impact drilling operations: •

•

6.10

Elli: The actual mud weight used took advantage of a 1 ppg "conservatism" (based on North Sea experience) in mud weight predictions from the wellbore stability model. Realtime 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 nearsurface core holes to bracket the expected surface areas. Real-time surface area measurements were used to qualitatively check shale sensitivity and monitor the inhibitive effects of glycol. DRILLING FLUID SYSTEM GUIDELINES

On-site measurements of surface areas are recommended when:


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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 operational decisions 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 be more 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.


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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 the completion of the pre-job transfer meeting, all persons involved in the transfer will sign this document indicating this procedure has been reviewed. I.

TRANSFER FROM MUD COMPANY TO BOAT A.

Prior to Loading Boat Inspect All Hoses, Couplings, and Lines G G G G G

B.

Location and Review ESD Operation and Procedure G G G

C.

G

Review Fire Fighting procedure Ensure that the Fire Fighting Equipment is in working order and close at hand

Inspect Receiving Vessel G G G

E.

Review and formulate (if necessary) ESD Procedure Ensure ESD works Individual is assigned to ESD station during transfer

Locate and Inspect Fire Fighting Equipment G

D.

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

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

Loading the Boat G G G G G

G

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 Exxon representative Verify the Transfer volume at completion


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II.

TRANSPORTING FLUID G G

III.

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

TRANSFER FROM BOAT TO LOCATION (DRILLING RIG) A.

Hold Pre-Job Safety Meeting and Review JSA, MSDS, and Transfer Policy G G G G G G G

B.


C.

G

Review Fire Fighting Procedure Ensure that Fire Fighting Equipment is in working order and close at hand

Receiving Tanks G G

E.

Review and formulate (if necessary) ESD procedure Ensure ESD works Individual is assigned to ESD station during transfer


D.

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.

Ensure tanks are clean and sealed Verify volume to be transferred

Transferring Mud to Rig G G G

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 ______________________



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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 the completion of the pre-job transfer meeting, all persons involved in the transfer will sign this document indicating this procedure has been reviewed. IV.

TRANSFER FROM RIG TO BOAT A.

Prior to Loading Boat Inspect All Hoses, Couplings, and Lines G G G G G

B.


C.

G

Review Fire Fighting Procedure Ensure that the Fire Fighting Equipment is in working order and close at hand

Inspect Receiving Vessel G G G

E.

Review and formulate (if necessary) ESD Procedure Ensure ESD works Individual is assigned to ESD station during transfer


D.

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

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

Loading the Boat G G G G G

G

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 Exxon representative Verify the Transfer volume at completion


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V.

TRANSPORTING FLUID G G

VI.

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

TRANSFER FROM BOAT TO MUD COMPANY DOCK A.

Hold Pre-Job Safety Meeting and Review JSA, MSDS, and Transfer Policy G G G G G G G

B.


C.

Review and formulate (if necessary) ESD procedure Ensure ESD works Individual is assigned to ESD station during transfer

Locate and Inspect Fire Fighting Equipment G G

D.

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 Fire Fighting Procedure Ensure that Fire Fighting Equipment is in working order and close at hand

Receiving Tanks G G G G

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 Company representative




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SECTION 6 - APPENDIX G-II 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 Mud Lab – dedicated to mud testing only Y Mud Lab – explosion Proof Fixtures Y Mud Lab – away from mud pits or Pressurized Y Signs Posted – “No Smoking & No Hot Work” Y Electrical equipment explosion proof – motors, lights Y Personal Protective Equipment: Mud area – PPE locker stocked with apron, gloves (heavy duty), boots, face Y shield, respirator Rig floor area – slicker suits (or aprons), work gloves, latex gloves, boots Long pants / long sleeve shirt worn Safety glasses with side shields worn Deluge shower – mud mixing area, rig floor Deluge shower – rig floor Eyewash Stations – rig floor, mud mixing area, other areas of potential exposure Wash Basins with hand cleaner available – rig floor, mud mixing area, mud pit area, pipe rack area, other affected areas

Shipping Hazards: Stair steps wrapped with burlap or have non-skid surfaces Floor mats placed at all entrances to living quarters Rotary has non skid matting Absorbent material available for rig floor, other spill areas Steam cleaner or high pressure wash-down unit available

Discharges: Ratholes/Mouseholes sealed with hose to disposal basin Pipe Rack Drains – drained to disposal basin Catch Pan under Rig Floor – drained to disposal basin Kick Plates around main deck/pipe rack area Kick Plates around the rig floor Dump valves double valved, locked, and signs posted with “Work permit require operate” Drill pipe wipers used – inside and outside Lower kelly mud saver used Mud bucket seals in good condition

N N N N N N N

Y Y Y Y Y Y Y

N N N N N N N

Y Y Y Y Y Y Y Y Y Y Y Y

N N N N N N N N N N N N

Y Y Y Y

N N N N

Y Y

N N

Y Y

N N

Y Y

N N

Water Contamination: Open mud pits covered Pits cleaned and isolation valves tested Base oil mud lines with hose and nozzles installed – rig floor, mud pit room, shaker area Sources of water isolated – rig floor, mud pit room, shaker area, mud mixing area Packing Elements on centrifugal pumps grease cooled, not water cooled – trip tank, mixing pumps Medium and coarse non-water absorbing LCM on rig DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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OIL BASE MUD READINESS CHECKLIST (continued)

Form D-200

Deterioration of Rubber goods: Base oil low in aromatic hydrocarbons, i.e. aniline above 145 Deg. F Oil Resistant (nitrile) rubber elements, i.e., mud pit valve seals, shaker valve seals, shaker mounts, and hoses Oil Resistant (nitrile) elements used in BOP, ram seals, annulars

Y Y Y

N N N

Y

N

Y Y Y Y

N N N N

Y

N

Personnel and Training: Two mud engineers on location Extra roustabouts for clean up duty Work-hour restrictions scheduled General Safety Meeting – explain OBM hazards and preventative actions explained, i.e., clean clothes, deluge showers, hand cleaners Use and need for PPE explained

General Comments:

Report By:

Position:

Date:

Location:

Rig:

Contractor:

Distribution: Operations Superintendent Rig file


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ABNORMAL PRESSURE DETECTION IN CLASTICS

7.0 ABNORMAL PRESSURE DETECTION IN CLASTICS

7.1 7.2 7.3 7.4 7.5

Background Pressure Indicators While Drilling Abnormal Pressure Detection Team Responsibilities Mud Logging Operational Guidelines

______________________________________________________________________________________ DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION MAY, 2003

1 2 10 11 15

7.1

BACKGROUND

For all Drilling Operations a casing seat or TD hunt will be prepared in conjunction with the Operations Geologist. Conventional abnormal pressure detection parameters as described in this 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 including controlled drilling, frequent flow-checks, preparedness for lost returns/fractures and consideration of correlation (whenever possible). Conversely, in clastics, the detection techniques 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 by a column of water of a specific density extending from the surface to the 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 for a given basin. Hydrostatic Pressure - the pressure exerted by the vertical height of a column of fluid. Transition Pressure - the interval in which the normal fluid pressure gradient changes to an abnormal fluid pressure gradient.

When does abnormal pressure occur

Abnormally high pressures are found worldwide. Such pressures occur when fluid in the pore space begins to support more overburden than just fluid weight; i.e., not all of the compressional forces are transmitted by the rock matrix.

Causes of abnormal pressure

Many factors can cause abnormally high formation pressures. In some areas, a combination of factors prevails. The most commonly described cause of abnormally pressured or over-pressured sediments is under-compaction. Other causes are thought to be: • • • • •

Chemical diagenesis Uplift Fluid density contrast Recharged or re-pressured formations, and Faulting.


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Because conditions can vary widely, special care should be taken not to assume that the cause of abnormal pressure established from experience in a well-known area necessarily is the cause of a similar condition in another basin which has not yet been adequately tested by drilling.

Documentation Ideally, Operations Geology should define well-specific abnormal of known well- pressure causes for any well to enhance understanding and operational specific planning to deal with the pressure when it is experienced. abnormal Pressure

7.2

Pressure Indicators While Drilling The following tools & parameters, listed in their order of reliability, are used to monitor for abnormal pressure in clastic sections while drilling: • • • • • • • •

Rate of Penetration (ROP) Interpretation

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)

An increase in ROP with constant parameters indicates a drill-off trend and generally indicates an increase in pressure. However, maintaining a constant ROP over a long interval may also indicate increasing pressure since the expected bit dulling trend (decrease in ROP) did not occur. Depending on bit type, increased ROP in the transition zone has consistently been one of the most definitive indicators of entry into overpressures when other drilling parameters are maintained constant.

Factors affecting ROP

Successful use of ROP to detect dulling trends and drill-off trends is dependent on maintaining constant drilling parameters. The following factors all affect ROP: •

weight on bit


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• • • • • • •

rotary speed bit type/size bit condition mud viscosity hydraulics differential pressure, and lithology

Reference: See Section III of the Abnormal Pressure Technology manual for additional information. Note: The referenced manual should be reviewed before interpreting these parameters during an abnormal pressure hunt.

ROP plotting

Plotting of ROP is used to differentiate pressure-induced drill-off trends from normally expected bit dulling trends. These trends are based on the common assumption that when a bit is first run in the hole and begins to rotate, it begins to wear out or dull which results in a slower ROP (dulling trend).

ROP and lithology

It is important to note lithology changes when plotting ROP. Normally, a drill-off (drilling break) will occur in a silty-shale or sandstone. Thus, when looking for drill-off and dulling trends, "clean" shale intervals should be used.

"d" exponent curve

Another curve used to predict increasing pore pressure is the "d" exponent curve. This drilling exponent is used to normalize ROP data and changes in bit weight, rotary speed, and hole size to detect increasing formation pressure. Reference: See Section III of the Abnormal Pressure Technology manual for additional information. Note: The referenced manual should be reviewed before interpreting these parameters during abnormal pressure hunt.

"dc" exponent Another curve used in the corrected "d" exponent ("dc"). This value is curve the "d" value corrected to the gradient of the basin in which the well is drilled, and for the mud weight. Reference: See Section III of the Abnormal Pressure Technology manual for additional information.


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Note: The referenced manual should be reviewed before interpreting these parameters during an abnormal pressure hunt.

Gas units

One of the most important surface measurement parameters used to indicate abnormal pressure is the "gas unit". There is no quantitative correlation between gas units and pore pressure.

Interpretation of gas readings

Detection of abnormal pressure, and even the evaluation of a zone of interest, is a matter of comparing parameters through the interval in question with the previously established trends. The key to interpretation is not the magnitude of the gas readings but the relative change 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.

Background Gas (BGG) aka Drill Gas

Background Gas (BGG), or Drill Gas is the average gas observed while drilling, exclusive of shows. Background gas represents the gas liberated from the pores in the rock that is being ground up by the bit.

Effect of drill pipe pulling speed on trip gas

Pulling pipe can create a swabbing effect, which lowers the effective bottom hole hydrostatic pressure during tripping. Drill pipe pulling speeds must be reduced in critical sections of the well to a level which minimizes swabbing to ensure that trip gas will be a valid parameter reflecting the actual degree of overbalance of the pore pressure by the static mud weight.

Trip Gas (TG) Trip GAS (TG) is the maximum gas observed on bottoms up after a trip. Trip gas represents the amount of gas feeding into the hole when the pumps are shutdown and the pipe is tripped.


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Connection Gas (CG)

Connection Gas (CG) is the maximum gas observed on bottoms up after a connection. Connection gas represents the amount of gas feeding into the hole when the pumps are shutdown while making a connection. When the pumps are shutdown, the effective mud weight, or equivalent circulating density (ECD) is decreased because of loss of the annulus flow friction effect. Some portion of the connection gas may also be due to swabbing when picking up for the connection.

Connection consistency

To be a meaningful parameter, connections should be made consistently, requiring the same amount of time and pick-up speed to complete each connection. When picking up to make a connection, the pumps 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 simulate connections 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 up capacity plus drill pipe capacity), it sometimes shows a gas peak. These phenomena should be distinguished from connection gas.

Circulating Gas (Circ BGG)

Circulating Gas (Circ BGG) is the stabilized level of gas observed after all of the cuttings have been circulated out of the hole. It represents residual gas in the mud system after recent cuttings gas has been circulated out of the well.

Time for Background gas (when drilling) or bottoms-up gas (after tripping) circulating gas should drop quickly to a stabilized level after circulating out the to stabilize cuttings or trip gas. If significant time is required to reach the stabilized level, gas could be feeding in because of insufficient mud weight.

Show Gas

Show Gas is cuttings gas observed while drilling a potential reservoir interval (usually associated with a drilling break).

Reactions to show gas

Mud weight should not be raised solely in response to show gas from cuttings. When in doubt, circulate out to determine the circulating background gas level. If the excessive gas units drop rapidly to below


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drilling background levels, the gas came from drill cuttings. If the gas units continue to be excessive after circulating out, the well could be at or very near balance conditions.

Shutdown Gas Shutdown Gas is gas resulting from pump shutdown period; i.e., for equipment repair, etc.

Gas reporting

The table below describes how to report the various types of gas.

Gas type Report as Background BGG (Depth to Depth) Gas (BGG) aka Drill Gas Trip Gas (TG) Maximum gas observed from trip depth minus background gas prior to trip. Also note the time between B/U trip gas peak and return to background gas level and report if more than normal. Connection Maximum gas observed from Gas (CG) connection depth minus background gas prior to connection. Also note the time between the B/U gas peak and the return to the prior gas level and report if more than normal. Circulating Stabilized gas units without drill Gas (Circ gas or trip gas. BGG)

Show Gas

Maximum gas observed from the drilling break minus background gas.

Example BGG 40 units from 7000' to 7500' and 60 units from 7500' to 8000'. Background Gas before trip: 50 units Maximum gas observed from trip depth: 150 units Report Trip Gas as: 100 units or 100 units over BGG Background Gas before connection: 50 units Maximum gas observed from connection depth: 75 units Report Connection Gas as: 25 units or 25 units over BGG BGG while drilling is 50 units, after picking up off bottom and circulating out bottoms up, the gas level falls to 25 units. Report Circ BGG as 25 units or 25 units over BGG. Background Gas before drilling break: 50 units Maximum gas observed from drilling break: 750 units Report Show Gas as: 700 units or 700 units over BGG


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Background Gas before shutdown: 50 units Maximum gas observed from shutdown period: 75 units Report Shutdown Gas as: 25 units or 25 units over BGG

Shutdown Gas

Maximum gas observed from shutdown period minus background gas prior to shutdown.

Mud properties to plot

The mud properties to be plotted include: • • • • • •

Frequency of mud properties check

mud density total chlorides (titrated or resistivity) temperature ion change (calcium and sodium) mud viscosity (funnel, plastic, yield point and gels) and pH factor.

When looking for abnormal pressure, the mud properties should be kept as 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 gas cut. Bottoms up after each trip should also be checked.

Plotting method The mud properties should be plotted in a graphical or columnar form.

Changes in rheological properties

Any significant change in the rheological properties of the drilling fluid (especially a freshwater mud) when drilling over-pressured formations may be an indication of an under-balanced wellbore condition.

Changes in chlorides

An increase in the total chlorides over the average for the normal pressure portion of the hole may indicate a formation water influx and entry into higher pore pressure. An increase of chlorides causes drilling fluid chemical changes that show up as an increase in: • • •

funnel viscosity plastic viscosity, and yield point.


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Oil / water ratio If drilling with an oil based mud , the oil/water ratio may be an

indicator of an influx of formation water.

Temperature gradient changes

A temperature gradient change as indicated by the temperature of the mud returns at the flowline may indicate that over-pressured sediments are being drilled. Generally, this change will be an increase in the flowline temperature due to a higher geothermal gradient in the overpressured zone. However, a change in the temperature gradient may also indicate: • • •

Factors affecting temperature

When considering circulating mud temperature to detect a transition zone, it is very important to remember that these temperatures depend upon the following items: • • • • • • •

Temperature plotting guidelines

the crossing of a fault an unconformity, or a change in lithology.

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.

The following guidelines are recommended in order to obtain meaningful temperature data that can be assimilated into pressure indicator 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' of drilling). Observe sudden increase in the outlet/inlet differential.


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Changes in physical properties of cuttings

Cuttings from the transition zone will have different physical properties from normally pressured cuttings. Some of the physical changes are:

Color change

Color change is often noted from multi-colored green, reddish brown, tan and light gray non-marine shales in normally pressured sediments to a darker gray and often dark brown to gray marine shales in abnormally pressured zones.

Texture change

Textural change in shale may be from silty and rough to waxy, slick or soapy.

Shape change

A change in shape may occur from semi-flat, rounded cuttings to angular, flat, splintery and often jagged and elongated (propeller shaped) concave curved cuttings. Sometimes large cuttings several inches long, known as spalling shale, are noted when drilling underbalanced.

Quantity change

Quantity of cuttings often increases when the overpressure becomes greater than the mud column pressure. This occurs when the formation begins to implode into the wellbore. Occasionally, there is simultaneously torquing of the drill pipe and the pump pressure increases. Also, this is generally when you get fill on bottom after making a connection.

Density change

A decrease or departure from the normal compaction trend in the sale density of the cuttings is another indication of drilling overpressured shales.

• • • • • • • •

Composition Color Texture Size Shape Fracture quantity, and bulk density.


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7.3

Abnormal Pressure Detection Team Responsibilities

Team make-up

When deployed an abnormal pressure detection team should consist of the following members: • • • • • •

When should team arrive

Rig Supervisor Wellsite Geologist Drilling Engineer (if required) Paleontologist (if required) Mudloggers, and MWD personnel Rig Hands § Driller, and Shaker hand § Mud Engineer

All team members should be at the well site ±24 hrs before the transition zone is expected. This allows time to monitor all the indicators so that a "normal trend" reference line can be established.

Mission of team

Team members responsibilities

Role Rig Supervisor

Wellsite Geologist

Drilling Engineer Paleontologist

The table below describes the responsibilities of each member of the team. Responsibilities The Rig Supervisor is responsible for the drilling rig and all on-site activities and is designated as the Team Leader. The supervisor has the ultimate onsite authority on when to raise the mud weight, stop drilling, and log based on the advice of the other team members. The Wellsite Geologist's duties are to plot and interpret various geological abnormal pressure indicators, interpret and correlate logs (MDS/LWD logs, electric wireline logs, mud logs, etc.), and calculate estimated pore pressure from logs and shale density plots. The Drilling Engineer's duties are to interpret drilling parameters. The Geologist and Drilling Engineer must maintain close communication and closely analyze the various indicators as the hole is drilled. The Paleontologist's duties (if required) are to identify correlative microfossil zones, construct paleobathymetric maps, and help the team better understand the geology.


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MWD Engineer Mudlogger

Driller

Mud Engineer

Shaker Hand

The MWD Engineer's duties are to maintain QC of LWD logs, and estimate pore pressure changes from log plots. The Mudlogger's duties are to record all abnormal pressure parameters, make lithologic descriptions of the cuttings, watch for hydrocarbon shows, and maintain a lithology/drilling parameter log plotted up to date continuously as the well is being drilled. The driller's duty is to maintain the drilling parameters (WOB and RPM) as constant as possible and as specified by the Rig Supervisor. He should immediately notify the Rig Supervisor of any changes. The Mud Engineer's duty is to measure the mud weight at intervals specified by the Operations Supervisor and keep the other team members updated. The shaker hand's duties are to assist the mud engineer in monitoring mud properties, monitor cutting size and volume, and monitor for flow when pumps are down.

* Most abnormal pressure detection operations are conducted by contract Geologist with no EMDC Geologist or Engineer on site. Proper communication should be made through with the team members at the rig site and office.

7.4

Mud Logging

Where are specifications found

Mud logging services and interval will be specified in the Drilling Program.

Abnormal pressure parameters to be monitored

Abnormal pressure parameters are to be monitored by the mudloggers and 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.


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Plotting Data

While drilling, the Mudloggers will plot the specified data on a mud log on a continuous basis and maintain 24 hour surveillance of the wellbore.

Distribution/ frequency of reports

The Mudloggers will: • •

provide the Drilling Supervisor a copy of the mud log and mud logging report daily, and fix a copy to Company personnel as specified by the Drilling Supervisor/Wellsite Geologist.

Note: It may be required to fax the mud log to the office more often when drilling in or near possible transition zones (typically, a minimum of twice a day to office for Operations Geologist, and Superintendent's review).

Mud logging unit specifications

The mud logging unit should met the following specifications: •

• •

A pressurized logging unit large enough to accommodate the required 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 be intrinsically safe. The unit should have an alarm to detect depressurization.

Detailed specifications for the mud logging unit and associated equipment will be in the mudlogging contract.


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Gas detection equipment

• • • •

Gas trap equipment

•

• •

Computer equipment

•

•

A Hydrogen Flame Ionization Gas Detector (FID) and Hydrogen Flame Ionization Gas Chromatograph system will be supplied on the unit with a second system provided as backup. An integrator will be supplied for gas percentage calculations from 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) will be made each 24 hours to check operation of gas detectors and lag time.

The primary gas trap must be constructed so that mud enters through a 1.5" to 2" hole in a bottom plate on the trap. Two (2) opposed, open stirrup (curved or straight) agitator blades should be 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 the mud. It should be self-calibrating and incorporate two (2) FIDs as sensors.

A minimum of three (3) monitors are to be installed as indicated below: § 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 measuring and 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


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§

mud density

This software and instrumentation should be independent from the rig's instrumentation and have alarms with high/low levels.

Lithology description equipment

• • • •

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.


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7.5 Operational Guidelines Guidelines

Guidelines for drilling in abnormal pressure areas are: •

• • • •

• • • •

•

The BOP must be tested and functioned, and the drill crews determined to be qualified and competent (via training and drills) on flowcheck and well shut-in procedures in accordance with the Well Control Section of this manual. Reference: See the Well Control Section of this manual for additional information. The drilling fluid should be stabilized at the pre-determined weight. Adequate barite must be on the drilling rig to weight up to at least the expected mud weight (minimum: the higher of 1000 sacks 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 of barite at their base and how rapidly it can be mobilized to the rig site. The PVT and FLO-SHO alarms should be set to the lowest practical limits. The abnormal pressure detection parameters specified in the Drilling Program must be monitored continuously. The drilling parameters should be stabilized as soon as possible during each bit run and maintained constant to allow for more accurate pressure detection. If mud weight must be raised in response to abnormal pressure indicators, drilling should cease and the well should be circulated until the system is stabilized at the new mud weight. After consultation with the Operations Superintendent, the mud weight may be increased gradually while drilling if conditions allow. Consideration should be given to using mill tooth bits as they have been the most reliable in responding to abnormal pressure indicators. Successful abnormal pressure hunts have been conducted with insert bits, and PDC bits in areas with significant local knowledge and where offset experience exists.


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Guidelines

Guidelines for drilling in abnormal pressure areas are: •

• • • •

• • • •

•

The BOP must be tested and functioned, and the drill crews determined to be qualified and competent (via training and drills) on flowcheck and well shut-in procedures in accordance with the Well Control Section of this manual. Reference: See the Well Control Section of this manual for additional information. The drilling fluid should be stabilized at the pre-determined weight. Adequate barite must be on the drilling rig to weight up to at least the expected mud weight (minimum: the higher of 1000 sacks 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 of barite at their base and how rapidly it can be mobilized to the rig site. The PVT and FLO-SHO alarms should be set to the lowest practical limits. The abnormal pressure detection parameters specified in the Drilling Program must be monitored continuously. The drilling parameters should be stabilized as soon as possible during each bit run and maintained constant to allow for more accurate pressure detection. If mud weight must be raised in response to abnormal pressure indicators, drilling should cease and the well should be circulated until the system is stabilized at the new mud weight. After consultation with the Operations Superintendent, the mud weight may be increased gradually while drilling if conditions allow. Consideration should be given to using mill tooth bits as they have been the most reliable in responding to abnormal pressure indicators. Successful abnormal pressure hunts have been conducted with insert bits, and PDC bits in areas with significant local knowledge and where offset experience exists.


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FORMATION EVALUATION

8.0 FORMATION EVALUATION

8.1 8.2 8.3 8.4 8.5 8.6 8.7

General Conventional Coring Wireline Logging Program Sidewall Coring Operations Wireline Radioactive Sources MWD/LWD Logging Mud Logging and Cuttings Samples


1 1 8 11 12 12 14

FORMATION EVALUATION 8.1

GENERAL

Formation evaluation takes many forms and in many respects is the province of the wellsite geologist. However, operation of the equipment and its effect on well safety, is the responsibility of the operations supervisor. Therefore, each major method of formation evaluation will be discussed in view of operational considerations. 8.2

CONVENTIONAL CORING

For all Drilling Operations, a supplemental procedure will be prepared detailing the coring operations. The objective of coring is to obtain a formation sample for geological or reservoir evaluation, 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 the maximum 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 is successful and that the money used to obtain and analyze the core is well spent. Deciding on the coring objective, mud type, core cutting method, and core handling procedures at the surface are the first steps in the planning process. The most widely used coring method today is the conventional double tube (inner and outer) core barrel with a PDC or diamond core head. Diamonds cut with a shearing action and thus greatly reduce the fracturing of the core. This enhances the recovery because a non-fractured core is less like 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. Closed catcher core systems such as Baker Hughes Inteq's "Hydro-Lift", used almost exclusively in the Gulf of Mexico, are used in coring unconsolidated formations to enhance recovery. In these cases, use of a face discharge bit (in which the inner core barrel can extend into the bit throat area) is recommended 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 (if possible) by all personnel that will be involved. At the meeting, the coring objectives and the coring plan can be reviewed and minor changes can be made if necessary. The role and responsibilities of all 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


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FORMATION EVALUATION general, for soft formations, large diamonds are spaced relatively far apart, whereas in hard formations, smaller diamonds are set closer together. The cost of the core bit depends on the total carat weight of the diamonds plus the setting charge. Used bits are returned for salvage of the diamonds 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 the formation to be cored along with the available pump horsepower. Relatively large fluid courses permit 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 abrasive formations. When coring in soft formations, EMDC may elect to have the coring company manufacture the core bits with their "throats" 1/8" smaller than the inner barrel or liner inside diameter. This clearance will allow the shales to swell and hopefully prevent the barrel from jamming and resulting in poor recovery. 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 careful monitoring for excessive drag, particularly in the lower portion of the last bit run. As a bit drills hard formations, the gauge protection of the bit can wear creating an under gauged hole. As the full gauge coring assembly enters this part of the hole, the bit and full gauge stabilizers on the core barrel could stick. If the drag becomes excessive, the assembly should be pulled from the hole and a hole opener 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. In order to obtain a good core, the inner barrel must not rotate with the outer barrel. This is accomplished by suspending the inner barrel on a swivel assembly which utilizes a mud lubricated anti-friction bearing. The core bit is made up on the bottom of the outer barrel while the inner barrel is fitted with a core catcher assembly at its bottom. Conventional wall thickness barrels are generally available in the following sizes: Outer Barrel Diameter 4-1/8" 4-3/4" 5-3/4" 6-1/4" 6-3/4” 7" 8"

Core Diameter 2-1/8" 2-5/8" 3-1/2" 4" 4" 4-3/8" 5-1/4"


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FORMATION EVALUATION If either barrel becomes bent, the unit should be replaced because the inner tube will probably rotate with the outer tube. The inner barrel must have a smooth uniform bore to allow passage of the core and to prevent wedging. The unit should always be checked before starting in the hole. The assembly can be hung in the derrick and the inner barrel hand-rotated before making up the core head. Inner Barrel Plastic Liners When coring in soft, unconsolidated formations, a plastic liner can be run that will help prevent the inner barrel from jamming, and help protect and preserve the core during removal and transport. In medium to hard formations, these liners are normally not run. There are three types of plastic liners: 1) Polyvinyl chloride (PVC) with temperature limitations up to 150 degrees F, 2) Acrylonitrile Butadiene Styrene (ABS) with temperature limitations up to 180 degrees, and 3) Butyrate, a clear plastic liner that has a temperature limitation of 140 degrees F. The PVC plastic liner is typically run when coring soft formations, though aluminium liners have been used 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" depending on the size barrel being used. Fluted Aluminium Inner Barrel Very high recovery of long cored intervals has been achieved with fluted aluminium inner barrel in Norway. The design is believed to reduce core to inner barrel friction and therefore reduced jamming. Stabilizers Full gauge (1/32” under) integral bladed stabilizers near the top and just above the bit will keep the barrel from wobbling while coring, and should be replaced when worn down more than 1/8". If under 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 the assembly. An additional trip with a reamer or hole opener may be necessary before coring can commence. Safety Joint A safety joint at the top of the core barrel enables recovery of the inner barrel and core should the outer barrel become stuck. This will leave only the outer barrel and core bit to be fished from the hole. It should be noted that the safety joint is made with a left-hand thread that only requires 50% of the make-up torque to release. In high angle directional wells it may be impossible to work down enough left hand torque to the safety joint without backing-off the drill string at a higher point.


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FORMATION EVALUATION Pump-Out Sub A pump-out sub (circulating sub) should be run above the coring assembly that can be opened in the event that the flow passages around the bit should become plugged during coring operations. A ball is normally dropped and the drill string pressured-up rupturing a disk that opens flow ports in the sub. 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 coring company provides these pump-out subs. Coring Jars Mechanical jars should NOT be run when coring because they can do serious damage to a core barrel assembly. If the drill string is stuck at the bit, mechanical jars have been known to tear the throats out of a core bit. A hydraulic jar (such as Bowen or Houston Engineering) is preferred by most 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 of the 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 prevent damage to the PDC or diamonds. If necessary, a junk boot basket can be used during the last bit run prior to coring. If there is junk suspected on bottom after the last bit run before coring a boot basket run is recommended. The drilling engineer should work closely with the core bit manufacturer to select the best design and type of bit for the type of formation to be cored, anticipated mud properties, and available hydraulic horsepower. As with all drilling assemblies, accurate measurement of the core barrel assembly including the BHA should be made before going in the hole. After touching bottom while circulating, the bit should be held approximately 3 foot off-bottom and circulation continued to wash the hole clean of any 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 as possible without sacrificing hole cleaning. A low water loss mud will reduce filter cake build-up and minimize the chances of sticking. Low viscosity and low water loss will also help reduce pump pressures. In studies performed by Conoco in 1986, they found that very good core recovery (100%) was obtained in their offshore operations when the pressure of the mud column was kept at least 300 psi above the formation pressure using a Saltwater/New Drill type mud system. Coring runs in holes using a freshwater lignosulfonate mud were not as successful (the shales became swollen causing DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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FORMATION EVALUATION them to become sticky and jamming the core barrel), and in those operations done with very low differential pressures, no core was recovered. LCM can be pumped through a core barrel, but the material should be restricted to fine material only. 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 the drill string and is seated in the top of the inner barrel. Coring fluid is then diverted between the inner 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. A stabilizer just above the bit will normally give sufficient stabilization if it is not allowed to get more than 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 4,000 lbs bit weight and with reduced rotary speed. After the stabilizer is buried in the core hole, bit weight and rotary speed may be increased. While coring, the bit weight should be maintained continuously and the weight must never be allowed to drill-off. Allowing the weight to drill-off will produce 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's recommendations. 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-hard formations 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 or undercut 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 could damage 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 be significant to coring success.


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FORMATION EVALUATION When the core is being cut and begins to enter the inner barrel, the pump pressure will increase from 200 to 300 psi and is the result of the pressure drop across the diamond bit. This pressure should be monitored during the coring operation, an increase or decrease normally indicates that something abnormal is occurring and the cause must be determined. Coring operations should cease, the bit should 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 bit is set back on bottom, the bit has probably failed. A ring of diamonds that has been damaged will allow the formation to cut into the matrix, restricting the watercourses and causing the pressure 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 passages in the bit or circulatory system may be the cause. Continued high pressure may also be an indication of swivel failure resulting in lowering of the inner barrel and closing of the fluid passages. In either condition pull the bit.

•

An abrupt increase in standpipe pressure may be caused by plugging of the core barrel from an accumulation 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 the surface equipment, or a hole in the drill string. If this pressure decrease is accompanied by a decrease in penetration rate AND less torque, a wedged core has probably developed holding the bit off bottom. If this condition continues after picking up and setting down the bit, pull out of the hole and recover what core has been cut.

•

When pump pressure fluctuates continuously and the ROP is erratic, it is possible that alternate wedging and crushing of the core is occurring. The barrel should be pulled to avoid loss of recovery.

Making Connections and Pulling the Core A complete set of drill pipe pup joints should be available when coring to prevent making an extra connection. 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 table and pick the core barrel off bottom slowly. A noticeable jump on the indicator will result when the core breaks. If the core is hard to break, pull 15,000 to 30,000 lbs above the weight of the string, set the 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 the new core is entering the inner barrel. This same procedure should be used before pulling the core to avoid leaving a section of core in the hole. It should be noted that not all core barrels have the ability 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 slowly and not rotated to prevent losing the core. Do not pump a slug, and use the trip tank to ensure that DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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FORMATION EVALUATION the wellbore takes the proper amount of mud. Killing a well with a coring assembly in the hole will be 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 to remove a core. In hard formation areas where a plastic inner liner is not used, the inner barrel can be removed from the top of the core barrel and laid on the catwalk where the core is recovered. The core can also be removed while the barrel is left hanging in the derrick a few inches above the rig floor. The core catcher and lower shoe are removed and the core is slid out of the inner barrel and cut into 3 foot sections. In areas where soft, unconsolidated formations are cored, the plastic liner is pushed-out of the inner barrel and cut into sections as it is removed on the catwalk. These sections are marked with orientation stripes, the well name, and coring depth. Small holes are normally drilled into each 3 foot section through the PVC/fiberglass/aluminium liner to vent any trapped gas. These holes are later 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 phases will 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 if the core contains H2S. If working in an H2S area, all personnel on the rig floor will don a self contained 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 off the inner barrel cannot be pumped down. Special inner relief valves must be installed at the surface because it is unlikely that a ball would remain seated in a horizontal well. Do not use MWD or motors when coring. Additional thrust and radial bearings must be built into the coring assembly as well to prevent the inner barrel from rotating. Internal stabilization of the inner barrel to minimize its bending inside the outer barrel may also be needed. It is prudent to run only a 30 foot long core barrel in most instances, unless conditions are extremely favorable. Fiberglass inner barrels should be considered to reduce friction of the core on the bottom side of the inner wall where the core rests as it enters.


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FORMATION EVALUATION A core barrel with high torque threads is recommended for coring in higher angle wells. This type of barrel allows coring in more difficult formations, and will allow more torque to be supplied to the core 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 of the 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, and the 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, the Operations Supervisor and wellsite geologist should thoroughly discuss the various logs and the proper sequence in which they are to be run. If there is any question, the Operations Supervisor should notify the Operations Superintendent. A logical running order is, with GR run on each log for depth control, is: 1. 2. 3. 4. 5. 6. 7. 8.

IES or IES-Sonic as required; GR and /or FDC/CNL as required; Conditioning trip if necessary; MDT/RFT's as needed; Dipmeter as required; Velocity survey if required. Conditioning trip if necessary; Sidewall cores as required;

The correct scales (5" or 1") for each log should be discussed with the logging engineer and checked to prevent having to re-log the well. The logging engineer should be instructed to report to the Operations Supervisor any drag on successive logging runs and any sticking or spudding with the logging tools. Wireline Logging Guidelines 1.

Pre-job meetings will be conducted with the logging engineer prior to beginning each logging job. The Company technical requirements for logging and the specific logging program should be discussed, along with safety procedures for handling radioactive tools and sidewall core guns (SWCs).

2.

The logging Engineer will record digital logging data and provide the required number of final log copies in accordance with the logging program and to the satisfaction of the wellsite geologist.


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FORMATION EVALUATION 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 into consideration the hole condition and previous experience in the area. Typically samples should be taken at the deepest zone of interest first and subsequent samples taken as the tool is pulled up the wellbore to reduce the potential for wireline sticking. However, it may be appropriate to vary the sequence, to ensure the highest priority intervals are tested, in the event that adverse hole 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 at or above BOP stack.

7.

A wiper trip to the casing shoe should normally be made and the hole should be circulated clean prior to pulling out of the hole for logging. A high viscosity gel sweep to remove any loose cuttings may be necessary during this circulation. A logging pill may be spotted on bottom to help suspend any cuttings left in the hole during logging operations. These pills will be detailed in the appropriate drilling procedures.

8.

The Drilling Fluids Engineer will take an "Out" sample of the drilling fluid before stopping circulation prior to POOH for logging and give samples of the drilling fluid, fluid filtrate, and a filter 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 trip tank levels at scheduled intervals (15-minute maximum). The Mud Loggers will also record trip tank levels at the same intervals as a crosscheck. The amount of drilling fluid required to fill 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 equipment at 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. Wash down water will not be used as this will complicate trip tank level readings.


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Hole caliper information (if available) and bottom hole logging temperatures will be sent to the Drilling 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 running casing.

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 tool handling.

18. Logging company personnel will wear appropriate radioactive monitoring devices and take the necessary 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 H2S areas 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 specified in the contract.

2.

Ensure that sufficient tools (primary and back-up) are onboard the drilling rig as specified in the contract.

3.

Ensure that all tools are in operating order immediately after arriving at the wellsite. Provide service 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 tool run in the hole.

5.

Ensure that overshot grapples and cut and strip equipment is available on the drilling rig for each different size of fishing neck before running the logging tool.

6.

Ensure that logging tools are not stationary in the wellbore except when taking a sample/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 any oil or lubricants prior to leaving the location.


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FORMATION EVALUATION

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 will be observed when attempting to free stuck tools: 1.

A 75% criteria will be used for maximum overpull of stuck tools/wireline (i.e., overpull will not exceed 75% of the rating of either the rope socket or the wireline). If a cable head tension surface read-out is available, surface line tension will be used to determine the pull on the wireline, and the cable head tension surface read-out can be used to determine the amount of pull on the rope socket. NOTE: If the float equipment has been drilled out with an undersized bit that results in a core of cement remaining in the shoe joints, watch for line key seating. If the logging tool becomes stuck, refrain from repeated pulls on wireline, to prevent damaging and cutting the line. Even though it is time consuming, a strip-over job has less risk than a wireline-fishing job.

2.

All personnel will be cleared from the rig floor and from any areas under the wireline when pulling 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 and flagged 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 the drilling rig when picking-up, laying-down and tripping in the hole with the sidewall core guns until the guns are well below the mudline.

3.

All helicopters and boats in the immediate area will be notified to maintain radio silence until further notice.

4.

The shore base will be advised of the radio silence start and end times.


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All non-essential personnel will be cleared from the rig floor when handling the core gun on the rig floor.

6.

All personnel working below the rig floor (e.g., Texas deck area of the rig and well bay/+15 area of a platform) will be alerted and removed from the area when running a sidewall core gun into the wellbore. Once the gun is below the mud line, normal work can continue. When pulling the SWC gun from the wellbore and the gun is at or above the mud line the precautions mentioned above will be taken.

*NOTE: See EMDC Safety Manual for recommended safe working practices in Wireline Perforating 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 off bullets" 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 of misfires, number of bullets left in hole, number of cores recovered, any other gun parts left in the 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 the most 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 high quality data prior to hole erosion and invasion, and to facilitate abnormal pressure hunts, casing seats, and core points.


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MWD/LWD tools with integral blade stabilizers should be used if a near bit stabilizer is necessary.

Stuck Pipe MWD/LWD tools should be run near the bit since the inside diameter of the tools will prevent wireline access for free-pointing stuck pipe. Several systems allow wireline passage after retrieving the electronics package. Use of downhole screens just above the MWD to prevent jamming may be used but could eliminate retrieving sources or electronics in the event of a stuck BHA. DP screen decision 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 may cause 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 screen inside drill pipe at each connection will prevent the use of wireline tools if the drill pipe becomes stuck or during well control operations. Use of downhole filter screens just above the MWD are permitted, but may prevent retrieval of sources or electronics. Use of downhole screens must be coordinated with the Operations Superintendent.

3.

The MWD/LWD power turbine (if not battery operated) should be sized to obtain the range of flow rates needed for drilling the hole section expected to be penetrated on that run (coordinate with service company personnel). Additionally, MWD/LWD equipment hydraulic pressure requirements 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 supply vessel and around the drilling rig.

2.

Extreme care should be exercised when moving MWD/LWD tools onto the rig floor to prevent any unnecessary blows or jars that could cause internal damage. These tools do not have the wall thickness of drill collars and they can bend quite easily. Rough handling can damage the internal electronic packages of the tools.

3.

Only MWD/LWD service personnel will handle the tools as some LWD logs have radioactive materials.

Lost Circulation Material (LCM) Lost circulation treatment options are limited with MWD/LWD tools in the hole (check with LWD personnel for specific tool details). If severe lost circulation is expected, MWD/LWD tools should not be used. These tools are very expensive and lost circulation can easily result in stuck pipe and DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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FORMATION EVALUATION the loss of the tools or damage to the tools. Should lost circulation occur with an MWD/LWD tool in the hole, the following steps should be taken •

If lost returns are expected, size and set-up the MWD/LWD and motor as applicable to accommodate 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 at all possible.

•

If necessary, pump fine or medium grade LCM well mixed. Limit LCM (nutplug) to a maximum concentration of about 30 ppb fine, or 20 ppb medium when pumping through an MWD/LWD tool.

•

For specific LCM material or concentrations consult with the service company and refer to the applicable drilling procedure. Newer generation MWD/LWD tools have a higher tolerance for lost circulation material; service personnel can give a good estimate on the concentration of material each tool can withstand before plugging. Some tools can be "turned off" by adjusting flow 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 used in 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 part of formation evaluation, has been previously addressed in Section 7 of this manual. Cuttings samples will also be collected, as specified in the drilling program. Typically, several sets of washed and unwashed cuttings samples will be required. These samples will be collected at the intervals 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. Inspect the hoses (typically Polyflow) every 2-3 months, and replace if it has been pinched, is brittle, or is discolored from the normal clear or white color (OIMS Manual Element 6).


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CASING OPERATIONS

9.0 CASING OPERATIONS

9.1 9.2 9.3

Casing Running Casing Connection Make-up Casing Checklist


1 5 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 rig is ready to have the casing sent to location, the Operations Supervisor is to call out and arrange delivery from shore base.. Unless otherwise noted in the applicable procedure, the casing operating guidelines in this section will apply. It is the responsibility of the Operations Supervisor to ensure that the casing running or liner running operation is conducted according to the guidelines and requirements in this manual and/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 all personnel involved with the casing/liner running will review the JSA.

OIMS REQUIREMENT: Use an Excel spreadsheet to generate the casing tally report. The original should be forwarded to the Drilling Engineer and should be included in the final well report (OIMS Manual 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 of joints will be counted and compared with the cargo manifest. Any discrepancies will be noted and recorded.

3.

The weight and grade of each joint of the casing will be checked to ensure that the proper casing 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 time connections will be "field prepped" and doped with the proper thread compound at the yard prior to sending to location. The casing, threads and couplings will be visually inspected for any 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 personnel understand what areas of the connections are the sealing areas.


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CASING & LINER OPERATIONS 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 the diamond (1-2 inches before the thread run-out on the pin end). This can result in the casing shoe being deeper than anticipated if measurements are made to the thread run-out. Ensure strap 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 of joints, 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 be kept 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 possible design productive zones in order to facilitate future correlation. RA (Radioactive) Tags may also be useful to ensure accurate tie in when drilling high angle directional wells or when a premium casing thread may be difficult to see with a casing collar locator log (e.g. CRA casing, integral connection). Use of such devices will be specified in the appropriate casing procedure. 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. The general guideline on rathole is no more than +/- 50' TVD of the permit depth, deep enough to get all LWD information required below the sand bottom, or deep enough so that the float equipment does not need to be drilled out on production casing. Rathole is more critical for mandrel 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 of casing should be run between the float shoe and the float collar as float joints. Typically one joint with the float collar made up on the end and thread locked and one joint with the float shoe made up on the end and thread locked are assembled in the yard and sent to the rig. A back up set of float equipment is also sent to the rig loose.


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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 applicable procedure.

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 deems necessary.

2.

Prior to running casing, a planning meeting will be held with personnel that are directly involved with the casing job to ensure that key personnel understand the job and their particular responsibilities. The casing running procedure will be reviewed and it will be verified 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 head should be spaced out if possible, so that the mandrel casing hanger can be run all the way through the stack and landed without having to make a connection while the hanger is in the BOP.

4.

The casing hanger and wellhead running tools will be carefully inspected and serviced prior to running. These tools should be made up and stood back in the derrick if possible prior to the wiper trip before running casing.

5.

The drill string should be strapped out of the hole after TD of the hole section. discrepancy 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 of pipe 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. discretion based on current well conditions.) Prior to pulling out of the hole on the wiper trip after logging, the drilling fluid will be conditioned to ensure that it is virtually free of cuttings and is of uniform density, with acceptable properties. Based on hole conditions, a casing running pill may be spotted after conditioning the fluid properties and before pulling out of the hole.


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If a


The primary well control method is fluid weight. The annular preventer will be used as the secondary means of well control with the casing rams as the third method during casing running operations. Before running casing, reduce the regulator pressure on the annular preventer per manufacturer's specification for the casing size in order to prevent collapse of the 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 the casing 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 valve such as a TIW valve. •

Perform a function test of the safety valve on the casing-by-drill pipe crossover and casing swedge before running casing. Record this safety valve function test on the Daily IADC Report and morning report.

12.

For heavy liners, the casing load and overpull limitations will be calculated to ensure that the drill 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 one joint of casing by filling the casing with fluid and picking up to ensure that the fluid drops out of the casing and stays out after running it back in the hole (if Auto-Fill equipment is not being used).

15.

The casing will be filled on a regular basis while picking up the next joint and the fill is to be confirmed at regular intervals. The casing should be filled with the drilling fluid used while drilling the hole. Stop in cased hole and fill the casing entirely prior to running casing/liner into the open hole. Once the casing is in the open hole fill the casing as run but do not stop to fill 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 counteract the buoyant effect of the casing in the mud (buoyant effect can dislodge the casing from the slips and the casing can fall downhole).

18.

Returns will be monitored (watch for indications of the well flowing) and running speed adjusted to minimize drilling fluid losses to the hole. Any limitations on casing running speed will be specified in the Drilling Program.


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CASING & LINER OPERATIONS 9.2

CASING CONNECTION MAKE-UP

1.

Make-up torque will be specified in the Drilling Program based on the connection type, mill coating on the threads, and the thread compound to be used. For all offshore wells using API STC and LTC connections for any string, EMURC Torque-Position values will be used. For API BTC connections, use the EMURC Torque-Position Manual and Torque Position values for casing sizes less than or equal to 7-5/8". For BTC connections in casing sizes greater than 7-5/8" use the EMURC Torque-Position Manual 4-T method. For premium connections, connections will be made up per the manufacturer's recommended procedure. (Reference Operations Technology Bulletin 98-68 revised 11/9/1998.) Modified API connections with seal 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 specifications will be used.

3.

Use tong mounted computer to track each connection make-up. The casing company will ensure 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 casing troubles are encountered (e.g. casing leak) and the make-up torques need to be reviewed.

9.3

CASING CHECKLIST

Casing 1. 2. 3. 4. 5. 6. 7.

Is condition of casing acceptable? Is size and condition of casing drifts adequate? Has casing been drifted, strapped, tallied and verified? Is condition of casing threads acceptable? Is enough excess casing on board ? Is numbering of casing joints correct? Is thread compound type and quantity acceptable?

Yes/No Yes/No Yes/No Yes/No Yes/No Yes/No Yes/No

Operations 1. 2. 3. 4. 5. 6. 7. 8. 9.

Are theoretical returns and casing fill up volume calculations correct? Are fill-up and displacement volumes correct? Is the reduction of the hydrostatic pressure due to spacer volume a problem? Is as much rig up completed as possible during HO run, and logging operations? Are drill floor and catwalk clear of non-essential equipment? Has a safety meeting been held prior to rigging up equipment? Is hole monitored on trip tank while completing rig up? Does Driller know proper casing running speed? Does the Tong hand know the correct make-up speed and torque?


Yes/No Yes/No Yes/No Yes/No Yes/No Yes/No Yes/No Yes/No Yes/No

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CASING & LINER OPERATIONS Casing Running Equipment 1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

Is all casing running equipment onboard and in acceptable condition? Are casing slips the correct size and in good condition? Are the ratings of spiders/elevators/links acceptable for the casing job? Are tong dies the correct size and in good condition? Are clamp-on protectors the correct size and is the quantity on board acceptable? Is the tensile strength of the landing string sufficient? Does the casing/drill pipe crossover thread match the casing? Does the circulating swedge thread match the casing? Has the safety valve been actuated, left in the open position, and recorded on the IADC/morning report? Has the stabbing board been inspected and found to be acceptable? Raise permit for use of stabbingi board & review JSA.

Yes/No Yes/No Yes/No Yes/No Yes/No Yes/No Yes/No Yes/No Yes/No Yes/No

Cementing Equipment/Accessories 1. 2. 3. 4. 5. 6. 7. 8. 9.

Is cementing head the correct size, threads, and in good condition? Are casing subs and swedges the correct size, threads, and in good condition? Is operations supervisor's visual inspection of all other threads complete? Is float equipment the correct size, weight, and threads? Are centralizers the correct size, number, with adequate stop rings? Is there enough Thread-Lok and Threadkote or equivalent for casing job? Is float shoe and float collar clean and free of debris and the cement undamaged? Is the landing joint/cementing head made up? Have the wiper plugs been inspected and installed correctly in cement head?

Yes/No Yes/No Yes/No Yes/No Yes/No Yes/No Yes/No Yes/No Yes/No

ExxonMobil Drilling Superintendent to verify proper loading of plugs in head.


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CASING & LINER OPERATIONS 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", American Petroleum 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 December 1999, Wells and Materials Division.

6.

EUSADO, Operations Technical Bulletin 98-68, revised November 9, 1998.


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CEMENTING

10.0 CEMENTING

10.1 10.2 10.3 10.4 10.5 10.6 Appendix G-I

General Cementing Guidelines Primary Cementing Remedial Cementing Cementing Checklist Reference ExxonMobil Cement Testing Guidelines


1 1 3 5 6 7

CEMENTING 10.1

GENERAL

This section provides guidelines and procedures for cementing operations. Whenever possible, a cementing 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.). The chart 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 of cementing operations a procedure should be written using the guidelines found in this section as a reference (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 are directly involved with the cement job to ensure that key personnel understand the job and their particular responsibilities. The cementing procedure should be reviewed and it verified that job responsibilities and safety precautions are clear to all personnel.

2.

A good communication system between the rig floor and the cement unit is necessary. Rig phones or hand-held radios are acceptable means of communication.

3.

Assign one individual (preferably the Operations Supervisor) to coordinate and direct operations between the rig floor and the cementing unit.

4.

All lines including the cement manifold should be pressure tested to the pressure specified in the applicable cementing procedure prior to cementing.

5.

All cementing equipment, including the densiometer, should be thoroughly checked to ensure it is in good repair and functions properly.

6.

Hole calliper information and bottom hole logging temperatures should be sent to the Drilling Engineer as soon as practical during logging operations in order to finalize cement volumes and confirm cement thickening times. Hole calipers may be backed out of same LWD data and some 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 are important to consider when deciding which pump to use for displacement. The following are general guidelines:

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

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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 be displaced to about 20 feet below the stinger.

•

For full casing string cementing either the cement unit or rig pumps may be used for displacement. As a guideline, use the cement unit for displacements < 200 bbls or where the casing will not be drilled out. Use the rig pumps for displacements > 200 bbls or if the string will be drilled out. Each job should be considered individually based on conditions at the time of the cement job.

•

For liners, the cementing pump should be used until the top plug is launched, then the rig pump may be used, if desired, to complete the displacement and bump the plug. If high pressures (i.e. > 3000 psi) are anticipated it is probably best to continue displacement with the cementing unit.

2.

If cement is to be displaced with the rig pumps, the pumps are to be calibrated using the trip tank prior to starting the cement job. As a contingency displacement mud pit to be observed for fluid loss when pumping with rig pumps.

3.

Ensure the cement unit is ready to finish the cement displacement if the rig pumps encounter a problem and vice versa. Have the ability to switch from the rig pumps to the cement pumps as needed.

4.

Do not over displace the cement by more than 50% of the volume of the float joints. If the casing 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 require leaving 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 be checked to ensure they are in proper working order and that safety devices are in place to prevent 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 the casing / liner during displacement of the cement.

4.

A cement manifold that is designed for a top drive system is to be used, if applicable.


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CEMENTING 5.

If the casing / liner is to be reciprocated or rotated during the cement job, the top drive cement head/manifold rating must be adequate to support the casing and landing string weight plus 100,000 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 not sufficient 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) are available on the floor for the appropriate size and threads casing. Function test these valves and 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 to help 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. If practical, there should be 50-100% excess cement and 100% excess liquid/dry additives at the rig 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 cause plugging during the cement transfer).

4.

At least two people will calculate the total cement job volumes, including the required volume to displace the top plug to the float collar.

5.

The volume of mix water pumped will be used to calculate the actual volume of cement pumped. Never rely on P-tank volumes.

6.

Circulate and condition the hole prior to cementing. The drilling fluid should be conditioned to ensure that it is virtually free of cuttings, that gas is back down to background levels and that it is of uniform density with acceptable properties.


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CEMENTING 7.

Ensure that the cement head/manifold releasing mechanisms are working properly and that personnel are familiar with their operation.

8.

The Operations Supervisor will witness the cementer load the wiper plugs in the cementing head/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 returns during cementing operations should be reported on the daily morning report, noting time of loss and pressures. Run ECD calculating software tool on cement jobs where lost returns are possible to fine tune displacement rates.

10. The slurry weight should be kept as consistent as possible to keep from extending or retarding setting 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 balance to 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 during cementing. A styrofoam/paper coffee cup filled three-fourths full, stored in a protected area is an adequate sampler. 13. After mixing the cement, release the top plug and pump the spacer with the cement unit placing a small volume of cement on top of the wiper plug. If desired, switch to the rig pumps to finish displacement. 14. Displace the calculated casing volume or until the plug bumps. Do not over displace unless told 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 to rock them on seat by repressuring the casing string. If flow back continues, shut in and hold pressure on the casing at least until surface samples setup or no backflow occurs.


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CEMENTING 10.4

REMEDIAL CEMENTING

Remedial cementing is sometimes necessary to rectify poor leak-off below a casing shoe, repair casing or liner top leaks, squeeze off perforations, etc. The primary techniques used for these operations 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 these procedures may be required. When a squeeze procedure is prepared, two cement slurries should be designed and tested. If a low injection rate is all that can be established a low fluid loss cement slurry should be pumped to prevent the cement from being dehydrated as it is squeezed away. If a high injection rate can be established, a cement slurry with higher fluid loss (less expensive) should be pumped. Depending on 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 desired bottom of cement.

2.

Circulate and condition the hole prior to cementing. The drilling fluid should be conditioned to ensure that it is virtually free of cuttings, that gas is back down to background levels, and that 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 top of 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 the top a minimum of 165' above the casing shoe. Attempt to rotate drill string to improve displacement 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 by pumping 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 compressive strength. 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 is acceptable. POOH.


5 of 7

CEMENTING 10.5

CEMENTING CHECKLIST

Squeeze/Open Hole Plug Work Strings 1. 2.

Is there (+/- 700') of stinger (2-7/8" or 3-1/2" tbg, or 3-1/2" DP) at rig? Are there appropriate handling tools for stinger at rig?

Yes/No Yes/No

Cementing Equipment/Accessories 1. 2.

Are wiper plugs correct size for casing and free of cuts and/or defects? Witness loading of wiper plugs in cementing head/manifold?

Yes/No Yes/No

Cement Supply 1. 2. 2. 3.

Is correct type and amount (50-100% excess if practical) of cement at rig? Are adequate quantities (100 % excess if practical) of additives onboard? Inspection of cement storage and transfer facilities complete? Is there an alternate source(s) of cement if a pneumatic line breaks or plugs?

Yes/No Yes/No Yes/No Yes/No

Cementing Personnel 1. 2. 3.

Do cementer and key personnel agree on all volumes and rates? Does cementer understand contingency plan/procedures? Are two individuals assigned to record displacement volumes?

Yes/No Yes/No Yes/No

Cement Pumping 1. 2.

In case of cement pump failure, is rig pump ready to take over? Is rig pump efficiency known by pumping into a calibrated tank?

Yes/No Yes/No

Cement Mixing 1. 2. 3. 4.

Is cement mixing equipment working properly before cementing? Is calibration of pressurized mud balance complete? Are densiometers operating correctly before cementing (calibrated)? Are adequate blended sample containers available?


Mix Water/Displacement Fluid 1. 2.

Is quality and supply of cement mix water satisfactory? Is quality and supply of displacement fluid satisfactory?

Yes/No Yes/No

Pressure Testing/Safety 1. 2. 3. 4.

Is chiksan line from cement manifold safely chained to hook or bails? Is testing of cement lines to specified working pressure complete? Has cement manifold been pressure tested to specified working pressure? Has safety valve been installed at top of work string.



6 of 7

CEMENTING 10.6 1. 2. 3. 4.

REFERENCE EPR, Cement Slurry Design Manual EPR, Primary and Remedial Cementing Halliburton, Technical Data Cementing Notebook Halliburton, Cementing Tables Handbook.


7 of 7

SQUEEZE PROCEDURE

EMDC DRILLING

SECTION 10 - APPENDIX I EXXONMOBIL DEVELOPMENT COMPANY DRILLING 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 tailoring the procedure to specific applications. Comments and hidden text can be viewed by choosing View on the menu bar and Comments from the drop down menu. The paragraph symbol (¶) on the standard tool bar also turns the hidden text on and off.) Engineering/Operations Comments Revision

JWB/AMK

1.2 PROCEDURE OBJECTIVE AND KEY ISSUES This 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 successful pressure 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 WANT CLARIFICATION ON WITH THE ENGINEER AND/OR OPERATIONS SUPERINTENDENT. DISTRIBUTE PROCEDURE TO FIELD PERSONNEL FOR EQUIPMENT AND PROCEDURE VERIFICATION. DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING

Version 3–April 2003 Page 1 of 18

SQUEEZE PROCEDURE

EMDC DRILLING

SIGNIFICANT CHANGES IN OPERATIONS FROM PROCEDURE REQUIRE EVALUATION AND DOCUMENTATION. DISCUSS WITH APPROPRIATE TEAM MEMBERS AND COMPLETE MOC FORM.

1.3 SAFETY Prior to starting each different type of operation, conduct safety meeting with all personnel involved and review job plans. Prepare and review JSA's for all critical operations. Rig Superintendent and Toolpusher should review each JSA prior to beginning work for thoroughness, proper hazard identification, and risk mitigation.

1.4 LIST OF APPLICABLE OP-TECH BULLETINS BULLETIN NUMBER 26 56 98

TITLE Failure to use recommended set screw w/ EZSV cement retainer results in expensive fishing job. Considerations for liner top squeeze cementing in OBM in Directional Hole Stuck "Fasdrill" retainer on recent Pecan Island well.

1.5 SERVICE COMPANY INFORMATION SERVICE Cementing Operations Lab Sales

COMPANY BJ Services

LOCATION Houma New Orleans New Orleans

REPRESENTATIVE Dispatcher John St. Clergy Sparky Barkman

PHONE NUMBER (281) (281) (281)

Squeeze tool provider

Halliburton

Houma New Orleans New Orleans

Dispatcher Rick Dupont Mark 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 DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING


SQUEEZE PROCEDURE

EMDC DRILLING

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

DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING


SQUEEZE PROCEDURE

EMDC DRILLING

2. DESIGN BASIS 2.1 GENERAL INFORMATION Casing Shoe Squeeze Before Opening Squeeze Tool

Liner Top Squeeze Before Opening Squeeze Tool

After Squeeze

Squeeze Tool @ 9315'

After Squeeze

Squeeze Tool @ 8800' TOC @ 8950'

TOC @ 8950' Top of Liner @ 9150' Casing shoe @ 9315'



SQUEEZE PROCEDURE

EMDC DRILLING

2.2 CURRENT STATUS Pipe Set

MD (ft) -

24” Drive Pipe 20” Conductor Casing 16” Surface Casing 9-5/8” Protective Casing 8.500”: Drift diameter of 9-5/8” casing

TVD (ft) -

Casing in which squeeze tool will be set in: 7-5/8" 39.0# 6.625"ID Casing burst rating w/ (1.375) SF: - psi Casing was successfully tested to - psi or Estimated Pore pressure at casing shoe: - psi or Estimated Frac pressure at casing shoe: - psi or Desired PIT or Liner Top Test is - psi or 5 Maximum angle in wellbore above planned squeeze tool depth: 1.5 Maximum dogleg in wellbore above planned squeeze tool depth: Mud Weight: - ppg Mud Type (WBM / OBM ): -

ppg EMW @ casing shoe/liner top ppg EMW ppg EMW ppg EMW ° ° per 100'

DEPTHS FROM RKB Description Depth to Top of Liner/Casing Shoe Planned Depth of Squeeze Packer Planned Height of Cement in Casing Estimated TOC in casing

MD (ft) 9315 8915 150 9165

TVD (ft) 9315 8915 200 9165

CAPACITIES/DISPLACEMENTS Size

Weight

Nom. ID

Drift ID

Footage

7-5/8" 3-1/2" IF -

39# 13.3# S-135 -

-

-

250' 8915' -

X X X X



Capacity Bpf .054375 .007220 -

= = = =

Displacement Bbls 10.70 64.40 0

SQUEEZE PROCEDURE

EMDC DRILLING

2.3 CEMENT DATA SUMMARY Cement Company: Dowell @ 512-456-9874 High injection rate/Low injection pressure slurry Cementing Slurry ---Sacks Class " " ---Additive ---Additive ---Additive ---ppg slurry ---cf/sk yield ---gal/sk mix water ---bbl slurry volume ---bbl water volume ---Estimated pump time

Pilot Test Results ---Thickening Time ---psi 12 hour compressive strength ---psi 24 hour compressive strength ---cc/30 min water loss ---ml/250ml Free Water -------

oF

----

Pilot Test Requested

oF

BHST BHCT (sqz schedule)

Low injection rate/High injection pressure slurry Cementing Slurry ---Sacks Class " " ---Additive ---Additive ---Additive ---Ppg slurry ---cf/sk yield ---Gal/sk mix water ---Bbl slurry volume ---Bbl water volume ---Estimated pump time

Pilot Test Results ---Thickening Time ---psi 12 hour compressive strength ---psi 24 hour compressive strength ---cc/30 min water loss ---ml/250ml Free Water -------

oF

----

Pilot Test Requested

oF

BHST BHCT (sqz schedule)

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 casing scraper thoroughly across the interval of pipe at planned SQZRETAINER setting depth. Circulate bottoms up below 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: DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING


SQUEEZE PROCEDURE

• • • •

EMDC DRILLING

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 the bottom 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 rig circulated 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). Set SQZRETAINER @ TOOLMD MD (do not set retainer below 10,005’ which is where cement was tagged when running in the hole to clean out). Ensure that the retainer will not be set in a casing collar. Verify setting with 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 at 1/2, 1, 2, 3, and 4 bpm without exceeding injection pressures of 4,500 psi (Engineer to comment on basis for maximum 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”). Monitor annulus 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 have been 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 Superintendent and the Drilling Engineer to discuss results of the injection test (injectivity will dictate if a change is needed in the 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 not yet 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 - 6 bpm. 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 outrun the pump rate due to U-tube pressure. Take returns through the choke, if necessary, so that back pressure can be applied to prevent cement from circulating around DP before stinging into SQZRETAINER.



SQUEEZE PROCEDURE

EMDC DRILLING

PUMP SCHEDULE BEFORE STINGING INTO THE SQZRETAINER Description Density Pump Rate 30 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 the SQZRETAINER) 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 and pressure up 500 - 1,000 psi on the DP by casing annulus. Pump an additional 119 bbls of 15.7 ppg mud at 4 bpm followed by 5 bbls of freshwater down the DP. This will leave 2 bbls of cement in the DP above the retainer. Do not overdisplace the cement. PUMP SCHEDULE AFTER STINGING INTO THE SQZRETAINER Description Density Pump Rate 119 bbls mud 15.7 5 bbls Fresh Water 8.3 This will leave 2 bbls cement above the SQZRETAINER in the DP. (118' inside the DP above the SQZRETAINER) Note: Displacement volumes assume a 12 ppg FCS in the G-series sand at 10,000' TVD. 5 bbls of water displacement 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 drill pipe, perform the following steps: sting out of retainer, POOH 2 stands, reverse circulate out 2 workstring volumes at the maximum rate while keeping the pipe moving (do not exceed the casing test pressure of 3520 psi 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 rate possible (do not exceed the casing test pressure of 3520 psi 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” clean out assembly and TIH to 9,750’ MD. (180' above expected TOC). 10. Ensure 18 hours has elapsed since cement was pumped and wash down to TOC. Drill cement/SQZRETAINER and continue drilling down to the LNROD liner top @ 10,255’ MD. Do not rotate excessively on the liner top to avoid damaging the tie-back receptacle. C&C mud to clean wellbore.



SQUEEZE PROCEDURE

EMDC DRILLING

Note: If ratty and/or soft cement is encountered as deep as 90' above the expected TOC, PU 3 stands and circulate 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 not hard. 11. Pressure test the LNROD liner top to 2,300 psi with 15.7 ppg mud. Use the PIT technique at 1/2 bpm and record pressure vs. volume pumped. Hold test pressure for 30 minutes. After test, record volume of mud bled 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 scraper thoroughly across the interval of pipe at planned SQZTOOL setting depth. Circulate bottoms up below the SQZTOOL 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 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 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 the bottom 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 rig circulated 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). Set SQZTOOL @ TOOLMD MD (do not set squeeze tool below 10,005’ which is where cement was tagged when running in the hole to clean out). Ensure that the squeeze tool will not be set in a casing collar. Verify setting 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) 4. Close annular BOP and pressure up on DP by casing annulus to 500-1000 psi. Establish injection rates at 1/2, 1, 2, 3, and 4 bpm without exceeding injection pressures of 4,500 psi (Engineer to comment on basis for maximum 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”). Monitor annulus 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 have been tested to 5,000 psi, and the SQZTOOL is rated for 5,000 psi of differential pressure. DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING


SQUEEZE PROCEDURE

EMDC DRILLING

Use the PIT plotting technique to record pressure vs volume pumped. Contact the Operations Superintendent and the Drilling Engineer to discuss results of the injection test (injectivity will dictate if a change is needed in the 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 not yet 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 pump rate due to U-tube pressure. Take returns through the choke, if necessary, so that back pressure can be applied to prevent cement from circulating above the SQZTOOL before the bypass is closed. PUMP SCHEDULE BEFORE CLOSING THE BYPASS ON SQZTOOL Description Density Pump Rate 30 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 the SQZTOOL) 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 casing annulus. Pump an additional 119 bbls of 15.7 ppg mud at 4 bpm followed by 5 bbls of freshwater down the DP. This should leave TOC 250' below the SQZTOOL, and 250' above the liner top. PUMP SCHEDULE AFTER CLOSING THE BYPASS ON SQZTOOL Description 119 bbls mud 5 bbls Fresh Water This will leave the TOC 250' below the SQZTOOL, and 250' above the liner top.

Density 15.7 8.3

Pump Rate

Note: Displacement volumes assume a 12 ppg FCS in the G-series sand at 10000' TVD. 5 bbls of water displacement 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 drill pipe, perform the following steps: release the squeeze tool, POOH 5 stands, reverse circulate out 2 workstring volumes at the maximum rate (do not exceed the casing test pressure of 3520 psi while reversing), POOH 1 additional stand, set the packer and put 500-1000 psi on the annulus.



SQUEEZE PROCEDURE

EMDC DRILLING

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 first 3.0 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 hold whatever pressure is achieved for required stage time before continuing with next stage. Stop pumping at any point if 1675 psi is reached (21.0 ppg EMW). If pressure limit is reached, discontinue staging process and hold final pressure for WOC time. If 1675 psi is not reached after squeezing 5.0 bbls, stop staging process and hold whatever pressure is present. Estimated TOC after the hesitation squeeze is 185' above the liner top. 9. Hold the final squeeze pressure for 12 hours. The drill pipe pressure should increase due to thermal expansion. Allow the drill pipe pressure to rise as high as 4500 psi (21.0 ppg EMW) before bleeding off any pressure. If the pressure builds to 4500 psi, bleed back to 3500 psi before continuing to hold squeeze pressure. If backside pressure increases above 500-1000 psi, it may be indicative of a leak in either the packer 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. If OK, 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 cement down to the LNROD liner top @ 10,255’ MD. Do not rotate excessively on the liner top and avoid damaging the tie-back receptacle. C&C mud to clean wellbore. Note: If ratty and/or soft cement is encountered as deep as 90' above the expected TOC, PU 3 stands and circulate 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 not hard. 12. Pressure test the LNROD liner top to 2,300 psi with 15.7 ppg mud (20 ppg EMW at the liner top). Use the PIT technique at 1/2 bpm and record pressure vs volume pumped. Hold test pressure for 30 minutes. After test, 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 casing scraper thoroughly across the interval of pipe at planned SQZRETAINER setting depth. Circulate bottoms up below 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 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.



SQUEEZE PROCEDURE

• •

EMDC DRILLING

After determining that a squeeze was necessary, the BHA was tripped and rotated across the bottom 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 rig circulated 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). Set SQZRETAINER @ TOOLMD MD (do not set retainer below 10,005’ which is where cement was tagged when running in the hole to clean out). Ensure that the retainer will not be set in a casing collar. Verify setting with 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) 4. Close annular BOP and pressure up on DP by casing annulus to 500-1000 psi. Establish injection rates at 1/2, 1, 2, 3, and 4 bpm without exceeding injection pressures of 4,500 psi (Engineer to comment on basis for maximum 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”). Monitor annulus carefully for pressure response indicative of packer or DP leak. Note that the CGOD CGWT was last tested to 3,825 psi with 15.7 ppg mud, the cement lines have been tested to 5,000 psi, and the SQZRETAINER is rated for 5,000 psi of differential pressure. Use the PIT plotting technique to record pressure vs volume pumped. Contact the Operations Superintendent and the Drilling Engineer to discuss results of the injection test (injectivity will dictate if a change is needed in the cement design or pump volumes). Do not exceed the PIT test pressure of 3300 psi with 12.7 ppg mud (15.0 ppg EMW) if injection has not yet been 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 - 6 bpm. 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 outrun the pump rate due to U-tube pressure. Take returns through the choke, if necessary, so that back pressure can be applied to prevent cement from circulating around DP before stinging into SQZRETAINER. PUMP SCHEDULE BEFORE STINGING INTO THE SQZRETAINER Description 30 bbls pre-flush spacer (MCS-3) 38 bbls (150 sacks) low FL squeeze slurry (See Cement Data for recipe) DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING


Density

Pump Rate

SQUEEZE PROCEDURE

EMDC DRILLING

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 the SQZRETAINER) 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 and pressure up 500 - 1,000 psi on the DP by casing annulus. Pump an additional 119 bbls of 15.7 ppg mud at 4 bpm followed by 5 bbls of freshwater down the DP. This will leave 2 bbls of cement in the DP above the retainer. Do not overdisplace the cement. PUMP SCHEDULE AFTER STINGING INTO THE SQZRETAINER Description Density Pump Rate 119 bbls mud 15.7 5 bbls Fresh Water 8.3 This will leave 2 bbls cement above the SQZRETAINER in the DP. (118' inside the DP above the SQZRETAINER) Note: Displacement volumes assume a 12 ppg FCS in the G-series sand at 10,000' TVD. 5 bbls of water displacement 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 drill pipe, perform the following steps: sting out of retainer, POOH 2 stands, reverse circulate out 2 workstring volumes at the maximum rate while keeping the pipe moving (do not exceed the casing test pressure of 3520 psi 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 3520 psi 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' above expected TOC) 10. After WOC for 18 hours since the cement was pumped, wash down to TOC. Drill cement/SQZRETAINER and 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 Superintendent immediately. Note: If ratty and/or soft cement is encountered as deep as 90' above the expected TOC, PU 3 stands and circulate 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 not hard. DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING


SQUEEZE PROCEDURE

EMDC DRILLING

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 PIT technique at 1/2 bpm and record pressure vs. volume pumped. Do not test the shoe to higher than 17.0 ppg EMW. 12. After successful test, proceed with drilling operations per the deeper drilling procedure.

3.4 SHOE SQUEEZE - RETRIEVABLE PACKER 1. Make a casing scraper run if deemed necessary prior to running in with SQZTOOL. Work casing scraper thoroughly across the interval of pipe at planned SQZTOOL setting depth. Circulate bottoms up below the SQZTOOL 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 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 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 the bottom 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 rig circulated 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 in the hole to clean out). Ensure that the squeeze tool will not be set in a casing collar. Verify setting 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) 4. Close annular BOP and pressure up on DP by casing annulus to 500-1000 psi. Establish injection rates at 1/2, 1, 2, 3, and 4 bpm without exceeding injection pressures of 4,500 psi ( Engineer to comment on basis for maximum 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”). Monitor annulus 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 have been 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 Superintendent and the Drilling Engineer to discuss results of the injection test (injectivity will dictate if a change is needed in the cement design or pump volumes). DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING


SQUEEZE PROCEDURE

EMDC DRILLING

Do not exceed the PIT test pressure of 3300 psi with 12.7 ppg mud (15.0 ppg EMW) if injection has not yet been 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 pump rate due to U-tube pressure. Take returns through the choke, if necessary, so that back pressure can be applied to prevent cement from circulating above the SQZTOOL before the bypass is closed. PUMP SCHEDULE BEFORE CLOSING THE BYPASS ON SQZTOOL Description Density Pump Rate 30 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 the SQZTOOL) 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 casing annulus. Pump an additional 119 bbls of 15.7 ppg mud at 4 bpm followed by 5 bbls of freshwater down the DP. This should leave TOC 250' below the SQZTOOL, and 250' above the casing shoe. PUMP SCHEDULE AFTER CLOSING THE BYPASS ON SQZTOOL Description Density 119 bbls mud 15.7 5 bbls Fresh Water 8.3 This will leave the TOC 250' below the SQZTOOL, and 250' above the casing shoe.

Pump Rate

Note: Displacement volumes assume a 12 ppg FCS in the G-series sand at 10000' TVD. 5 bbls of water displacement 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 drill pipe, perform the following steps: release the squeeze tool, POOH 3 stands, reverse circulate out 2 workstring volumes at the maximum rate (do not exceed the casing test pressure of 3520 psi while reversing), POOH 1 additional 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 first 3.0 bbls. Afterwards, pump in 1.0 bbl at 1/4 bpm every 60 minutes for the last 2 bbls (total squeeze volume = DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING


SQUEEZE PROCEDURE

EMDC DRILLING

5.0 bbls). If a pressure break-over is seen prior to finishing each stage, stop pumping immediately and hold whatever pressure is achieved for required stage time before continuing with next stage. Stop pumping at any point if 1675 psi is reached (21.0 ppg EMW). If pressure limit is reached, discontinue staging process and hold final pressure for WOC time. If 1675 psi is not reached after squeezing 5.0 bbls, stop staging process and hold whatever pressure is present. Estimated TOC after the hesitation squeeze is 185' above the shoe. 9. Hold the final squeeze pressure for 12 hours. The drill pipe pressure should increase due to thermal expansion. Allow the drill pipe pressure to rise as high as 4500 psi (21.0 ppg EMW) before bleeding off any pressure. If the pressure builds to 4500 psi, bleed back to 3500 psi before continuing to hold squeeze pressure. If backside pressure increases above 500-1000 psi, it may be indicative of a leak in either the packer 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. If OK, 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 and 5-10' of new formation noting any voids or changes in wellbore conditions. If high gas and/or lost returns are encountered just below the shoe, contact the Operations Superintendent immediately. Note: If ratty and/or soft cement is encountered as deep as 90' above the expected TOC, PU 3 stands and circulate 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 not hard. 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 PIT technique at 1/2 bpm and record pressure vs volume pumped. Do not test the shoe to higher than 17.0 ppg EMW. 13. After successful test, proceed with drilling operations per the deeper drilling procedure.

5. ENGINEERING FOLLOW-UP Well Name: WELLNAME Superintendents: Drilling Supts Engineer(s): Drilling Engineer Well engineer is responsible for verbal follow-up with rig supervisor. Engineer is to identify and document below sections of the procedure which did not meet the drilling team's needs and describe key learning's to be incorporated into core procedure.



SQUEEZE PROCEDURE

EMDC DRILLING

Return follow-up to core procedure owner:

Recommended Modifications to Procedure: _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________

Submitted By: Phone: (

______________________________________________________________

)

DATE___________



SECTION 10 - APPENDIX II Well Name Rig Name

Previous casing OD=

16

ID=

15.22

Annular Volume

MD=

1000

0.1128 bpf

TVD=

1000

PROPOSED CASING DESIGN (bottom to top) WGHT GRADE/CONN 1

45.5 K-55,BTC

LENGTH MD

ID

CAP. (bpf) CAP. (bbls) DISPLACE.

4900

10.05

0.0982

481.0

0.0166

Pit gain from casing (bbls):

4900

MISC. ENGINEERING CALCS.

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 16.5 " Setting MW

Annular Volume

9.2

Pre-flush with

20

bbls of

8.7

ppg

seawater

spacer.

Post-flush with

20

bbls of

8.7

ppg

seawater

spacer.

CEMENT

0.1523 bpf Washout =

49%

Lead Slurry:

Class 'H' with liquid additives

Mixed to:

Mixwater:

Sea

Yield:

Number of sacks: Calculated=

at

13.23 gal/sk

1525 Volume:

2.32 cu.ft/sk

1526

Tail Slurry:


Mixed to:

13.5

Mixwater:

Sea

Yield:

Number of sacks: Calculated= Tail is estimated at 4400 ' MD

12.6 ppg

630.1 bbls

Bit Size(in)

at

4.68 gal/sk

425 Volume:

16.2 ppg 1.11 cu.ft/sk

84.0 bbls

425

DISPLACEMENT After postflush, displace w/

453.1 bbls of

9.2

ppg

mud.

4400 ' TVD 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

Which is

500 ' above

Proposed Casing

20 bbl postflush

10.75

Casing Point

6

3.3

3.3

433.1 bbls displacement

6

72.2

72.2

20 bbls displacement

2

4900 ' MD Float Length=

80

Float Capacity=

7.9

Bottom hole static temperature Bottom hole circulating temperature

81.2

Excess bbls of cement at

4883 ' TVD bbls

Contingency

10.0

10.0

60

60

Estimated Job Time

270

165

EJT (hours)

4.49

2.74

EJT with contingency

5.49

3.74

138 degrees F (est. from log temps) 110 degrees F (from API Spec 10)


1 of 2

Well Name Rig Name

Previous casing OD=

16

ID=

15.22

MD=

1000

TVD=

1000

10.75 " SHOE SQUEEZE CASING DESIGN (bottom to top) WGHT GRADE/CONN

LENGTH MD

ID


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 15

WEIGHT/CONN LENGTH MD

ID


19.5 #/NC50/X-95 4400

4400

4.276

0.017268 76.0

0.0078

0

0

0.000000 0.0

0.0000

2

0

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 Casing 10.75 "

Lead Slurry:


Mixed to:

16

Mixwater:

Sea

Yield:

1.65 cu.ft/sk

Number of sacks: Desired underdisplacement of pre-flush

Calculated=

at

13.23 gal/sk

257 Volume:

ppg

75.5 bbls

257

when bypass is closed

5 bbl

DISPLACEMENT

Squeeze packer setting depth

Close bypass after pumping

71.0 bbls of preflush and cement

After spacer, displace w/

80.5 bbls of

9.2

ppg

mud.

4400 ' MD TOC desired

250 feet above shoe

PUMP TIMES

Rate

Squeeze Slurry

Mix Squeeze Cement

4

18.9

Desired squeeze volume

10 bbl spacer

50 bbl

Casing Shoe

80.5 bbl displacement

4900 ' MD Length of new hole:

10 '

Bit size:

9.875 "

New hole volume:

4883 ' TVD

0.95 bbl

Bottom hole static temperature Bottom hole circulating temperature

0 bbl other

4

2.5

4

20.1

4

Contingency

0.0 60

Estimated Job Time

102

EJT (hours)

1.69

EJT with contingency

2.69

138 degrees F (est. from log temps) 110 degrees F (from API Spec 10)


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PRESSURE INTEGRITY TESTS

11.0 PRESSURE INTEGRITY TESTS

11.1 11.2 11.3 11.4 11.5

General Casing Test Leak-Off Test Jug Test (Limited PIT) Open Hole Leak-Off Test

______________________________________________________________________________ DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION MAY, 2003

1 2 3 4 4

PRESSURE INTEGRITY TESTS 11.1

GENERAL

There are three main types of Integrity Tests that are conducted by EMDC drilling. The Casing Test, the Leak Off Test (LOT), and the Jug Test (PIT). A casing test is used to ensure the casing will not fail in a well control situation or completion operation. The LOT and PIT tests are used in open hole just below the shoe to determine the equivalent mud weight that can be held, or that will initiate a fracture and cause leak-off to the formation. One additional type of test that may be performed during drilling operations is an open hole integrity test. If this test is required the applicable drilling procedure will detail that test. Casing tests are to be charted and the chart maintained at the rig and in the office per regulatory agency requirements. The MMS requirement is to pressure test all casing strings except the drive pipe, to hold the test for 30 minutes (generally for non-MMS regulated operations, 15 minute tests are sufficient) with <10% loss in pressure, and to document the test on the IADC report. For all EMDC 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 be performed 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 test interpretation. Additional information regarding test procedures and analysis is contained in the EPR publication "Pressure Integrity Test - Field Guide". The Operations Supervisor is responsible for completing the PIT form and forwarding it to the Drilling 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 the approved 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 conductor casing. Based on geologic conditions or planned setting depths, a test of the conductor casing shoe 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 governing regulatory agency orders, the test is to be conducted after drilling new formation, but must be performed 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 test surface 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 pressure charts 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 is less than anticipated.

DRILLING OPERATIONAS MANUAL - JACK-UP/PLATFROM/BARGE RIG DRILLING First Edition - May, 2003

1 of 6

PRESSURE INTEGRITY TESTS 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 the Drilling 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 and Operations 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 conducted using one of the following methods: a.

After completing the required BOP test, the blind rams will be closed and the casing will be 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 on the 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 pump until reaching the casing test pressure specified in the drilling program. Record bbls pumped to reach the test pressure.

3.

Stop pumping and record the shut-in pressure for 30 minutes per MMS requirements or other regulatory agency requirements (generally, for non-MMS regulated operations, 15-minute tests may be sufficient).

4.

Bleed off the pressure and record the bleed back volume. Record the test data in the Integrity Test Workbook.

5.

Open the BOP.


2 of 6

PRESSURE INTEGRITY TESTS 11.3

LEAK-OFF TEST

Prior to conducting the Leak-Off Test, the EMDC Integrity Test Workbook is to be prepared for plotting pump pressure and shut-in pressure as a function of cumulative bbls pumped and shut-in time. The drill pipe float valve, either solid or ported, can influence the results; take it into consideration. The accompanying equations may be helpful in calculating pressures and volumes during a leak-off test. Additionally, a spreadsheet to calculate the compressibility of Water or Oil based muds may be found on the LAN or Global Share. The casing test also provides a good indication 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 cuttings and 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 to greater than the expected surface pressure as specified in the Drilling Procedure. The test surface 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 up versus cumulative barrels pumped. Pump at 1/4 bpm if the wellbore volume is <1000 bbls and 1/2 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 in the 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 for pressure 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 float does not restrict flow. 11. Review the gradial plot in the Integrity Test Workbook and determint the LOT. Repeat the test if the interoperation is not clear. Repeat the PIT test if unacceptable. If it appears that the PIT was unacceptable due to fluid leaking off into a permeable sand, a seepage spill may be spotted prior to repeating the test. Use 20-30 ppb of 5 micron (fine) CaCO3. Discuss this option with Operations Superintendent prior to pumping the second test. DRILLING OPERATIONAS MANUAL - JACK-UP/PLATFROM/BARGE RIG DRILLING First Edition - May, 2003

3 of 6

PRESSURE INTEGRITY TESTS 12. Open the BOP. 13. Attempt to identify the minimum stress (MS) from the shut in data and record it in the results section of the Integrity Test Workbook. If a distinct inflexion is not seen at fracture closure record the MS as "N/A". Complete the workbook, including the comments section, form and fax 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 to calculate the PIT. PIT (ppg) = [[ MW (ppg) * 0.052 * TVD of casing shoe (feet) ] + Surface pressure (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-off pressure. The test plots are similar in all areas except the top of the pressure build-up curve. In the LOT, the plot bends to the right at the leak-off point. In the jug test, the entire build-up plot should be 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 in new formations drilled. Normally this test is necessary after penetrating porous/permeable formations that have the potential for lost returns and/or when the mud weight nears the last leak-off value. The same procedure is used as for performing an open hole test after the bit is pulled up inside the casing. A higher pump rate may probably be needed than was used in the PIT at the casing shoe because of the extended open hole section and potential permeability, however the initial attempt should be made 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 to TD 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


4 of 6

PRESSURE INTEGRITY TESTS 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


5 of 6

PRESSURE INTEGRITY TESTS

Integrity Test Plot Well Csg Size (in) Rig RKB (AMSL, ft) Water Depth (ft) Field Country

Test and interpretation comments...

Example W ell 9.625 Example Rig 100 2,000 Example Field International

Final Interpretation Test

Test 1 Test 2 Test 3

Depth (ft)

Integ (ppg)

11,000 0 0

16.2

Type

MS (ppg)

LOT

15.6

3,000

2,500

Surface Pressure (psi)

EMW = 16.25 ppg

2,000

ISIP

1,500

1,000

500

0 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) Casing Test

Test 1

Test 2

Test 3

FIGURE 11-1 (Intergrity.xls output)


6 of 6

PRODUCTION TESTING

12.0

PRODUCTION TESTING

12.1 12.2 12.3 12.4 12.5 12.6 12.7 12.8 12.9 12.10 12.11 12.12 12.13

Production Testing Objectives Well Test Design Test String Surface Equipment Measurement Equipment Safety Personnel Responsibilities Pre-test Planning and Preparation Information Retrieval Well Killing and Zone Abandonment Emergency Procedures Hydrogen Sulfide Hydrates


1 1 3 4 4 5 6 9 10 11 11 11 12

PRODUCTION TESTING For Development Jack-up, Platform, & Barge Rig Drilling Operations, a production test is not usually performed. The wells drilled in during development are usually completed and brought on production by the Production group after the drilling rig has moved off location. In the event that a production test is required (e.g. exploratory well), a detailed Well Testing Procedure will be developed by the Well Test Engineer and/or the Drilling Engineer on a well specific basis. This procedure 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 ExxonMobil Production and Development Company Safety Manuals for safety guidelines concerning drill stem testing, 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 Well Production Testing operations. 12.1

PRODUCTION TESTING OBJECTIVES

A production test is a formation evaluation technique which may be designed to provide the following 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 the production test or through analytical methods using the appropriate reservoir description model, in conjunction with information obtained from the well test. In exploration well testing, the well may be temporarily completed so that reservoir fluids can be flowed to the surface and measurements of pressure and flow rate can be made. Since hydrocarbons surface during the production test, extreme caution is to be taken by all personnel involved with testing operations. It is essential to select equipment and adopt test procedures which will ensure the 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, final flow, and final build-up. The reservoir's pressure response during each of these time periods is shown schematically in Figure 12-1. The length of each time period is dependent on the reservoir producing 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 a pressure differential exists from the formation into the wellbore. The initial flow period is usually short in duration (anywhere from 2 minutes to 1 hour). For an oil well test or bottom hole shut-in test, it is generally not necessary to flow formation fluids to surface during the initial flow. For a gas well test, all liquids should be completely removed from the wellbore below the first closed valve to prevent a phase hump in wellbore pressure from forming due to gas rising through liquids DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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PRODUCTION TESTING left in the wellbore. For a surface shut-in gas well test, the initial flow period could last several hours. Initial Build-Up Period Following the initial flow period, the well is shut-in in order to measure the initial reservoir pressure. Ideally, the initial build-up period should last until the bottom hole pressure has completely stabilized; however, this is not always feasible. The initial build-up period will normally be two to four times the length of the initial flow period, with lower productivity reservoirs receiving the higher multiplier. The minimum length for the initial build-up should be 1 hour regardless of the length of the initial flow period. In tests which utilize surface readout bottom hole pressure gauges, it is possible to monitor the bottomhole pressures and plot the data in real-time on a Horner or superposition plot. The shut-in period should, where practical, last until an initial reservoir pressure can be obtained unambiguously from 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 obtain fluid samples for laboratory analysis. The pressure transient introduced into the formation during the final flow period will be used to determine the reservoir permeability-thickness product and identify 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 obtain definitive flow data. In some cases, flow periods exceeding 12 hours may be required to ensure data quality. If produced liquids are flowed to storage tanks, then the flow rate and flow time will have to 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 may dictate the actual length of the final flow period. Fluid samples from both the full well stream and the 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-up response 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 low productivity reservoirs, the build-up period should be 1-1/2 to 2 times the length of the final flow period. If bottom hole samples are required, they should be taken following the final build-up period.


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PRODUCTION TESTING 12.3

TEST STRING

Test String The test string contains those components necessary for sealing the tubing annulus, shutting in the tubing downhole (if desired), and suspending pressure and temperature gauges. The shut-in method used will depend on such considerations as types of fluids produced, objectives of the test, and safety 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 well control 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 is in communication with the formation. This can lead to two detrimental effects, afterflow and phase redistribution in the wellbore. Afterflow is defined as flow from the formation into the wellbore after the well is shut-in at the surface. Formation fluid can flow into the wellbore because of the compressibility of the fluid in the wellbore. Afterflow is usually not a problem in oil or gas wells having moderate to good productivity. 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 from high liquid ratio gas wells and high GOR oil wells. If phase redistribution occurs, it can usually be recognized as a hump in the plot of build-up data. If pressure humping lasts throughout the test, the build-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 it eliminates the effects of afterflow and phase redistribution. However, a bottom hole shut-in requires a somewhat complex string of downhole tools, which increases the probability of a mechanical malfunction. With some test strings, pipe motions are required to operate tools while the 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.


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PRODUCTION TESTING

12.4

SURFACE EQUIPMENT

The surface testing equipment is designed to process produced formation fluids from the surface test tree to a point of disposal. Typically, the major components of this system are: data header, choke manifold, flow lines, heater, separator, test/gauge tank, transfer pump, and burner(s). The surface and bottom hole test equipment required for a particular well test will vary depending upon individual well conditions and specific reservoir requirements and will be specified in the Well Testing Procedure. 12.5

MEASUREMENT EQUIPMENT

Obtaining accurate measurements of bottom hole and surface pressure and temperature is one of production testing's main objectives. Subsurface pressure and temperature gauges can be either mechanical or electronic downhole recording devices or wireline run electronic gauges which provide a surface readout. Surface pressures are normally obtained with either dial gauges or dead weight testers. Subsurface Measurement Equipment Subsurface gauges are run into the wellbore to record the reservoir pressure and temperature response during flowing and shut-in periods. Subsurface pressure and temperature gauges can either be landed in a nipple located below the perforated joint or run in gauge carriers. There are two basic types of subsurface pressure gauges available, the subsurface recording gauges and the surface readout subsurface gauges. 1.

Subsurface Recording Gauges

Subsurface recording gauges make a record of pressure and/or temperature versus time. The record can be read at the surface when the gauges are retrieved. These gauges are self-contained recording devices which do not require a physical link to surface equipment. Subsurface recording gauges will either be mechanically or electronically operated. 2.

Surface Readout Subsurface Gauges

Surface readout subsurface gauges allow real time bottom hole pressure and temperature measurements to be read at the surface. These gauges transmit their data through a monoconductor cable. Because of the electric cable, these gauges cannot be used with a standard bottom hole shutin test assembly. Surface Measurement Equipment Surface pressure and temperature measuring equipment can be connected to the data header located upstream of the choke manifold. Surface pressure can be measured with either dial type gauges, a dead weight tester, and/or electronic gauges.


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PRODUCTION TESTING 12.6

SAFETY

General Safety Guidelines 1.

The drilling supervisor is to hold a safety meeting prior to the initiation of each production test. All personnel are to attend this meeting.

2.

Do not subject Oilfield Explosives (perforating guns, tubing cutters, string shots, severing charges, etc.) to pressures higher than the allowable (rated) pressure specified by the manufacturer. This includes pressure testing lubricators that contain electric line conveyed perforating guns, cutters, etc. and also while running explosives into the well (e.g. multiple runs 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 also recommended that start-up of the production test be initiated during daylight. Extra lighting may be necessary to insure potential leaks do not go undetected if testing continues after daylight hours.

4.

The drilling rig is to be equipped with a warning system, which will be activated any time the well is being tested. During this period, it will be necessary for personnel to follow ExxonMobil Safety Manual guidelines for welding, cutting, electrical work, sand blasting, or other 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 to stay 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 determine if 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 from the tree.

11.

A contractor representative of the tree supplier must be present on the rig floor or near the control unit at all times when the well is "live".

12.

If methanol is utilized, ensure that flame and mitigation detection contingencies are in place and reviewed with all personnel.


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12.7

PRODUCTION TESTING PERSONNEL RESPONSIBILITIES

The overall responsibility for conducting a safe testing operation rests with the Operations Supervisor. The Operations Supervisor is to work closely with the Drilling/Well Test Engineer, and Service Company Personnel to ensure that all test objectives are achieved. Responsibility guidelines for a typical offshore production test are listed below; refer to Section 2.6 of this manual for 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 adjacent equipment. Ensure that critical spares are available.

3.

Witness pressure and function tests of surface and subsurface test equipment. Coordinate Third Party witnessing of equipment inspections and testing prior to sending equipment to location.

4.

Supervise the make-up of the test string and check clearances. Ensure that string spaceout is correct.

5.

Ensure that packer, seal assembly, and tail pipe assemblies have the proper OD's, ID's and lengths.

6.

Witness perforating operations (if applicable).

7.

Ensure that all wireline tools and equipment are available and compatible with durable conditions.

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 tactical decisions.

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.


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2.

PRODUCTION TESTING 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 the Drilling/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 all valves, observing separator pressures, and monitoring gas and liquid flow rates, running gauges, 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 valving under the direction of the separator operator and help monitor wellhead pressures. Coordinate burner 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 wellhead temperatures.

6.

Operate chemical injection of glycol / methanol, as necessary.

7.

Coordinate operation of surface test tree and floor choke manifold and be prepared to handle an 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 choke manifold are carried out.

10.

Assist in monitoring casing annulus pressure and production test data.


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11.

PRODUCTION TESTING Prepare subsurface recording pressure and temperature gauges. Continuously monitor panel for surface reading subsurface pressure and temperature gauges.

Mud Logger 1.

Take periodic samples of gas at the floor choke manifold during flow periods and analyze samples with the gas chromatograph.

2.

Use gas detectors to determine possible presence of gas on the rig floor and in the wellhead/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 and water properties.

Cementer 1.

Perform well killing and cementing operations as required. Have pumping equipment in a state 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 casing size used in production test.

3.

Assist drill crew and subsurface test hole personnel in operation testing of downhole equipment.

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 rig equipment.

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 casing annulus pressure and production test data.

3.

Ensure that production test string is properly made up.


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12.8

PRODUCTION TESTING 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 size rams as necessary to accommodate the test string equipment in the hole. All surface testing equipment 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 production test. All personnel are to attend this meeting. During the pre-test meeting, the following items are to 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 clearly understood. Surface Equipment Preparation At an appropriate time, well before the test string is run in the hole, the separator, heater, transfer pump, 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 that compatible chiksan or other flexible connections are available. The fail-safe closed valve on the surface test tree flowline is to be checked for proper operation. The surface test tree, the flowline chiksans, and the floor choke manifold are to be checked for connection compatibility. The floor choke manifold is to be rigged up with the proper size chokes for the initial flow. The data header is to be checked and the adapters, if required, for the various gauges and transducers are to be made up. Surface Equipment Pressure Testing Make up the surface test tree and rig floor equipment. instrumentation is functioning properly.

Ensure that the data header and all

Note: Have an OEM (Original Equipment Manufacture) service representative on location during installation and pressure testing of all Christmas tree equipment. Place a permanent warning sign on the valves which have the potential for internally trapped pressure "Warning: This valve has the potential to internally trap pressure". DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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PRODUCTION TESTING Note: Whenever a back pressure valve (BPV) is to be removed from a tubing hanger, a lubricator shall be installed and anchored. Prior to retrieving the plug, confirmation of pressure equalization should be made if possible. If working on a well with H2S gas, all workers 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 Production Testing Program, using the cementing unit, as follows. The test pressure is to be held stable for at least 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 accurate reservoir description. To accomplish this objective, it is essential that the data gathering activity be given high priority both in planning and during testing operations. This can best be accomplished by ensuring that each individual involved in the test fully understands his responsibilities and the operation of the equipment he is assigned to oversee. Persons responsible for actually gathering data must know what data to gather and which data form is required for transcribing the data. During the pre-test meeting, the Drilling/Well Test Engineer is to assign the appropriate form to each of the individuals involved with data collection. Refer to the EMPC 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 well during the period. In general, data entries should be made more frequently during periods when well conditions are changing rapidly with time (e.g., immediately following shut-in or flow initiation) and less frequently during stable conditions. The primary goal is to ensure that data are smooth and continuous when plotted against time. The actual frequency for collecting data will be specified by the Drilling/Well Test Engineer, but for most test situations, the following guidelines apply: 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 chart recorder and pressure recorder as follows- ensure high frequency reading downhole for buildup analysis: • • • •

3.

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.

Subsurface Pressure Chart Reading:

At the conclusion of the final build-up period, the subsurface pressure gauges are to be recovered and checked for mechanical malfunction and the pressure readings obtained.


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PRODUCTION TESTING Sample Gathering Samples of gas, oil/condensate and water are to be collected during each production test for laboratory analysis. Surface and/or bottom hole samples are to be obtained as described in the Well Testing Procedure. A master sample list is to be maintained. This list should identify each sample and provide information necessary to track the sample at a later date. For example, it should identify the sample container by the container serial number and contain all the data specified on the sample label. This will 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 this purpose. Bottom hole samples may be required by Reservoir Engineering. When bottom hole samples are required, they will generally be taken directly opposite the perforations, if possible, and with 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 the wellbore for the purpose of avoiding formation of hydrates in the test string. Additional downhole work, such as pulling the pressure gauges, obtaining bottom hole samples, or performing other final actions 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, the significant point is to ensure that a column of mud, with sufficient weight to ensure that an overbalance 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 H2S in the production stream requires special procedures for conducting the well test and testing equipment that has metallurgical properties compatible with the H2S environment. Due to the extreme toxicity of H2S, self-contained breathing apparatus (SCBAs) must be available during the test if H2S is expected. If the potential exists for H2S in the formation fluids, an H2S contingency plan 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 hydrogen sulphide and certified (i.e. Fit Tested, and applicable certification). H2S drills are to be performed with all personnel on the rig.


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PRODUCTION TESTING 2.

All surface and downhole equipment which may be exposed to H2S must be designed for use in H2S environments.

3.

Every effort must be made to ventilate the rig floor and separator area before the well is opened.

4.

Each individual who will be on the rig floor or working with the hydrocarbon processing equipment (separator, burners, etc.) is to have a self-contained breathing apparatus available in 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 will be 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 hydrocarbons combine with water. Hydrate formation is associated with gas production and is a function of temperature and pressure. Figure 12-3 is a hydrate formation conditions chart. The areas above each curve represent the conditions of temperature and pressure under which hydrates can form if sufficient water is present. At low water concentrations and high flow rates, the formation of hydrates may not be sufficient to cause blockage of the flow stream. However, upon shutting in the well, hydrates may form a blockage and prevent further well flow. Even minor hydrate formation can interfere with wireline/slickline operation for setting plugs or retrieving data. A hydrate mitigation plan should be in place if hydrate conditions are possible.


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PRODUCTION TESTING FIGURE 12-1


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Production Tubing

Permanent Packer

Locator Seal Assembly Landing Nipple Perforated Joint Spacer Tube No-Go Landing Nipple Wireline Entry Guide

Perforations

Production Casing

Lower String Asssembly for Surface Shut-in (Permanent Packer) DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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PLUG AND ABANDOMENT

13.0 PLUG AND ABANDONMENT

13.1 13.2 13.3 13.4

General Permanent Plug and Abandonment Temporary Plug and Abandonment Site Clearance Verification

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PLUG AND ABANDONMENT 13.1

GENERAL

Before performing any Permanent or Temporary Plug and Abandonment work, regulatory approval must be obtained from the applicable regulatory agency. The objective of the following general guidelines is to plug and abandon wells in accordance with the governing regulatory agency and ExxonMobil requirements; such that all hydrocarbon zones, abnormally pressured water zones, and freshwater aquifers, are isolated to permanently prevent their contents from escaping into other strata or to the seafloor. Procedures may be adjusted to fit specific hole conditions but should at least meet the minimum objectives described in these guidelines (MMS or local regulatory body and ExxonMobil requirements). 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 water aquifers should be verified by tagging and/or pressure testing. Coordinate any plugs that must be tagged with the applicable regulatory agency and EMPC. 2. During each phase of the plug and abandonment operation, a means of performing well control is to be maintained. This is valid until casing with a non-sealed outer annulus (generally surface or conductor casing) is to be cut or perforated. 3. When casing is cut, pressure control is to be maintained by closing the annular preventer around the drill pipe. This is valid until casing with a non-sealed outer annulus (generally surface or conductor casing) is to be cut. If communication from an open formation to the surface via the annulus is found, the flow is to be controlled with kill mud and the annulus squeeze cemented through the cut or perforations. The annulus is to be pressure tested after cementing to ensure that it has been properly sealed. 4. When conducting plug and abandonment operations, all mud returns are to be analyzed by the Mud 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 a corrosion inhibitor and/or a bactericide. 6. During each phase of the plug and abandonment operation, the mud left in the hole above a cement and/or a mechanical plug is to have a weight sufficient to withstand, together with the plugs, 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 casing strings and well bore annulus are permanently sealed. Well specific procedures may vary and will be specified in the Plug and Abandonment Program:


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PLUG AND ABANDONMENT 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' below the bottom to 100' above the top of the zone(s) to be isolated. Any porous or permeable zone containing hydrocarbons should be isolated. Typically cement volumes in open hole are based on gauge hole plus 10% excess.

•

Other methods of abandonment may be more practical. The appropriate regulatory agency and the operations superintendent must approve these alternate methods. Note: The placement of a hi-vis pill below cement plugs can be beneficial in preventing 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.

3.

•

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 below the shoe and place 50' of cement above the retainer.

•

If lost returns have been experienced place a permanent type bridge plug <150' above the shoe and place 50' of cement above it.

•

Other methods of abandonment may be more practical. The appropriate regulatory agency and the operations superintendent must approve these alternate methods.

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 to 100' below the bottom of the perforated interval.

•

Set a cement retainer 50' - 100' above the top of the perforated interval, squeeze cement to 100' 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 interval with 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 plug within the first 100' above the top of the perforated interval.


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PLUG AND ABANDONMENT •

4.

Other methods of abandonment may be more practical. The appropriate regulatory agency and the operations superintendent must approve these alternate methods.

Plugging of Casing Stubs Cut and pull any casing strings required and isolate all annular spaces by placing a balanced cement plug, 100' above and below, the remaining stub or one of the following methods:

5.

•

A cement retainer or a permanent-type bridge plug is set 50' above the stub and 50' of cement placed on top of it.

•

A cement plug, which is at least 200' long, is set with the bottom of the plug within 100' of the casing stub.

•

If the stub is below larger size casing plugging shall be accomplished as required to isolate zones or open hole as described above.

Plugging of Annular Space Any annular space that communicates with open hole and extending to the mud line will be plugged with at least 200' of cement.

6.

Surface Plug •

7.

Set a balanced cement plug at least 150' in length with the top of the plug within 150' below the mud line. The plug will be placed in the smallest string of casing that extends to the mud line.

Testing of Plugs The condition and location of certain cement plugs shall be verified by one of the following methods: •

By tagging the cement plug, cement retainer, or bridge plug with 15 kips while circulating against 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 excess of the formation breakdown pressure or within the working limits of the weakest exposed casing 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).


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PLUG AND ABANDONMENT 8.

Clearance of Location All wellheads, casing, pilings, and other obstructions shall be removed to a depth of 15' below the 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 and wellhead 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. Perforations are 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 in the 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 string unless 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 set in the casing within the first 200' below the mudline.

7.

Exceptions to these guidelines must be approved by the applicable regulatory agency, the operations superintendent and EMPC.

13.4

SITE CLEARANCE VERIFICATION

Final site clearance after abandonment must be approved by the regulatory agency. Typically one of the 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.


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WELL CONTROL

14.0 WELL CONTROL 14.1 14.2 14.3 14.4 14.5 14.6

Well Control – General Hole Monitoring Equipment Testing Equipment Specifications Well Control Drills Well Control Procedures

______________________________________________________________________________________ DRILLING OPERATIONS MANUAL- JACK-UP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION MAY, 2003

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WELL CONTROL 14.1

WELL CONTROL - GENERAL

Well Control operations are performed to mitigate well control incidents by minimizing the severity of the influx, properly shutting-in the well as soon as practical, and surfacing the influx in a safe manner or pumping/bullheading the influx back into the formation (when bringing the influx to the surface may be too hazardous, like with H2S). Uncontrolled flows into the wellbore must always be kept below the blowout preventer stack. Safety of all personnel on the rig is the primary consideration when conducting well control operations. Integrity of the drilling unit and adverse economic impacts are of secondary importance. General step-by-step procedures may vary depending on the BOP configuration on each individual drilling unit. The Drilling Contractor's specific shut-in procedures for each drilling unit are to be reviewed to determine if they are acceptable for EMDC's operations. For all locations, a site specific well control plan is to be in place which includes diverter and well control procedures specific 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 drilling operations.

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 Control Equipment Testing" section of this manual.

4.

A current status board of critical drilling parameters will be maintained at the Driller's console in 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 the Driller's console. Rig specific station bills, listing duties of the crew members, will also be posted on the rig floor and/or bulletin board.

6.

Lost Circulation Procedures will be posted on the rig floor.


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WELL CONTROL 7.

The Driller will be instructed to shut-in the well using his judgment and indicators such as pit gain, flow after stopping the pumps, or improper fill-up on trips. The Driller does not have to secure 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 sufficient casing to shut in the well, the float valve will be ported, unless a solid float is approved by the Operations 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) for drill pipe and an inside BOP, with crossover subs for drill collars and casing, will be on the rig floor and ready for immediate use (i.e., open). These will be available for all drillstring sizes in use. The safety valve(s) must be function tested and the test must be documented on the IADC report and DMR. The safety valve will always be picked up first. A safety valve will be 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 not seal from either direction if pressure is applied from above. Class I valves are not API pressure rated externally and may leak through the stem. Class II valves are designed for rated working pressure from below and above the ball and externally to 2000 psi minimum. If there is a probability that stripping operations will be required, Class II should be utilized at the rigsite. Section 8 in the "ExxonMobil Drilling Surface Blowout Prevention and Well Control Equipment Manual" provides a listing of manufacturers known to be capable of supplying proven Class II safety valves.

10.

Circulate choke and kill lines to ensure lines are clear (frequency will depend on drilling fluid).

11.

The choke will be in the open position with the first valve downstream of the choke in the closed position as well.

12.

Maintain a "Well Kill Worksheet" for the current wellbore configuration and update the worksheet (or KIK PC program) at least daily while drilling is in progress, or as hole conditions change.

13.

Keep the inner choke and kill valves on the BOP in the closed position while drilling. Keep the 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 will determine if hanging-off the drill string is necessary based on existing operating conditions.


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WELL CONTROL 18.

If an annular is used to circulate out the influx, the closing pressure may be backed off per the manufacturer's recommendations to reduce wear on the element. Sufficient operating pressure will be maintained to prevent leakage and avoid gas escaping to the rig floor. Closing pressure can be reduced to allow limited pipe movement to avoid sticking the drillstring while circulating out an influx. However, tool joints should not be cycled through the annular element 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 pressures stabilize. After stabilization, record the shut-in pressure on the drill pipe and casing every 10 minutes until well control operations end.

2.

Record the pressure necessary to pump open the float valve as the stabilized drill pipe pressure 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 well control operation.

4.

Shut down the pumps and shut-in the well to check pressures if a problem arises while circulating out an influx into the wellbore.

5.

Determine a new friction pressure if using a different pump rate when restarting circulation after 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 will occur when the top of the influx is at that point or when the influx is on bottom in the case of short open hole intervals or long bottom hole assemblies and the top of the bubble is above the casing shoe. This is especially true in deep wells.


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WELL CONTROL

Pump Rate Guidelines 1.

Ensure that the selection of the circulation rate considers such factors as: a) formation integrity at the casing shoe, b) rig well control equipment, c) capacity of barite additions to the mud 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 3 BPM 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. Be prepared 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 Operations and Engineering personnel communicate clearly during the operation and perform the necessary calculations. After the BOP stack is installed, a "Well Killing Worksheet" will be prepared. The worksheet will be maintained for the current wellbore configuration and update the worksheet at least daily while drilling 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.

2.

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.

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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WELL CONTROL •

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 volume increase.

5.

Calculate the circulation rate and the pressure change schedule:

6.

7.

•

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.

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 based on 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)

Perform influx height and gradient calculations: •

14.2

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. 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 gains or losses using the trip tank. The following guidelines should be followed to ensure a full column of 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 trip tank level will be recorded a minimum of every 15 minutes when pipe is out of the hole. A trip book will be maintained for each well and at least one person is to be assigned to monitor the trip tank on a continuous basis while tripping. The trip book log should compare trips volumes to both the theoretical volume and the previous trip volumes


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WELL CONTROL 2.

If the rig is equipped with a top drive system, back-reaming and pumping out the first 10 stands of open hole when tripping should be considered. This is especially relevant while drilling 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-up volume 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 be advised 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 before attempting 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 in at least 1/2 barrel increments.

6.

A grease type packing is to be used on the centrifugal pump that feeds the trip tank. Water injection will not be used.

7.

The mud loggers should also closely monitor trip tank volumes while tripping out of the hole and confirm the displacement volumes recorded by the drilling contractor. They should also monitor volumes while tripping in the hole if requested by the Operations Supervisor or if it is specified in the Drilling Program.

8.

The maximum amount of drill pipe than can be run in the hole without being filled must be specified 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 to calculate 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 monitored using the trip tank. The FDM can provide an exception to using the trip tank when tripping in hole. Note:

Field modification of drill pipe floats is not allowed. There are no exceptions to this policy.

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).


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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 a drilling break over 5' on a development well if expecting abnormal pressure or hydrocarbons in the zone. •

A drilling break is generally defined as a doubling of the rate of penetration (ROP), but can vary depending upon the area.

5.

Flow checks will be planned at intervals less than 100' when drilling with a top drive system in an abnormal pressure zone.

6.

It should be stressed to the driller that the Company will support the driller's judgment when making additional flow checks (not included in these guidelines) or when shutting-in the well due to flow.

Degasser Guidelines 1.

The degasser will be operated whenever there is significant gas in the return flow stream, as indicated 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 drive system/kelly safety valves are to be pressure tested in accordance with the following requirements:


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WELL CONTROL BOP Pressure Tests ACTIVITY

BOP TESTING REQUIREMENTS

1)

Initial BOP acceptance test (when the Test with water to 200 psi low and rated rig comes under contract) working pressure of preventer/equipment

2)

Initial Installation on Wellhead if NOT Test with water to 200 psi low and rated fully tested to rated working pressure as WP of preventer/equipment or the per 1) above. wellhead, whichever is less. At least once per well the rams must be tested to their rated WP when the appropriate wellhead is installed. Initial installation on wellhead if fully Test with water to 200 psi low. Test annular to tested to rated WP as per 1) above. 70% of rated working pressure or rated working pressure of wellhead, whichever is less.

3)

For 5k psi rams or lower, test rams/equipment to rated working pressure. For 10k psi rams or higher, test rams/equipment to a pressure that exceeds the maximum anticipated surface pressure but not less than 5k psi. At least once per well the rams must be tested to their rated working pressure when the appropriate wellhead is installed.

4) After setting casing string AND prior to drilling out casing shoes. 5) Subsequent tests not exceeding every 14 days. 6) After disconnection or repair of any pressure containing seal but limited to the affected component.

Note: On wells governed by MMS rules, all rams/equipment must be tested to their rated working pressure or rated working pressure of wellhead, whichever is less (unless approved otherwise by District Supervisor). Same as 3) above. Same as 3) above. On workovers governed by MMS rules, then test frequency is every 7 days instead of 14. Test with water to 200 psi and rated working pressure of preventer/equipment or wellhead, whichever is less.


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WELL CONTROL Notes: 1.

Regulatory requirements may require variations from the above and will govern, if more stringent.

2.

Pressure tests will be alternated between control stations. After pressure testing from one control 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 Drilling Program. The pressures will be held stable for at minimum of 5 minutes on both the low pressure 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 days thereafter, as required by OIMS. The high pressure side of the choke manifold is to be pressure tested to the required BOP ram test pressure. The low pressure side of the choke manifold 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 Daily Drilling Report and IADC Report. Detailed test data will also be recorded by the drilling contractor on a BOP test form designed specifically for the drilling rig. This report should be reviewed by the Operations Supervisor to ensure they are satisfied that sufficient data will be recorded to ensure confidence 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 to the Operations Supervisor, along with the pressure recording chart supporting the BOP testing operation. All pressure charts are to be dated and properly labeled as to each component tested. All records 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 file upon request. Function Tests The diverter system is to be function tested daily and the BOP system is to be function tested weekly. When conducting these tests, all closing and opening times required to function each component are to be recorded for comparison with previous tests. Do not pull out of the hole just to function 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 drill pipe will be recorded and reported on the BOP test form.

2.

After initial installation, all diverter lines will be pumped through at the maximum rate possible, to detect leaks, verify correct line up, and inspect for excessive vibration.


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WELL CONTROL 14.4

EQUIPMENT

Equipment specifications for well control equipment are provided below. Deviations for less than the guidelines shown should be based on a risk assessment and should have both EMDC and Drilling 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 working pressure. 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 remote location 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 the diverter valves and close the diverter annular and be capable of being operated from the main control 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 with annular and rams capable of shutting in on all drill pipe sizes in use for that hole section in accordance with the following specifications: DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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WELL CONTROL Note:

If Hydrogen Sulfide gas is expected, all BOP components and element seals must be certified for H2S service.

BOP Stack 1.

The BOP stack should be arranged as specified in the Surface Blowout Prevention and Well Control 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 two pipe 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 master ram. See Section 4.0 of the Surface Blowout Prevention and Well Control Equipment Manual for details and additional scenarios.

4.

All rams, choke/kill lines, and choke/kill valves shall have a working pressure rating equivalent or greater than the wellhead working pressure rating. Annular shall have working pressure 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 if they 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 be available on the rig).

10.

Rams must be capable of hanging off the maximum anticipated drill string load with the tool joints in use and maintain a seal against wellbore pressure equivalent to the ram body working pressure rating. VBRs are not recommended as the hang-off rams. If VBRs are to be used as the hangoff rams, the manufacturer's specifications will be checked for pipe size and hang-off load rating. Only "hang-off" type ram blocks, with a hardened area around the lip of the ram block, should be used.


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WELL CONTROL 11.

Drilling spools must have at least the ID clearance and working pressure rating as that of the ram bodies.

Choke and Kill Lines The Choke and Kill Lines shall be equipped with and have a working pressure rated at least equivalent 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 pump manifold 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 least equivalent to the "A" section top flange.

2.

All wellhead sections shall have a flanged valve with a rated working pressure at least equivalent to the section top flange.

3.

A second valve of the same working pressure shall be installed on any wellhead sections where 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 blind flange installed on the outlet.

5.

A pressure gauge shall be installed on all wellhead sections outside of the valves to facilitate monitoring of casing annulus pressure.

BOP Control System BOPs shall be controlled by a Control System meeting the criteria listed below and must meet the following 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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WELL CONTROL •

Close each Annular Preventer < 18-3/4" within 30 seconds and within 45 seconds for preventers ³ 18-3/4".

Surface Accumulator Bottles 1.

A sufficient number of accumulator bottles will be installed, at a minimum, to meet EMDC's technical specifications, API RP 16D (Part I & II), and/or local requirements for accumulator unit sizing. See Section 5.0 of the Surface Blowout Prevention and Well Control Equipment Manual for details on EMDC requirements. NOTE: “API RP 16E as referenced in the BOP manual has since been recalled. The correct API reference for accumulator design is now API Spec 16D”.

2.

The precharge pressure for all accumulator bottles will be verified upon mobilization of the drilling unit and approximately every 60 days thereafter.

3.

Accumulator bottles shall be divided into at least two or more separate banks of generally the same 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 when primary 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 fluid capacity 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 the reserve 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 allowable pressure) 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 and protected from damage from other rig sources.

10.

Check for type of alarm system installed. See required alarms below.


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WELL CONTROL 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 the surface regulators, unless the regulators are of the worm gear type or equivalent, to avoid losing 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 pressure requirements for high expected shut-in pressures and annular pressures for larger sizes of pipe and casing.

BOP Operating Panels 1.

Two operating panels will be available, containing all BOP functions, one of which will be located 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 accumulator unit control station to prevent inadvertent operation. The guard at the accumulator unit is not to interfere with remote operating capabilities.

3.

If an electrical relay system is used, emergency generator power or a battery back-up system will 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 accumulator control 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 following specifications: 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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WELL CONTROL 2.

A minimum of two (2) valves will be upstream of each choke and one (1) valve between any other outlets on the manifold such as the standpipe manifold, trip tank bleed line, and the cement 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 pressure and casing pressure immediately upstream from the choke in operation. If the control panel has dual chokes, a casing pressure gauge will be available to monitor pressure upstream of each choke.

•

A choke panel which contains a gauge indicating choke position, gauges to read pump rate and cumulative pump strokes, and a control to zero the cumulative pump stroke counter.

•

A selection of calibrated gauges of various ranges that can help determine shut-in drill pipe and casing pressure accurately.

4.

Adequate pressure sensors will be installed on the choke manifold and standpipe manifold to monitor 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 working pressure 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 and kill 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 the choke 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 when circulating through the choke manifold during a well control operation.


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WELL CONTROL 2.

Provide a sufficient head to force gas out the vent line as well as separate gas from the drilling fluid. •

See Surface Blowout Prevention and Well Control Equipment Manual (page 8-19 and 820 for details).

3.

Vent line from the mud gas separator will have a minimum diameter of 8" and contain a minimum 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 the separator. During mobilization and after each use for well control, the separator should be drained, washed and visually inspected.

5.

A by-pass valve will be installed which vents gas out a direct vent line and isolates the shale shaker room when the liquid leg is lost at the mud gas separator. The location of the by-pass valve 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 that drilling 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 while drilling and tripping is automatic. The drill crew members must detect a simulated well flow and react in the proper manner within the time limit required. A schematic of the BOP will be posted on the drill floor showing distances from RKB to the various BOP components. The Driller must know 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", the first valve downstream of the hydraulic choke should be in the open position with the choke closed as 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 of the 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 influx while making a trip. After the BOP is installed, this drill must be held with each crew until they are thoroughly familiar with the procedure and thereafter with each crew at a frequency specified by OIMS. While tripping and after the drill string has been pulled into the casing, without prior notice, the apparent trip tank level is to be gradually increased by manually raising the mud pit level float or verbally notifying the Driller from the Trip Tank Hand or the Mud Logging unit (if being used) that DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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WELL CONTROL an increase in trip tank level has occurred. The Driller, Drill Crew, and Mud Loggers should recognize a 10 bbl trip tank gain within 1 minute and shut 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 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, torqueup safety valve. Make sure the choke manifold valve downstream of the power choke is closed.

8.

Immediately notify ExxonMobil Drilling Supervisor and Toolpusher. Record the time to shutin 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 stripping operations).

10.

Record casing pressure and gain in trip tank. Check accumulator pressures. Check BOP system 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 the Daily Drilling Report and IADC Report. Note:

A typical drill would stop at Step #10, although the documentation under Step #13 would still be performed. Steps #11 - #12 may be performed for additional training and extended drills.

Pit Drill The purpose of this drill is to reduce the time required for the Driller to detect and react to a change in the pit level. After the BOP is installed, this drill will be held with each crew until they are thoroughly familiar with the procedure and thereafter with each crew at a frequency specified by OIMS.


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WELL CONTROL While drilling on bottom, without prior notice, the apparent pit level is to be gradually increased by manually 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 and shut 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 the well flowing).

5.

If flowing, shut in the well by opening the BOP choke line valve (HCV) and closing the annular.

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 accumulator pressures. Check BOP system components and choke manifold for correct position. Check for 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/or have 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 the Daily Drilling Report and IADC Report. Note:

A typical drill would stop at Step #6, although the documentation under Step #12 would still be performed. Steps #7 – #11 may be performed for additional training and extended drills.

Power Choke Drill Crews are encouraged to conduct power choke drills prior to drilling-out after setting of each casing string. The drill provides practice for the Drilling Supervisor, Toolpusher, and crew members in operating the power choke. If done from a floating rig, it is an opportune time to measure the choke line 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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WELL CONTROL 3.

Take slow circulation rates at 20, 30, and 40 spm down the drill pipe and out the choke line with 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 casing pressure constant to desired pump speed. The casing pressure can be varied to illustrate the time required for the pressure pulse to travel down the annulus and back up the drill pipe pressure 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 Daily Drilling Report.

14.6

WELL CONTROL PROCEDURES

Laminated copies of rig specific shut-in procedures shall be posted on the rig floor near the Driller's console. Rig specific station bills, listing duties of the crew members, will also be posted 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 the Senior Drilling Contractor toolpusher and such work must be cleared with the Operations Supervisor 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 designated muster area.

5.

If any of the following occur, the rig site is to be immediately abandoned:

6.

•

Gas surfaces uncontrolled at the rig floor

•

Well fluids broach around the casing

•

Well flow is detected with no diverter or no BOP installed.

A pre-job safety meeting will be held with all involved personnel prior to attempting a well kill operation.

Diverter Installed Successfully diverting a well flow before gas surfaces and without broaching requires that all surface equipment be ready to close the diverter bag immediately yet have a relief path for the well fluids to prevent broaching. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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WELL CONTROL While drilling with a Diverter System using a Remote Operated Ball Valve, the valve open function should be plumbed into the diverter close line such that the valve will open prior to the annular closing. Mud should be pumped through the diverter lines every tour to ensure the line and relief path are not plugged. 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 pits followed by water from the water pit if the mud does not kill the well. Pumping will also keep the gas flow wet and reduce the fire hazard. Note:

8.

If tripping, running casing, or out of the hole, it may be necessary to strip back to bottom prior to attempting the dynamic kill.

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 a competent 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 Procedures for Drilling, Tripping, & Running Casing" and the "Station Bill during Well Control Operations"

•

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 drilling operations.


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WELL CONTROL Flowcheck Procedure - Drilling 1.

2.

The well is to be checked for flow if any of the following occur at anytime during drilling or circulating 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.

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 further approval 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 choke manifold 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 10 minutes thereafter.


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WELL CONTROL 8.

Complete the 'Well Killing Worksheet'. Select kill method and determine materials needed to circulate out the kick.

9.

Adjust regulator pressure on annular preventer. sticking.

10.

Prepare to extinguish sources of ignition.

Reciprocate pipe, if possible, to avoid

Flowcheck Procedure - Tripping 1.

2.

The well is to be checked for flow if any of the following occur at anytime during tripping operations: •

Hole not taking the correct amount of fluid.

•

Gain in trip tank.

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:

3.

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 65/8 Reg box x 4-1/2" IF box crossover.

Observe the well for flow. If there is any question as to whether the well is flowing, it should be 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 any further 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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WELL CONTROL 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 for correct 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 be necessary to strip the drill pipe back to bottom before circulating out the influx. See Stripping 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 or spiral 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 possible through the choke line on BOP stack configurations where the blind ram is located below the choke 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 running operations: •

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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WELL CONTROL 2.

Close the annular preventer. •

3.

The annular closing pressure should have been adjusted for the larger OD pipe prior to starting to run casing.

Install a crossover and make up a safety valve. Note:

If the casing float equipment leaks, it may be necessary to open the annular temporarily 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, amount of well flow, condition of the float equipment, and the annulus pressure. The option selected should be 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 consulting with the Operation Superintendent, when practical, as to which of the following methods to use based on actual wellbore conditions:

•

Drillers Method - Circulate out the influx using the original weight fluid, then circulate kill weight 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 barite is on hand to weight up the fluid, this method should generally be used rather than suspending operations until barite becomes available.

•

Weight and Wait Method - Circulate out the influx in one circulation using a balanced fluid weight. This method generally results in the lowest surface pressure and minimizes the time lost by returning to normal drilling operations as soon as possible if a sufficient volume of heavier fluid is available on the Drilling rig and ready to pump. In some instances, the time necessary to weight up the fluid can be excessive.

2.

Mixing rate capabilities of the drilling rig are to be considered. Generally, incremental mud weight 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 the well. Higher trip margins may be necessary for wells with swabbing problems, etc.


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WELL CONTROL Circulating Rate Selection: 1.

The circulating rates for the well kill operations are to be selected after consulting the Operations Superintendent, when practical. A pump rate in the 1 to 3 BPM range should typically 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 of the liquid leg in the mud gas separator.

4.

When necessary to change circulating rates, the well is to be shut-in and a new friction pressure determined.

Constant Bottom Hole Pressure Method Well Kill Procedure The objective of circulating out influxes is to maintain a constant bottom-hole pressure sufficient to prevent further influxes while minimizing lost circulation at the casing shoe. Following are steps to achieve this goal. 1.

With hydraulic choke closed, open the valve downstream of the choke to allow returns to be taken 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 to hold a constant casing pressure on the annulus equal to the original shut-in pressure on the casing plus a 25 to 50 psi safety margin.

3.

Read and record drill pipe pressure after the pump reaches the desired constant speed and after casing pressure stabilizes to the desired value. Note:

4.

The drill pipe pressure at this point is the pressure necessary to maintain a constant bottom-hole pressure when circulating at that particular pump speed only. The difference between the initial shut-in pressure on the drill pipe and the pumping pressure on the drill pipe is the friction pressure necessary to circulate drilling fluid at that particular pump speed only.

Maintain the desired drill pipe pressure at the constant pump rate while circulating out the influx by manipulating the hydraulic choke taking returns from the annulus.


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WELL CONTROL

5.

•

Changes in pressure due to choke manipulation require approximately 2 seconds per 1000' of drill string to register on the stand pipe gauge; however, this lag in response time can 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.

Circulate using the desired fluid weight increments until kill weight mud is circulated around and it is verified that the well is dead. Use caution at all times since additional influxes could enter the wellbore.

Stripping Operations This section is applicable after making the decision to strip in the hole in order to perform a kill operation 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 the stripping team.

3.

The stripping procedure is to be reviewed and calculations are to be performed for the capacity 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 the person monitoring the trip tank has been established.

6.

Ensure that everything is ready to take returns from the choke manifold through the mud gas separator 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 force from 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 upward force from the wellbore.

3.

Monitor well bore pressures and control the surface pressures using the bubble migration technique/procedures while rigging up to strip in the hole.


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WELL CONTROL 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 not using 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 closed blind rams.

8.

Bullhead a higher weight drilling fluid down the choke and kill lines to lower the shut-in casing 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 the equivalent 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 sticking while rigging up to strip.

13.

Reduce the closing pressure on the annular preventer as necessary in order to minimize wear on 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 string has a ported float valve. Note:

15.

Ensure the drill pipe safety valve is opened prior to stripping in the hole.

Always use the safety valve on the rig floor and not the top drive when shutting in the well on a trip. After installation of the safety valve, ensure that a backup valve is on the rig floor before stripping operations begin.

Stripping Procedure: 1.

Record the shut in casing pressure.

2.

Install the inside BOP and open the safety valve. Note:

3.

Do not forget to open the safety valve.

Fill the drill pipe with a gel pill above the inside BOP to prevent trash in the drill string from plugging the valve.


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WELL CONTROL 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 between the 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 maintain the following, whichever occurs first: •

A returns volume which is equal to the capacity and displacement of the pipe being stripped into the hole, OR:

•

A casing pressure which is equal to the pressure recorded prior to stripping the stand in the hole, OR:

•

Gas is returned at the choke. Note:

Fluid is sometimes lost to the formation resulting in reaching a casing pressure that is equal to the recorded pressure at the start of the stand, before a returns volume 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 into the 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 if the influx to due to swabbing unless the trip margin is insufficient for safe tripping.

Well Control for Wireline Operations Procedures and requirements for additional equipment for well control during wireline operations are usually generated by the affiliate drilling team, unless local regulatory specifications are in effect. In many cases the well is completely stable with the mud weight in use at the time logging operations occur and no lubricator system is required. Since the annular preventer may not totally close off the wellbore with wireline in the hole, wirecutters should be available to cut the wire, if DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003

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WELL CONTROL required. Each operational team should plan for this possibility, including securing the surface cut section 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 sensitive areas, 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 and riser assembly that is anchored across a closed element of the annular preventer or flanged to the top of the annular preventer. If the well starts to flow while the logging tool is in the hole, the tool string is pulled into the lubricator and the blind rams are shut to isolate the wellbore. Pressure is then 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 greater than the formation pressure. The following three characteristics of barite plugs are the result of an analysis of industry experience and laboratory studies: 1.

High density and good pump ability are the most important parameters to consider when designing a heavy kill slurry.

2.

The settling of barite from a barite plug is a slow process that is usually of little value in most well 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 minimize confusion during the plug setting operation.

3.

Ensure that each cementing operator is familiar with the problems of mixing and pumping a barite 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 to the cement unit if plugging occurs.

7.

Ensure that a barite deliverability test to the cementing unit is performed prior to attempting to set a barite plug.


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WELL CONTROL Barite Plug Mixing Guidelines: 1.

Use either the "Settling Recipe" or "Non-Settling Recipe" shown below when mixing a barite plug. SETTLING RECIPE 1 bbl 15 lb. 2 lb.

Water (fresh or seawater) Lignosulfonate Caustic; pH = 10.5 - 11.5

NON-SETTLING RECIPE 1 bbl Water (fresh or seawater) 15 lb. Lignosulfonate 2 lb. Caustic; pH = 10.5 - 11.5 1 lb. XC Polymer As 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 the final slurry volume.

4.

Prepare a 21 ppg barite slurry by mixing 700 lbs of barite with 0.54 bbl of mix water. Mix the non-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 (do not 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 to be rigged up to reach the cementing manifold. Do not pump through a kelly or top drive system (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 for displacement 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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WELL CONTROL 6.

The valves on the cementing unit fill up line are to be tested for leaks and to ensure they function 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 discard the 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 the bypass line.

11.

Zero the barrel counter and continue mixing the slurry using the cementing unit and cement displacement tanks.

12.

Displace the barite plug without shutting down. Note:

Actual displacement volume depends on whether it is possible to pull out of the plug or if the pipe is stuck.

13.

Displace the barite slurry at a rate fast enough to get pumping pressure at the stand pipe. The heavier barite in the drill pipe will tend to fall, and it is desirable to keep up with it by pumping 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 of successfully 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 the displacement 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 slips while 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 the barite plug in order to be certain that plug is in place.


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WELL CONTROL ExxonMobil Development Company Drilling CREW STATION BILL AND RESPONSIBILITIES DURING WELL CONTROL OPERATIONS DRILLER 1) 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 MAN 1) 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 HAND 1) 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.

DRILLING OPERATIONS SUPERVISOR 1) 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. TOOLPUSHER 1) 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 OPERATOR 1) Assemble roustabout crew. 2) Standby to assist in well control operations. 3) Coordinate barite material movement. MUD ENGINEER 1) 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/ELECTRICIAN 1) Check closing unit. 2) Check accumulator pressure. MUD LOGGERS 1) Monitor pump strokes, gas units, and pit levels. 2) Work up kill sheet.

FLOOR HANDS 1) 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.


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Exon-Mobile Drilling Guide

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