ABS Drlling Systems Guide

Guide for the Classification of Drilling Systems

GUIDE FOR THE

CLASSIFICATION OF DRILLING SYSTEMS

MARCH 2011

American Bureau of Shipping Incorporated by Act of Legislature of the State of New York 1862

Copyright © 2011 American Bureau of Shipping ABS Plaza 16855 Northchase Drive Houston, TX 77060 USA

ii ABS GUIDE FOR THE CLASSIFICATION OF DRILLING SYSTEMS . 2011

Foreword

Foreword This Guide has been revised to assist the industry with Classification of Drilling Systems. This revision supersedes the 2006 ABS Guide for the Certification of Drilling Systems. This Guide becomes effective as of 1 March 2011.

The Guide describes criteria to be used for drilling systems, which are to be approved by the American Bureau of Shipping (ABS), and it is built upon requirements of the recognized codes and standards, as referenced in this Guide. The Guide contains the following nine (9) main sections and five (5) appendices:

Section 1 Scope and Condition of Classification

Section 2 Design of Drilling Systems

Section 3 Drilling Systems

Section 4 Scope of Drilling System and Equipment Approval

Section 5 Drilling System Piping

Section 6 Materials for Drilling Systems and Equipment

Section 7 Welding and Nondestructive Examination

Section 8 Surveys at Vendor’s Plant During Installation and Commissioning

Section 9 Surveys After Construction and Maintenance of Class

Appendix 1 Typical Codes and Standards Related to ABS Classification of Drilling Systems

Appendix 2 Sample Manufacturer’s Affidavit of Compliance

Appendix 3 Sample of Independent Review Certificate

Appendix 4 Sample of Certificate of Conformity

Appendix 5 Sample of Maintenance Release Note

This Guide is to be used in conjunction with other applicable ABS Rules and Guides, codes and standard as referenced therein, and applicable national regulations.

ABS Classification continues to provide the offshore industry with a pathway toward agreement by Regulatory Authorities. However, the Owner/Operator’s specific request for compliance with applicable requirements of Flag or Coastal State Authorities affecting the drilling systems is to be filed as an addendum to the Request for Classification.

The following major changes to the Guide were incorporated into the March 2011 CDS Guide:

General • The scope has been revised to “ABS Guide for the Classification of Drilling Systems” from “ABS

Guide for the Certification of Drilling Systems”

Section 1 • “Scope and Condition of Classification” section is modified to be in the same format and layout as

ABS Rules Conditions of Classification – Offshore Units and Structures (Part 1).

• The “Scope” of Section 1 was expanded to cover all applicable drilling systems, subsystems, equipment, and/or components.

• “Definitions” and “Acronyms and Abbreviations” sections relating to drilling system terminology were added.

Section 2 • The “Design Plans and Data” have been significantly expanded in order to clearly identify the

engineering submittal requirements for drilling systems, subsystems, equipment and/or components.

ABS GUIDE FOR THE CLASSIFICATION OF DRILLING SYSTEMS . 2011 iii

Section 3 • The general structure of the Guide and specifically Section 3, “Drilling Systems”, has been revised to

address the Classification requirements starting from the wellbore migrating towards the top of the derrick.

• Additional requirements for “autoshear”, “deadman”, “acoustic control” and “additional shear rams for DP units”, etc.

Section 4 • Clarified and identified the steps to ABS approval process of drilling systems, subsystems, equipment

and/or components.

• Vendor Release Note (VRN) deleted from the Guide. ABS no longer issues any document to the Vendor without satisfactory completion of the required design review and surveys.

• Clarified and expanded Table 1 of Section 4 to list additional drilling system equipment and components, and further clarified ABS approval process (i.e., ABS Design Review, ABS Approval Letter, IRC, etc.) and the limited use of PDA/ABS Type Approval.

Section 5 • Clarified the requirements for “Flexible Lines/Hydraulic Hoses” to consider different servcie

categories.

Section 6 • Categorized and defined the load-bearing and pressure-retaining equipment and components.

• Clarified the toughness requirements and values based on the equipment or component loading category.

Section 7 • Editorial changes

Section 8 • Clarified and expanded the requirements for surveys at manufacture and during assembly, and surveys

onboard during installation, particularly by requiring proper record keeping of inspections and testing done on equipment for well control system.

Section 9 • Maintenance Release Note (MRN) – Further clarified the requirement for issuance of the MRN and its

affect on maintenance of the drilling system certification.

• Revised and clarified Annual Survey and Special Periodical Survey requirements, particularly by requiring the surveys to be carried in accordance with an ABS reviewed and agreed inspection program called “In-Service Inspection Program” (ISIP), and by requiring proper record keeping of maintenance, inspections and testing done on equipment for well control system.

Appendix 1 • Updated the title and contents of Appendix 1 to “Typical Codes and Standards Related to ABS

Classification of Drilling Systems”

Appendix 2 • Updated the contents to provide additional parameters for Appendix 2 “Sample of Manufacturer’s

Affidavit of Compliance”

Appendix 3 • The sample copy of a Vendor Release Note is deleted and replaced by the sample copy of an Independent

Review Certificate (IRC).

iv ABS GUIDE FOR THE CLASSIFICATION OF DRILLING SYSTEMS . 2011

Appendix 4 • The sample copy of the Maintenance Release Note is replaced by the sample copy of a Certificate of

Compliance (CoC). The sample of Maintenance Release Note is moved to Appendix 5.

Appendix 5 • The sample copy of the Maintenance Release Note (MRN) is provided.

ABS GUIDE FOR THE CLASSIFICATION OF DRILLING SYSTEMS . 2011 v

Table of Contents

GUIDE FOR THE

CLASSIFICATION OF DRILLING SYSTEMS

CONTENTS SECTION 1 Scope and Conditions of Classification............................................... 1

1 Classification.......................................................................................1 1.1 Process ...........................................................................................1 1.3 Certificates and Reports ..................................................................1 1.5 Representations as to Classification ............................................... 2 1.7 Scope of Classification ....................................................................2

3 Suspension and Cancellation of Class ...............................................3 3.1 Termination of Classification and Notice of Surveys .......................3 3.3 Suspension of Class........................................................................3 3.5 Lifting of Suspension .......................................................................3 3.7 Cancellation of Class.......................................................................4

5 Class Notation.....................................................................................4 5.1 ABS Class Notation.........................................................................4 5.3 Systems Not Built Under Survey .....................................................4

7 Rules for Classification .......................................................................4 7.1 Applications .....................................................................................4 7.3 Effective Date of Change of Requirement .......................................5 7.5 Scope ..............................................................................................5 7.7 Alternatives......................................................................................6

9 Other Regulations ...............................................................................8 9.1 International and Other Regulations................................................8 9.3 Governmental Regulations ..............................................................8

11 IACS Audit ..........................................................................................8 13 Submission of Plans ...........................................................................8 15 Conditions for Survey After Construction............................................9

15.1 Damage, Failure and Repair ...........................................................9 15.3 Notification and Availability for Survey...........................................10

17 Units ..................................................................................................10 19 Fees ..................................................................................................10 21 Disagreement....................................................................................10

21.1 Rules and Guides.......................................................................... 10 21.3 Surveyor ........................................................................................10

23 Limitation of Liability..........................................................................11 25 References........................................................................................11 27 Definitions .........................................................................................12 29 Acronyms and Abbreviations ............................................................20

vi ABS GUIDE FOR THE CLASSIFICATION OF DRILLING SYSTEMS . 2011

SECTION 2 Design of Drilling Systems .................................................................. 22 1 Design of Drilling System..................................................................22

1.1 General..........................................................................................22 1.3 Equipment Layout..........................................................................22 1.5 Overpressurization Protection .......................................................23 1.7 Materials ........................................................................................23 1.9 Welding and Nondestructive Examination .....................................23

3 Design Specifications........................................................................23 5 Design Considerations......................................................................23

5.1 Recognized Standards ..................................................................23 5.3 Alternative Basis of Design............................................................24 5.5 Corrosion/Erosion Allowance.........................................................24 5.7 Design Conditions..........................................................................24

7 Design Plans and Data .....................................................................25 7.1 General Arrangement for Drilling System ......................................26 7.3 Well Control Systems and Equipment ...........................................26 7.5 Marine Drilling Riser Systems........................................................30 7.7 Drill String Compensation Systems ...............................................31 7.9 Bulk Storage, Transfer, and Circulation Systems ..........................32 7.11 Hoisting, Lifting, Pipe Handling System .........................................33 7.13 Mechanical Load-Bearing Equipment ............................................36 7.15 Well Testing System......................................................................37 7.17 Electrical Systems and Equipment ................................................39 7.19 Control Systems ............................................................................39 7.21 Pressure-Retaining Equipment......................................................40 7.23 Piping Systems and Piping Components.......................................40 7.25 Flexible Lines/Hydraulic Hoses......................................................41 7.27 Manufacturing Specifications.........................................................41

SECTION 3 Drilling Systems ................................................................................... 42

1 General .............................................................................................42 3 Well Control System .........................................................................43

3.1 Blowout Preventer System and Equipment ...................................43 3.3 Lower Marine Riser Package (LMRP) ...........................................47 3.5 Choke and Kill Systems and Equipment........................................48 3.7 Diverter System and Equipment ....................................................52 3.9 Marine Drilling Riser Systems........................................................53 3.11 Auxiliary Well Control Equipment...................................................53

5 Marine Drilling Riser System.............................................................54 5.1 Riser Tensioning System and Equipment......................................55 5.3 Marine Drilling Riser Operating Envelope......................................55 5.5 Technical Requirements ................................................................56 5.7 Design Documentation ..................................................................57

7 Drill String Compensation System ....................................................58 7.1 Drill String Compensation Equipment ............................................58

ABS GUIDE FOR THE CLASSIFICATION OF DRILLING SYSTEMS . 2011 vii

9 Bulk Storage, Circulation and Transfer Systems..............................58 9.1 Bulk Storage and Transfer Equipment .......................................... 59 9.3 Cementing System and Equipment ............................................... 59 9.5 Mud Return System and Equipment.............................................. 60 9.7 Well Circulation System and Equipment........................................ 60

11 Hoisting, Lifting, Rotating and Pipe Handling Systems ....................61 11.1 Derricks/Masts...............................................................................61 11.3 Hoisting Equipment ....................................................................... 64 11.5 Lifting Equipment........................................................................... 67 11.7 Pipe Handling Equipment .............................................................. 71 11.9 Rotary Equipment..........................................................................72 11.11 Miscellaneous Equipment.............................................................. 73

13 Well Test System..............................................................................73 13.1 Well Test System and Equipment ................................................. 74 13.3 Burner/Flare Booms ......................................................................74 13.5 Hydrocarbon Disposal Facilities .................................................... 75 13.7 Surface Safety Systems ................................................................75 13.9 Classified Areas ............................................................................ 75 13.11 Operational Procedures.................................................................76

15 Control Systems................................................................................76 15.1 Control Systems ............................................................................76 15.3 Control Systems for Well Control Equipment ................................ 77 15.5 Electrical Control Systems and Computer-Based Systems...........77 15.7 Safety Systems .............................................................................78

17 Pressure-Retaining Equipment.........................................................78 17.1 Pressure Vessels ..........................................................................78 17.3 Hydraulic Cylinders .......................................................................79

19 Electrical Systems and Equipment ...................................................79 21 Rotating Machinery ...........................................................................80

21.1 Internal Combustion Engines ........................................................ 80 21.3 Electrical Rotating Machinery ........................................................80

23 Skid Mounted Equipment..................................................................80 23.1 Skid Structures ..............................................................................80 23.3 Drip Pans.......................................................................................81

SECTION 4 Scope of Drilling System and Equipment Approval.......................... 82

1 General .............................................................................................82 3 Approval Process..............................................................................82

3.1 Design Review ..............................................................................83 3.3 ABS Survey ...................................................................................84 3.5 Issuance of Certificates and Reports............................................. 84 3.7 Individual Equipment Approval: Non-Class Installation ................. 85 3.9 Vendor Coordination Program.......................................................85

TABLE 1 Approval Codes for Drilling Systems and Equipment.............86

viii ABS GUIDE FOR THE CLASSIFICATION OF DRILLING SYSTEMS . 2011

SECTION 5 Drilling System Piping ....................................................................... 102 1 General ...........................................................................................102 3 Design Criteria ................................................................................102

3.1 Piping Systems and Components................................................102 3.3 Fittings and Valves ......................................................................103 3.5 Piping Connections......................................................................103 3.7 Flexible Lines/Hydraulic Hoses....................................................104

5 Materials..........................................................................................106 5.1 Toughness...................................................................................106 5.3 Composite Materials ....................................................................106

7 Welding and NDE ...........................................................................106 SECTION 6 Materials for Drilling Systems and Equipment ................................ 107

1 General ...........................................................................................107 3 Selection of Structural Steels..........................................................107 5 Selection of Drilling Equipment Materials .......................................107

5.1 Material Properties.......................................................................108 5.3 Toughness...................................................................................108 5.5 Corrosion – Hydrogen Sulfide......................................................109

7 Fabrication Considerations .............................................................109 7.1 Welding........................................................................................109 7.3 Forming .......................................................................................109

9 Primary Product Form.....................................................................110 9.1 General........................................................................................110 9.3 Rolled Products ...........................................................................110 9.5 Forgings.......................................................................................110 9.7 Castings.......................................................................................110

11 Sealing Materials ............................................................................110 11.1 Elastomeric Sealants ...................................................................110 11.3 Ring Joint Gaskets.......................................................................110

13 Materials and Traceability ...............................................................111 13.1 Materials ......................................................................................111 13.3 Traceability ..................................................................................111

SECTION 7 Welding and Nondestructive Examination....................................... 112

1 General ...........................................................................................112 3 Specifications..................................................................................112

3.1 Welding Procedure Specification .................................................112 3.3 NDE Procedures..........................................................................113

5 Welder/Welding Operator Qualification ..........................................113 7 Qualification of Nondestructive Technicians...................................113 9 Post Weld Heat Treatment..............................................................113 11 Nondestructive Examination ...........................................................113

11.1 Extent of Examination for Materials and Welds ...........................113 11.3 Methods and Acceptance Criteria................................................114

13 Record Retention ............................................................................115

ABS GUIDE FOR THE CLASSIFICATION OF DRILLING SYSTEMS . 2011 ix

SECTION 8 Surveys at Vendor’s Plant During Installation and Commissioning .................................................................................. 116 1 General ...........................................................................................116 3 Surveys at Manufacture and During Assembly...............................116

3.1 Testing of Well Control Equipment and BOP’s ............................ 117 3.3 Testing of Marine Drilling Riser System and Associated

Components ................................................................................ 117 3.5 Testing of Drill String Compensation System .............................. 118 3.7 Testing of Bulk Storage, Circulating and Transfer Systems ........ 118 3.9 Testing of Hoisting, Lifting, Rotating, and Pipe Handling

Systems.......................................................................................118 3.11 Testing of Well Test Equipment................................................... 118 3.13 Testing of Skid Structures ........................................................... 118

5 Onboard Surveys During Installation ..............................................119 5.1 Testing of Base-mounted Winches and Other Lifting Appliances 121 5.3 Testing of Burner/Flare Boom ..................................................... 121

7 Commissioning Surveys of the Drilling Systems ............................121 SECTION 9 Surveys After Construction and Maintenance of Class.................. 123

1 General ...........................................................................................123 3 Surveys Onshore and Issuance of Maintenance Release

Notes...............................................................................................123 5 Survey of Drilling Systems..............................................................124

5.1 Survey Intervals and Maintenance Manuals/Records ................. 124 5.3 Annual Surveys ........................................................................... 124 5.5 Special Periodical Surveys .......................................................... 125 5.7 Continuous Survey Program ....................................................... 126 5.9 Survey Based on Preventative Maintenance Techniques ........... 126 5.11 Surveys Using Risk-based Techniques....................................... 126

7 Modifications, Damage and Repairs...............................................126 APPENDIX 1 Typical Codes and Standards Related to ABS Classification of

Drilling Systems ................................................................................. 127 APPENDIX 2 Sample Manufacturer’s Affidavit of Compliance............................. 131 APPENDIX 3 Sample of Independent Review Certificate (IRC) ............................ 132 APPENDIX 4 Sample of Certificate of Conformity (CoC) ...................................... 135 APPENDIX 5 Sample Maintenance Release Note (MRN)....................................... 136

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ABS GUIDE FOR THE CLASSIFICATION OF DRILLING SYSTEMS . 2011 1

Section 1: Scope and Conditions of Classification

S E C T I O N 1 Scope and Conditions of Classification

1 Classification The requirements for conditions of Classification for entire drilling units and offshore structures are contained in the ABS Rules for Conditions of Classification – Offshore Units and Structures (Part 1). Additional requirements specific to a drilling system, its subsystems, equipment or components are contained in this Guide.

1.1 Process The term Classification, as used herein, indicates that drilling systems, subsystems, equipment, and/or components have been designed, constructed, installed, and surveyed in compliance with this Guide, in conjunction with other applicable ABS Rules and Guides, codes and standards as referenced therein, and applicable national regulations. The continuance of Classification is dependent on the fulfillment of requirements for surveys after construction.

The Classification process consists of:

a) The development of Rules, Guides, standards and other criteria for the design, construction, installation and maintenance of drilling systems, subsystems, equipment, and/or components;

b) The review of the design and survey during and after construction to verify compliance with such Rules, Guides, standards or other criteria;

c) The assignment and registration of Class when such compliance has been verified, and;

d) The issuance of a renewable Classification certificate, with annual endorsements, valid for five (5) years.

The Rules, Guides and standards are, in general, developed by the International Association of Classification Societies and ABS staff and passed upon by committees made up of naval architects, ocean and marine engineers, shipbuilders, engine builders, steel makers, process engineers and by other technical, operating and scientific personnel associated with the worldwide maritime industry. Theoretical research and development, established engineering disciplines, as well as satisfactory service experience are utilized in their development and promulgation. ABS and its committees can act only upon such theoretical and practical considerations in developing Rules and standards.

ABS Surveyors apply normally accepted examination and testing standards to those items specified for each survey by the Rules; construction/manufacturing procedures, safety procedures and construction supervision remain the responsibility of the shipyard, the offshore unit or structures repairer, manufacturer, Owner/Operator or other client.

For Classification, the drilling system, subsystems, equipment, and/or components are to comply with the requirements of this Guide, in conjunction with all other applicable ABS Rules and Guides, codes and standards as referenced therein.

1.3 Certificates and Reports Plan review and surveys during and after construction are conducted by ABS to verify to itself and its committees that a drilling system, subsystem, equipment or component is in compliance with this Guide and to the satisfaction of the attending ABS Surveyor. All reports and certificates are issued solely for the use of ABS, its committees, its clients and other authorized entities.

ABS will release information from reports and certificates to the cognizant authorities (e.g., Coastal State or Flag State) to assist in rectification of deficiencies during any intervention by the authorities. Such information includes text of conditions of Classification, survey due dates and certificate expiration dates. The Owner/Operator will be advised of any request and/or release of information.

Section 1 Scope and Conditions of Classification

2 ABS GUIDE FOR THE CLASSIFICATION OF DRILLING SYSTEMS . 2011

ABS will release certain information to the offshore unit or structure’s underwriters for underwriting purposes. Such information includes text of overdue conditions of Classification, survey due dates and certificate expiration dates. The Owner/Operator will be advised of any request and/or release of information. In the case of overdue conditions of Classification, the Owner/Operator will be given the opportunity to verify the accuracy of the information prior to release.

ABS may release offshore unit or structure-specific information related to the Classification and statutory certification status. This information may be published on the ABS website or by other media and may include the offshore unit or structure classification, any operating restrictions noted in the ABS Record, the names, dates and locations of all surveys performed by ABS, the expiration date of all Class and statutory certificates issued by ABS, survey due dates, the text of conditions of Classification (also known as outstanding recommendations), transfers, suspensions, withdrawals, cancellations and reinstatements of Class, and other related information as may be required.

1.5 Representations as to Classification Classification is a representation by ABS as to the structural and mechanical fitness for a particular use or service, in accordance with its Rules, Guides and standards. The Rules and Guides of the American Bureau of Shipping are not meant as a substitute for the independent engineering judgment of professional designers, naval architects, marine engineers, owners, operators, masters and crew, nor as a substitute for the quality control procedures of ship and platform builders, engine builders, steel makers, suppliers, manufacturers and sellers of marine vessels, materials, system components, machinery or equipment. ABS, being a technical society, can only act through Surveyors or others who are believed by it to be skilled and competent.

ABS represents solely to the drilling system Owner/Operator or other client of ABS that when assigning Class, it will use due diligence in the development of Rules, Guides and standards, and in using normally applied testing standards, procedures and techniques as called for by the Rules, Guides, standards or other criteria of ABS for the purpose of assigning and maintaining Class. ABS further represents to the Owner/Operator or other client of ABS that its certificates and reports evidence compliance only with one or more of the Rules, Guides, standards or other criteria of ABS, in accordance with the terms of such certificate or report. Under no circumstances whatsoever are these representations to be deemed to relate to any third party.

The user of this document is responsible for ensuring compliance with all applicable laws, regulations and other governmental directives and orders related to a vessel, its machinery and equipment, or their operation. Nothing contained in any Rule, Guide, standard, certificate or report issued by ABS shall be deemed to relieve any other entity of its duty or responsibility to comply with all applicable laws, including those related to the environment.

1.7 Scope of Classification Nothing contained in any certificate or report is to be deemed to relieve any designer, builder, owner, manufacturer, seller, supplier, repairer, operator, other entity or person of any warranty, express or implied. Any certificate or report evidences compliance only with one or more of the Rules, Guides, standards or other criteria of the American Bureau of Shipping, and is issued solely for the use of ABS, its committees, its clients or other authorized entities.

Nothing contained in any certificate, report, plan or document review or approval is to be deemed to be in any way a representation or statement beyond those contained in 1/1.5. ABS is not an insurer or guarantor of the integrity or safety of a drilling system, subsystem, equipment or component. The validity, applicability and interpretation of any certificate, report, plan or document review or approval are governed by the Rules, Guides and standards of the American Bureau of Shipping, who shall remain the sole judge thereof. ABS is not responsible for the consequences arising from the use by other parties of the Rules, Guides, standards or other criteria of the American Bureau of Shipping, without review, plan approval and survey by ABS.

The term “approved” is to be interpreted to mean that the plans, reports or documents have been reviewed for compliance with one or more of the Rules, Guides, standards or other criteria of ABS.

This Guide is published with the understanding that responsibility for shutting down drilling operations, beyond the limit specified in the drilling system design basis, does not rest upon the Committee.



3 Suspension and Cancellation of Class

3.1 Termination of Classification and Notice of Surveys The continuance of the Classification of the drilling system, subsystem, equipment, and/or component is conditional upon the Guide requirements for periodical, damage and other surveys being duly carried out. The Committee reserves the right to reconsider, withhold, suspend or cancel the Class of any drilling system, subsystems, equipment, and/or components for noncompliance with the Rules, for defects reported by the Surveyors which have not been rectified in accordance with their recommendations or for nonpayment of fees which are due on account of Classification. Suspension or cancellation of Class may take effect immediately or after a specified period of time.

It is the responsibility of the Owner/Operator to ensure that all surveys necessary for the maintenance of Class are carried out at the proper time. ABS will give proper notice to an Owner/Operator of upcoming surveys. This may be done by means of a letter, a quarterly status report or other communication. The non-receipt of such notice, however, does not absolve the Owner/Operator from his responsibility to comply with survey requirements for maintenance of Class.

3.3 Suspension of Class Class will be suspended and the Certificate of Classification will become invalid from the date of any use, operation or other application of any drilling system, subsystems, equipment, and/or components for which it has not been approved and which affects or may affect Classification or the structural integrity, quality or fitness for a particular use or service.

Class will be suspended and the Certificate of Classification will become invalid in any of the following circumstances affecting the drilling system:

i) If Continuous Survey items which are due or overdue at the time of Annual Survey are not completed and no extension has been granted,

ii) If the Periodical Surveys required for maintenance of Class, other than Annual or Special Periodical Surveys, are not carried out by the due date and no Rule-allowed extension has been granted, or

iii) If any damage, failure or deterioration repair has not been completed as recommended.

Class will be subject to a suspension procedure if recommendations issued by the Surveyor are not carried out and/or completed by their due dates and no extension has been granted.

Class may be suspended, in which case the Certificate of Classification will become invalid, if proposed repairs, as referred to in 1/15.1, have not been submitted to ABS and agreed upon prior to commencement.

Class is automatically suspended and the Certificate of Classification is invalid in any of the following circumstances:

i) If the Annual Survey is not completed by the date which is three (3) months after the due date,

ii) If the Special Periodical Survey is not completed by the due date, unless the drilling system is under attendance for completion prior to resuming operation. Under exceptional circumstances, consideration may be given for an extension of the Special Survey, provided the drilling system is attended and the attending Surveyor so recommends. Such an extension shall not exceed three (3) months.

3.5 Lifting of Suspension Class will be reinstated after suspension for overdue surveys upon satisfactory completion of the overdue surveys. Such surveys will be credited as of the original due date. Class will be reinstated after suspension for overdue recommendations upon satisfactory completion of the overdue recommendation. Class will be reinstated after suspension for overdue continuous survey items upon satisfactory completion of the overdue items.



3.7 Cancellation of Class If the circumstances leading to suspension of Class are not corrected within the time specified, Class will be cancelled.

Class is cancelled immediately when drilling systems, subsystems, equipment, and/or components are operated without having completed recommendations which were required to be dealt with before the drilling system was brought back into service.

When Class has been suspended for a period of three (3) months due to overdue Annual, Special or other periodical surveys required for maintenance of Class; overdue Continuous Survey items; or overdue outstanding recommendations, the CDS Notation will be canceled. A longer suspension period may be granted for drilling systems, subsystems, equipment, and/or components which are either laid up, awaiting disposition of a casualty or under attendance for reinstatement.

5 Class Notation

5.1 ABS Class Notation Drilling systems, subsystems, equipment, and/or components that have been built, installed and commissioned to the satisfaction of the Surveyors to the full requirements of this Guide, where approved by the Committee for service for the specified design environmental conditions, will be classed and distinguished in the ABS Record by the notation À CDS.

5.3 Systems Not Built Under Survey The symbol “À” (Maltese-Cross) signifies that the drilling system, subsystems, equipment, and/or components were built, installed and commissioned to the satisfaction of the Surveyors. Drilling systems, subsystems, equipment, and/or components that have not been built under ABS survey, but which are submitted for Classification, will be subjected to special consideration. Where found satisfactory and thereafter approved by the Committee, they will be classed and distinguished in the Record by the notation described above, but the symbol “À” signifying survey during construction will be omitted.

7 Rules for Classification

7.1 Applications This Guide contains provisions for the Classification of offshore drilling systems, subsystems, equipment, and/or components that are used for hydrocarbon well drilling, completion, workover, and/or well testing or supporting such activities on mobile offshore drilling units (MODUs), offshore installations, tendering vessels, and other structures that are classed by ABS. This Guide is intended for use in conjunction with the latest edition of the following or other applicable ABS Rules and Guides:

• ABS Rules for Building and Classing Mobile Offshore Drilling Units (MODU Rules)

• ABS Guide for Building and Classing Mobile Offshore Units (MOU Guide)

• ABS Rules for Building and Classing Offshore Installations (Offshore Installations Rules)

• ABS Guide for Building and Classing Floating Production Installations (FPI Guide)

• ABS Rules for Building and Classing Steel Vessels (Steel Vessel Rules)

• ABS Guide for Building and Classing Facilities on Offshore Installations (Facilities Guide)

If specifically requested by the Owner/Operator, this Guide can also be used as a basis for acceptance or certification under the requirements of other Administrations. An Owner/Operator who requires a drilling system to be evaluated for compliance with other national regulations should contact ABS.

If specifically requested by the manufacturers, Owner/Operator, or designers, ABS can provide approval of individual equipment or component associated with drilling systems or subsystems in accordance with the requirements of this Guide (see 4/3.7), and where the installation unit may not be classed with ABS.



7.3 Effective Date of Change of Requirement 7.3.1 Effective Date

This Guide and subsequent changes to this Guide are to become effective on the date specified by ABS. In general, the effective date is not less than six months from the date on which the Guide is published and released for its use. However, ABS may bring into force the Guide or individual changes before that date, if necessary or as appropriate.

7.3.2 Implementation of Rule Changes In general, until the effective date, plan approval for designs will follow prior practice, unless review under the latest Guide is specifically requested by the party signatory to the application for Classification.

Where design of drillings systems, subsystems, equipment or components comply with the requirements of this Guide at the time of approval and/or construction, no retroactive application of later requirement changes to such drilling systems, subsystems, equipment or components will be required unless necessary or appropriate.

7.5 Scope This Guide covers the aspects of drilling systems, subsystems, equipment, and/or components used in connection with hydrocarbon well drilling, completion, workover, and well testing operations.

Compliance with this Guide is required for the drilling systems, subsystems, equipment, and/or components mentioned in Section 3, “Drilling Systems,” and typical listing in Section 4, Table 1. The drilling system includes, but is not limited to, the following:

• Well Control System

- Blowout Preventer (BOP) Equipment

- Lower Marine Riser Package (LMRP)

- Choke and Kill System

- Diverter System

- Auxiliary Well Control Equipment

• Marine Drilling Riser System and Associated Components

- Riser Tensioning System

- Riser Joints

- Connectors

- Riser Handling Tools

• Drill String Compensation System

• Bulk Storage, Circulating and Transfer System

• Hoisting, Lifting, Rotating and Pipe Handling System

• Derrick, Derrick Support Structures

• Drawwork, Rotary Table

• Well Test System

• Burner Booms

• Internal Combustion Engines Driving Drilling Machine

• Pressure Vessels Associated with Drilling and Well Control, Tensioning, and Fluid Storage

• Compressors for Drilling-Related Functions



• High Pressure Piping, Flexible Lines, and Hydraulic Hoses

- Choke and Kill

- Mud and Cement

- Rotary and Vibratory Hoses

• Fire Detection, Gas Detection, and Fire Protection Systems

• Well Control and Drilling Control Systems

• Emergency Shutdown Systems

• Electrical Systems and Equipment

• All Lifting Devices for Drilling and Drilling Support Operations

• Miscellaneous Drilling Support Systems

7.7 Alternatives 7.7.1 General

The Committee is ready to consider alternative arrangements and designs which can be shown, through either satisfactory service experience or a systematic analysis based on sound engineering principles, to meet the overall safety, serviceability and design standards of the Rules and Guides.

7.7.2 National Standards i) The Committee will consider special arrangements or design of drilling systems and their

equipment which can be shown to comply with standards recognized in the country provided that the proposed standards are not less effective.

ii) When alternate standards are proposed, comparative analyses are to be provided to demonstrate equivalent level of safety to the recognized standards as listed in this Guide and to be performed in accordance with 1/7.7 of this Guide.

7.7.3 Novel Features Drilling systems which contain novel features of design to which the provisions of this Guide are not directly applicable may be classed, when approved by the Committee, on the basis that this Guide, insofar as applicable, has been complied with and that special consideration has been given to the novel features, based on the best information available at that time. Justifications of the novel features can be accomplished by applying 1/7.7 of this Guide.

7.7.4 Risk Evaluations for Alternative Arrangements and Novel Features i) Risk evaluations for the justification of alternative arrangements or novel features may be

applicable either to the drilling system as a whole, or to individual systems, subsystems, equipment or components.

ii) ABS will consider the application of risk evaluations for alternative arrangements and novel features in the design of the drilling system, subsystems, equipment or components, verification surveys during construction, and surveys for maintenance of Class.

iii) When applied, risk assessment techniques are to demonstrate that alternatives arrangements and/or novel features provide acceptable levels of safety in line with current offshore and marine industry practice.

iv) The ABS Guidance Notes on Review and Approval of Novel Concepts, ABS Guidance Notes on Risk Assessment Applications for the Marine and Offshore Oil and Gas Industries, and ABS Guide for Risk Evaluations for the Classification of Marine-Related Facilities provides guidance to ABS clients on how to prepare a risk evaluation to demonstrate equivalency or acceptability for a proposed drilling system design.



v) Portions of the drilling system or any of its subsystems, equipment or components not explicitly included in the risk evaluation submitted to ABS are to comply with any applicable part of the ABS Rules and Guides.

vi) If any proposed alternative arrangement or novel feature affects any applicable requirements of Flag and Coastal State, it is the responsibility of the Owner/Operator to discuss with the applicable authorities the acceptance of alternatives based on risk evaluations.

7.7.4(a) Risk Assessment.

i) Risk assessment techniques may be used to demonstrate that alternatives and novel features provide acceptable levels of safety in line with current offshore and marine industry practice.

ii) When this optional risk assessment is applied at the specific request of the designer or manufacturer, all hazards that may affect the drilling system or any of its subsystems, equipment or components are to be identified.

iii) A systematic process is to be applied to identify situations where a combination or sequence of events could lead to undesirable consequences (property damage, personnel safety and environmental damage), with consideration given to all foreseeable causes.

iv) The objective of the hazard identification is to identify areas of the design that may require the implementation of further risk control options in order to reduce the risk to an acceptable level.

v) The hazard identifications are to consider, as a minimum, the following events:

• Release of H2S, CO2, etc.

• Hydrocarbon Release (Liquid or Gas)

• Blowout

• Fire and Explosion

• Loss of Purge Air

• Structural Failure

• Mechanical Failure

• Electrical Failure

• Loss/Failure of Mooring

• Loss/Failure of Station Keeping

• Loss of Stability

• Impact to Equipment

• Dropped Objects

• Collision

• Helicopter Crash

• Extreme Environment

vi) The identified risk control options (prevention and mitigation measures) deemed necessary to be implemented are to be considered part of the design basis of the drilling system.

vii) Appendix 4 in the ABS Guide for Risk Evaluations for the Classification of Marine-Related Facilities contains a description of the most common hazard identification techniques. Also, Appendix 2 in the same Guide provides an overview of how to assemble an appropriate risk assessment team.

viii) When the risk assessment technique is considered, ABS’ participation in the hazard identification meeting(s) is recommended. Tangible benefits can be derived by the participation of an ABS representative who will later be directly involved in reviewing the designs for ABS Classification.



9 Other Regulations

9.1 International and Other Regulations i) While this Guide covers the requirements for the Classification of drilling systems, subsystems,

equipment, and/or components, the attention of Owner/Operator, designers and builders is directed to the regulations of international, governmental and other authorities dealing with those requirements in addition to or over and above the Classification requirements.

ii) Where authorized by the Administration of a country signatory thereto and upon request of the Owner/Operator of a classed drilling system or one intended to be classed, ABS will survey for compliance with the provision of International and Governmental Conventions and Codes, as applicable.

9.3 Governmental Regulations Where authorized by a government agency and upon request of the Owner/Operator of a new or existing drilling system, ABS will survey and certify a classed drilling system or one intended to be classed for compliance with particular regulations of that government on their behalf.

11 IACS Audit The International Association of Classification Societies (IACS) conducts audits of processes followed by all of its member societies to assess the degree of compliance with the IACS Quality System Certification Scheme requirements. For this purpose, auditors for IACS may accompany ABS personnel at any stage of the Classification or statutory work, which may necessitate the auditors having access to the drilling system, subsystems, equipment, and/or components or access to the premises of the builder or manufacturer.

In such instances, prior authorization for the auditor’s access will be sought by the local ABS office.

13 Submission of Plans Typical documentation that is required to be submitted for drilling system, subsystems, equipment, and/or components for the ABS Classification process is provided in Subsection 2/7 of this Guide.

i) Section 4 provides the ABS approval process for drilling systems, subsystem, equipment, and/or components. Subsequently, Section 4, Table 1 identifies the typical drilling system, subsystems, equipment, and/or components that are part of the ABS Classification process.

ii) Drilling system, subsystem, equipment and/or component-related drawings, calculations and documentation are required to be submitted to ABS by entities as listed in Subsection 2/7 of this Guide to substantiate that the design of the systems, subsystems, equipment and/or components are in compliance with this Guide, and applicable codes or standards, as listed in this Guide.

iii) Upon satisfactory completion of ABS review of design plans and data, ABS Engineers will issue an ABS approval letter and an Independent Review Certificate (IRC), as specified in Section 4, Table 1 of this Guide. This letter or certificate, in conjunction with ABS approved documentation, will be used and referenced during surveys. Subsequently, the ABS Surveyor will issue appropriate survey reports.

iv) Upon satisfactory completion of all of the required engineering design review and survey processes (inspection, testing, installation and commissioning), ABS will issue the Classification Certificate to the operating unit, including the Class notation À CDS (abbreviation for Classed Drilling System).



15 Conditions for Survey After Construction

15.1 Damage, Failure and Repair 15.1.1 Examination and Repair

i) Damage, failure, deterioration or repair to the drilling system, subsystems, equipment, and/or components which affects Classification is to be submitted by the Owner/Operator or their representatives for examination by the Surveyor at the first opportunity.

ii) All repairs found necessary by the Surveyor are to be carried out to the Surveyor’s satisfaction.

15.1.2 Repairs i) Where repairs to the drilling system, subsystems, equipment, and/or components which

may affect Classification are planned in advance to be carried out, a complete repair procedure including the extent of the proposed repair and the need for Surveyor’s attendance is to be submitted to and agreed upon by the Surveyor reasonably in advance.

ii) Failure to notify ABS in advance of the repairs may result in suspension of the drilling system’s Classification until such time as the repair is redone or evidence is submitted to satisfy the Surveyor that the repair was properly carried out.

15.1.3 Representation Nothing contained in this section or in a Rule or regulation of any government or other administration, or the issuance of any report or certificate pursuant to this section or such a Rule or regulation, is to be deemed to enlarge upon the representations expressed in 1/1.1 through 1/1.7 hereof, and the issuance and use of any such reports or certificates are to be governed in all respects by 1/1.1 through 1/1.7 hereof.

15.1.4 Temporary Installation, Maintenance, Modification, Repair or Replacements 15.1.4(a) Temporary Installation

i) ABS is to be notified of the Owner/Operator’s intention to install temporary equipment that can affect the safety or intended functioning of the classed drilling system.

ii) The installation of temporary equipment is to be no less effective than permanent drilling system equipment.

iii) ABS reserves the right to approve such equipment and is to be advised of temporary installations.

15.1.4(b) Maintenance

i) When the subsystems, equipment, and/or components of the drilling system are subject to annual maintenance or inspections due to repairs by qualified personnel on the drilling unit or by an authorized company/manufacturer offshore or onshore, ABS is to be notified for survey of the subsystems, equipment, and/or components preferably before it is placed into service (see Subsection 9/3).

ii) These surveys will be carried out in accordance with API requirements or other recognized codes/standards referenced in this Guide and is to be considered part of ABS’s Annual Survey for Drilling Systems.

15.1.4(c) Modification. Where a major modification or replacement is made to subsystems, equipment, and/or components that are part of a classed drilling system, ABS is to be notified and the applicable requirements of this Guide are to be met.

15.1.4(d) Repair or Replacement. When any subsystems, equipment, and/or component of the drilling system is replaced, modified, repaired or undergone maintenance which may affect Classification, relevant documents are to be included in a drilling system log for Surveyor’s verification during periodical surveys.



15.3 Notification and Availability for Survey The Surveyors are to have access to classed drilling systems, subsystems, equipment, and/or components at all reasonable times.

i) For the purpose of Surveyor monitoring, the attending Surveyors are also to have access to classed drilling systems, subsystems, equipment, and/or components at all reasonable times. Such access may include attendance at the same time as the assigned Surveyor or during a subsequent visit without the assigned Surveyor.

ii) The Owner/Operator or their representatives are to notify the Surveyors for inspection on occasions when the units on which the drilling systems are installed are in dry dock or on a slipway.

iii) The Surveyors are to undertake all surveys on classed drilling systems, subsystems, equipment, and/or components upon request, with adequate notification, of the Owner/Operator or their representatives, and are to report thereon to the Committee.

iv) Should the Surveyors find occasion during any survey to recommend repairs or further examination, notification is to be given immediately to the Owner/Operator or their representatives so that appropriate action may be taken.

v) The Surveyors are to avail themselves of every convenient opportunity for carrying out periodical surveys in conjunction with surveys of damages and repairs in order to avoid duplication of work.

17 Units This Guide is written in three systems of units, viz., SI units, MKS units and US customary units. Each system is to be used independently of any other system. Unless indicated otherwise, the format of presentation of the three systems of units in this Guide is as follows:

SI units (MKS units, US customary units)

19 Fees Fees in accordance with normal ABS practice will be charged for all services rendered by ABS. Expenses incurred by ABS in connection with these services will be charged in addition to the fees. Fees and expenses will be billed to the party requesting that particular service.

21 Disagreement

21.1 Rules and Guides Any disagreement regarding either the proper interpretation of Rules and Guides or the translation of Rules and Guides from the English language edition is to be referred to ABS for resolution.

21.3 Surveyor In case of disagreement between the Owner/Operator or builders and the Surveyors regarding the material, workmanship, extent of repairs or application of the Rules and Guides relating to any system classed or proposed to be classed by ABS, an appeal may be made in writing to the Committee, who will order a special survey to be held. Should the opinion of the Surveyor be confirmed, expense of this special survey is to be paid by the party appealing.



23 Limitation of Liability The combined liability of the American Bureau of Shipping, its committees, officers, employees, agents or subcontractors for any loss, claim or damage arising from its negligent performance or nonperformance of any of its services or from breach of any implied or express warranty of workmanlike performance in connection with those services, or from any other reason, to any person, corporation, partnership, business entity, sovereign, country or nation, will be limited to the greater of a) $100,000 or b) an amount equal to ten times the sum actually paid for the services alleged to be deficient.

The limitation of liability may be increased, up to an amount twenty-five times the sum paid for services, upon receipt of Client’s written request at or before the time of performance of services, and upon payment by Client of an additional fee of $10.00 for every $1,000.00 increase in the limitation.

25 References In addition to the ABS Rules, and Guides as listed in 1/7.1, the additional requirements of the following Guides, codes or standards are referenced in this Guide:

• ABS Guidance Notes on Review and Approval of Novel Concepts (Novel Concepts Guide)

• ABS Guide for Risk Evaluations for the Classification of Marine-Related Facilities

• ABS Guidance Notes on Risk Assessment Applications for the Marine and Offshore Oil and Gas Industries

• ABS Guide for Well Test Systems

• ABS Guide for Certification of Lifting Appliances

• ABS Guide for Surveys Using Risk-Based Inspections for the Offshore Industry(RBI Guide)

• ABS Guide for Surveys Based on Reliability-Centered Maintenance (RCM Guide)

• AGMA – American Gear Manufacturers Association

• AISC – American Institute of Steel Construction

• ANSI – American National Standards Institute

• API – American Petroleum Institute

• ASME – American Society of Mechanical Engineers

• ASNT – American Society for Nondestructive Testing

• ASTM – American Society for Testing and Materials

• AWS – American Welding Society

• IEC – International Electrotechnical Commission

• IEEE – Institute of Electrical and Electronic Engineers

• IACS – International Association of Classification Societies

• ISO – International Organization for Standardization

• NACE – National Association of Corrosion Engineers

• NEMA – National Electrical Manufacturers Association

• NFPA – National Fire Protection Association

• NFPA – National Fluids Power Association

• SAE – Society of Automotive Engineers

• SPE – Society of Petroleum Engineers

• UL – Underwriters Laboratory

ABS is prepared to consider other recognized codes, standards, alternative design methodology and industry practice, on a case-by-case basis, with justifications as indicated in 1/7.7 of this Guide.



27 Definitions The following definitions are provided to clarify the use of certain terms in the context of this Guide:

Accumulator: A pressure vessel charged with high pressure air or nitrogen gas and used to store hydraulic fluid under pressure for operation of blowout preventers.

Acoustic Control Systems: Acoustic signal transmission may be used as an emergency backup means for controlling critical BOP stack functions, such as pipe ram preventers, shear ram preventer and marine drilling riser connector including LMRP. The acoustic control system includes a surface electronics package, acoustic pod transponder, subsea electronic package and a subsea electro-hydraulic package.

Acoustic Pod Transponder: Device which receives acoustic signals from the surface and provides command signals to the subsea BOP control system.

Actuator: A mechanism for the remote or automatic operation of a valve or choke.

Annular Blowout Preventer: A device typically installed above the ram preventers used to control wellhead pressure. A reinforced rubber packing element is compressed by hydraulic pressure to actuate the device to seal. A standard annular BOP will shut off annular pressure, open-hole pressure and afford stripping of tubing/drill pipe while containing well pressure.

Autoshear System: A safety system that is designed to automatically shut-in the wellbore in the event of a disconnect of the LMRP. When the autoshear is armed, disconnect of the LMRP closes the shear rams on BOP stack.

Auxiliary Line: A conduit (excluding choke and kill lines) attached to the outside of the drilling riser main tube (e.g., hydraulic supply line, buoyancy control line, mud boost line).

Backpressure (Casing Pressure, Choke Pressure): The pressure existing at the surface on the casing side of the drill string/annulus flow system.

Backup: An element or system that is intended to be used only in the event that the primary element or system is nonfunctional.

Blind Rams: See “Rams”

Blind-shear Rams: See “Rams”

Blowout: An uncontrolled flow of well fluids/gas and/or formation fluids/gas from the wellbore to the surface or into lower pressured subsurface zones (underground blowout).

Blowout Preventer (BOP): The equipment installed at the wellhead to prevent the escape of fluids under pressure either in the annular space between the casing and drill pipe or in an open hole during drilling and completion operations.

Blowout Preventer (BOP) Handling Crane: Gantry-type crane used to move BOP from storage location to BOP transporter/skidder location.

Blowout Preventer (BOP) Operating and Control System: System of pumps, valves, accumulators, fluid storage and mixing equipment, manifold, piping, hoses, control panels and other items necessary to hydraulically operate the BOP equipment.

Blowout Preventer (BOP) Assembly: The complete assembly of BOP stack, frame, accumulators, pods, valves, piping, connectors, jumpers, control systems, ROV interface panels, control piping, etc.

Blowout Preventer (BOP) Stack: The complete assembly of well control equipment including preventers, spools, valves, and nipples connected to the top of the casinghead.

Blowout Preventer (BOP) Stack Frame: Steel frame to which the lower stack is mounted for handling and mating with LMRP. Also serves as a support structure to mount various subsea equipment, such as subsea accumulators and control pods.

Blowout Preventer (BOP) Transporter/Skidder: C-frame or fork-lift type trolley used to position the BOP for deployment on the riser. May include integrated test stump.



Buffer Tank: A targeted, horizontal or vertical, cylindrical tank that changes the direction of fluid flow downstream of the choke and serves as a flow director to the flare line, gas buster or mud-gas separator.

Bulk Storage: Tanks that are designed for storage of bulk materials for drilling fluid and cement mixing (barite, bentonite, cement, etc.).

Buoyancy Equipment: Devices added to riser joints to reduce their apparent weight, thereby reducing riser top tension requirements.

Burner Boom: Boom which extends over the deck edge to flare hydrocarbon from kick circulation or well test operations.

Casinghead/Spool: The part of the wellhead to which the BOP stack is connected.

Casing Stabbing Board: Folding platform located in the derrick which positions the stabbing hand (pipe stabber) while running casing. Similar to monkey board, but at a lower height.

Catastrophic Release: Major hydrocarbon release that results from uncontrolled developments and that may lead to serious danger to personnel, asset, and environment.

Catwalk Ramp (Riser Skate): Combination conveyer and lifting riser transport system used to move riser sections, drill pipes, casing or tool joints from deck storage to the drill floor.

Cementing Manifold: Used to direct high pressure cement through the cement standpipe.

Cement Pump: High pressure positive-displacement-type pump used for cementing operations, often connected to the kill line for emergency kill operations, usually smaller capacity than mud pump.

Choke: A device with either a fixed or variable orifice used to control the rate of flow of liquids and/or gas. Chokes are also used to control the rate of the flow of drilling mud out of the hole when the well is closed in with the blowout preventer and a kick is being circulated out of the hole.

Choke Line: The high-pressure piping (flexible lines, rigid piping, valves, connectors, fittings, etc.) between the mud pumps and BOP outlets or wellhead outlets.

Choke Line Valve: The valve(s) connected to and a part of the BOP stack that allows fluids flow to the choke manifold.

Choke Manifold: An assembly of valves, chokes, gauges, and piping components through which drilling fluid is circulated when the blowout preventer is closed to control the pressure encountered during a kick.

Clamp Connection: A pressure sealing device used to join two items without using conventional bolted flange joints. The two items to be sealed are prepared with clamp hubs. These hubs are held together by a clamp containing minimum of four bolts.

Classified Area: A location in which flammable gases or vapors are or may be present in the air in quantities sufficient to produce explosive or ignitable mixtures (see the MODU Rules, API RP 500 or API RP 505 for additional details).

Closing Unit: The assembly of pumps, valves, lines, accumulators, and other items necessary to open and close the BOP equipment.

Computer-Based Systems: Programmable Logic Solvers (PLC), Distributed Control Systems (DCS), PC or server-based computation systems and any E/E/PES. In most situations, hydraulic and/or pneumatic medium is controlled by the computer-based control system.

Control Panel/Console: Main operator interface for various installation systems (may be hydraulic, electric, electronic, mechanical, pneumatic, or any combination thereof).

Control Manifold: An assembly of valves and piping to control the flow of hydraulic fluid to operate the various components of systems, equipment or components.

Control Panel, Remote: A panel containing a series of controls that will operate the valves on the control manifold from a remote point.

Control Pod: An assembly of subsea valves and regulators that when activated from the surface will direct hydraulic fluid through special apertures to operate the BOP equipment.



Control Stations: Spaces containing the following, as applicable:

• Radio or main navigation equipment

• Central process control rooms

• Dynamically positioning control system

• Centralized ballast control station

• Battery room

• Fire control equipment and fire recording

• Fire extinguishing system serving various locations

• Emergency source of power

• CO2 bottle room

• Fire pumps

Crown: Upper sections of the derrick

Crown Block: Assembly of sheaves mounted at the derrick top (crown) through which the drilling line is reaved.

Deadman System: A safety system that is designed to automatically close the wellbore in the event of a simultaneous absence of hydraulic supply and signal (control and communication) transmission capacity in both subsea control pods.

Degasser: Device used to remove entrained gas from a drilling fluid in normal well circulation.

Desander: Centrifugal device for removing sand from drilling fluid.

Desilter: Centrifugal device used for removing silt from drilling fluid.

Deadline Anchor: Device to securely fasten one end of drill line to the drill floor or derrick structure.

Derrick (Mast): Main load-bearing structure in drilling unit used as support structure for the drill string, and top drive assembly.

Design Approved Products (PDA): See 1-1-A2/5.1.3 of the ABS Rules for Conditions of Classification – Offshore Units and Structures (Part 1).

Design Pressure: The pressure used in the design of pressure-retaining equipment or piping systems for the purpose of determining the minimum permissible thickness or physical characteristics of the different parts of the pressure-retaining equipment or piping systems. When applicable, static head and other external loads (e.g., bending, torsional, tension, compression, temperature gradient, etc.) are to be added to the design pressure to determine the thickness of any specific part of the pressure-retaining equipment or piping systems.

Diverter: A device attached to the wellhead or marine drilling riser to close the vertical access in order to prevent upward flow of well fluids and direct flow into a line away from the rig floor.

Diverter Control System: The assemblage of pumps, accumulator bottles, manifolds, control panel, valves, lines, etc., used to operate the diverter system.

Diverter System: The assemblage of an annular sealing device, flow control means, vent system components, and control system that facilitates closure of the upward flow path of well fluids and opening of the vent to atmosphere.

Diverter Vent Line/Diverter Piping: The conduit which directs the flow of gas and wellbore fluids away from the drill floor to the atmosphere.

Drape Hoses (Moonpool Line): A flexible line connecting a choke, kill, and auxiliary line terminal fitting on the telescopic joint to the appropriate piping on the rig structure. A U-shaped bend in this line allows for relative movement between the vessel and the outer barrel of the telescopic joint as the vessel moves.

Drawworks: Large winch located on the drill floor used to raise and lower the drill string, top drive assembly by taking in or paying out the drilling line through the crown block and traveling block.

Drill Floor Substructure: The foundation structure(s) on which the derrick, rotary table, drawworks, and other drilling equipment are supported.

Drill Pipe Safety Valve: A full-opening valve located on the rig floor with threads to match the drill pipe connections in use. This valve is used to close off the drill pipe to prevent flow from the well.



Drilling Spool: A fitting placed in the blowout preventer stack with internal diameters at least equal to the bore of the BOP to provide space between preventers with smaller side outlets for facilitating stripping and other operations, to permit attachment of choke and kill lines, and for localizing possible erosion by fluid flow to the spool.

Dump Tank: Calibrated tank used to measure the volume of a liquid, may be drilling mud or reservoir fluids.

Electrical Control System: Control systems that are based on relays and analog discrete components without a central processor unit. Manual switches, relays and potentiometers are used for control of the equipment. In most situations, hydraulic and/or pneumatic medium is controlled by the electrical control system.

Elevator, Drilling: Hinged clamp-type device used to grasp drill pipe or casing for lifting by the drilling hook, may be either manually or hydraulically/pneumatically operated.

Elevator, Personnel: Lifting device used for rig personnel, may be on or off the drill floor.

Equipment: Mechanical and structural components of the drilling systems.

Escape Routes: Designated path used by personnel to evade an immediate danger and ultimately leads to a temporary refuge or muster station.

Finger Board: A rack located in the derrick that supports the top of the stands of pipe stacked in the derrick.

Fill-up Valve: A special riser joint having a valve means to allow the riser annulus to be opened to the sea. To prevent riser pipe collapse, an automatic actuator controlled by a differential-pressure sensor may open the valve.

Flammable Fluid: Any fluid, regardless of its flash point, capable of feeding a fire. Examples are diesel fuel, hydraulic oil (oil-based), lubricating oil, crude oil, or hydrocarbons.

Flash Point: The minimum temperature at which a combustible liquid gives off vapor in sufficient concentration to form an ignitable mixture with air near the surface of the liquid or within the vessel used, as determined by the test procedure and apparatus specified in NFPA 30.

Flex Joint: A steel and elastomer assembly having central through-passage equal to or greater in diameter than the riser bore that may be positioned in the riser string to reduce local bending stresses.

Flexible Lines/Hydraulic Hoses: Conduits that can accommodate the relative motion, and/or vibration encountered on drilling facility and use to transfer fluids (mud, cement, hydraulic fluids, etc.). Typical uses for flexible lines and/or hydraulic hoses within the drilling facility are:

• Rotary and vibratory hoses

• Cementing hoses

• Choke and kill flexible lines, and auxiliary lines (drapes and jumpers)

• Hydraulic hoses for control functions and operations

Floating Installation: An offshore facility designed to provide hydrocarbon processing and/or hydrocarbon storage, and offload hydrocarbons. The term is used to generically identify a buoyant facility that is site-specific. The installation is securely and substantially moored so that it cannot be moved without a special effort.

Gimbal: Shock absorbing support for the riser spider which allows some angular movement of the spider and riser relative to the rig support structure.

Gooseneck: Curved connection between the rotary hose and the swivel or top drive.

Hazardous Area: See “Classified Areas”.

Heave: Vessel motion in the vertical direction due to marine environment.

Hook, Drilling: Hook-shaped lifting device attached to the traveling block from which the swivel (or top drive) is suspended.

Hydraulic Cylinder: Mechanical device used to convert hydraulic fluid pressure to linear action.



Hydraulic Hoses: Conduits that can accommodate the relative motion, and/or vibration encountered on a drilling facility and used to transfer fluid for hydraulic system functions.

Hydraulic Power Unit (HPU): Skid-mounted systems used to provide hydraulic power, usually comprised of a hydraulic fluid reservoir, filters, hydraulic pump, motor and control.

Hydrogen Sulfide (H2S): A highly toxic, flammable, corrosive gas sometimes encountered in hydrocarbon-bearing formations.

Hydrogen Sulfide Service: Refers to equipment designed to resist corrosion and hydrogen embrittlement caused by exposure to hydrogen sulfide.

Ignitable Mixture: A mixture that is within the flammable range (between the upper and lower limits) and is therefore capable of propagation of flame away from the source of ignition.

Inside Blowout Preventer (IBOP): Backpressure or check valve installed in drill string to prevent a blowout inside the drill string. Flow is possible only downward, allowing mud to be pumped in but preventing any flow back up the drill string.

Iron Roughneck: Tool with automated combination of spinning and torqueing for make-up or break-down of drill string pipes during drilling operation.

Jumper Line: A flexible section of choke, kill, or auxiliary line that provides a continuous flow around a flex/ball joint while accommodating the angular motion at the flex/ball joint.

Kelly: The uppermost component of the drill string; the kelly is an extra-heavy joint of pipe with flat or fluted sides that is free to move vertically through a “kelly bushing” in the rotary table; the kelly bushing imparts torque to the kelly and thereby the drill string is rotated.

Kelly Bushing: Device which imparts torque to the kelly from the master bushing and permits vertical movement of the kelly.

Kelly Cock: A valve immediately above the kelly that can be closed to confine pressures inside the drill string.

Kelly Spinner: Pneumatically-operated device mounted to the top of the kelly used to spin up the kelly for making connections on a rotary table-type rig.

Kelly Valve, Lower: An essentially full-opening valve installed immediately below the kelly, with outside diameter equal to the tool joint outside diameter.

Kick: Unscheduled, unwanted entry of water, gas, oil or other formation fluid into wellbore. It occurs because pressure exerted by column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation drilled. If prompt action is not taken to control the kick or kill the well, a blowout will occur.

Kill: In drilling/well servicing, to prevent a threatened blowout by taking suitable preventative measures (e.g., to shut in well with blowout preventer, circulate kick out, and increase weight of drilling/completion/ workover fluid).

Kill Line: The high-pressure piping (flexible lines, rigid piping, valves, connectors, fittings, etc.) between the pumps (cement or mud pumps) and BOP outlets or wellhead outlets.

Kill Unit: Control panel for choke manifold.

Links, Drilling (Bell Nipple): Strong rods which connect the drilling elevators to the hook and allow movement for the elevator to be pushed out of the way when not in use.

Lower Explosive Limit (L.E.L.): The lowest concentration of combustible vapors or gases, by volume in mixture with air, which can be ignited at ambient conditions.

Lower Marine Riser Package (LMRP): Part of the blowout preventer stack assembly; usually contains LMRP connector, one or more annular-type preventers, lower flex joint, riser adapter, and MUX control pods.

Lower Marine Riser Package (LMRP) Connector: Hydraulic connector used to securely latch the LMRP to the BOP stack.



Lower Marine Riser Package (LMRP) Frame: Structural frame which is used for handling of the LMRP and integration with the BOP stack. It also serves as a support structure to mount various subsea equipment such as subsea accumulators and control pods.

Machinery Spaces (other than Category A): All spaces containing machinery, boilers, and other fired processes, oil fuel units, steam and internal combustion engines, generators, and major electrical machinery, oil filling stations, refrigerating, stabilizing, ventilation, and air-conditioning machinery and similar spaces.

Machinery Spaces of Category A: All spaces which contain internal combustion-type machinery used either: • For main propulsion; or

• For other purposes where such machinery has in the aggregate a total power of not less than 375 kW; or

• Which contain any oil-fired boiler or oil fuel unit; and trunks to such spaces.

Manifold: An accessory system of piping to a main piping system (or another conductor) that serves to divide a flow into several parts, to combine several flows into one, or to reroute a flow to any one of several possible destinations.

Manriding Winch: Winch used solely for personnel lifting operations.

Marine Drilling Riser System: The extension of the well bore from the subsea BOP stack to the floating drilling vessel which provides for fluid returns to the drilling vessel, supports the choke, kill, and control lines, booster lines, auxiliary lines, guides tools into the well, and serves as a running string for the BOP stack.

Master Bushing: Device which imparts torque from the rotary table to the kelly bushing and accepts the slips.

Maximum Allowable Working (Operating) Pressure (MAWP) or Rated Working Pressure (RWP): The maximum internal pressure equipment or system is designed to operate or work and to contain and/or control the pressure.

Minimum Design Temperature (MDT): The lowest predictable metal temperature occurring during normal operation including start-up, shut-down and ambient situation is to be used.

Mud Agitator: Motor-driven paddle or blade to mix, or maintain mixture of, drilling mud in the mud pits.

Mud Boost Line: An auxiliary line which provides supplementary fluid supply from the surface and injects it into the riser at the LMRP to assist in the circulation of drill cuttings up the marine drilling riser, when required.

Mud-Gas Separator: A vessel for removing free gas from the drilling fluid returns, generally used when circulating a gas kick out of the well.

Mud Pump: Large high-pressure pump used to circulate drilling fluid, usually positive-displacement type.

Multiplex (MUX) Control System: A system utilizing electrical or optical conductors in an armored subsea umbilical cable such that, on each conductor, multiple distinct functions are independently operated by dedicated serialized coded commands.

Nonhazardous Areas (Unclassified Locations): Locations determined to be neither “hazardous areas” nor “classified areas” (see Classified Area” for definition).

Operating Conditions: A set of conditions (e.g., pressure, temperature, flow rates, composition, loads, etc.) chosen for normal operation of a facility, system, or equipment.

Personnel Basket: Device in which personnel ride in during lifting operations in personnel cranes, elevators, and man-riding winches.

Pipe Rams: See “Rams”.

Power Slips: Automated slips controlled by the driller, usually hydraulically or pneumatically operated.

Power Tongs: Automated tongs used to torque drill pipe to final torque or to breakout pipe connections.

Process Area: Area where processing equipment is located to handle hydrocarbon. This includes wellhead/manifold areas, well testing equipment.

Pulsation Dampeners: Chambered device used to dampen pressure pulsations in a fluid flow.



Pup Joint: A shorter-than-standard-length riser joint, tool joint, or drill pipe.

Rams: Mechanical device use for closing, shearing and sealing component of a blowout preventer. One of three types – blind, shear, or pipe – may be installed in several preventers mounted in a stack on top of wellbore.

• Blind rams: Blind ram ends are not intended to seal against any drill pipe or casing. The rams seal against each other to effectively close the hole.

• Shear rams:

- Shear rams (non-sealing): Shear rams have a built-in cutting edge that will shear tubular that may be in the hole.

- Blind-shear rams: Blind rams with a built-in cutting edge that will shear against any drill pipe or casing. They seal against each other to effectively close the hole.

- Super shear ram: Shear rams that are capable to shear drill collars and large diameter casing. These rams are also capable of shearing heavy wall drill pipe and tool joints. The super shear rams are non-sealing rams.

• Pipe ram is a sealing component with an indentation and packing for drill pipe, drill collars or casing that closes the annular space between the pipe and the blowout preventer or wellhead. Separate rams are necessary for each size (outside diameter) pipe in use. Pipe rams can include:

- Fixed bore pipe ram: Closing and sealing component in a ram blowout preventer that is capable of sealing only specified tubular size

- Variable bore pipe ram: Closing and sealing component in a ram blowout preventer that is capable of sealing on a range of tubular sizes

Rated Setback Load: The maximum weight of tubular goods which can be supported by the substructure in the setback area.

Rated Working Pressure (RWP) or Maximum Allowable Working (Operating) Pressure (MAWP): The maximum internal pressure equipment or system is designed to operate or work and to contain and/or control the pressure.

Remotely Operated Vehicle (ROV): An unmanned vehicle for offshore subsea use.

Reels (MUX, Hotline): Large spool and winch system used to store, deploy and retrieve flexible lines.

Riser Adapter: Crossover between riser and flex/ball joint.

Riser Joint: A section of riser main tube having flanged connector (or equivalent ) ends fitted with a box and pin and including choke, kill and (optional) auxiliary lines, booster lines, and their support brackets.

Riser Running/Handling Tool: A device that joins to the upper end of a riser joint to permit the lifting and lowering of the joint and the assembled riser string in the derrick by the elevators.

Riser Spider – Fixed: A device having retractable jaws or dogs used to support the riser string on the uppermost coupling support shoulder during deployment and retrieval of the riser.

Riser Spider – Elevator: Riser spider that is capable of being used as elevators.

Riser Tensioners: Systems for providing and maintaining top tension on the deployed riser string to prevent buckling.

Riser Tensioner Ring: The structural interface of the telescopic joint outer barrel and the riser tensioners. The tensioner ring may be an integral part of the telescopic joint.

Rotary Hose (also known as Kelly Hose): Flexible hose which conducts high-pressure drilling fluids from the standpipe to the gooseneck/swivel and kelly or top drive.

Rotary Swivel: A device hanging on the traveling hook that allows the drill string to rotate while hanging and provide path for fluids flow.



Rotary Table: A device through which passes the bit and drill string and that transmits rotational action to the kelly.

Rupture (or Bursting) Disc: A device designed to rupture or burst and relieve pressure at a defined pressure and rate. The device will not close after being activated.

Safe Working Load (SWL): The maximum rated load within the lifting appliance rated capacity for the given operating conditions.

Safety Factor: The relationship between maximum allowable stress level and a defined material property, normally specified minimum yield strength.

Safety Shutdown: A safety system action that will be initiated upon signal or failure and is to result in shutdown of systems, subsystems, equipment, component, or part of the facility.

Safety System: Electronic or electrical or mechanical system installed to execute protective measures based on a predefined logic to bring an undesirable event under control based on manual or automatic execution or to monitor critical parameters and initiate alarms.

Shale Shaker: Any of several mechanical devices utilizing screens and vibration that remove cuttings and other large solids from drilling fluid.

Shear Rams: See “Rams”.

Sheaves: Grooved pulley for use with wire rope.

Shut-in: A condition resulting from a shutting-in of the wellbore caused by the occurrence of one or more undesirable events and/or actions of the safety shutdown.

Spudding: The start of drilling the subsea well.

Subsystem: An assembly of interconnected or interrelated parts that performs tasks as a component as a subset of a system.

System: An assembly of various subsystems combing in to a unified whole.

Surveyor: ABS’s representative on location to perform examination or inspection activities.

Survival Condition: Condition during which a unit may be subjected to the most severe environmental loading for which the unit is designed. Drilling or similar operations may have been discontinued due to the severity of the environmental loading. The unit may be either afloat or supported on the sea bed, as applicable.

Telescopic Joint (Slip Joint): A riser joint having an inner barrel and an outer barrel with sealing means between. The inner and outer barrels of the telescopic joint move relative to each other to compensate for the required change in the length of the riser string as the vessel moves due to marine environment.

Tensioning Unit: Main operator interface for riser tensioning system.

Test Pressure: The pressure at which the component or system is tested to verify structural and pressure integrity.

Test Stump: Stump with wellhead profile used to support the BOP during surface pressure test operations. Also used during BOP storage.

Top Drive (Power Swivel): A device used to support, drive and rotate the drill string and drilling tools in or out of the well, may be either electrically or hydraulically powered.

Transit Condition: Unit movements from one geographical location to another.

Traveling Block: Set of sheaves which move up and down in the derrick as drilling line is paid out or taken in.

Trip: The operation of hoisting the drill string from and returning it to the wellbore.

Trip Tank: Small mud tank used to keep track of the volume of mud displaced by the drill string during “trip in” and “”trip out”

Type Approval: See Appendix 1-1-A2 of the ABS Rules for Conditions of Classification – Offshore Units and Structures (Part 1).



Uninterruptible Power Supply (UPS): Device supplying output power in some limited time period after loss of input power with no interruption of the output power.

Umbilical: A control hose bundle or electrical cable that runs from the reel onto the control pod on the LMRP.

Upset Condition: A condition that occurs in a system, subsystem, equipment or component when an operating variable deviates substantially from its normal operating limits. If left unchecked, this condition will result in a threat to safety, or undesirable events, and may cause shutting-in of system, subsystems, equipment or component.

Utility Systems: Various systems providing the supporting functions to the drilling operations. Typical utility systems are cooling water, hot oil for heating, chemical systems for injection, hydraulic, potable water, nitrogen generation and system, instrument air and power generation system, etc.

Wellhead Connector: Hydraulic connector used to securely latch the lower BOP stack to the wellhead.

Wire Rope: Cable composed of steel wires twisted around a central core of wire or fiber.

Wireline Spoolers: System consisting of a drum, motor and control system used for running or retrieving wireline. Often skid-mounted, may be electrically, pneumatically or hydraulically operated.

Working Load: The mass of the load lifted plus the mass of the accessories (e.g., sheave blocks, hooks, slings, etc.).

29 Acronyms and Abbreviations The following acronyms and abbreviations are used in this Guide:

• AHC Active Heave Compensation

• BHA Bottom Hole Assembly

• BOP Blowout Preventer

• CoC Certificate of Conformity

• CPU Central Processing Unit

• CTOD Crack-tip Opening Displacement

• CVN Charpy V-Notch

• DCS Distributed Control Systems

• E/E/PES Electric, Electronics, Programmable Electronics

• ESD Emergency Shutdown

• FMEA Failure Modes and Effects Analysis

• FMECA Failure Modes and Effects Criticality Analysis

• H2S Hydrogen Sulfide

• HAZ Heat-Affected Zone

• HAZOP Hazard and Operability

• HAZID Hazard Identification

• HCR Hydraulic Control Remote

• I/O Input / Output

• IRC Independent Review Certificate

• IBOP Internal Blowout Preventer

• ITP Inspection and Test Plans



• LEL Lower Explosive Limits

• LMRP Lower Marine Riser Package

• LP Liquid Penetrant Examination

• MT Magnetic Particle Examination

• MAC Manufacturer’s Affidavit of Compliance

• MASP Maximum Anticipated Surface Pressure

• MAWP Maximum Allowable Working (Operating) Pressure

• MDT Minimum Design Temperature

• MRN Maintenance Release Note

• MTR Material Test Report

• MUX Multiplex Systems

• NDE Nondestructive Examination

• NDT Nil Ductility Transition

• P&ID Piping and Instrumentation Diagram

• PO Purchase Order

• PDA Design Approved Product

• PHC Passive Heave Compensation

• PLC Programmable Logic Solvers

• PPM Parts per Million

• PQR Procedure Qualification Record

• RT Radiographic Examination

• RWP Rated Working Pressure

• ROV Remotely Operated Vehicles

• SMYS Specified Minimum Yield Strength

• SSL Structural Safety Level

• SWL Safe Working Load

• UT Ultrasonic Examination

• UTS Ultimate Tensile Strength

• VIV Vortex-Induced Vibration

• WP Working Pressure

• WPS Weld Procedure Specification


Section 2: Design of Drilling Systems

S E C T I O N 2 Design of Drilling Systems

1 Design of Drilling System

1.1 General The designer of the drilling system is to evaluate the system as a whole, considering the interfacing and interdependence of subsystems.

The required design plans and data to be submitted for ABS design review and approval related to the drilling systems, subsystems, equipment, and/or components are listed in Subsection 2/7 and Section 4, Table 1 of this Guide.

1.3 Equipment Layout Equipment layout and work areas associated with the drilling activities are to be arranged with the following objectives:

i) Safety of personnel and operation

ii) Separation of nonhazardous areas from those classified as hazardous areas

iii) Separation of fuel and ignition source as far as practical

iv) Minimizing the likelihood of uncontrollable releases of hydrocarbon to the environment

v) Minimizing the spread of flammable liquids and gases which may result in a hazardous event and facilitating rapid removal of any accumulations

vi) Minimizing the probability of ignition

vii) Minimizing the consequences of fire and explosions

viii) Preventing fire escalation and equipment damage

ix) Providing for adequate arrangements for escape and evacuation

x) Facilitating effective emergency response

xi) Minimizing dropped objects hazards to personnel, equipment (on facility and subsea), and structure

xii) Protection of critical systems, subsystems, equipment and/or components from damage during drilling operation, such as:

• Electrical cables and cableways

• Well control equipment

• Exhaust ducting and air intake ducting

• Control and shutdown systems

• Safety systems, fire-gas detection, and fire-fighting equipment are to be arranged so that they are protected from damage during drilling operations.

xiii) Equipment arrangements are to provide access for inspection and servicing and safe means of egress from all machinery spaces.

xiv) The installation of electrical equipment within hazardous areas is to be in compliance with the MODU Rules. Combustion equipment and combustion engines are not to be located in hazardous areas.



xv) Equipment arrangement drawings are to show the location of all equipment, living quarters, all machinery spaces, tanks, derrick, wellheads/moon pool, flare and vents, escape route, evacuation equipment, air intake, opening to close spaces, and any fire and barrier walls.

xvi) Additional requirements related to general arrangement and equipment layout are also to consider the applicable requirements of the MODU Rules.

xvii) The equipment arrangement drawings are to indicate the hazardous areas throughout the facility, as defined in Section 4-3-6 of the MODU Rules.

1.5 Overpressurization Protection Systems, subsystems, equipment, and/or components that may have the potential of exposure to pressure greater than for which they are designed are to be protected by suitable pressure protection devices:

i) The drilling systems, subsystems, equipment and/or components that may have the possibility of overpressure are to be protected by suitable means, acceptable to ABS, such as relief valves, burst disk, fusible plug, etc., or the equivalent. The equipment will be reviewed for the specified design parameters, as specified in the applicable “Design Basis” in Subsection 2/7 of this Guide.

ii) It is to be the responsibility of the systems and equipment designers to specify and consider the most severe combination of pressure sources, such as formation pressure, pumps, flow restriction, static heads, hammer effects, fire and/or thermally-induced pressures, in the design and selection of suitable overpressure protection devices.

1.7 Materials The materials for each component are to be selected with consideration of their fitness for the intended service and in accordance with the applicable codes and standards as referenced in this Guide, in addition to the material requirements of Section 6 of this Guide.

The experience of the manufacturers, designers and related performance records will be specially considered in accordance with 1/7.7 of this Guide.

1.9 Welding and Nondestructive Examination General requirements for welding and nondestructive examination (NDE) are to be in accordance with Section 7 of this Guide.

3 Design Specifications The design specification for drilling systems, subsystems, equipment and/or components is to consider as a minimum, but not limited to, the most adverse combination of applicable loads listed in 2/5.7 and is to consist of design plans, drawings, data, and calculations, as outlined in Subsection 2/7, to substantiate the design.

i) In addition to the design specifications, the manufacturing specifications are to include material specifications, WPS/PQR, NDE, and testing procedures/specifications utilized in the manufacturing, installation, and commissioning of each system, subsystem, equipment, and/or component and are to comply with the applicable section of this Guide, in addition to the codes or standards used.

ii) Design plans and data are to be submitted for ABS approval of drilling systems, subsystems, equipment, and/or components, in accordance with Subsection 2/7 and the requirements of this Guide.

5 Design Considerations

5.1 Recognized Standards The submitted design is to be in accordance with the requirements of this Guide and the specified codes and standards as referenced herein.

i) Designs complying with other international or national standards not listed in Appendix 1 will be subject to special consideration in accordance with 1/7.7 of this Guide.

ii) ABS advises the designer/manufacturer to contact the ABS Technical office early in the design phase for acceptance of alternate design codes and standards.



iii) When alternate design codes and standards are proposed, justifications can be achieved through equivalency, gap analysis or appropriate risk analysis/philosophy to demonstrate that the proposed alternate design code and standard will provide an equivalent level of safety to the recognized standards as listed in this Guide and are required to be performed in accordance with 1/7.7 of this Guide.

5.3 Alternative Basis of Design Designs based on manufacturer’s standards may also be accepted. In such cases, complete details of the manufacturer’s standard and engineering justification are to be submitted for review.

i) The manufacturer will be required to demonstrate by way of testing or analysis that the design criteria employed results in a level of safety consistent with that of a recognized standard or code of practice.

ii) Where strain gauge testing, fracture analysis, proof testing or similar procedures form a part of the manufacturer’s design criteria, the procedure and results are to be submitted for ABS review.

iii) Historical performance data for drilling systems, subsystems, equipment or components is to be submitted for justification of designs based on manufacturer’s standards.

iv) ABS will consider the application of risk evaluations for alternative or novel features for the basis of design in accordance with 1/7.7 of this Guide, as applicable.

5.5 Corrosion/Erosion Allowance Where drilling systems (including piping systems), subsystems, equipment, and/or components are subjected to a corrosive, erosive or abrasive environment, the design is to include allowances for such extra material as required.

i) Alternative allowances will be considered when supplemented with technical justification. This justification can be in the form of previous documented experience or consideration of in-service thickness monitoring records, in which case, a detailed summary of the monitoring records is to be submitted for consideration.

ii) The amount of additional material needed will be determined based on the predicted rate of corrosion and/or erosion and the design service life of the component.

iii) In the absence of any standard allowance or submitted information, a corrosion allowance of 1.6 mm (0.0625 in.) is to be utilized or as justified by the designer/manufacturer.

5.7 Design Conditions The drilling systems, subsystems, equipment, and/or components are to be designed to account for all applicable environmental, operational, and test loads, or combination thereof. These include, but are not limited to, the following:

i) Environmental Conditions, as applicable

• Earthquake

• Ice

• Current, waves

• Wind

• Temperature

• 1, 10, 50, 100 year storm event, as applicable

ii) Operational

• Static pressure

• Transient pressure excursion

• Temperature excursion

• Tension

• Bending

• Vibration

• Acceleration loads due to movement of the drilling unit

• Retrieval

• Drifting

iii) Transportation



iv) Installation

v) Commissioning

vi) Storage and Maintenance

vii) Test Loads

7 Design Plans and Data The following paragraphs describe documentation and ABS approval requirements for Classing of drilling systems, subsystems, equipment, and/or components.

i) Section 4 of this Guide provides the general process for ABS approval of a drilling system. Subsequently, Section 4, Table 1, “Approval Codes for Drilling Systems and Equipment” identifies the typical drilling system, subsystems, equipment and/or components that require approval for ABS Classification of the drilling system.

ii) It should be noted that Section 4, Table 1 is provided as a general reference listing, and is not to be considered as the complete drilling system, subsystem, equipment or component listing. For drilling systems, subsystems, equipment or components not listed in Section 4, Table 1, the designer/ manufacturer should contact the appropriate ABS Technical office for guidance on technical and survey requirements and completion of the approval process.

iii) The manufacturer’s plans and data, as specified in Subsection 2/7 of this Guide, are to be generally submitted electronically to ABS. However, hard copies will also be accepted.

iv) All plan submissions originating from manufacturers are understood to be made with the knowledge of the main contracting party.

v) Design plans and data, as listed in Subsection 2/7 of this Guide, are expected to be submitted by the entity(ies) outlined in the table below. Depending on the contractual agreement between entities, the responsible party for design plans and data submittal may vary.

Submittal of Design Plans and Data Shipyard Owner/Operator/Designer Manufacturers

Drilling Systems General arrangement X X Well control X X Well circulation X X Pipe handling and lifting X X Interface details between systems and/or subsystems

X X

Marine interface X Electrical X Control X X X

Equipment Assembly details, etc. X X Subsystems X Components X Installation integration X

Note: Where multi-entities are indicated, any one entity or all entities may be responsible for the design plan and data submittals, dependent on contractual agreement between entities.



7.1 General Arrangement for Drilling System General arrangement plans are to provide the following information, as applicable:

i) General arrangement of the installation/facility where the drilling system and its machinery are installed

ii) Equipment layout, detailed arrangements and elevation drawings showing:

• Locations of all machinery, equipment, structures for drilling operations

• Piping systems associated with the drilling systems, support systems

• Locations of all control panels/stations for drilling systems, including all drilling support systems

• Locations of the fire and gas monitoring and fire fighting control locations

• Detailed arrangements of the well test areas or location of well test equipment

• Escape and egress routes, including their protections, and muster stations

• The locations of openings (air intake, exhaust, windows, doors, etc.) for all closed spaces

• Ventilation arrangements

iii) HAZOP and/or HAZID study reports for the drilling systems or subsystems

iv) Classified areas (hazardous areas) drawings and/or details identifying nonhazardous areas and hazardous areas in accordance with the MODU Rules, API RP 500 or API RP 505.

7.3 Well Control Systems and Equipment Typical well control systems and equipment are identified as follows:

• Blowout preventer (BOP) equipment

• Lower marine riser package (LMRP) for subsea well control

• Choke and kill equipment

• Marine drilling riser systems – See 2/7.5

• Diverter equipment

• Auxiliary well control equipment

7.3.1 Blowout Preventer Systems and Equipment Submit the following documentation for the well control systems, BOP systems and/or well control equipment, as applicable:

i) Design basis:

• Descriptions of the well control systems and equipment for surface and subsurface BOPs

• Design parameters: pressure rating, temperature rating (min/max)

• P&IDs and schematic diagrams

• Shutdown logic

• Details on hierarchy of control: primary, secondary, emergency, etc.

• Equipment technical specifications and data sheet

• Design references, codes, standards, or guidelines

ii) Failure Modes and Effects Analysis, FMEA [see 3/15.5.2(b)], Failure Modes, Effects and Criticality, FMECA [see 3/15.5.2(c)] or similar analysis for the complete integrated drilling systems and/or subsystems

iii) All control panel arrangements for well control of BOP systems



iv) Design and manufacturing details for BOP stack equipment to include preventers, drill spools, wellhead connectors, clamps, spacer spools, adapter spools, etc.:

• Design parameters: pressure rating (RWP/MAWP, or design pressure), temperature rating (min/max), loads, maximum water depth, service conditions, etc.

• Dimensional detailed drawings and fabrication details

• Material specifications and material properties

• Design analysis for pressure-retaining equipment

• Individual BOP (annular and ram) details. This is to include manufacturer documentation to specify and to attest BOP minimum and maximum capability with regard to:

- Drill pipe size

- Tool joints

- Casing

- Wire line, or

- Combination of the above

• Documentation to confirm the shear rams capability of shearing the various tubulars (sizes, grades, strengths, etc.) under the specified design conditions

• Prototype test data, as required by the design code

• Manufacturing specifications (see 2/7.27)

v) BOP stack assembly

• BOP stack configuration with individual annular and ram preventer details. This is to include manufacturer’s documentation to specify and to attest BOP stack minimum and maximum capability with regard to:

- Drill pipe size

- Tool joints

- Casing

- Wire line, or

- Combination of the above

• BOP stack assembly drawings for BOP systems showing:

- Stack configuration showing all equipment

- Structural frame details

- Lift points/attachments

- Arrangements showing accumulators, pods, valves, piping, connectors, jumper lines, etc.

• Design details and structural analysis for BOP structural frame and lifting attachments



vi) Control system details:

• Control panel and control equipment arrangements, showing locations on drilling unit

• See 2/7.19, “Control Systems”

vii) Subsea control pods drawings and associated calculations

viii) Pressure relief system: Arrangements, size, materials, back pressure and capacity calculations, as applicable

ix) Design details electrical systems and equipment:

• See 2/7.17, “Electrical Systems and Equipment”



x) Design details for pressure vessels, accumulators, cylinders:

• See 2/7.21, “Pressure-Retaining Equipment”

xi) Design details for piping, valves, and fittings:

• See 2/7.23, “Piping Systems and Piping Components”

xii) Design details for flexible lines and hydraulic hoses:

• See 2/7.25, “Flexible Lines/Hydraulic Hoses”

xiii) Manufacturing specifications (see 2/7.27)

xiv) Manufacturer’s affidavit of compliance (see 4/3.1.2)

7.3.2 Lower Marine Riser Package i) Design basis, including, as applicable:

• Descriptions of the lower marine riser package system

• Equipment technical specifications and data sheets

• Load cases and limit states for all design and operating conditions


• Design analysis methodology for the lower marine riser package, including computer modeling and computer program used

• Design analysis methodology of lower marine riser package, including loading parameters from global marine drilling riser analysis, computer modeling, and computer program used

ii) Design analysis of lower marine riser package mechanical-load bearing components (see 2/7.13) and pressure-retaining equipment (see 2/7.21), as applicable

iii) BOP annular preventers, adapter spools, and connector details, as applicable [see 2/7.3.1iv)]

iv) LMRP structural frame [see 2/7.3.1v)]

v) Material specifications, including material properties

vi) Prototype test data, as required by the design code

vii) Manufacturing specifications (see 2/7.27)

viii) Manufacturer’s affidavit of compliance (see 4/3.1.2)

7.3.3 Choke and Kill Systems and Equipment Typical choke and kill systems and equipment are identified as follows, as applicable:

• Choke and kill manifold and buffer tanks

• Chokes

• Flexible choke and kill lines, drape hoses, jumper hoses, mud boost and hydraulic hose

• Rigid choke and kill lines

• Swivel joints

• Union connections

• Drilling choke controls

• Valves: check valves, flow valves

• Crosses and tees

• Actuators: valves, drilling choke, or production choke

• Control system



i) Design basis:

• Descriptions of the choke and kill systems and equipment, including design parameters, pressure rating (internal/external), temperature rating (min/max.)


• Equipment arrangement details



ii) Design details electrical systems and equipment:


iii) Control system details:


iv) Design details for manifolds, pressure vessels, and tanks:


v) Design details for rigid piping, valves, and fittings:


vi) Design details for flexible lines:

• See 2/7.25, “Flexible Lines/Hydraulic Hoses”

vii) Prototype test data, as required by the design code

viii) Manufacturing specifications (see 2/7.27)

ix) Manufacturer’s affidavit of compliance (see 4/3.1.2)

7.3.4 Diverter Equipment i) Design basis:

• Descriptions of the diverter system and equipment, including design parameters, pressure rating (internal/external), temperature rating (min/max)




ii) Design details electrical systems and equipment:


iii) Control system details:


iv) Design details for manifolds:


v) Design details for piping, valves, and fittings:




viii) Manufacturer’s affidavit of compliance (see 4/3.1.2)



7.3.5 Auxiliary Well Control Equipment Typical auxiliary well control equipment include kelly valves, drill pipe safety valves, IBOP, drill string float valves, etc.

i) Design details for valves, and fittings (see 2/7.23)

ii) Manufacturing Specifications, as applicable (see 2/7.27)

iii) Manufacturer’s affidavit of compliance (see 4/3.1.2)

7.5 Marine Drilling Riser Systems Typical marine drilling riser subsystems and components include the following:

• Riser tensioning equipment

• Riser joints

• Riser couplings (connectors)

• Telescopic joints

• Pup joints

• Buoyancy devices

• Ball and flex joints

• Riser running equipment

• Riser recoil system

• Special equipment, including fill-up valves, mud boost system, drag reducing devices

Submit the following documentation for the marine drilling riser system and/or its components, as applicable:

i) Design basis, including, as applicable:

• Descriptions of the marine drilling riser system and its components (telescopic joint, flexible joint, connectors, etc.)



• Assumptions used in the global design analysis of the marine drilling riser system and design analysis of its components


• Design analysis methodology for the marine drilling riser system, including computer modeling and computer program used

• Design analysis methodology of marine drilling riser components, including loading parameters from global marine drilling riser analysis, computer modeling, and computer program used

• Support unit reports with information pertaining to any supporting units that affects the marine drilling riser system. Reports to include unit response amplitude operators (RAOs), physical layout of the drilling floor, derrick and pipe racks, and auxiliary lifting equipment

ii) Design analysis of marine drilling riser systems (global riser analysis)

iii) Design analysis of marine drilling riser system associated components, as referenced

iv) Installation analysis

v) Riser and its components fabrication drawings

vi) Material specifications, including material properties

vii) Prototype test data, as required by the design code



viii) Input data:

• Riser configuration

• Riser joint properties

• Design pressure and loads

• Load combinations (design, environmental, operations, fatigue, etc.)

• Design temperatures (maximum, minimum)

• Installation motion (RAO)

• Components interface/interactions

• Boundary conditions/constraints

• Wall thickness selections

• Corrosion allowance and tolerances

ix) Analysis results and evaluations, including:

• Maximum stress

• Displacement/deflection

• Stability and buckling

• Fatigue and fracture analyses

• Validation of results in accordance with design references

x) See 3/5.7 of this Guide for additional details on marine drilling riser design documentation

xi) Design details for mechanical load-bearing components:

• See 2/7.13, “Mechanical Load-Bearing Components”

xii) Design details for pressure vessels, accumulators, cylinders:


xiii) Manufacturing specifications (see 2/7.27)

xiv) Manufacturer’s affidavit of compliance (see 4/3.1.2)

7.7 Drill String Compensation Systems The drill string compensation system and equipment can be categorized as follows:

• Active heave compensation (AHC)

• Passive heave compensation (PHC)

Submit the following documentation for the drill string compensation system and associated equipment, as applicable:

i) Schematics and P&IDs

ii) Design basis:

• Descriptions of the drill string compensation systems and associated equipment

• Design parameters, pressure rating (internal/external), temperature rating (min/max)

• Load capacity





iii) Prototype test data, as required by the design code

iv) Design details for mechanical load-bearing components:


v) Design details electrical systems and equipment:


vi) Design details for control systems:


vii) Design details for pressure vessels, accumulators, cylinders:


viii) Design details for piping, valves, and fittings:


ix) Manufacturing specifications (see 2/7.27)

x) Manufacturer’s affidavit of compliance, as applicable (see 4/3.1.2)

7.9 Bulk Storage, Transfer, and Circulation Systems The bulk storage, circulation and transfer system equipment can be categorized as follows:

• Bulk storage and transfer equipment

• Cementing system and equipment

• Mud return system and equipment

• Mud conditioning equipment

• Well circulation system and equipment

• Mud-gas separator (poor boy), Degasser

Submit the following documentation for the bulk storage, circulation and transfer systems, as applicable:

i) P&IDs and schematic diagrams

ii) Design basis:

• Descriptions of the bulk storage, circulation and transfer systems, and all associated equipment (e.g., mud-gas separator, degasser, desilter, desanders, shale shakers, agitators, etc.)

• Design parameters, pressure rating (internal/external), temperature rating (min/max) and flow simulation

• Pressure relief philosophy


• Design references, codes, and standards

iii) Pressure relief equipment rating/capacity

iv) Details of prime movers, such as diesel engines, motors, and generators, as applicable

v) Design details for pumps, including:

• Power rating and capacity

• Temperature rating



vi) Design details for mechanical load-bearing components:


vii) Design details electrical systems and equipment:


viii) Design details for control systems:


ix) Design details for pressure vessels, accumulators, cylinders:


x) Design details for piping, valves, and fittings:


xi) Manufacturing specifications (see 2/7.27)

xii) Manufacturer’s affidavit of compliance, as applicable (see 4/3.1.2)

7.11 Hoisting, Lifting, Pipe Handling System Submit the following documentation for the hoisting, lifting, and pipe handling systems, as applicable:

7.11.1 Derrick Structure i) Design basis for the derrick structure, including:

• Descriptions of the derrick structure and associated components

• Equipment technical specifications



• Assumptions used in the design analysis of the derrick structure and associated components

• Design conditions, including:

- Environmental

- Operating

- Static

- Storm survival

- Waiting on weather

- Temperature, min/max

- Field transit

- Ocean transit

- Lifting, if applicable

• Combined load cases and limit states for all design and operating conditions

• The center of rotation (floating condition) specified in terms of the vertical and horizontal distances between the derrick base and the center of flotation of the vessel/unit

• Design analysis methodology for the derrick structure and associated components, and component analyses including computer modeling and computer program used

• Material specifications and material properties for all load-bearing components and bolts (if bolted design), including CVN testing requirements, as applicable

• Corrosion control plans

• Rigging arrangement

ii) Identification of the host vessel/unit for the derrick

iii) Is the host vessel/unit ABS Class only or ABS Class with CDS Notation?



iv) Descriptions of all computer programs, analysis methodologies and limits, and other calculation procedures that will form the basis of the structural design and analysis

v) Structural analysis report:

• Design load development and computer input for all design conditions

• Computer model geometry plots (group IDs, joint numbers, members and lengths, critical unity checks)

• Allowable stresses

• Computer stress analysis

• Computer output; support reactions, unity stress checks

• Justifications for any stress exceeding the stated allowable stress

• Derrick bolt design and torque procedures by manufacturer

• Attachment locations for other equipment (e.g., drill string compensation, riser tensioning, etc.)

• Supplemental calculations:

- Sheave shaft strength (including shafts for cluster, fastline, and deadline sheaves)

- Crown frame and Water table beams (or Top beams)

- Bolting designs for base plates and splice plates

- Strength of welded joints

- Platforms or sub-structure, as applicable

- Padeyes, as applicable

vi) Structural drawings:

• General arrangement drawings

• Derrick assembly drawings

• Crown block assembly drawings

• Water table assembly drawings

• Geometry layout drawing; showing overall dimensions of derrick and indicating the size of each member

• Detailed drawings of the main structural elements of the derrick, crown frame, and water table beams, including:

- Details and sizes for main structural elements

- Material specifications and material properties for all load-bearing components and bolts (if bolted design), including CVN testing requirements, as applicable

- Bolt connections and tightening procedures

- Welding details and other methods of connection

• Base plate, anchor bolt plan and bolting procedures

• Bolts sheet


viii) Manufacturer’s affidavit of compliance, as applicable (see 4/3.1.2)



7.11.2 Cranes and Lifting Appliances i) Design basis for the cranes (gantry or pedestal), including:

• Descriptions of the crane structures and associated components

• Equipment technical specifications


• Load cases and limit states for all design and operating conditions or combination thereof:

- Dead, live and dynamic loads, including loads due to list and/or trim of the drilling unit, as applicable

- Environmental loads including the effects of wind, snow and ice

ii) General arrangement, assembly plans and description of operating procedures and design service temperature.

iii) Details of the principal structural parts and crane supporting structure.

iv) Stress diagram, stress analysis and other supporting calculations, suitably referenced. Where computer analysis is used for the determination of scantlings, details of the programs describing input and output data and procedures are to be included together with the basic design criteria.

v) Wire rope specifications.

vi) Material specifications including material properties.

vii) Welding details and procedures and a plan indicating extent and locations of nondestructive inspection of welds for crane structure and foundation.

viii) Crane capacity rating chart.

ix) Design details electrical systems and equipment:


x) Design details for control systems:



xii) Manufacturer’s affidavit of compliance, as applicable (see 4/3.1.2)

7.11.3 Riser and Pipe Handling i) Design basis for the riser and pipe handling system:

• Description of system


• Design references, codes, or standards

• Design conditions:

- Environmental

- Operating

- Static

- Survival


• Load and temperature rating

• Rotating equipment power rating

ii) General arrangement drawings showing locations of all equipment



iii) Assembly and equipment drawings

iv) Structural analysis report

v) Dimensional detailed drawings


vii) Design details electrical systems and equipment:


viii) Design details for control systems:

• See 2/7.19, “Control System”, as applicable

ix) Design details for pressure vessels, accumulators, cylinders:


x) Design details for piping, valves, and fittings:



xii) Manufacturer’s affidavit of compliance (see 4/3.1.2)

7.11.4 Other Load-bearing Equipment i) Load-bearing equipment, and associated support structural may include, but is not limited to,

BOP handling crane, BOP transporter/skidder, drawworks, crown block, traveling block, top drive, hook and rotary swivel, power swivel, pipe, rackers/manipulator systems, stabbing board, racking platforms, man-riding elevators, winches, wire lines/ropes, cranes and other lifting devices.

ii) See Section 4, Table 1 for additional equipment or components and the ABS approval requirements. Manufacturers are to contact the ABS Technical office for equipment or components items not identified or listed in Section 4, Table 1 for ABS approval details.

iii) Design details for mechanical load-bearing equipment:

• See 2/7.13, “Mechanical Load-Bearing Equipment”

iv) Design details electrical systems and equipment:


v) Design details for control systems, as applicable:


vi) Manufacturing specifications, as applicable (see 2/7.27)

vii) Manufacturer’s affidavit of compliance, as applicable (see 4/3.1.2)

7.13 Mechanical Load-Bearing Equipment Unless required otherwise in 2/7.3 through 2/7.11, the following documentation for mechanical load-bearing components is to be submitted for ABS review, as applicable.

See Section 4, Table 1, “Approval Codes for Drilling Systems and Equipment” for ABS approval requirements.

i) Design specifications, including design codes, standards, and references

ii) Design parameters: loads, temperature, environmental conditions, etc.

iii) Design analysis and/or calculations, as applicable

iv) Dimensional drawings and fabrication details

v) Material specifications and material properties




vii) Design details for mechanical load-bearing equipment:

• See 2/7.13, “Mechanical Load-Bearing Equipment”

viii) Design details electrical systems and equipment:


ix) Design details for control systems, as applicable:


x) Manufacturing specifications, as applicable (see 2/7.27)

xi) Manufacturer’s affidavit of compliance, as applicable (see 4/3.2.1)

7.15 Well Testing System Well test systems may include well control equipment, process pressure vessels and separators, piping and electrical components, control systems, burners, gas flares, burner/flare booms, heat exchangers, transfer pumps and electric submersible pumps

7.15.1 Well Testing System and Equipment i) Design basis:

• Descriptions of the well testing system, and well test equipment

• General arrangement drawings showing locations of all equipment

• Design parameters: pressure rating, temperature rating (min/max)


• Gas dispersion and flare/heat radiation analyses

• Shutdown logic



ii) Well Test equipment:

• Well test assembly drawings, including tree arrangements

• Design parameters: pressure rating, temperature rating (min/max), loads, maximum water depth, etc.

• Design analysis to justify safety factor

• Structural design analysis for skid mounted equipment

• Dimensional detailed drawings and fabrication details



iii) Control system design details:

• See 2/7.19, “Control System”

iv) Design details for electrical systems and equipment:




7.15.2 Burner/Flare Booms Submit the following documentation for the burner/flare boom:

i) Design basis for the burner/flare boom, including:

• Descriptions of the burner flare boom and associated components

• Equipment list



• Assumptions used in the design analysis of the burner flare boom structure and associated components

• Design conditions, including:

- Environmental

- Operating

- Static

- Survival


• Combined load cases and limit states for all design and operating conditions

• Plans showing intended location of the boom on the installation


• Design analysis methodology for the burner flare boom structure and associated components, and component analyses including computer modeling and computer program used

• Design temperature (maximum, minimum)

• Material specifications and material properties for all load-bearing components and bolts (if bolted design), including CVN testing requirements, as applicable.

ii) Descriptions of all computer programs, analysis methodologies and limits, and other calculation procedures that will form the basis of the structural design and analysis

iii) Structural analysis report:

• Design load development and computer input for all design conditions

• Computer model geometry plots (group IDs, joint numbers, members and lengths, critical unity checks)

• Allowable stresses

• Computer stress analysis

• Computer output: support reactions, unity stress checks

• Justifications for any stress exceeding the stated allowable stress, as applicable

iv) Structural drawings:

• General arrangement drawings

• Burner Flare Boom assembly drawings

• Geometry layout drawing; showing overall dimensions of burner flare boom and indicating the size of each member



• Detail drawings of the main structural elements of the burner flare boom, including:

- Details and sizes for main structural elements

- Material specifications and material properties for all load-bearing components and bolts (if bolted design), including CVN testing requirements, as applicable

- Bolt connections and tightening procedures

- Welding details and other methods of connection

• Base plate and anchor bolt plan

• Bolts sheet

7.15.3 Pressure-Retaining Equipment See 2/7.21, “Pressure-Retaining Equipment”.

7.15.4 Piping System See 2/7.23, “Piping Systems and Piping Components”.

7.15.5 Pressure Relief Equipment Submit capacity calculations, sizes, arrangements, and material specifications for the pressure relief valves and depressurization systems.

7.15.6 Manufacturing Specifications See 2/7.27, “Manufacturing Specifications”

7.15.7 Manufacturer’s Affidavit of Compliance See 4/3.1.2, “Manufacturer’s Affidavit of Compliance”

7.17 Electrical Systems and Equipment Design plans and data are to be submitted for electrical systems and equipment in accordance with 4-3-1/5, 4-3-2/1, 4-3-3/1 and 4-3-4/1 of the MODU Rules. See Subsection 3/19 of this Guide.

7.19 Control Systems The following control system plans and data are to be submitted for design review, as applicable:

i) Arrangement plans showing location of units controlled, instrumentation and control devices

ii) Design basis and specifications for control and instrumentation equipment

iii) Set points for control system components

iv) Control system operating and maintenance manuals

v) Control system details:

• Details on hierarchy of controls: primary, secondary, emergency, etc., as applicable

• Volumetric capacity calculations for the accumulator systems, primary and secondary (as applicable)

• Hydraulic power unit (HPU) reservoir details/arrangements:

- Pump system details and arrangements

- Prime mover details

• Hydraulic, pneumatic, and electrical schematics

• Pressure relief system: Arrangements, size, materials, back pressure and capacity calculations, as applicable


• Manufacturer’s affidavit of compliance (see 4/3.1.2)



vi) FMEA, FMECA or similar analysis for computer-based systems [see 3/15.5.2(b) and (c)]

vii) Documentation in accordance with the recognized industry standard is to be submitted for review to justify the safety integrity levels, when applicable [see 3/15.5.2(d)]

viii) Calculations for control systems demonstrating the system’s ability to react adequately to anticipated occurrences, including transients

ix) Arrangements and details of control consoles/panels, including front views, installation arrangements together with schematic plans and logic description for all power, control and monitoring systems, including their functions

x) Type and size of all electrical cables and wiring associated with the control systems, including voltage rating, service voltage and currents, together with overload and short-circuit protection

xi) Schematic plans and logic description of hydraulic and pneumatic control systems together with all interconnections, piping sizes and materials, including working pressures and relief-valve settings

xii) Description of all alarm and emergency tripping arrangements and functional sketches or description of all special valves, actuators, sensors and relays

xiii) Shutdown logic and/or shutdown cause and effect charts

xiv) Hydrocarbon and H2S gas detection system plans and data, including detectors, piping, set points, type of detectors, and location of alarm panels, and recalibration program for gas detectors

7.21 Pressure-Retaining Equipment Unless required otherwise in 2/7.3 through 2/7.11, the following documentation for pressure-retaining equipment is to be submitted for ABS review and approval, as applicable:

i) Design specifications, including design codes, standards, and references

ii) Design parameters: pressure rating (internal/external), temperature rating (min/max), loads, etc.

iii) Design analysis and/or calculations, as applicable

iv) Dimensional drawings and fabrication details

v) Material specifications and material properties

vi) Details for manufacturing specifications (see 2/7.27)

vii) Manufacturer’s affidavit of compliance, as applicable (see 4/3.1.2)


7.23 Piping Systems and Piping Components Design documentation is to be submitted for review and is to include the following information, as applicable:

i) Piping Systems:

• P&IDs for piping systems associated with drilling systems or subsystems

• Piping specifications, including material specifications

• Design parameters: pressure, temperature rating (min/max)

• Pipe stress and flexibility analyses, including design verification of erosional allowance due to fluid velocity



ii) Piping components are considered, but not limited to, pipes, valves, hoses, fittings, flanges, bolts, etc. Piping component design specifications to include the following information in accordance with piping standard rating, as applicable:

• Technical specifications

• Design pressure (internal/external) and/or pressure rating

• Design temperature (min/max)

• Fluid medium (specifically note if piping standard rating is for sour service)

• Design code and standards

• Corrosion/erosion allowances

• Wall thickness for each line size

• Material specifications including material properties

• Details for manufacturing specifications (see 2/7.27)

• Manufacturer’s affidavit of compliance (see 4/3.1.2)


7.25 Flexible Lines/Hydraulic Hoses Flexible lines and hydraulic hoses documentation is to include, as applicable:

i) Pressure (internal/external) and temperature (min/max) ratings

ii) Construction materials details / material specifications

iii) Design analysis

iv) Prototype testing procedures and data, as required by design code

v) End connections and termination details, as applicable

• Stress analysis

• Material specifications

• Prototype testing procedures and data

vi) Manufacturing specifications (see 2/7.27)

vii) Manufacturer’s affidavit of compliance (see 4/3.1.2)

7.27 Manufacturing Specifications Manufacturing plans and/or fabrication details are to include but not limited to, as applicable:

i) Quality plan and specifications

ii) WPSs and PQRs

iii) NDE procedures

iv) Detailed Inspection and Test Plans (ITP), including associated test procedures for system, subsystem, equipment or component, as outlined in Section 4, Table 1 of this Guide, as applicable during:

• Manufacturing

• Installation

• Commissioning

• In-service

v) Installation, and Commissioning plans and procedures

vi) Maintenance and Operating manuals


Section 3: Drilling Systems

S E C T I O N 3 Drilling Systems

1 General Drilling systems consist of multiple sub-systems simultaneously operating together to bore a hole on the surface of subsea floor. A drilling system must contain the ability to hoist, pump fluids down the well through the drill bit, must be able to clean the drill fluid returning from the well while maintaining hole quality.

Drilling systems typically consist of the following systems and/or sub-systems:

• Well Control System

- Blowout Preventer (BOP) Equipment

- Lower Marine Riser Package (LMRP)

- Choke and Kill System

- Diverter System

- Auxiliary Well Control Equipment

• Marine Drilling Riser System and Associated Components

- Riser Tensioning System

• Drill String Compensation System

• Bulk Storage, Circulating and Transfer System

• Hoisting, Lifting, Rotating and Pipe Handling System

- Derrick, Derrick Support Structures

• Well Test System

• Burner Booms

• Drawwork, Rotary Table

• Power Generation

• Control Systems

This Guide provides detailed procedures for ABS approval of drilling system, subsystems, equipment, and/or components for Classification of drilling system. The term Classification, in this document, indicates that a drilling system and its equipment have been designed, constructed, tested, installed and surveyed in compliance with relevant ABS Rules, Guides, this Guide or other recognized standards.

The following is to be considered in ABS Classification of Drilling Systems:

i) The drilling system, subsystems, equipment, and/or components are to be designed and manufactured in compliance with the recognized codes and standards, as listed in Appendix 1, and the additional requirements specified in this Guide.

ii) Where a certain aspect of the design is not in compliance with the recognized code, standard or the requirements of this Guide, the specific variations are to be advised and justified and will be specially considered by ABS in accordance with 1/7.7 of this Guide, on a case-by-case basis.

iii) ABS approval requirements for typical drilling systems, subsystems, equipment, and/or components are outlined in Section 4, Table 1 - “Approval Codes for Drilling Systems and Equipment” of this Guide.



3 Well Control System The well control systems and associated subsystems and equipment can be typically categorized as follows:

• Blowout preventer (BOP) system and equipment

• Lower marine riser package

• Choke and kill system and equipment

• Diverter system and equipment

• Marine drilling riser system (see Subsection 3/5)

• Mud circulation system and equipment (see Subsection 3/9)

• Auxiliary well control equipment

The well control systems, equipment, and/or components are to be in compliance with the following API standards and the additional requirements of this Guide:

Blowout Preventer (BOP) System and Equipment API Spec 16A, Spec 16D API RP 53, RP 59

Lower Marine Riser Package (LMRP) API Spec 16A, Spec 16D, Spec 16F, Spec 16R API RP 16Q

Choke and Kill System and Equipment API Spec 6A, Spec 16C, Spec 16F API RP 53, RP 59

Diverter System and Equipment API Spec 6A, Spec 16D API RP 53, RP 64

Marine Drilling Riser System API Spec 16A, Spec 16F, Spec 16R API RP 16Q, API Bull. 16J

Auxiliary Well Control Equipment API Spec 7-1, Spec 16A API RP 53

Mud Circulation System and Equipment See Subsection 3/9

BOP Stack Structural Frame and BOP Handling API RP 2A WSD AISC

3.1 Blowout Preventer System and Equipment Typical components of the BOP system and equipment would include ram and annular type BOPs, BOP stack structural frame, accumulators, connectors, clamps, drilling spools, spacer spools, control systems/consoles/ panels, control pods, umbilical, flexible/jumper lines (choke, kill, mud booster and hydraulic), hydraulic hoses, MUX (multiplex), cable reels, rigid piping, hydraulic power units, manifold, ROV interface, test stump and testing equipment.

3.1.1 Blowout Preventer Stack Configuration i) BOP stack configurations are to be in general agreement with API RP 53, applicable national

regulations and the additional requirements as listed below.

ii) As a minimum, the BOP stack is to consist of the following preventers:

• One (1) annular preventer

• One (1) blind-shear ram preventer with mechanical locking device for fixed units

• Two (2) pipe ram preventers with mechanical locking device

• Two (2) shear rams for moored or dynamically-positioned units, one being a blind-shear ram and the other to be a casing shear/super shear ram.



iii) Installed ram-type BOP is to have, as a minimum, a working pressure equal to 3.5 MPa (500 psi) greater than the maximum anticipated surface pressure (MASP) to be encountered.

iv) The ram-type BOP positions and outlet arrangements on subsea BOP stacks are to provide reliable means to handle potential well control events. Specifically for floating operations, the arrangement is to provide means 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 the annular BOP(s)

• Hang off the drill pipe on a ram-type BOP and control the wellbore

• Shear logging cable or the drill pipe and seal the wellbore

• Disconnect the riser from the BOP stack

• Circulate the well after drill pipe disconnect

• Circulate across the BOP stack to remove trapped gas

v) Systems of valves complying with the requirements of 3/3.5 are to be provided.

vi) For subsea BOP, the use of drilling spools is not recommended in order to reduce the overall height of the subsea BOP stack arrangements.

vii) Spacer spools are used to provide separation between two (2) drill-through components with equal sized end connections (nominal size designation and pressure rating). Typically, they are used to allow additional space between preventers to facilitate stripping, hang off, and/or shear operations but may serve other purposes in a stack as well.

viii) Spacer spools for BOP stacks are to meet the following minimum specifications:

• Have a vertical bore diameter the same internal diameter as the mating equipment

• Have a rated working pressure equal to the rated working pressure of the mating equipment

• Are not to have any penetrations capable of exposing the wellbore to the environment, without dual isolation capabilities

ix) The BOP equipment is to be designed for the specific drilling envelope, and suitable for the intended facility. BOP manufacturer is to specify and to attest BOP stack minimum and maximum capability with regard to the following including shearing and pressure-temperature capabilities:

• Drill pipe, tool joint, casing sizes

• Wire lines

• Water depth

• Pressure

• Temperature

x) The BOP structural frame and lifting attachments are to be designed considering applicable loads as specified in 2/5.7 of this Guide and in accordance with the requirements of API RP 2A-WSD or other recognized standards. Allowable stresses are to be in accordance with design standards and/or AISC.



3.1.2 Well Control Systems for Blowout Preventers – Surface and Subsea i) The control systems and components (hydraulic, pneumatic, electric, electro-hydraulic, etc.)

are to comply with Subsection 3/15 of this Guide and are to be in compliance with API Spec 16D, and API RP 53. This also includes response time, volumetric capacity of the accumulator system, hydraulic reservoir, pump system sizing and arrangements.

ii) For subsea, BOP systems are to have sufficient usable hydraulic fluid volume (with pumps inoperative) to close and open one annular-type preventer and all ram-type preventers from full-open position and open HCR valve against zero wellbore pressure. After closing and opening one annular preventer, all ram-type preventers and one HCR valve, the remaining pressure is to be 1.38 MPa (200 psi) or more above the minimum precharge pressure.

iii) For surface, BOP systems are to have sufficient usable hydraulic fluid volume (with pumps inoperative) to close one annular-type preventer, all ram-type preventers from a full-open position, and open one HCR valve against zero wellbore pressure. After closing one annular preventer, all ram-type preventers, and opening one HCR valve, the remaining pressure shall be 1.38 MPa (200 psi) or more above the minimum recommended precharge pressure.

iv) The minimum precharge pressure for the BOP system is to be determined based on the following in accordance with API Spec 16D and API RP 53:

• BOP stack configuration and minimum required operator pressure

• Water depth

• Hydraulic fluid density

• Local regulations

• Operational sequence

v) Floating installations or dynamically-positioned units require the following independent secondary well control systems and safety features. These systems are to be designed in accordance with API Spec 16D:

• Deadman System

• Autoshear System

vi) If installation is provided with acoustic control system, the system is to be designed in accordance with API Spec 16D. The acoustic control is to be a portable control unit, which can be handled by one person, and is to be available for the closing of the BOPs in the event of evacuation from the facility

vii) For surface well control systems, a reserve supply of pressurized nitrogen gas can serve as a backup means to operate functions in the event that the pump system power supply is lost.

viii) As a minimum, two (2) full-functioning well control panels are to be provided:

• One (1) well control panel is to be at driller’s station or cabin and where it is protected from drilling activities.

• A second well control panel is to be located in a nonhazardous area, as defined in the MODU Rules (see 4-3-5/7.1), API RP 500 or API RP 505, without having to cross the drill floor or cellar deck, and is to be arranged for easy access in case of emergency.

ix) Well control panels are to be accessible and operable at all times.

x) Well control panels are to be mutually independent and simultaneously functional (i.e., directly connected to the control system, and not connected in series).

xi) Control systems are to be arranged to ensure the operational capability upon loss of any single component. This will include the use of functionally independent actuation lines, input/output devices and the provision of system isolation.



xii) The well control panels are to include controls for at least, but not limited to:

• Close or open of all rams, annular preventers, and choke and kill valves (HCR valves) at BOP

• Diverter operations

• Disconnect of riser connector (floating installations)

• Emergency disconnect (DP units)

• Mechanical locking of rams, as applicable

xii) BOP stack is to be equipped with ROV intervention equipment, which at the minimum allows the closing of one set of pipe ram, closing of one each blind-shear rams, and unlatching of the LMRP. These functions are to operate independently of the primary BOP control system.

xiv) ROV interface and/or receptacles are to mate with API 17H high-low stabs. Operated control systems and interventions are to be provided for subsea BOP stack for all installations

xv) For subsea BOP stack, adequate measure is to be provided to prevent accidental unlatching of the wellhead connector until the well is secure, such as two-hand function, two-step action, protective cover or equivalent.

3.1.3 Blowout Preventer Equipment 3.1.3(a) Design Requirements.

i) Surface and subsea, ram and annular blowout preventers, including workover and well servicing BOPs, ram blocks, annular packing units, valves, wellhead connectors, drilling spools, adapter spools and clamps are to be designed, fabricated and tested by the respective manufacturers for compliance with API Spec 6A, Spec 16A, Spec 16C, Spec 16D and the additional requirements of this Guide.

ii) The working pressure of ram-type BOPs is to exceed the maximum anticipated surface pressure (MASP). Provisions are to be made for closing BOPs on all sizes of drill pipe, drill collars and casing that may be used.

iii) Hydraulically-operated wellhead, riser and choke and kill line connectors are to have redundant mechanisms for unlock and disconnect.

iv) The secondary unlock and disconnect mechanism may be hydraulic or mechanical, but must operate independently of the primary unlocking and disconnect mechanism.

v) In addition to the design conditions/loads listed in 2/5.7 of this Guide, the design of preventers is to consider the following loads, as applicable:

• The weight of a specified length of drill string suspended in the pipe ram preventer

• Loads induced from the marine drilling riser

vi) On fixed units, if the tool joints cannot be sheared, the following is to be considered:

• Two (2) shear rams must be installed as for DP units, or

• Lifting or lowering of main hoisting system is to be possible in all operational conditions, including emergency operation. The main hoisting system is to be included in the emergency power source.

vii) The blind-shear rams are to be capable to seal after shearing operation.

viii) The shear rams are to be capable of shearing the largest section and highest-grade of tubulars (drill pipe, casing, tool joints, wireline, etc), as applicable, under the design conditions and at the rated working pressure.



ix) The shear ram is to be capable to shear at the minimum operator design pressure and is to consider the following, simultaneously, as applicable:

• Forces to shear highest-grade of tubulars

• Rated working pressure of BOP

• Internal pressure of the drill pipe due to fluids

• Frictional force

• Test mandrel/piston closing area

x) The annular, pipe and blind ram BOP operator design pressure is to consider the following, simultaneously, as applicable:

• Well bore pressure

• Rated working pressure of BOP

xi) Procedures to test preventers during manufacturing and “on-site” are to be developed and submitted for ABS review.

xii) For subsea BOP and associated components such as valves, control system components, sealing components, elastomeric components, etc., are to be designed with consideration to marine conditions and external pressure gradient due to rated water depth.

xiii) All nonmetallic materials are to be suitable for the intended service conditions, such as temperature and fluid compatibility.

xiv) Materials are to be in accordance with Section 6 of this Guide.

xv) Welding and NDE are to be in accordance with Section 7 of this Guide, as applicable.

3.1.3(b) Operations/Maintenance Manuals.

i) Blowout preventer manufacturers are to provide the Owner/Operator with product operations and maintenance manuals to assist in the safe operation of each assembly on each installation.

ii) The manufacturer’s recommended maintenance schedules are to be available for each component of the assembly. These schedules are to prescribe maintenance routines.

3.3 Lower Marine Riser Package (LMRP) Typical components of the lower marine riser package, including connectors, flex joints, and adapter spools are to be designed, fabricated, and tested by the respective manufacturers for compliance with API Spec 16F, API Spec 16R and API RP 16Q and the additional requirements of this Guide.

The LMRP package typically includes an annular BOP that is to be designed, fabricated, and tested in accordance with 3/3.1 of this Guide, API Spec 16A, API Spec 16D and API RP 53, and the additional requirements of this Guide.

i) Lower marine riser package disconnect arrangements are to be designed for all possible operating and loading conditions. The loading conditions of the LMRP are to consider, but not limited to, the following:

• Riser angle – min/max

• Side loads

• Bending loads

• Currents

• External pressure due to static head

• Internal pressure

• Top tension – min/max



ii) The LMRP design is to consider the induced loads as defined in API Spec 16F and API RP 16Q, as a minimum, for the following modes:

• Installation

• Drilling

• Retrieval

• Storage and maintenance

• Hang-off

• Drifting

iii) For dynamically-positioned floating units, an emergency disconnect is to be provided.

iv) The emergency disconnect is to initiate and complete disconnection in correct sequence. Typical emergency disconnect sequence would be:

• Blind-shear drill string and/or casing

• Disconnect LMRP

• Close well

v) For the LMRP and associated components such as valves, control system components, sealing components, elastomeric components, etc., are to be designed with consideration to marine conditions and external pressure gradient due to rated water depth.

vi) Adapter spools are used to connect drill-through equipment with different end connections, nominal size designation and/or pressure ratings to each other. Typical applications in a subsea stack are:

• The connection between the LMRP and the lower stack

• The connection between the lowermost BOP and the wellhead connector

vii) Adapter spools for BOP stacks are to meet the following minimum specifications:

• Have a minimum vertical bore diameter equal to the internal diameter of the mating equipment

• Have a rated working pressure equal to the lowest rated end connection of the mating equipment

viii) LMRP structural frame and lifting attachments are to be designed with consideration to all applicable loading conditions. Applicable structural design code and standard including loading conditions are provided in 3/3.1.1x) of this Guide.

3.5 Choke and Kill Systems and Equipment Typical components of the choke and kill system and equipment would include the choke and kill manifolds, including their chokes, spools, flanges and valves, choke and kill lines, connectors and flexible lines (drape hoses at moonpool area and jumper lines at LMRP), BOP stack fail-close valves, connecting piping from the cementing unit and drilling fluid manifold to the choke manifold, buffer tanks and control systems.

Choke and kill systems, manifolds, arrangements, and associated components are to be in compliance with API Spec 6A, API Spec 16C, API Spec 16F, API Spec 16D, API RP 53 and the additional requirements of this Guide.

Piping, flexible lines and hydraulic hoses are to be in accordance with Section 5 of this Guide, and the standards listed above.

Materials are to be in accordance with Section 6 of this Guide, and the standards listed above.

Welding and NDE are to be in accordance with Section 7 of this Guide, as applicable, and the standards listed above.



3.5.1 Choke and Kill Lines i) Each choke and kill line from the BOP stack to the choke manifold is to be equipped with

two (2) valves installed on the BOP stack.

• For surface BOP stacks, one of these two valves is to be arranged for remote hydraulic operation.

• For subsea BOP stacks, these two valves are to be arranged for remote hydraulic operation.

• Hydraulically-operated valves are to be fail-close valves to seal upon failure of the control system pressure.

ii) The design pressure of the pipes, valves, flexible lines, connectors, fittings, and the choke manifolds from the BOP stack to the isolation valve downstream of the choke is to be the same as that of the ram-type BOPs or greater.

iii) The line connected to the lowermost outlet of the BOP is to be designated as the “kill line”. Placement of this outlet is to be below the lowermost pipe ram, or below the test ram, if installed.

iv) One (1) choke line and one (1) kill line connection is to be located above the lower most ram BOP.

v) The choke line, that connects the BOP stack to the choke manifold, and lines downstream of the choke are to:

• Be as straight as practicable; turns, if required, are to be targeted

• Be firmly anchored to prevent excessive dynamic effect of fluid flow and the impact of drilling solids and/or vibration

• Supports and fasteners located at points where piping changes direction are to be capable of restraining pipe deflection in all operating conditions

• Have bore of sufficient size to prevent excessive erosion or fluid friction due to velocity

3.5.2 Components of Choke and Kill i) For rated working pressure of 20.7 MPa (3000 psi) and above, only flanged, welded or

clamped connections, and rated hammer unions (except connections to the choke) are to be used. See Section 5 of this Guide for additional piping component requirements.

ii) For rated working pressure of 20.7 MPa (3000 psi) and 34.4 MPa (5000 psi), the minimum size for the choke lines is to be 50.8 mm (2.0 in.) nominal diameter.

iii) For rated working pressure of 69 MPa (10000 psi), 103 MPa (15000 psi) and 137 MPa (20000 psi), the minimum size for the choke lines is to be 76.2 mm (3.0 in.) nominal diameter.

iv) For high volume air or gas drilling operations, the minimum nominal diameter pipe size is to be 101.6 mm (4.0 in.) nominal diameter.

v) Minimum size for vent lines downstream of the choke is to be 50.8 mm (2.0 in.) nominal diameters.

vi) When buffer tanks are utilized, provisions are to be made to isolate a failure or malfunction without interrupting flow control.

vii) All choke manifold valves subject to erosion from well control are to be full-opening and designed to operate in high pressure gas and abrasive fluid service.



3.5.3 Arrangement of Choke Manifold i) The choke and kill manifold assembly is to include the following:

• The choke manifold is to be designed for a minimum of three (3) chokes, of which at least one (1) is remotely controlled and one (1) is manual.

• Any one of the chokes is to be capable of being isolated and replaced while the manifold is in use.

• Choke and kill manifold is to permit pumping or flowing through either line.

• A remotely controlled adjustable choke and a manual choke system to permit control through either the choke or kill line.

• Tie-ins to both drilling fluid and cement unit pump systems.

ii) Where changes in direction cannot be avoided downstream of the choke and kill manifolds, choke and kill lines are to be provided with targeted tees or elbows fitted with a doubler plate on the outside radius or elbows with a radius of 20 times the diameter of the pipe.

iii) Each of the manifolds’ inlet and outlet lines is to be fitted with a valve. A valve immediately upstream of each choke is to be provided on the manifolds. All valves are to be in compliance with API Spec 16C, API Spec 6A, and API RP 53, and the additional requirements of this Guide, as applicable.

iv) Lines downstream of the choke manifold are to permit flow direction either to a mud-gas separator, degasser, vent lines, or to test facilities, or emergency storage.

v) Alternate flow and flare routes downstream of the choke line are to be provided so that eroded, plugged, or malfunctioning parts can be isolated for repair without interrupting flow control.

vi) In the event the capacity of the mud-gas separator is exceeded, the choke manifold is to have the capability to divert flow to alternate locations for safe discharge, such as vent lines, flare or overboard (port and starboard), as applicable.

vii) The bleed line (the vent line that bypasses the choke) is to be at least equal to or greater than the diameter to the choke line.

viii) Additional provisions are to be provided to minimize erosion or abrasion from high velocity flow (such as targeted flanges).

ix) The Joule-Thompson effects are to be considered in the design and material selections of choke and kill manifold and downstream piping and associated components.

3.5.4 Mud-Gas Separator (Poor Boy) i) Mud-gas separator is be designed and manufactured in accordance with ASME Section

VIII Boiler and Pressure Vessel Code and Subsection 3/17 of this Guide.

ii) Piping is to be in accordance with the requirements of Section 5 of this Guide.

iii) Materials are to be in accordance with Section 6 of this Guide.

iv) Welding and NDE are to be in accordance with Section 7 of this Guide, as applicable.

v) Precautions are to be taken to prevent erosion at the point the drilling fluid and gas flow impinges on the vessel wall.

vi) Mud-gas separator is to be vented to atmosphere through the vent line.

vii) The vent line is be sized and designed to minimize backpressure in order to assist with maximum separation of gas from the mud.

viii) Mud-gas separator is to be equipment with provisions to prevent gas blow-by to the mud condition equipment downstream of the mud-separator. These provisions can be achieved through providing P-trap, mud level monitoring and shutdown, etc.



ix) Mud-gas separator is to be provided with high level sensor (LSH) or equivalent for notification of diverting flow to overboard or alternate route. Alternate arrangement for LSH sensor will be specially considered by ABS.

x) Sizing of the mud-gas separator is to be performed in accordance with SPE Paper No. 20430: Mud-Gas Separator Sizing and Evaluation.

3.5.5 Degasser i) Degasser is to be provided to separate entrained gas bubbles in the drilling fluid which are

too small to be removed by the mud-gas separator.

ii) Degasser is be designed and manufactured in accordance with ASME Section VIII Boiler and Pressure Vessel Code and Subsection 3/17 of this Guide.



v) Typically, the degasser is designed so that it can be operated under partial vacuum to assist in removing the entrained gas.

vi) Provisions are to be provided to vent gas to the appropriate location.

vii) The drilling fluid inlet line to the degasser is to be placed close to the drilling fluid discharge line from the poor boy separator to reduce the possibility of gas breaking out of the drilling fluid in the pit.

3.5.6 Mud Returns The mud return system includes flowlines, degasser, shale shaker, desilter, desander, agitator, mud pit, mud tanks, pumps, mixing tanks, hoppers, volume measuring systems, etc.

i) The mud return system, associated equipment and piping systems are to be designed in accordance with Subsection 3/17 and Section 5 of this Guide.

ii) Piping is to be in accordance with the requirements of Section 5 of this Guide.



v) The piping system design is to allow the returns from the flowlines to installed mud conditioning equipment as listed above to the mud pit.

3.5.7 Gas Vents i) Vent lines from mud-gas separator are to extend 4 m (13 ft) above the crown block.

ii) The vent system is to be as straight as possible, free of obstructions, and is to be sized and arranged to minimize backpressure in the upstream equipment of vent line.

iii) A bypass line to alternate locations for safe discharge, such as vent lines, flare or overboard (port and starboard), as applicable, must be provided in case of malfunction or in the event the capacity of the mud-gas separator is exceeded.

iv) Overboard lines (port or starboard) are to be directed for discharge in downwind directions and safe distance away from facility.

3.5.8 Choke and Kill Flexible Lines i) Refer to the requirements contained in 5/3.7 of this Guide.

ii) End connectors are to be in accordance with the applicable parts of Section 5 of this Guide.



3.5.9 Control Systems for Choke and Kill Equipment i) The control systems and components (hydraulic, pneumatic, electric, electro-hydraulic, etc.)

are to comply with Subsection 3/15 of this Guide and are to be in compliance with API Spec 16C, API Spec 16D, and API RP 53, and the additional requirements of this Guide (see also 3/3.1.2).

ii) The choke control station, whether at the choke manifold or remote from the rig floor, is to be easily accessible and is to include all monitors necessary to furnish an overview of the well control situation.

iii) Any remotely operated valve or choke is to be equipped with an emergency backup power source.

iv) All valves are to be provided with “open” and “close” indicators.

v) Electrical systems are to be in accordance with Subsection 3/19 of this Guide.

3.7 Diverter System and Equipment Typical components of the diverter system and equipment would include annular sealing device (packer, housing), vent outlets, valves, power unit and piping, control systems/consoles/panels.

The diverter equipment and arrangements are to be in compliance with the requirements of API RP 64, API RP 53, API Spec 16D, and the additional requirements of this Guide.

3.7.1 Diverters i) A diverter with a securing element for closing around the drill string in the wellbore or open

hole is to be provided when it is desired to divert wellbore fluids away from the rig floor.

ii) The diverter is to be equipped with two (2) 10 in. or larger lines that are to be piped to opposite sides of the rig floor. Alternative arrangements will be specially considered and justification in accordance with 1/7.7 of this Guide.

3.7.2 Diverter Valve Assembly i) Valves in the discharge piping are to be of the full opening and full bore type.

ii) Valves and their actuators are to be sized to be capable of operating the diverter valve under all design conditions.

iii) During the operational tests at the manufacturer’s plant, a full design differential pressure opening test is to be carried out for each valve and actuator combination.

iv) The diverter valve assembly and a control system are to be designed to safely vent well bore fluids at the surface or subsea.

3.7.3 Control Systems for Diverters i) The diverter control systems and components (hydraulic, pneumatic, electric, electro-

hydraulic, etc.) are to comply with Subsection 3/15 of this Guide and are to be in compliance with API RP 64, API RP 53 and API Spec 16D. This also includes response time, volumetric capacity of the accumulator system, hydraulic reservoir, pump system sizing and arrangements.

ii) Any remotely operated valve or choke is to be equipped with an emergency backup power source.

iii) The diverter system is to be controlled from two (2) locations; one is to be located near the driller’s console/workstation and the other is to be located at an accessible location away from the well activity area and reasonably protected from physical damage from drilling activities on the drill floor. Both controls are to be arranged for ready operation by the driller.

iv) The control systems are to have interlocks so that the diverter valve opens before the annular element closes around the drill string.



v) When the diverter element close function is activated, the return flow to the mud system is to be isolated.

vi) The range of diverter elements is to be suitable to seal on all sizes of drill string elements on which the diverter is required to operate.

vii) A relief valve is required to prevent overpressurization of the diverter packer. If applicable, the diverter system is to have an interlock system to prevent insert packer closure unless the insert packer is installed and the insert packer lock-down dogs are energized.

viii) All valves are to be provided with “open” and “close” indicators.

ix) Electrical systems are to be in accordance with Subsection 3/19 of this Guide.

3.7.4 Diverter Piping i) Pipe size, arrangement and support is to be determined with due consideration given to

maximum pressure and maximum reaction loads, erosion resistance and the range of temperatures likely to be encountered in service.

ii) Discharge pipe slope downward from the diverter valves.

iii) Piping is to run as straight as practicable. Where changes in direction cannot be avoided, they are to be accomplished by employing targeted tees or elbows fitted with a doubler plate on the outside radius or elbows with a radius of 20 times the diameter of the pipe.

iv) Flexible lines are to be avoided where possible. When this is not practicable, data is to be submitted substantiating their suitability for the maximum pressure, maximum reaction loads, fire-resistance, erosion resistance, expected range of temperatures, and their compatibility to associated piping provided it is adequately supported and connected.

v) Piping systems are to be in accordance with Section 5 of this Guide.

vi) Materials are to be in accordance with Section 6 of this Guide.

vii) Welding and NDE are to be in accordance with Section 7 of this Guide, as applicable

viii) Suitable pipe supports in accordance with ASME B31.3.

ix) Diverter outlet is to be provided with extra heavy pipe schedule.

3.9 Marine Drilling Riser Systems See Subsection 3/5 of this Guide for specific requirements for marine drilling riser systems and associated components.

3.11 Auxiliary Well Control Equipment Auxiliary equipment includes the upper and lower kelly valves, drill pipe safety valves, IBOPs, drill string float valves and kelly.

i) Auxiliary well control equipment, such as kelly valves, drill pipe safety valves, IBOP, drill string float valves, are to be used in a rotary drilling system.

ii) For drilling installation using a top drive system, an automated or manual drill pipe safety valve must be installed.


iv) Auxiliary well control equipment is to be in compliance with API Spec 7-1, API RP 53, Section 5 and the additional requirements of this Guide.



3.11.1 Kelly Valves i) The drill string is to be equipped with two (2) kelly cocks, one of which is to be mounted

below the swivel (upper kelly cock), and the other at the bottom of the power swivel or kelly (lower kelly cock).

ii) The lower kelly cock is a full-opening valve that backs up the upper kelly cock. The lower kelly cock is to be sized so that it can be run through the blowout preventer stack when the blowout preventers are not installed on the seabed.

iii) Testing of kelly cocks are to be performed bi-directionally and at a low and high pressure, with the low pressure tests first.

3.11.2 Drill Pipe Safety Valves i) A full-opening manual safety valve is to be available on the rig floor to be installed into

the drill string immediately in the event of a kick occurring during a trip.

ii) The wrench to operate the valve is to be readily accessible to the crew to perform this operation.

3.11.3 Internal Blowout Preventer (IBOP) i) An internal blowout preventer or IBOP is a back pressure or check valve that is to be

provided in the drill string.

ii) IBOP is spring operated and is locked in the open position with a removable rod lock screw.

3.11.4 Drill String Float Valve i) A float valve is to be installed just above the drill bit to protect the drill string from back

flow or inside blowouts.

ii) The two (2) most common types of floats are spring-operated piston (plunger) and flapper types.

5 Marine Drilling Riser System Typical subsystems and associated components of the marine drilling riser system include the following:

• Riser tensioning system and equipment

• Telescopic joints

• Pup joints

• Riser joints

• Buoyancy devices

• Riser couplings (connectors), mechanical, hydraulic, etc.

• Ball and flex joints

• Riser running and handling equipment

• Riser recoil

• Special equipment, including fill-up valves, mud boost system, drag reducing devices.



5.1 Riser Tensioning System and Equipment Typical components of the riser tensioning system would include accumulators, air/nitrogen compressors, air/nitrogen dryers, control systems/consoles/panels, hydraulic cylinders, HPU, piping, pressure vessels, tensioners, guideline, podline, wireline, sheaves for tensioners, telescopic arms, wire ropes, etc. The design of these components is to be in accordance with the applicable sections of this Guide.

5.1.1 Component Specific Requirements i) The marine drilling riser system and associated components listed above are to be designed

and fabricated in accordance with applicable sections of API RP 2RD, API Spec 16F, API RP 16Q and API Spec 16R, and the additional requirements of this Guide.

ii) The manufacturer is to establish a rated capacity through appropriate design analysis and prototype testing.

iii) Design analysis is to be submitted for review, showing that the drilling riser system and all associated components will not be overstressed at the rated capacity, either in axial loading or bending, overpressure at rated tensioning capacity in specified design conditions.

iv) Piping and hoses are to be in accordance with Section 5 of this Guide.

v) Materials are to be in accordance with Section 6 of this Guide.

vi) Welding and NDE are to be in accordance with Section 7 of this Guide, as applicable.

vii) Load-carrying parts are to be in accordance with 3/11.3.4 of this Guide.

viii) If the locking mechanism is in the load path, it is to be in accordance with 3/11.3.4 of this Guide.

ix) Hydraulic and pneumatic cylinders are to be in accordance with 3/17.3 of this Guide.

5.1.2 Control Systems for Riser Tensioning System i) The control systems and components are to be in accordance with the applicable sections

of this Guide.

ii) The control systems are to be in accordance with Subsection 3/15 of this Guide.

iii) Electrical systems are to be in accordance with Subsection 3/19 of this Guide.

iii) Any remotely-operated valve is to be equipped with an emergency backup power source.

iv) Provisions for load monitoring are to be provided for riser tensioning system.

5.3 Marine Drilling Riser Operating Envelope Marine drilling riser operating envelope is to comply with the following requirements:

i) In order to provide a set of criteria for the drilling operation, an envelope of operating parameters is to be established, preferably in the form of a chart. The chart is to clearly show the limits not to be exceeded for each marine drilling riser type in use for any combination of applied loading conditions and the anticipated environmental conditions.

ii) Where applicable, consideration is to be given to the limits on dynamically-positioned or turret-moored drill ships and the heading change limitations imposed by the length of the choke and kill lines, and restrictions with the slip joint fluid ring.

iii) The development of the chart is to take into consideration all applicable loading conditions, load effects, mechanical stops or other limitations on the marine drilling riser system and any component of the drilling riser.

iv) The drilling riser is to be designed so that the maximum stress intensity for the operating modes, as described in API RP 16Q, is not to be exceeded.



v) The design limits or combination thereof for consideration in the design and structural analysis of the drilling riser system are to consider, but not limited to:

• Maximum stress

• Maximum deflection or curvature

• Fatigue for service life

• Strain

• Temperature

• Hydrostatic collapse

• Maximum loading on specific components vi) The drilling riser loads and load effects are to be considered in the design and structural analysis

of the marine drilling riser system in conjunction with the design limits indicated above. The marine drilling riser loads effects are categorized as follows:

• Functional, as applicable:

- Nominal top tension

- Internal pressure

- External hydrostatic pressure

- Thermal

- Vortex-induced vibration (VIV)

- Hang-off

- Inertia

- Vessel constraints and/or offsets (DP, moored installations, etc.)

- Internally run tools

- Installation

- Weight of riser

- Weight of attachments and/or tubing

- Weight of tubing contents and annulus fluid (mud)

• Environmental, as applicable:

- Waves

- Wind

- Current

- Vessel motions (DP, moored installations, etc.)

- Seismic

- Ice

• Accidental, as applicable:

- Small dropped objects

- Normal handling impacts

- Tensioner failure

- Partial loss of station keeping capability

- Emergency disconnect

5.5 Technical Requirements Marine drilling riser system technical requirements are to comply with the following:

i) Marine drilling riser system is to be verified through global riser analysis.

ii) The design analyses of the individual marine drilling riser components are to be performed using loads obtained from a global drilling riser analysis.

iii) The marine drilling riser system and components are to be evaluated for the design conditions and service life criteria as indicated in 3/5.3 of this Guide.

iv) The individual components of the marine drilling riser system are to be adequately designed to withstand stresses expected throughout the service life of the particular component. In design, consideration is to be given to the maximum stress, fatigue damage, maximum deflection and stability against column buckling.

v) The maximum permissible deflection of the drilling riser system is to be limited to that value which would cause interference with the passage of any downhole tools that would be used in the different operating modes.

vi) The drilling riser running equipment, which includes the drilling riser running/handling tool, riser spider, gimbal and shock absorber (if applicable) is to be designed and rated in accordance with API Spec 8C and the additional requirements of this Guide.



vii) The mud boost system is to be provided with safety relief valves capable of protecting system equipment with the lowest pressure rating, including the marine drilling riser.

viii) Riser make-up and break-up equipment and procedures are to be provided for ABS review.

5.7 Design Documentation Design documentation are to include the reports, calculations, plans, manuals and other documentation necessary to verify the global riser analysis and structural integrity of the individual riser components. Additional documentation may be required based on the relative complexity of the marine drilling riser system or relevant conditions in the geographic area of operation.

5.7.1 Reports i) Reports are to fully describe the loads and resulting stresses for the global drilling riser

system, individual components, and the operating and environmental conditions that produce those loads and/or restrict the ability of the drilling riser system to meet its designed function.

ii) The environmental reports are to be based on appropriate original data. Data from analogous areas may be considered. The information contained therein is to include all environmental phenomena that would affect the drilling riser system.

iii) Data presented is to include tables that summarize wave height vs. percentage of time, wave height vs. direction, wave and overall current statistics for return periods of 1 year, 10 years and 50 years.

iv) Fatigue data are to be included.

v) Design air and water temperature ranges are to be specified and suitably accounted for should their extreme values interfere with the operation of any system component.

5.7.2 System Calculations i) Design analyses are to be submitted that clearly demonstrate the capability of the marine

drilling riser system to withstand the imposed loads for the intended operating envelope.

ii) The operating envelope defines the range of individual operating conditions for which the drilling riser system is suitable and which also defines the boundaries for combinations of operating conditions within the acceptable ranges of individual conditions (e.g., the combination of offset, water depth, mud weight, etc.)

iii) Information to be clearly stated includes the following:

• Elevations of the components and riser joint types.

• Riser section properties for each type of riser joint. This includes joint length, principal tube dimensions, overall drag diameter, number of attached lines, buoyancy devices, bare joint weight, total joint weight in air and water, material characteristics.

• Location and extent of any concentrated loads.

• Details on the properties of the slip joint.

• Details of ball/flex joints.

5.7.3 Support Unit Reports This report is to contain any information pertaining to the supporting unit that affects the marine drilling riser system. Items to be included are unit response amplitude operators (RAOs), physical layout of the drilling floor, derrick and pipe racks, and auxiliary lifting equipment.

5.7.4 Plans Plans are to include arrangement plans, elevations and plan views clearly showing in sufficient detail the overall configurations, dimensions and layout of the marine drilling riser system and all of its components. Plans are to be submitted for each type of connector used in the drilling riser system. See Subsection 2/7 of this Guide for additional details.



5.7.5 Other Data This is to include information in support of novel features utilized in the marine drilling riser system. Novel features will be specially considered by ABS with justifications in accordance with 1/7.7 of this Guide.

7 Drill String Compensation System The drill string compensation system can be categorized as follows:

• Active heave compensation (AHC)

• Passive heave compensation (PHC)

Theory of operation is to be included in design plans and data, and is to include the backup braking system and computer/control redundancy studies.

7.1 Drill String Compensation Equipment Typical components of the drill string compensation equipment, AHC and PHC, would include accumulators, air/nitrogen compressors, air/nitrogen dryers, compensators, control systems/consoles/panels, hydraulic cylinders, HPU, piping, pressure vessels, sheaves, wire ropes, etc.

The design of these equipment and/or components is to be in accordance with the applicable sections of this Guide.

7.1.1 Component Specific Requirements i) Pressure vessels are to be in accordance with Subsection 3/17 of this Guide.

ii) Piping and hoses are to be in accordance with Section 5 of this Guide.



v) Load-carrying parts are to be in accordance with 3/11.3.4 of this Guide.

vi) If the locking mechanism is in the load path, it is to be in accordance with 3/11.3.4 of this Guide.

vii) Hydraulic and pneumatic cylinders are to be in accordance with 3/17.3 of this Guide.

7.1.2 Control Systems for Drill String Compensation i) The control systems are to be in accordance with Subsection 3/15 of this Guide.

ii) Electrical systems are to be in accordance with Subsection 3/19 of this Guide.

iii) Any remotely-operated valve is to be equipped with an emergency backup power source.

9 Bulk Storage, Circulation and Transfer Systems The bulk storage, circulation and transfer system equipment can be categorized as follows:

• Bulk storage and transfer equipment

• Cementing system and equipment

• Mud return (conditioning) system and equipment

• Well circulation system and equipment

• Mud-gas separator/Poorboy (see 3/3.5.4), and Degasser (see 3/3.5.5)



9.1 Bulk Storage and Transfer Equipment Typical components of the bulk storage and transfer equipment would include bulk storage vessels, utility air system, and transport and transfer piping.

i) Provisions are to be made so that utility air used to transport cement or bulk mud is dried to a water dew point of at least 7°C (13°F) below the minimum ambient air temperature.

ii) All utility air piping is to be designed to be purged with dry air prior to transfer operations.

iii) The utility air transfer piping is to be fitted with relief valves set at a pressure not greater than the working pressure of the bulk storage tanks.

iv) Bulk storage vessels are to be fitted with safety relief valves or rupture disks piped to a safe relief area. Unless they are fitted with a relief line to an open area, the use of rupture disks is to be limited to tanks installed in open areas.

v) A P&ID or equivalent schematic of the bulk transfer system is to be clearly posted at the operator station to facilitate operation of the system during well kill circulation.

vi) Piping systems and their components are to be in accordance with Section 5 of this Guide.

vii) Materials used for bulk storage and transfer equipment are to be in accordance with Section 6 of this Guide.

viii) Welding and NDE are to be in accordance with Section 7 of this Guide, as applicable.

ix) The control systems are to be in accordance with Subsection 3/15 of this Guide, as applicable.

x) Electrical systems are to be in accordance with Subsection 3/19 of this Guide.

9.3 Cementing System and Equipment Typical components of the cementing equipment would include cement pump, centrifugal pumps for mixing cement, piping to and from cement pumps, pulsation dampeners and safety valves.

i) The cement pumps are to be arranged to be capable of emergency well kill circulation, using the drilling fluid transferred from the mud pits.

ii) Cement pump installations or modifications to existing installations are to be subjected to ABS review.

iii) The interconnect lines between systems that are used only for emergency well kill circulation are to be fitted with blind or spectacle flanges, lockable valves or similar devices that can be opened as needed, but positively isolate the systems during normal operations. These flanges are to be clearly identified and labeled on the P&ID, and corresponding flanges or valves are to be appropriately identified and their function indicated.

iv) The cement manifold is to be rated to the ram-type BOPs pressure rating.

v) Pressure-retaining equipment associated with cementing equipment is to be in accordance with the requirements of Subsection 3/17 of this Guide.

vi) Piping systems and their components are to be in accordance with Section 5 of this Guide.

vii) Materials used for cementing system and equipment are to be in accordance with Section 6 of this Guide.

viii) Welding and NDE are to be in accordance with Section 7 of this Guide

ix) The control systems are to be in accordance with Subsection 3/15 of this Guide.




9.5 Mud Return System and Equipment Typical components of the mud return equipment would include agitators, chemical mixers, degassers, desanders, desilters, centrifuges, mud pits, dump tanks, piping from degassers to burners or vents, piping of mud return, shale shakers and trip tanks.

i) The mud circulating piping system is to be arranged so that the mud reconditioning system may be run in a series with the degasser, desander, desilter and centrifuge so as to prevent mud from entering other piping systems.

ii) Pressure-retaining equipment associated with mud return equipment is to be in accordance with the requirements of Subsection 3/17 of this Guide.

iii) Piping systems and their components are to be in accordance with Section 5 of this Guide.

iv) Materials used for mud return system and equipment are to be in accordance with Section 6 of this Guide.

v) Welding and NDE are to be in accordance with Section 7 of this Guide, as applicable.

vi) The control systems are to be in accordance with Subsection 3/15 of this Guide.


9.7 Well Circulation System and Equipment Typical components of the well circulation equipment would include mud tank, mud pumps, charge pumps to pipe, pipe to kelly (rotary hose), vibratory hoses, mud booster hoses, standpipe manifold, standpipe, standpipe to kelly hose, gooseneck, top drive/ kelly, bottom-hole assembly (BHA), BHA to flowline, flowline to shale shaker, degasser, desilter, desander.

High-pressure mud pumps are to be fitted with safety relief valves whose maximum setting is no higher than the maximum allowable pressure of the system.

i) Relief lines from the mud system are to be self-draining.

ii) Where rupture disk type pressure relief devices are installed, rupture disks are to be certified to meet a recognized standard and the disk assembly is to be subjected to survey in accordance with the manufacturer’s specifications.

iii) Rotary hoses in well circulation system are to be designed and constructed in accordance with 5/3.7 of this Guide and API Spec 7K.

iv) Piping systems and their components, and flexible lines are to be in accordance with Section 5 of this Guide.

v) Materials used for well circulation systems and equipment are to be in accordance with Section 6 of this Guide.

vi) Welding and NDE are to be in accordance with Section 7 of this Guide, as applicable.

9.7.1 Mud-Gas Separator (Poor Boy), Degasser See 3/3.5.4 and 3/3.5.5 of this Guide.

9.7.2 Mud, Cement and Kill Pumps The mud and cement pumps specified in 3/9.3 and 3/9.7 are to comply with the following requirements:

i) Fluid ends, pressure-retaining components, and mechanical load-bearing components including, but not limited to, gears, shafting, clevis linkages, gears of all types, keyways, splines, etc., are to be in compliance with API Spec 7K or equivalent recognized standard, and the additional requirements of this Guide.

ii) Materials and Welding/NDE used for major pressure-retaining equipment of the fluid ends and mechanical load-bearing components are to be in accordance with Section 6 and Section 7 of this Guide, respectively.



iii) The fluid end and associated manifolds (suction and discharge) are to be hydrostatically tested as required by Section 4, Table 1 of this Guide.

iv) Motor couplings and shafting are to comply with a recognized standard and be suitable for intended service in terms of maximum power and minimum operating temperature.

v) Materials used for discharge manifold components on pumps designated as kill pumps must also comply with 6/5.3, of this Guide regardless of minimum design temperature (MDT).

vi) The pumps are to be equipped with suitable vibration (pulsation) dampening devices.

vii) Discharge high pressure piping to comply with ASME B31.3, or equivalent recognized standard, and Section 5 of this Guide.

viii) The prime movers (electric motor or diesel) are to be in accordance with Subsection 3/21 of this Guide.

9.7.3 Control System for Well Circulation Equipment i) The control systems are to be in accordance with Subsection 3/15 of this Guide.

ii) Electrical systems are to be in accordance with Subsection 3/19 of this Guide.

iii) All valves are to be provided with “open” and “close” indicators.

11 Hoisting, Lifting, Rotating and Pipe Handling Systems The hoisting, lifting, rotating and pipe handling systems equipment can be categorized as follows:

• Derricks

• Hoisting equipment

• Lifting equipment

• BOP handling crane

• Pipe handling equipment

• Riser handling equipment

• Rotary equipment

• Miscellaneous equipment

11.1 Derricks/Masts 11.1.1 Recognized Codes and Standards

i) Except as provided below, the design and fabrication of drilling derricks/masts are to be in accordance with API Spec 4F, MODU Rules, and the additional requirements of this Guide.

ii) Alternatively, other recognized standards may be used when agreed to by ABS. When alternate codes or standards are proposed, comparative analyses are to be provided to demonstrate an equivalent level of safety to the recognized standards as listed in this Guide and to be performed in accordance with 1/7.7 of this Guide, on a case-by-case basis.

iii) The following derrick/mast structural components are considered to be primary load-bearing structure in accordance with the MODU Rules:

• Upper section: crown shaft, main crown beam, main top beams/water table beams

• Lower section: legs, “V” door beams, shoes, and girths

• Main load path structural components



iv) Materials are to be in accordance with Section 6 of this Guide.

v) Welding and NDE are to be in accordance with Section 7 of this Guide, as applicable.

vi) Complete Data Book, as specified in Annex A – A.3 SR3 of API Spec 4F, is to be provided for Surveyor review.

11.1.2 Design Loads For structural design of the derrick/mast, design loads, definition of forces and loads, and applicable loading conditions are to be in accordance with API Spec 4F, and as specified below:

i) Structure failure consequences are to be categorized as medium or higher, as defined in API Spec 4F for the Structural Safety Level (SSL).

ii) The derrick design is to consider both fixed and pinned boundary conditions.

iii) For fixed boundary condition, ABS allows a 20% increase in allowable stresses, as provided in API Spec 4F.

iv) The Owner/Operator is required to specify the geographic region of operation, the static loads (dead weight, hook load, static rotary load, fluid load, setback loads, etc.) and dynamic loads (inertial, dynamic amplification, erection, transportation, wind, transit, motion, acceleration, seismic, etc.) on the derrick/mast, as required in API Spec 4F. Additionally, the following loads are also to be given consideration, where applicable:

a) The accumulation of ice and snow on a structure in increasing its dead load.

b) The wind-induced load is to be included in the design analysis of the derrick/mast structure and is to consider the following, as applicable:

1) The use of wind speeds higher than those provided in API Spec 4F, where required by the Owner/Operator, for regions not specified within API Spec 4F, ISO 19901-1, or API Bull 2INT-MET.

2) The minimum wind velocity for unrestricted offshore service for all normal drilling and transit conditions is not to be less than 36 m/s (70 knots), as specified in 3-1-2/1.3 in the MODU Rules.

• For host structures other than mobile offshore drilling units, such as production unit or fixed structure, the transit conditions are to be in compliance with ABS FPI Guide and ABS FOI Rules.

3) For MODU Rules unrestricted service, the wind speed to be considered in the Survival Case (no hook load or setback loads) is not to be taken less than 51.4 m/sec (100 knots).

4) If only CDS notation is required, it is not mandatory to use wind velocity higher than 51.4 m/sec (100 knots) for regional requirements as specified in API Spec 4F, ISO 19901-1, or API Bull 2INT-MET, unless required by Owner/Operator.

• When requested by Owner/Operator, higher wind velocity is to be used in accordance with regional requirements as specified in API Spec 4F, ISO 19901-1, or API Bull 2INT-MET.

5) When other static and/or dynamic loading conditions are proposed by the Owner/Operator, technical justification in accordance with 1/7.7 of this Guide is to be applied, on a case-by-case basis.

c) The use of a higher rated setback, where required by the operational demands of the Owner/Operator.



d) For dynamic loading due to motion of the hull are to be provided, as specified below, by the Owner/Operator or designer as specified in API Spec 4F for installation, transit, operation, survival condition of the floating units, as applicable. The above conditions are not to be less than those specified in the MODU Rules, Steel Vessel Rules, ABS FOI Rules, and ABS FPI Guide.

1) For the calculation of dynamic loading induced by floating hull motion, the vertical distance and the horizontal distance, where applicable, between the center of flotation of the host drilling unit and the center of gravity of the derrick are to be provided by the Owner/Operator to the derrick designer and are to be used in the calculations.

2) The horizontal distance is to be considered in addition to the vertical distance in the transit condition for self-elevating drilling units.

3) If motion analysis for floating structure is performed, the appropriate acceleration data from the analysis are to be provided for ABS review.

11.1.3 Live Loads for Local Structure and Arrangements i) The arrangement of members is to allow the free drainage of water from the structure.

ii) The following are the minimum vertical live loads that are to be considered in the design of walkways:

• General Traffic Areas – 4,500 N/m2 (94 psf)

• Working Platforms – 9,000 N/m2 (188 psf)

• Storage Areas – 13,000 N/m2 (272 psf)

iii) It is to be noted that various national and international regulatory bodies have requirements for the loading, arrangement and construction of local structure such as guardrails, ladders and walkways. ABS will include in the scope of its design review and fabrication inspection such requirements, when requested.

11.1.4 Allowable Stresses i) To prevent excessive stresses in structural members and connections, or buckling, reference

is to be made to the allowable stress limits given in the AISC or other recognized standard.

ii) AISC permits a one-third increase in permissible stress for loading conditions that include wind loads. Approval to increase AISC-specified stress limits by one-third is to be specially approved for loading conditions which include loads resulting from wind speeds less than 36 m/sec. (70 knots).

iii) Where the one-third increase is granted, it is to be verified that higher stress levels would not have resulted from a loading condition where the wind- and motion-induced loads were ignored and the one-third increase not used. That is, a static hook load analysis is to be performed without using the one-third increase in allowable stress.

iv) The extent to which fatigue has been considered in design is to be indicated in submitted design documentation.

v) For allowable stresses in plate structures, refer to 3/11.1.5 of this Guide.

vi) Consideration is to be given in stress calculations to ensure that maximum stress loads include “Jarring Procedures”.



11.1.5 Equivalent Stress Criteria for Plate Structures i) For plate structures, members may be designed according to the Von Mises equivalent stress

criterion, where the equivalent stress, σeqv, defined as follows, is not to exceed Fy/F.S.

ii) The Factor of Safety (F.S.) will be specially considered when the stress components account for surface stress due to lateral pressures.

σeqv, = 222 3 xyyxyx τσσσσ +−+

where

σx = calculated in-plane stress in the x direction

σy = calculated in-plane stress in the y direction

τxy = calculated in-plane shear stress

Fy = manufacturer’s guaranteed minimum yield point

F.S. = 1.43 for static loading

1.11 for combined loading (includes dynamic loading)

11.1.6 Bolted Connections i) Where bolted connections are used in the derrick, the design documentation, including

torqueing procedures, is to be submitted for ABS review.

ii) Bolted connections in the main load path such as on upper mast, foundation, and crown, etc. are to be provided with secondary retention or locking mechanism.

iii) Bolted connection designs are to consider the following:

• Fatigue

• Design loading in accordance with 3/11.1.2

• Allowable stress in accordance with AISC

iv) Bolt torqueing procedures are to include, but not limited to, sequencing, torque loads, etc.

v) Bolt materials are to be selected with consideration to stress corrosion cracking, fatigue, marine environment, etc.

11.3 Hoisting Equipment Typical components of the hoisting system would include crown block with its support beams, traveling block with its guide track and dolly, sheaves for crown block and traveling block, deadline anchors, drawworks, drilling hook, drilling line and sand line, drilling elevators and links, hydraulic cylinders for overhead lifting, pipe racking, power swivel, bells, and rotary swivel, wire rope and hoisting equipment gears.

11.3.1 Drawworks i) Drawworks are to be provided with primary and emergency braking systems. Both

braking systems are to be designed for full rated load at rated speed.

ii) Drawworks emergency brakes are to be fail-safe design.

iii) Anti-crown collision/upper limits, and lower limits (“Crown-No-Matic” or switches) are to be provided.



iv) Zone management principle is to be followed for all hoisting activity in order to provide additional safety to personnel and collision safeguard associated with drilling activities. Zone management consideration can be any one or combinations of the following:

• Markings

• Strobe light

• Proximity sensors

• Alarms

v) Drawworks control is to be provided with deceleration parameters for upper and lower limits for the traveling block/top drive to safely stopping the load.

vi) Drawworks construction is to comply with API Spec 7F for chains and sprockets.

vii) All mechanical load-bearing components are to be in compliance with API Spec 7K.

viii) The mechanical coupling between the drawworks drum and the electromagnetic brake is to be provided with a system to prevent unintentional disengagement.

ix) Drawworks auxiliary brakes and all other electrical power and control systems are to be suitable for the intended hazardous area.

x) The diameter of auxiliary brake shafts is to be determined by the following equation:

d = 2.42 6 22 )()( mMbT + mm d = 0.10 6 22 )()( mMbT + in.

where

d = shaft diameter at section under consideration, mm (in.)

Y = yield strength (offset = 0.2%, ASTM E-8), kg/mm2 (psi)

b = 0.073 + (19.5/Y) for SI or MKS units

= 0.073 + (27,800/Y) for US units

m = 121/(42.2 + Y) for SI or MKS units

= 172,000/(60,000 + Y) for US units

T = torsional moment at rated speed, kg-cm (lb-in.)

M = bending moment at section under consideration, kg-cm (lb-in.)

xi) For hydrodynamic brake systems, detailed drawings and supporting calculations proving that the proposed braking system is as effective as other drawworks braking systems are to be submitted for review.

xii) Electromagnetic dynamic brake systems are to be arranged to prevent inadvertent failure of the drawworks to suspend the derrick overhead load.

xiii) Electromagnetic systems are to include the following provisions:

a) Cooling water temperature and flow indicators and alarms for abnormal or upset conditions.

b) An automatically activated emergency stop system capable of applying full braking torque to stop and lower the full rated load by the application of friction brake or by connection of the electromagnetic brake to an alternative power supply (back-up battery or UPS).



c) A system that monitors either electrical faults within the system or the kinetic energy of the traveling block arranged to actuate the emergency stop system. Where a fault monitoring system is provided, provisions are to include the following:

1) System must be provided with emergency power source

2) Brake coil current

3) Monitors that initiate emergency stop upon detection of a preset brake coil current or a brake coil current varying in proportion to the driller’s control lever position

4) Brake coil leakage current detector

5) Audible and visual alarms at driller’s control panel to indicate when the limiting parameters of the auxiliary brake have been reached or when the emergency stop system has been activated.

6) In the case of AC motors using variable frequency drives for braking, an abnormality in any of the connected drives is to alarm to the driller’s control station.

d) A manual emergency stop button is to be installed within reach of the driller.

xiv) The control systems are to be in accordance with Subsection 3/15 of this Guide.

xv) Electrical systems are to be in accordance with Subsection 3/19 of this Guide.

11.3.2 Power Swivels, Rotary Swivel, and Top Drives i) Power swivels, rotary swivel and top drives are devices used to rotate the drill string other

than by means of the rotary table.

ii) Major mechanical load-bearing components are to be in accordance with the requirements of 3/11.3.4 of this Guide, as applicable.

iii) Pressure-retaining equipment are to be in accordance with the applicable requirements of Subsection 3/17 of this Guide.

iv) The control systems are to be in accordance with Subsection 3/15 of this Guide.

v) Electrical equipment are to be in accordance with the requirements of Subsection 3/19 of this Guide.

vi) Piping systems are to be in accordance with Section 5 of this Guide.

vii) Gears and couplings are to comply with AGMA or equivalent and be suitable for their intended service in terms of maximum power rating, service life and minimum operating temperature.

11.3.3 Safety Devices and Instrumentation i) The hoisting equipment is to have a weight indicator installed and the display is to be

easily read from the driller’s console.

ii) A safety device is to be installed to prevent the traveling block from contacting the crown block. This safety device is to be designed to be fail-safe (i.e., if the sensor is destroyed or fails, the blocks cease to move).

iii) Testing intervals for the safety devices are to be agreed upon by the Owner/Operator, but is not to be less frequent than as specified by the drawworks manufacturer.

iv) If override to the uppermost limit of travel is provided, it is to be part of the testing, accordingly.



11.3.4 Hoisting Equipment Specific Requirements i) Crown block, sheaves, traveling block, hook, rotary swivel, tubular goods elevators and

other overhead hoisting equipment are to be designed in compliance with API Spec 8A or Spec 8C and the additional requirements of this Guide.

ii) The results of the prototype load test required in API Spec 8A or Spec 8C along with design calculations for the component tested are to be submitted with the design specification outlined in Subsection 2/7 of this Guide.

iii) Materials for mechanical load-bearing or pressure-retaining equipment are to be in accordance with the material traceability and toughness requirements of Section 6 of this Guide.

iv) Welding and NDE are to be carried out in accordance with Section 7 of this Guide, as applicable.

v) Wire rope is to be designed in compliance with API Spec 9A.

vi) Main load-bearing weld connections are to be full penetration. Where partial-penetration welds are utilized, validation through design and fatigue analyses, manufacturing process and procedure qualifications (WPS and PQR) are required.

vii) Lighting fixtures and other equipment installed in the derrick are to be secured against vibration to prevent falling.

viii) Gears having a rated power of 100 kW (135 hp) and over and that are part of the critical load path are to be designed, constructed, certified and installed in accordance with AGMA or equivalent. ABS is to review the design and the gears are to be constructed under the attendance of the ABS Surveyor.

ix) Gears having a rated power of 100 kW (135 hp) and over, but not part of the critical load path, and all gears having a rated power of less than 100 kW (135 hp) are to be designed, constructed and equipped in accordance with recognized commercial and marine practice. Acceptance of such gears will be based on manufacturer’s affidavit stating compliance with a recognized standard, verification of gear nameplate data and subject to a satisfactory performance test after installation conducted in the presence of the Surveyor.

11.5 Lifting Equipment Typical lifting equipment are cranes (gantry, king post, knuckle boom, bridge racker), base-mounted winches, personnel handling devices, specialized automated handling equipment, etc, that are used for pipe handling, riser handling, LMRP handling, BOP handling, and for other lifting and moving activities associated with drilling activities.

11.5.1 Cranes i) Cranes are to be designed, constructed, and tested in accordance with the requirements of

API Spec 2C or the ABS Guide for Certification of Lifting Appliances.

ii) When alternate codes or standards are proposed, comparative analyses are to be provided to demonstrate an equivalent level of safety to the recognized standards as listed in this Guide and to be performed in accordance with 1/7.7 of this Guide, on a case-by-case basis.

iii) Design loads of the crane winches are to be the maximum line pull based on the design loading or the load created by dynamic braking, in accordance with the above design code. In either case, the distribution of loading from the reeving system is to be taken into account.

iv) Allowable stresses are to be in accordance with AISC or other recognized standard.

v) Drums and brakes are to be in accordance with API Spec 2C or the ABS Guide for Certification of Lifting Appliances.

vi) Wire ropes are to be in accordance with API Spec 2C and API Spec 9A.



vii) Design loads of the crane cylinders are to be the loads applied by the crane boom(s), in accordance with the design code. Allowable stresses or minimum scantlings are to be in accordance with ABS Rules or other recognized standard.

viii) Design loading for crane accumulators and crane piping systems is the resultant pressure as a result of the design loadings from the design code.

ix) Zone management principle is to be followed for all lifting activity in order to provide additional safety to personnel and collision safeguard associated with drilling activities. See 3/11.3.1iv).

x) The control systems are to be in accordance with Subsection 3/15 of this Guide.

xi) Electrical systems are to be in accordance with Subsection 3/19 of this Guide.

xii) Pressure vessels are to be in accordance with Subsection 3/17 of this Guide.

xiii) Piping systems are to be in accordance with Section 5 of this Guide.

xiv) Materials are to be in accordance with Section 6 of this Guide.

xv) Welding and NDE are to be in accordance with Section 7 of this Guide, as applicable.

11.5.2 Base-mounted Winches and other Lifting Devices 11.5.2(a) Design Loads. Design loads considered in the design analyses are to include, as appropriate, the following:

• Recommended single line pull at specified speed, drum size and layers of wire rope.

• Maximum load created by dynamic braking.

• Dynamics created by drilling unit motion (where applicable).

11.5.2(b) Design Standards and Factors of Safety.

i) Bases and other structural steel components are to be designed in accordance with AISC or other recognized standard. Allowable stress for bending, tension, shear and buckling are to be as specified herein.

ii) Factors of safety and critical ratios for wire rope, drums, shafts and other parts are as follows:

• Wire rope for lifting application is to be rated in accordance with API Spec 2C.

• Load-carrying member allowable stress is to be no greater than the following:

F = Fcr/1.25 for flat members

= Fcr/1.55 for curved members

Fa = Fy/1.33 Fy/Fu < 0.7

Fa = (Fy + Fu)/3.25 Fy/Fu > 0.7

Fs = 0.577Fa

where

Fa = allowable stress in tension or compression

F = allowable stress for buckling

Fs = allowable shear stress

Fy = material yield stress

Fu = material ultimate stress

Fcr = critical buckling stress

iii) In addition, any combined stresses are not to exceed Fa.



11.5.2(c) Materials and Fabrication.

i) All mechanical parts where failure could terminate the load-carrying capabilities of the systems are to be made of steel.

ii) Use of ductile iron for gears and drum and the use of aluminum for fabrication will be specially considered.

iii) Materials are to be in accordance with Section 6 of this Guide, as applicable.

iv) Welding, heat treatment and NDE are to be in accordance with Section 7 of this Guide, as applicable.

11.5.2(d) Drums.

i) The drum capacity is to accommodate the recommended rope size and length necessary to perform the function required for the load-handling equipment.

ii) Plain or grooved drums will normally be considered acceptable, provided no less than five (5) full wraps of rope remain on the drum with the load in its lowest possible position. Other design specifications/standards will be subject to special consideration based on calculations submitted to ABS.

iii) Each drum end of the rope is to be anchored by a clamp attached to the drum, or by a socket arrangement approved by the hoist or rope manufacturer, providing for attachment of rope to the drum.

iv) The outermost wrap layer of a wire rope in any load case must be at least two rope diameters below the edge of the drum flange.

v) The diameter of the drum is to provide first layer rope pitch diameter of not less than 18 times the nominal diameter of the rope used.

vi) Materials are to be in accordance with Section 6 of this Guide, as applicable.

vii) Welding, heat treatment and NDE are to be in accordance with Section 7 of this Guide, as applicable.

11.5.2(e) Wire Ropes.

i) Wire ropes are to be constructed in accordance with a recognized standard applicable to the intended service, such as API Spec 2C and API Spec 9A.

ii) Usage records such as ton-mile records are to be maintained and wire rope changed out in accordance with manufacturer’s recommendations.

iii) Wire ropes used in non-manriding applications are to be replaced if damage exceeds manufacturer’s specifications for their rated capacity or if damage could affect smooth passage through sheaves.

11.5.2(f) Brakes.

i) A power control braking means such as regenerative, dynamic, counter torque breaking, controlled lowering or a mechanically-controlled braking means are to be provided and are to be capable of maintaining controlled lowering speeds.

ii) Brakes are to set automatically upon loss of power or when the winch lever is returned to neutral.

iii) Brakes are to have the ability to stop and hold 100% of the design load with the outermost layer of wire on the drum.

iv) Thermal capacity of the brakes as outlined in the manufacturer’s ratings or charts is to be suitable for the intended services.

v) Brake linings containing asbestos material are not to be used.

vi) Documentation and calculations for the braking affect of the AC motors are to be submitted when they are the only backup system to the disc brakes.



11.5.3 Personnel Lifting Devices Personnel elevators used for access from/to the drilling areas are to comply with Chapter 5 of the ABS Guide for Certification of Lifting Appliances. Alternative design codes and standards will be specially considered by ABS with justifications in accordance with 1/7.7 of this Guide.

Manriding winches are to comply with the general requirements of this section. In addition, the following minimum criteria are to be complied with:

i) The personnel rated load is to be no greater than 20% of the load calculated in accordance with 3/11.5.2 of this Guide.

ii) The winch operating lever is to automatically return to neutral upon release from any position. All positions are to be clearly marked as to their intended function.

iii) Regardless of ton-miles, wire ropes used in manriding applications are to be replaced if kinks, rust, flattening, strand breakage or other physical damage is visible.

iv) All brakes are to be fail-safe.

v) Brakes are to set automatically upon loss of power or when the winch lever is returned to neutral.

vi) A secondary brake is to be provided to prevent the load from falling in the event of failure of the primary automatic brake.

vii) A clutch capable of disengaging is not to be fitted.

viii) Devices are to be fitted to prevent the winch from overriding or underriding, and a secondary means of lowering personnel is to be provided in case of winch or power failure.

ix) Wire rope for personnel lifting devices is to be in accordance with API Spec 2C and API Spec 9A.

x) Setting of upper limit is to provide at least a vertical clearance of six (6) feet from the upper block, and the lower limit is to be set so that the winch cannot be operated with number of wraps less than specified in 3/11.5.2(d) of this Guide.

xi) All winches are to be identified as “Manrider Only” and marked with their SWL.

xii) The control systems are to be in accordance with Subsection 3/15 of this Guide.

xiii) Electrical systems are to be in accordance with Subsection 3/19 of this Guide.

11.5.4 Lifting Attachments and Pad Eyes i) Design loads and test loads for lifting attachment are to be in accordance with the

requirements of API Spec 2C and API RP 2A WSD, respectively.

ii) Allowable stresses are to be in accordance with the specified design code and standard.

11.5.5 Safety Devices and Instrumentation i) All winches are to be marked with the maximum permissible load allowed for the winch

and its system components.

ii) Where pneumatic winches are provided, the air supply lines are to be sized to operate the winch at safe working loads (SWL).

iii) An air regulator and pressure relief valve, located upstream of the non-return valves, are to be provided to limit air supply pressure to the winch, and the supply lines serving the winches are to be fitted with appropriate non-return valves and water separators/filters before the operating valves.



11.7 Pipe Handling Equipment Typical components of the pipe handling equipment would include elevators, finger boards, racking arms, stabbing boards, iron roughnecks, cranes, winches, and wire ropes.

i) The drilling rig is to be equipped with hydraulic, pneumatic or mechanical equipment capable of lifting, transporting, suspending the drill pipe in the pipe rack, and making up or breaking out the drilling pipe.

ii) All drill pipes, collars, tubing and casing that may be racked in the derrick is to have provisions to be secured in place.

iii) Foundations and storage racks are to be designed to withstand the maximum anticipated setback load of the racked pipe, drill collars and other intended loads.

iv) All storage racks are to be designed to prevent drill collars, pipe and other tubulars from being released from the rack. Racking stands are to have provision for drainage.

v) Major mechanical load-bearing components are to be in accordance with 3/11.3.4 of this Guide.

vi) Hydraulic and pneumatic cylinders are to be in accordance with 3/17.3 of this Guide.

vii) Mechanized pipe handling systems must have their safety controls verified on computer-based racking systems.

viii) Indexing of all mechanical movement must be verified by operational testing. This procedure is to be carried out in all available fingerboard configurations, and system safety verified.

ix) Cranes and winches are to be in accordance with 3/11.5 of this Guide.

x) Zone management principle is to be followed for all pipe handling activity in order to provide additional safety to personnel and collision safeguard associated with drilling activities. See 3/11.3.1iv).

xi) All safety functions are to be provided with visual and audible indicators.

xii) The control systems are to be in accordance with Subsection 3/15 of this Guide.

xiii) Electrical systems are to be in accordance with Subsection 3/19 of this Guide.

11.7.1 Casing Stabbing Boards 11.7.1(a) Rails, Masts, Guides and Runners.

i) The rails and masts supporting the casing stabbing board are to be securely attached to their supports, designed so that they are unable to open under operating conditions and capable of supporting the casing stabbing board in the event of the operation of the safety gear.

ii) The guides and runners are to be designed so that in the event of a roller or wheel failure, the platform cannot become detached from the mast.

iii) Plates that are capable of supporting the weight of the fully loaded platform are to be fitted at the bottom of the rail.

iv) Upper and lower limits are to be provided and tested before use.

11.7.1(b) Controls and Safety.

i) The controls are to be arranged to stop the platform if the raising and lowering handle is released.

ii) Two (2) independent locking devices are to be provided. One (1) locking device is to be engaged when the lifting handle is in neutral and the second is to engage upon failure of the hoisting system.

iii) Fail-safe upper and lower limit switches are to be provided, as applicable.



iv) All platforms are to be fitted with sufficient anchoring points for safety harnesses.

v) A non-slip surface is to be provided on the platform, and adequate handrails, midrails and toe-plates are to be provided in accordance with 5-3-3/1 of the MODU Rules.

vi) The platform is to be fitted with a lock latch mechanism that secures it when it is not in motion.

vii) Additionally, adequate safety gear of the progressive type is to be provided, and designed so that it will be engaged within free fall conditions.

viii) Where two-point operation is used, the operator station in the basket is to override the remote.

ix) A safety override at the remote station is to be installed for use in the event that the work-performing personnel are incapacitated.

11.7.1(c) Hoisting.

i) Hoisting is to be arranged for both raising and lowering of the platform. The arrangement is not to be such that it is possible to lower the platform by brake only.

ii) Means of lowering the man to the drill floor must be provided that will function in case of failure of the normal hoisting mechanism.

iii) A speed-controlling device is to be provided which is designed to prevent the raising and lowering of the platform at speeds in excess of the tripping speed.

iv) The factor of safety for rope or chain is not to be less than 10:1.

v) If rack and pinion systems are used, they are to be designed so that the failure of either a rack or pinion will not cause the platform to fall.

vi) The hoisting system is to incorporate sufficient rope so that there are at least five (5) full turns of rope remaining on the winding drum when the platform is at its maximum level.

vii) The equipment associated with the operation of the casing stabbing board is to be securely anchored to the derrick structure.

viii) The anchorages for rope or chain are to be designed such that they will not be adversely affected by corrosion.

11.9 Rotary Equipment Typical components of the rotary equipment would include master bushing and the rotary table, including its skid adapters and driving unit. The rotary table and its components are to comply with the following requirements, as applicable:

i) All mechanical load-bearing components are to be in compliance API Spec 7K.

ii) Load-bearing beams are to be in accordance with this 3-2-3/5 of the MODU Rules and the requirements for structural materials in Sections 6 of this Guide.



v) The rotary table transmission and associated motor couplings and shafting are to comply with a recognized standard and be suitable for the intended service in terms of maximum power and minimum operating temperature.

vi) The control systems are to be in accordance with Subsection 3/15 of this Guide.

vii) Electrical systems are to be in accordance with Subsection 3/19 of this Guide.



11.11 Miscellaneous Equipment Typical components that can be categorized under miscellaneous equipment in the drilling system could include manual tongs, horizontal BOP transporter/skidders, power slips, power tongs, catwalk, mechanical mousehole and any other handling devices used to aid in the transfer of drilling tubulars and marine drilling riser between the rotary table and storage areas.

i) Major mechanical load-bearing components are to be in accordance with 3/11.3.4 of this Guide.

ii) Hydraulic and pneumatic cylinders are to be in accordance with 3/17.3 of this Guide.

iii) Horizontal BOP transporter/skidders are to be designed with consideration of loads, inertia, stability, pulling requirements, etc.

iv) All tongs are to be capable of being securely attached to the derrick mast or back-up post and anchored by appropriate means such as a wire rope line or stiff arm that will have a breaking strength greater than the force exerted by the tongs.

v) Safety lines on tongs are to be positioned in such a manner that the tongs cannot rotate beyond anticipated limits.

vi) Power tong pressure systems are to be equipped with safety relief valves that are to be set no higher than the maximum working pressure of the system.

vii) Safety cables attached to kelly hose, tongs and other suspended equipment are to be properly secured to prevent their breaking loose in the event of a connection failure.

viii) Suitable NDE on all drill pipe handling and auxiliary equipment are to be carried out on a regular basis and records maintained for review by the attending Surveyors.

ix) The control systems are to be in accordance with Subsection 3/15 of this Guide.

x) Electrical systems are to be in accordance with Subsection 3/19 of this Guide and the MODU Rules.

xi) Piping systems are to be in accordance with Section 5 of this Guide.

xii) Materials are to be in accordance with Section 6 of this Guide and the MODU Rules.

xiii) Welding and NDE are to be in accordance with Section 7 of this Guide, as applicable

13 Well Test System Well test systems are the facilities installed on vessels or mobile offshore drilling units (MODUs) for the purpose of evaluating the quality and/or quantity of the well fluid to determine whether the well is to be completed for production or plugged and abandoned.

Well test systems may include well control equipment, process pressure vessels, piping and electrical components, control systems, burners and gas flares and burner/flare booms.

i) Systems mounted permanently for at least 30 months on an installation and are intended for extended tests or early production are also to comply with the Facilities Guide.

ii) Temporary well test system (for less than 30 months), including burner booms, burners, well test equipment, process pressure vessels, piping, burners and gas flares, and control/safety systems are also to comply with the requirements of this Guide.

iii) In addition to the requirements of this section, skid-mounted packaged equipment is to be in accordance with Subsection 3/23 of this Guide.

iv) Individual well test equipment and/or skid-mounted equipment structural interface with the drilling unit is to be verified for structural adequacy in accordance with the MODU Rules.



13.1 Well Test System and Equipment Well test system, temporary or permanent, and equipment are to be in compliance with the applicable requirements of this Guide, the Facilities Guide and the ABS Guide for Well Test Systems.

i) Well control equipment such as flowheads, test trees and ESD valves are to be suitable for the intended pressure. Design and fabrication are to be in accordance with recognized standards such as API Spec 6A, API Spec 16C, API Spec 6D, and API Spec 6AV1.

ii) Pressure-retaining equipment such as separators, heaters, treaters, nitrogen storage, surge and transfer tanks, etc., are to be in accordance with Subsection 3/17 of this Guide.

iii) At least two (2) relief valves or the equivalent are to be provided on test separators. The relief valve vent lines are to be led outboard at least 120 pipe diameters or connected to a suitable hydrocarbon disposal facility in accordance with 3/13.5 of this Guide.

iv) Any vent line valving is to be interlocked to ensure one open flow path for all vents at any time.

v) Well test oil/gas separators are to be in compliance with the requirements of API Spec 12J.

vi) Piping systems and components are to be in accordance with Sections 5 of this Guide.

vii) Materials are to be in accordance with Section 6 of this Guide.

viii) Welding and NDE are to be in accordance with Section 7 of this Guide, as applicable.

ix) Flexible lines are to be designed and constructed in accordance with 3-3/19.7 and Appendix 3 of the Facilities Guide and 5/3.7 of this Guide.

x) Pumps handling hydrocarbon pumps are to be in compliance with the requirements of ANSI/API Std. 610.

xi) The control systems are to be in accordance with Subsection 3/15 of this Guide.

xii) Electrical components are to be certified for use for their intended service and classified areas as outlined in 3/13.9 of this Guide. Electrical installations are to be in accordance with Subsection 3/19 of this Guide.

xiii) The well test system burner/flare boom structure is to be in compliance with 3/13.3 of this Guide and the ABS Guide for Well Test Systems.

xiv) Skid structures are to be in accordance with Subsection 3/23 of this Guide.

13.3 Burner/Flare Booms 13.3.1 Design

i) The use of the flare boom is to extend and support the burner/flare at a safe distance away from the drilling area. This is to limit exposure of personnel, equipment, and helicopter traffic to vent gas, flare exhaust, or flare radiation.

ii) Flare and vent analysis are to be in compliance with 3-3/11.5 of the Facilities Guide and the additional requirements of this Guide.

13.3.2 Design Loads i) The loads to be considered in the design of a boom structure are to include, as applicable:

• Dead weight of structure, piping, fittings, rigging, snow and ice, walkways, guard rails, etc.

• Wind loads

• Thermal and impulsive loads resulting from the use of the flare

• Vessel motion-induced loads

ii) The values of all design loads are to be listed in the submitted design documentation.



iii) Loads resulting from vessel motions and wind loads can be established using the procedures given in API Spec 4F.

iv) The derivation of loading conditions to be used in the design is to give due account of the operational requirements of the Owner/Operator, and are to reflect both the operational and stowed modes of the boom.

13.5 Hydrocarbon Disposal Facilities Hydrocarbon disposal facilities are to be designed for the intended flow stream composition to safely handle and dispose hydrocarbons. The following specific requirements are applicable:

i) The sizing and design of the hydrocarbon disposal equipment (flare, flare tips, scrubber, piping, pump, atomization equipment, etc.) are to follow the principles of API Std. 521.

ii) Two (2) flares are to be provided on opposite sides of the installation to dispose hydrocarbon in an appropriate downwind direction.

iii) Flares and burner booms are to be arranged such that the incident heat on critical surfaces does not exceed 1500 BTU/hr/ft2 (including solar gain).

iv) In cases where crude oil is burned and atomization is used, atomization medium supply lines are to be provided with a non-return valve or some other approved means of preventing backflow of hydrocarbon into nonhazardous piping systems.

v) Gas flare tip flow rate is generally not to exceed 0.5 Mach. (See API STD 521).

13.7 Surface Safety Systems A system of automatic and manual controls together with shutdown and operating procedures are to be provided in accordance with the principles of API RP 14C with due consideration given to the normal manning during well test operations. The following specific requirements are applicable.

i) Process system pressure, level and temperature are to be monitored.

ii) Gas detection is to be provided in process areas.

iii) Visual and audible alarms are to be set at 20% and 60% (LEL) lower explosive limit and in the presence of H2S 10 PPM and 15 PPM.

iv) Fire-fighting equipment is to be adequate to water deluge process components with at least 10.2 liters per minute per square meter (0.25 gpm per square foot) of component surface area. Equivalent foam or dry chemical systems may be considered.

v) The arrangement of process components onboard is to allow for complete access to process controls and ingress for fire extinguishing agents.

vi) H2S gas detection systems are to be provided.

vii) Each well injection line is to be provided with a check valve located at a flowhead or test tree.

13.9 Classified Areas Classified areas are to be in accordance with the MODU Rules, API RP 500 or API RP 505 and consideration given to the following:

i) Hatches, companionways and ventilators within ten feet of classified areas are to be secured gas tight for the duration of the test program.

ii) Electrical equipment within classified areas is to be suitable for the hazard or de-energized.

iii) Areas around valves and ball and socket hammer unions are to be designated as Class 1 Division 2 (Zone 2) for a distance of 1 m. (3 ft).

iv) Fired heaters and diesel driven machinery (i.e., crude oil pumps, air compressors, etc.) are to have air intakes located at least ten (10) feet from any classified area.

v) Exhausts are to be equipped with spark arresting devices and are to discharge outside classified areas.



13.11 Operational Procedures Operational procedures are to be submitted for ABS review and are to include, but not limited to, the following:

i) Production test plan

ii) Manning requirements

iii) Equipment operations and testing procedures

iv) Process startup and shutdown procedures

v) Fire-fighting procedures

vi) Emergency evacuation procedures

15 Control Systems

15.1 Control Systems 15.1.1 Control System – General

The requirements below are to apply to well control systems, drilling systems and control systems covered by this Guide.

i) The control system (hydraulic, pneumatic, electric, electro-hydraulic, acoustic, etc.) is to be designed where no single control system component failure is to lead to a failure of the controlled system or loss of control.

ii) Transfer between control stations is to comply with the following requirements:

a) Transfer between control stations only applies to drilling control systems and does not apply to BOP, EDS, choke and kill, and diverter control systems.

b) Transfers between control stations are to comply with the following:

1) When control of the system or equipment is possible from more than one control location, control is to be possible only from one control location at a time.

2) Clear method to transfer control between stations is to be provided.

3) At each control location, there is to be an indicator showing which location is in control.

iii) Maximum control system voltages: 250 VAC 50 Hz or 60 Hz or VDC is to be the highest voltage in any of the control system panels.

iv) All safety functions are to be provided with visual and audible indicators

15.1.2 Logic Circuit Features Logic circuit is to comply with the following principles:

i) When logic circuits are used for sequential startup or for operating individual components, indicators are to be provided at the control console to show the successful completion of the sequence of operations by the logic circuit and start-up and operation of the component. If some particular step is not carried out during the sequence, the sequence is to stop at this point.

ii) Manual override is to be fitted in vital functions to permit control in the case of failure of a logic circuit.



15.3 Control Systems for Well Control Equipment Control systems for well control include the BOP, EDS, choke and kill and diverter control systems, as applicable. These control systems are to comply with the following requirements:

i) The control system (hydraulic, pneumatic, electric, electro-hydraulic, acoustic, etc.) is to be designed where no single control system component failure is to lead to a failure of the controlled system, loss of control or loss of well control.

ii) The control system and components are to be in compliance with API Spec 16C, API Spec 16D and with applicable recommended practices such as API RP 53, API RP 59, and API RP 64.

iii) See 3/3.1.2, 3/3.5.9 and 3/3.7.3 of this Guide for control system requirements for individual well control systems and/or equipment.

iv) FMEA, FMECA or similar analysis is also to be conducted to determine compliance with the above requirements and in accordance with Subsection 3/3 of this Guide.

15.5 Electrical Control Systems and Computer-Based Systems 15.5.1 Electrical Control Systems

i) Electrical control systems are to comply with 4-9-1/9 (except 4-9-1/9.9 and 4-9-1/9.11) of the Steel Vessel Rules. For general definitions, 4-9-1/5 of the Steel Vessel Rules may be used, as applicable.

ii) In addition, electrical control systems are to comply with 3/15.7 of this Guide, as applicable.

15.5.2 Computer-based Systems Computer-based systems are to comply with the requirements of 3/15.5.1 of this Guide and 4-9-6/3 (except 4-9-6/3.13 and 4-9-6/3.15) of the Steel Vessel Rules.

In addition, computer-based systems are to comply with the following.

15.5.2(a) Fail Safe. Computer-based systems are to be designed such that any of the system’s components will not cause unsafe operation of the system or equipment being controlled.

15.5.2(b) Failure Modes and Effects Analysis (FMEA). An FMEA is to be used to determine that any component failure will not result in the complete loss of control, the shutdown of the system or equipment being controlled, or other unsafe situation.

15.5.2(c) Failure Mode, Effects and Criticality Analysis (FMECA). An FMECA is an extension of the FMEA to include a criticality analysis that is used to identify the probability of failure modes against the severity of their consequences.

15.5.2(d) Safety Integrity

i) When computer-based systems have safety-related control functions and the associated failure modes identified in the FMEA/FMECA result in an undesirable situation, special consideration may be given, provided the appropriate level of safety integrity has been provided.

ii) The appropriate level is to be determined by the application of recognized industry standard, such as the IEC 61508 Series or the ANSI/ISA 84 Series.

iii) Further, documentation in accordance with the relevant industry standard is to be submitted for review to justify the appropriate safety integrity levels.



15.7 Safety Systems Safety systems are also to comply with the following requirements:

i) Means are to be provided to indicate the cause of the safety action.

ii) Alarms are to be given at each control location, including any local manual control positions, upon the activation of a safety system.

iii) Drilling systems or equipment shutdown by a safety system is to be designed not to restart automatically, unless first actuated by a manual reset.

iv) Systems are to have the following:

• Redundant processor, memory, and networks

• Local and remote I/O modules are to fail in a predetermined fashion when there is loss of communications with the CPU.

• Input and Output points are to be diagnostic type, where the program will read the diagnostic status of the I/O and perform safe actions. The program is to notify the operator if a point fails.

• Inputs and Outputs may be digital communication, discrete, analog with or without a signal riding on the analog signal or a combination.

v) All shutdowns are to be executed in a predetermined logical manner, as specified in the “Shutdown Logic”, and are to indicate or execute actions to:

• Limit the severity of the incident

• Protect personnel

• Limit environmental impact

• Escape, muster, and evacuation process, as necessary

vi) Shutdown is not to result in adverse cascade effects, which result from activation of other protection devices to maintain the facility in a safe condition.

vii) The shutdown systems are to be designed to provide that any ongoing operations can be terminated safely when a shutdown is activated.

viii) Adequate measure is to be provided to prevent accidental unlatching of the wellhead connector, emergency disconnect, and LMRP, such as two-hand function, two-step action, protective cover or equivalent.

ix) Control panels are to be clearly labeled.

17 Pressure-Retaining Equipment

17.1 Pressure Vessels Pressure vessels are considered to be accumulators, heat exchangers, pulsation dampeners, separators (oil/gas), mud-gas separator, degasser.

i) Pressure vessels are to be designed, constructed, and tested in accordance with ASME Boiler and Pressure Vessel Code Section VIII Div. 1 or Div. 2. Alternative design codes and standards will be specially considered by ABS with justifications in accordance with 1/7.7 of this Guide.

ii) Well test oil/gas separators are to be in accordance with the requirements of API Spec 12J.

iii) Materials of manufacturing for pressure vessels are to be in accordance with the specified design code and Section 6 of this Guide, and appropriately selected for the intended service.

iv) Welding and NDE for pressure vessels are to be in accordance with the specified design code and Section 7 of this Guide.



v) Consideration will be given to arrangements and details of pressure vessels that can be shown to comply with other recognized codes and standards, provided they provide an equivalent level of safety to the ASME Code.

vi) The design is also to ensure that stresses due to acceleration forces arising out of the motion of the installation, stresses due to external nozzle loads and moments, and stresses due to any other applicable external forces, such as winds, are within the limits allowed by the design code.

vii) All pressure vessels, accumulators, heat exchangers, and separators are to be suitably supported and properly secured to skid structure or rig floor.

17.3 Hydraulic Cylinders Hydraulic cylinders are to comply with the following requirements:

i) Design and manufacturing are to be based upon the strength criteria of the ASME Boiler and Pressure Vessel Code Section VIII Div. 1 or Div. 2, National Fluid Power Association or other recognized standards.

ii) Hydraulic cylinders that are part of overhead hoisting equipment are to also meet 3/11.3.4 of this Guide.

iii) Materials of manufacturing for hydraulic cylinders are to be in accordance with the specified design code and Section 6 of this Guide, and appropriately selected for the intended service.

iv) Welding and NDE for hydraulic cylinders are to be in accordance with the specified design code and Section 7 of this Guide, as applicable.

19 Electrical Systems and Equipment Electrical systems and equipment are to comply with the MODU Rules and are to comply with API RP 14F or API RP 14FZ.

i) Compliance with industry standards, such as the following, will be specially considered:

• API RP 2003

• IEEE C37.06.1

• IEEE C37.20.6

• IEEE Std. 45

• IEEE Std. 142

• IEEE Std. 242

• NFPA 70

• NFPA 496

• API RP 500

• API RP 505

ii) ABS is prepared to consider other industry standards and practices for electrical equipment, on a case-by-case basis, with justifications through novel features and/or comparative analyses to be provided to demonstrate equivalent level of safety to the recognized standards as listed in this Guide, performed in accordance with 1/7.7 of this Guide.

iii) All electrical components are to be designed to meet safe operating conditions by accounting for maximum and minimum temperatures and vibrations expected during service.

iv) Electrical equipment installed in a hazardous area is to be certified by an independent testing laboratory as suitable for the intended hazard.



21 Rotating Machinery

21.1 Internal Combustion Engines Internal combustion engines are to comply with the following requirements:

i) Engines and their installations are to be in accordance with NFPA Std. No. 37.

ii) The recommended service applications together with curves showing the recommended maximum standard brake horsepower within the recommended speed range for each service are to be submitted.

iii) Testing is to be performed under an approved quality assurance program or in the presence of the Surveyor.

21.3 Electrical Rotating Machinery Electrical machinery (rotating) are to comply with the following requirements:

i) All rotating machines (if any) 100 kW (135 hp) and above are to be of an ABS-approved design in accordance with the MODU Rules, tested in the presence of and inspected by the Surveyor at the plant of the manufacturer.

ii) For machines of less than 100 kW (135 hp), the tests may be carried out by the manufacturer under the attendance of the Surveyor and whose certificate of tests will be acceptable and are to be submitted to ABS.

23 Skid Mounted Equipment A typical list of skid-mounted equipment that provides support to the drilling, completion, testing, etc., operations includes, but is not limited to, the following:

• Utilities and instrument air

• Chemical injection

• Nitrogen generation and charging

• Hydraulics/Pneumatic pumping units (HPU)

• Sea water

• Pressure Wash

• Cementing skid (rental)

• Well test equipment

• Other temporary equipment

Skid mounted equipment are to comply with the following requirements, as applicable:

i) Pressure-retaining equipment is to be in accordance with the requirements of Subsection 3/17 of this Guide.

ii) Piping systems and their components are to be in accordance with Section 5 of this Guide.


iv) Welding and NDE are to be in accordance with Section 7 of this Guide

v) The control systems are to be in accordance with Subsection 3/15 of this Guide.

vi) Electrical systems are to be in accordance with Subsection 3/19 of this Guide.

23.1 Skid Structures Skid structures including the lifting attachments are to comply with the following requirements:

i) Skid structures for drilling system equipment packaged units are to be sufficiently rigid to support the mounted equipment and piping and, as required, to permit lifting during shipment without damage to the equipment or piping.

ii) Structural design calculations for skid units with a center of gravity height of more than 1.5 m (5 ft), or a maximum operating weight in excess of 10 MT (metric tons) or 22.05 Kips, calculated in dry conditions, are to be submitted for review.



iii) Lifting attachment and/or pad eyes, including the attachment to the skid structure are to be designed in accordance with the requirements of API RP 2A WSD and/or the ABS Guide for Certification of Lifting Appliances.

iv) Load testing of the lifting attachment and/or pad eyes, including the attachment to the skid structure is to be performed in accordance with Section 4, Table 1 of this Guide.

23.3 Drip Pans Drip pans are to comply with the following requirements:

i) Drip pans are to be provided to contain liquid spills and leaks from skid-mounted equipment and piping, and to drain the liquid with adequate slope of 1 cm per meter (0.125 inch per foot) into open drain systems.

ii) A minimum 150 mm (6 in.) coaming around the entire perimeter of a skid is to be provided.

iii) Spill containment with less than 150 mm (6 in.) coaming arrangement is subject to special consideration.

iv) Calculations showing sufficient spillage containment for the skid are to be submitted for verification.

v) Skid beams that extend above the drip pan may be considered as meeting the coaming requirement, provided that the drip pan is seal-welded to the skid beams.


Section 4: Scope of Drilling System and Equipment Approval

S E C T I O N 4 Scope of Drilling System and Equipment Approval

1 General This section provides detailed procedures for ABS approval of typical drilling system, subsystems, equipment, and/or components for Classification of drilling system, that require design approval and survey in accordance with Section 4, Table 1.

i) Section 4, Table 1 is provided as a general reference listing, and is not to be considered as the complete drilling system, subsystem, equipment or component listing.

ii) For drilling systems, subsystems, equipment or components not listed, the designer/manufacturer is to contact the appropriate ABS Technical office for guidance on the approval process

iii) ABS is prepared to consider alternative design methodology and industry practice for drilling system, subsystems, equipment, and/or component designs, on a case-by-case basis, with justifications through novel features as indicated in 1/7.7 of this Guide.

3 Approval Process ABS approval of drilling systems, equipment, and/or components is to be in accordance with the applicable codes and/or standards regarding design, fabrication, and testing, and is also to comply with the additional requirements of this Guide.

i) Drilling systems, subsystems, equipment, and/or components, including drilling support systems, are to be approved according to the following general procedures:

a) Design plans and data are to be submitted in accordance with this section and Subsection 2/7 of this Guide.

b) ABS design review for issuance of the following documents:

1) ABS approval letter

2) Independent Review Certificate (IRC), as applicable (see Section 4, Table 1 of this Guide)

c) ABS survey during construction and testing at manufacturing plant, as applicable (see 4/3.3.1, Subsection 8/3, and Section 4, Table 1 of this Guide)

d) ABS survey during installation and commissioning, as applicable (see 4/3.3.2, Subsections 8/5 and 8/7, and Section 4, Table 1 of this Guide)

e) Issuance of reports and certificates (see 4/3.5 and Appendices 3 and 4 of this Guide)

ii) Subsequent approval of individual or unit equipment and/or components can be combined towards the approval of complete systems or subsystems.

iii) ABS design review, survey, and the issuance of applicable reports or certificates constitute the ABS Classification of the drilling system inclusive of the subsystems, equipment and components.



3.1 Design Review Drilling system, subsystems, equipment, and/or components that require ABS design review and, subsequently, an ABS approval letter, and an IRC, as required for ABS Classification, are listed in Subsection 2/7 and Section 4, Table 1 and are detailed throughout this Guide.

i) ABS design review verifies that the design of systems, subsystems, equipment, and/or components meets the requirements of this Guide and the specified design codes, standards, or specifications, as applicable.

ii) The manufacturer must also provide manufacturer’s affidavit of compliance in accordance with 4/3.1.2 of this Guide.

iii) Upon satisfactory completion of the design review process, ABS will issue an ABS approval letter, and an IRC in accordance with Section 4 Table 1 of this Guide.

iv) ABS is prepared to consider manufacturer’s exception(s) to part(s) or section(s) of specified codes, and standards for drilling equipment and/or components, on a case-by-case basis, with justifications through:

• Stress calculations/analysis

• Finite element modeling/analysis

• Testing

• Historical performance/experience data

• Novel features, as indicated in 1/7.7 of this Guide

In this case, the manufacturer must provide details of the exception(s) to part(s) or section(s) of recognized design standards in the “Design Basis” submittal, as referenced in Subsection 2/7 and clearly stated in detail on the manufacturer’s affidavit of compliance as specified in 4/3.1.2 of this Guide.

3.1.1 Design Approved Products – PDA i) Equipment or components, as noted in Section 4, Table 1 of this Guide, that are allowed

and have PDA available, ABS design review and ABS approval letter are not required.

ii) It is to be noted that no changes can be made to the design details on the PDA from the date of issuance. Any design changes will require a revision to the PDA.

iii) Manufacturer/designers with existing PDAs for other equipment or components, not specified in Section 4, Table, 1 of this Guide will be specially considered.

3.1.2 Manufacturer’s Affidavit of Compliance (MAC) i) Manufacturers are required to provide a written affidavit of compliance stating that their

products are designed, manufactured, assembled and tested in accordance with specified codes, standards, or specifications, and the additional requirements of this Guide, as applicable. The codes, standards or specifications must be stated in the manufacturer’s affidavit of compliance.

ii) ABS is prepared to consider manufacturer’s exception(s) to part(s) or section(s) of specified codes, and standards for drilling equipment and/or components, on a case-by-case basis, with appropriate justifications [see 4/3.1iv)].

In this case, the manufacturer must provide details of the exception(s) to part(s) or section(s) of recognized design standards in the “Design Basis” submittal, as referenced in Subsection 2/7 of this Guide and clearly stated in details on the manufacturer’s affidavit of compliance.

iii) The manufacturer’s affidavits of compliance is to accompany the systems, subsystems or equipment placed onboard drilling units and is to be verified by ABS Surveyors prior to final Classification of the drilling system.

iv) See Appendix 2 of this Guide for a sample manufacturer’s affidavit of compliance and its contents.



3.1.3 Extension of Approval i) If drilling equipment and/or components have been previously approved by ABS, the

manufacturer can request extension of approval for a new project, clearly stating that no changes have been made to the equipment and/or components from the previous approval.

ii) If changes are made from previously approved equipment and/or components, documentation identifying and justification of the changes are required to be submitted for ABS review and approval.

3.3 ABS Survey 3.3.1 Survey at Plant

i) ABS Surveyor’s attendance is required at the plant of manufacturing for drilling system, subsystems, equipment, and/or components approval, as indicated in Section 4, Table 1 and in accordance with Subsection 8/3 of this Guide.

ii) Where final testing requires assembly and installation on-board facility, a partial survey report will be issued by the attending Surveyor for the work and partial testing completed at the manufacturing facility. After final testing on-board, the attending Surveyor will issue the final survey reports or CoC.

iii) Upon satisfactory completion of Surveyor’s witness of the completed drilling system, subsystems, equipment, and/or components manufacturing process, a survey report and/or CoC will be issued confirming stages of fabrication surveys with results.

3.3.2 Survey at Installation and Commissioning ABS Survey for the installation and commissioning of drilling systems is to be performed in accordance with Subsection 8/5 and 8/7 of this Guide.

3.5 Issuance of Certificates and Reports 3.5.1 ABS Approval Letter and Survey Reports

i) Upon satisfactory completion of the ABS design review process, based on design plans and data as specified in Subsection 2/7 of this Guide, an ABS approval letter will be issued as indicated by Section 4, Table 1 below.

ii) The ABS approval letter will describe the scope and results, including any applicable comments and correspondences for the design review performed of the submitted design plans and data, and the specified engineering criteria. The approved rating and/or capacity will be indicated for each system, subsystem, equipment or component in the ABS approval letter.

iii) The ABS Surveyor will issue appropriate survey reports for survey activities as specified in Section 4, Table 1 and Section 8/3 of this Guide.

3.5.2 IRC and CoC i) Upon satisfactory completion of the ABS design review process and issuance of ABS

approval letter, based on the design plans and data as specified in Subsection 2/7 of this Guide for well control equipment or components, an Independent Review Certificate (IRC) will be issued when indicated by Section 4, Table 1, in conjunction with the ABS approval letter.

ii) The IRC will describe the scope and results of the design review performed by ABS for the submitted design plans and data, and the specified engineering criteria. The approved rating and/or capacity will be indicated for each system, subsystem, equipment or component covered by the certificate. The certificate can also include a statement of the design compliance with the statutory regulations of the coastal states or supplementary requirements as requested.



iii) Upon issuance of an ABS approval letter, an IRC, and satisfactory completion of the required testing and survey, a Certificate of Conformity (CoC) will be issued when indicated by Section 4, Table 1 of this Guide.

iv) The CoC will affirm that, at the time of assessment and/or survey, the systems, subsystems, equipment, and/or components met the applicable requirements of this Guide with respect to design, manufacturing and testing, and the additional requirements, if any, specified by the Owner/Operator, designer or manufacturer.

v) While IRCs are issued for equipment model number, it is to be noted that CoC are issued for each individual equipment manufactured/fabricated (based on equipment serial number, as applicable)

vi) Appendix 3 and Appendix 4 of this Guide provide samples of IRC and CoC, respectively.

vii) The contents of the IRC and CoC are to be specific to the equipment and its respective design parameters.

3.7 Individual Equipment Approval: Non-Class Installation If specifically requested by the manufacturers, Owner/Operator, or designers, ABS can provide approval of individual equipment or component associated with drilling systems or subsystems in accordance with the requirements of this Guide, and where the installation unit may not be classed with ABS.

i) The individual equipment approval processes are outlined in Subsection 4/3 of this Guide.

ii) The final installation and commissioning surveys, as outlined in Subsection 4/3.i)d) of this Guide, is the responsibility of the Owner/Operator.

3.9 Vendor Coordination Program Major projects are to be coordinated through the ABS Vendor Coordination Program in order to facilitate the progress of the ABS approval process for the drilling systems, subsystems, equipment, and/or components.

i) In such cases, an electronic database reflecting the contents of Section 4, Table 1 of this Guide will be made available to all key personnel associated with the project; the Owner/Operator, the manufacturer, designers/engineers and ABS’s Engineers and Surveyors.

ii) Upon completion of each task outlined in Section 4, Table 1 of this Guide, the respective participant is to update the corresponding field in the database. The completed database is to be documented as part of the final ABS CDS Classification of the drilling system.

TAB

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ruct

ural

Fra

me

X

X

X

X

e

e –

Fram

e an

d pa

deye

s are

to

test

ed a

t 2 ×

wor

king

load

s

Blo

wou

t Pre

vent

er

Equi

pmen

t B

OPs

(Ann

ular

and

Ram

) X

X

X

X

X

X

a

and

b1

a an

d b2

Shea

r ram

s are

to b

e te

sted

to

rate

d/sp

ecifi

ed sh

ear c

apac

ity

[see

3/3

.1.3

viii)

and

3/3.

1.3i

x)]

See

Not

e 2

Blo

wou

t Pre

vent

er

Equi

pmen

t C

lam

ps

X

X

X

X

X

X

b1

a Se

e N

ote

2

Blo

wou

t Pre

vent

er

Equi

pmen

t C

onne

ctor

for W

ellh

ead

X

X

X

X

X

X

a an

d b1

a

and

b2

See

Not

e 2

Blo

wou

t Pre

vent

er

Equi

pmen

t C

ontro

l Sys

tem

/Con

sole

/Pan

el

X

X

X

X

a an

d b1

a

and

b2

b1, b

2 –

Man

ifold

If

hyd

raul

ic o

r pne

umat

ic

cont

rols

, the

n (b

1) a

nd (b

2) a

re

requ

ired,

as a

pplic

able

Blo

wou

t Pre

vent

er

Equi

pmen

t C

ontro

l Hos

es (H

ydra

ulic

) X

X

X

X

b1

a

and

b2

If v

alid

PD

A is

ava

ilabl

e, th

en

AB

S de

sign

revi

ew a

nd A

BS

appr

oval

lette

r are

not

requ

ired

Blo

wou

t Pre

vent

er

Equi

pmen

t C

ontro

l Pod

s (B

lue

and

Yel

low

) w

ith T

est S

tand

s X

X

X

X

a

and

b1

a an

d b2



TAB

LE 1

(con

tinue

d)

App

rova

l Cod

es fo

r Dril

ling

Syst

ems

and

Equi

pmen

t W

ell C

ontr

ol –

Sub

sea

and

Surf

ace

(as a

pplic

able

) (co

ntin

ued)

Equ

ipm

ent

Com

pone

nts

AB

S D

esig

n R

evie

w

AB

S A

ppr.

Lette

r IR

C

MA

C

Surv

ey

at

Ven

dor

CoC

Test

ing

at

Ven

dor

(1, 3

)

Test

ing

On-

boar

d R

emar

ks

Blo

wou

t Pre

vent

er

Equi

pmen

t D

eadm

an S

yste

m

X

X

X

a

a

Blo

wou

t Pre

vent

er

Equi

pmen

t D

rillin

g Sp

ools

X

X

X

X

X

X

b1

b2

Blo

wou

t Pre

vent

er

Equi

pmen

t H

ose

Ree

ls (H

ydra

ulic

Hos

es)

X

X

X

X

a an

d b1

a

and

b2

If v

alid

PD

A is

ava

ilabl

e, th

en

AB

S de

sign

revi

ew a

nd A

BS

appr

oval

lette

r are

not

requ

ired

Blo

wou

t Pre

vent

er

Equi

pmen

t

Hyd

raul

ic F

lexi

ble

and

Rig

id

Pipi

ng –

Onb

oard

, on

Ris

ers a

nd

on B

OP/

LMR

P St

acks

X

X

X

X

b1

a

and

b2

Blo

wou

t Pre

vent

er

Equi

pmen

t H

ydra

ulic

Pow

er U

nit (

HPU

) in

clud

ing

Pum

ps a

nd M

anifo

ld

X

X

X

X

a an

d b1

a

and

b2

Blo

wou

t Pre

vent

er

Equi

pmen

t M

UX

Cab

le R

eels

X

X

X

X

b1

and

e

a “T

estin

g at

Ven

dor”

, as

appl

icab

le

Blo

wou

t Pre

vent

er

Equi

pmen

t Sp

acer

Spo

ols

X

X

X

X

X

X

b1

b2

Blo

wou

t Pre

vent

er

Equi

pmen

t Te

st S

tum

p X

X

X

X

b1

b2

LMR

P A

nnul

ar P

reve

nter

X

X

X

X

X

X

a

and

b1

a an

d b2

If an

nula

r is i

nsta

lled

in L

MR

P,

see “

Blow

out P

reve

nter

Eq

uipm

ent”

abo

ve.

See

Not

e 2

LMR

P Em

erge

ncy

Dis

conn

ect S

yste

m

(ED

S)

X

X

X

X

a an

d b1

a

and

b2

For i

ndiv

idua

l com

pone

nt

test

ing,

see

the

appl

icab

le

com

pone

nt in

this

Tab

le.

LMR

P Fl

ex/B

all J

oint

X

X

X

X

X

X

a

and

b1

a an

d b2

LMR

P Fr

ame

(LM

RP)

X

X

X

X

X

X

e

e

– Fr

ame

and

pade

yes a

re to

be

test

ed a

t 2 ×

wor

king

load



TAB

LE 1

(con

tinue

d)

App

rova

l Cod

es fo

r Dril

ling

Syst

ems

and

Equi

pmen

t W

ell C

ontr

ol –

Sub

sea

and

Surf

ace

(as a

pplic

able

) (co

ntin

ued)

Equ

ipm

ent

Com

pone

nts

AB

S D

esig

n R

evie

w

AB

S A

ppr.

Lette

r IR

C

MA

C

Surv

ey

at

Ven

dor

CoC

Test

ing

at

Ven

dor

(1, 3

)

Test

ing

On-

boar

d R

emar

ks

LMR

P Ju

mpe

r Hos

es (C

hoke

and

Kill

, M

ud B

oost

er, a

nd H

ydra

ulic

) X

X

X

X

X

X

b1

a

and

b2

LMR

P R

iser

Ada

pter

/Ada

pter

Spo

ol

X

X

X

X

X

X

a an

d b1

a

and

b2

LMR

P R

iser

Con

nect

ors f

or B

OP

Stac

k X

X

X

X

X

X

a

and

b1

a an

d b2

Se

e N

ote

2

Mar

ine

Dril

ling

Ris

ers

See

Mar

ine

Dri

lling

Ris

er

Div

erte

r C

ontro

l Sys

tem

/Con

sole

/Pan

el

X

X

X

X

a

a an

d b2

Div

erte

r D

iver

ter H

ouse

with

Ann

ular

Se

alin

g D

evic

e X

X

X

X

X

X

b1

a

and

b2

See

Not

e 2

Div

erte

r H

ydra

ulic

Pow

er U

nit (

HPU

) in

clud

ing

Pum

ps a

nd M

anifo

ld

X

X

X

X

a an

d b1

a

and

b2

Div

erte

r Pi

ping

X

X

X

b1

b2

See

Not

e 2

Div

erte

r V

alve

s X

X

X

X

a

and

b1

a an

d b2

Cho

ke a

nd K

ill

Con

trol S

yste

m/C

onso

le/P

anel

X

X

X

X

a

and

b1

a an

d b2

b1 –

Man

ifold

If

hyd

raul

ic o

r pne

umat

ic

cont

rols

, the

n (b

1) a

nd (b

2) a

re

requ

ired,

as a

pplic

able

Cho

ke a

nd K

ill

Cho

ke a

nd K

ill –

Con

nect

ors

X

X

X

X

X

X

a an

d b1

a

and

b2

See

Not

e 2

Cho

ke a

nd K

ill

Chok

e an

d K

ill –

Val

ves

X

X

X

X

X

X

a an

d b1

a

and

b2

See

Not

e 2

Cho

ke a

nd K

ill

Cho

ke a

nd K

ill –

Man

ifold

s in

clud

ing

Buf

fer T

anks

, Cho

kes,

Spoo

ls a

nd V

alve

s, U

nion

and

Sw

ivel

Join

ts

X

X

X

X

X

X

a an

d b1

a

and

b2

See

Not

e 2

Cho

ke a

nd K

ill

Cho

ke, K

ill F

lexi

ble

(Dra

pe)

Line

s – F

lexi

ble

Line

s, C

onne

ctor

s, En

d Fi

tting

s,

X

X

X

X

X

X

a an

d b1

a

and

b2

See

Not

e 2



TAB

LE 1

(con

tinue

d)

App

rova

l Cod

es fo

r Dril

ling

Syst

ems

and

Equi

pmen

t W

ell C

ontr

ol –

Sub

sea

and

Surf

ace

(as a

pplic

able

) (co

ntin

ued)

Equ

ipm

ent

Com

pone

nts

AB

S D

esig

n R

evie

w

AB

S A

ppr.

Lette

r IR

C

MA

C

Surv

ey

at

Ven

dor

CoC

Test

ing

at

Ven

dor

(1, 3

)

Test

ing

On-

boar

d R

emar

ks

Cho

ke a

nd K

ill

Cho

ke, a

nd K

ill R

igid

Lin

es –

Rig

id P

ipin

g, H

amm

er U

nion

X

X

X

X

X

X

b1

b2

Se

e N

ote

2

Cho

ke a

nd K

ill

Emer

genc

y C

ircul

atin

g Pu

mp

(Pre

ssur

e Si

de)

X

X

X

X

X

X

a an

d b1

a

and

b2

Cho

ke a

nd K

ill

Kill

Uni

t X

X

X

X

a

and

b1

a an

d b2

Cho

ke a

nd K

ill

Hyd

raul

ic P

ower

Uni

t (H

PU)

incl

udin

g Pu

mps

and

Man

ifold

X

X

X

X

a

and

b1

a an

d b2

Aux

iliar

y Eq

uipm

ent

Dril

l Pip

e Sa

fety

Val

ves,

Dril

l St

ring

Floa

t Val

ves,

Non

-ret

urn

(NR)

Val

ve in

Dril

l Stri

ng (I

BO)

X

X

X

X

X

X

b1

a an

d b2

Se

e N

ote

2



TAB

LE 1

(con

tinue

d)

App

rova

l Cod

es fo

r Dril

ling

Syst

ems

and

Equi

pmen

t M

arin

e D

rilli

ng R

iser

Equ

ipm

ent

Com

pone

nts

AB

S D

esig

n R

evie

w

AB

S A

ppr.

Lette

r IR

C

MA

C

Surv

ey

at

Ven

dor

CoC

Test

ing

at

Ven

dor

(1, 3

)

Test

ing

On-

boar

d R

emar

ks

Mar

ine

Dril

ling

Ris

er

Ass

embl

ed M

arin

e D

rillin

g R

iser

and

Sys

tem

a

Com

mis

sion

ing

test

to v

erify

pr

oper

ass

embl

e of

com

plet

e M

arin

e D

rillin

g R

iser

Sys

tem

in

clud

ing

Ris

er T

ensi

oner

.

Mar

ine

Dril

ling

Ris

er

Bal

l and

Fle

xibl

e Jo

ints

X

X

X

X

X

X

a

and

b1

a an

d b2

Mar

ine

Dril

ling

Ris

er

Hyd

raul

ic C

onne

ctor

s X

X

X

X

X

X

a

and

b1

a

Mar

ine

Dril

ling

Ris

er

Ris

er S

ectio

ns in

clud

ing

Join

ts

X

X

X

X

X

X

b1

b1 –

Aux

iliar

y, c

hoke

and

kill

lin

es.

C&

K li

nes,

Mud

Boo

ster

, H

ydra

ulic

Lin

es –

See

ap

plic

able

sect

ions

.

Mar

ine

Dril

ling

Ris

er

Tens

ione

r Rin

g

X

X

X

X

X

X

e

e –

Prod

uctio

n lo

ad te

st a

t 1.

5 ×

max

imum

des

ign

load

s Lo

ad te

st to

incl

ude

bear

ing

shou

lder

and

all

load

-bea

ring

path

Mar

ine

Dril

ling

Ris

er

Tele

scop

ic Jo

int

X

X

X

X

X

X

a, b

1 an

d e

a an

d b2

Lo

ckin

g m

echa

nism

to b

e tes

ted

to 1

.5 ×

max

imum

des

ign

load

s

Ris

er R

unni

ng

Equi

pmen

t G

imba

l (or

Sho

ck A

bsor

ber)

X

X

X

X

e

a e

– Pr

oduc

tion

load

test

at

1.5 ×

max

imum

des

ign

load

s

Ris

er R

unni

ng

Equi

pmen

t G

imba

l (fix

ed)

X

X

X

X

a

e –

Prod

uctio

n lo

ad te

st a

t 1.

5 ×

max

imum

des

ign

load

s

Ris

er R

unni

ng

Equi

pmen

t R

iser

Run

ning

/Han

dlin

g To

ol

X

X

X

X

b1 a

nd e

a

e –

Pro

duct

ion

load

test

at

1.5 ×

max

imum

des

ign

load

s

Ris

er R

unni

ng

Equi

pmen

t R

iser

Spi

der (

used

as

elev

ator

s/lif

ting)

X

X

X

X

a,

b1

and

e a

and

b2

e –

Pro

duct

ion

load

test

at

1.5 ×

max

imum

des

ign

load

s

Ris

er R

unni

ng

Equi

pmen

t R

iser

Spi

der (

fixed

) X

X

X

X

a,

b1

and

e a

e –

Prod

uctio

n lo

ad te

st a

t 1.

5 ×

max

imum

des

ign

load

s



TAB

LE 1

(con

tinue

d)

App

rova

l Cod

es fo

r Dril

ling

Syst

ems

and

Equi

pmen

t M

arin

e D

rilli

ng R

iser

(con

tinue

d)

Equ

ipm

ent

Com

pone

nts

AB

S D

esig

n R

evie

w

AB

S A

ppr.

Lette

r IR

C

MA

C

Surv

ey

at

Ven

dor

CoC

Test

ing

at

Ven

dor

(1, 3

)

Test

ing

On-

boar

d R

emar

ks

Rise

r Ten

sioni

ng S

yste

ms

Acc

umul

ator

s (W

elde

d,

Seam

less

) X

X

X

X

b1

a

and

b2

Hyd

raul

ic o

r Pne

umat

ic

Rise

r Ten

sioni

ng S

yste

ms

Air/

Nitr

ogen

Buf

fer T

anks

X

X

X

X

b1

b2

Rise

r Ten

sioni

ng S

yste

ms

Com

pres

sors

X

X

X

X

a

and

b1

a an

d c

Rise

r Ten

sioni

ng S

yste

ms

Con

trol S

yste

m/C

onso

le/P

anel

X

X

X

X

a

a If

hyd

raul

ic o

r pne

umat

ic

cont

rols

, the

n (b

1) a

nd (b

2) a

re

requ

ired,

as a

pplic

able

Rise

r Ten

sioni

ng S

yste

ms

Dry

ers (

Nitr

ogen

) X

X

X

X

b1

a

Rise

r Ten

sioni

ng S

yste

ms

Hyd

raul

ic C

ylin

ders

X

X

X

X

a

and

b1

a an

d b2

Rise

r Ten

sioni

ng S

yste

ms

Hyd

raul

ic P

ower

Uni

t (H

PU)

incl

udin

g Pu

mps

and

Man

ifold

X

X

X

X

a

and

b1

a an

d b2

Rise

r Ten

sioni

ng S

yste

ms

Nitr

ogen

Gen

erat

ion

Skid

X

X

X

X

a

and

b1

a an

d b2

Rise

r Ten

sioni

ng S

yste

ms

Pipi

ng S

yste

m

X

X

X

X

a an

d b1

a

and

b2

Rise

r Ten

sioni

ng S

yste

ms

Pres

sure

Ves

sels

X

X

X

X

b1

b2

Rise

r Ten

sioni

ng S

yste

ms

Ris

er, G

uide

line

and

Podl

ine

Tens

ione

rs

X

X

X

X

a an

d b1

a

and

b2

Rise

r Ten

sioni

ng S

yste

ms

Ris

er (C

ondu

ctor

) Ten

sion

ing

Uni

t (R

TU/C

TU)

X

X

X

X

a, b

1 an

d e

a an

d b2

Rise

r Ten

sioni

ng S

yste

ms

Shea

ves f

or R

iser

Ten

sion

Li

nes,

Gui

delin

es a

nd P

odlin

es

X

X

X

If

val

id P

DA

is a

vaila

ble,

then

A

BS

desi

gn re

view

and

AB

S ap

prov

al le

tter a

re n

ot re

quire

d

Rise

r Ten

sioni

ng S

yste

ms

Tele

scop

ic A

rms

X

X

X

X

a an

d b1

a

and

b2

Rise

r Ten

sioni

ng S

yste

ms

Wire

Rop

es

X

X

X

X

e

If v

alid

PD

A is

ava

ilabl

e, th

en

AB

S de

sign

revi

ew a

nd A

BS

appr

oval

lette

r are

not

requ

ired



TAB

LE 1

(con

tinue

d)

App

rova

l Cod

es fo

r Dril

ling

Syst

ems

and

Equi

pmen

t D

rilli

ng S

trin

g C

ompe

nsat

ors

Equ

ipm

ent

Com

pone

nts

AB

S D

esig

n R

evie

w

AB

S A

ppr.

Lette

r IR

C

MA

C

Surv

ey

at

Ven

dor

CoC

Test

ing

at

Ven

dor

(1, 3

)

Test

ing

On-

boar

d R

emar

ks

Dril

l Stri

ng

Com

pens

ator

s A

ccum

ulat

ors (

Wel

ded,

Se

amle

ss)

X

X

X

X

a an

d b1

a

Hyd

raul

ic o

r Pne

umat

ic

Dril

l Stri

ng

Com

pens

ator

s C

ompr

esso

rs

X

X

X

X

a an

d b1

a

and

c

Dril

l Stri

ng

Com

pens

ator

s D

ryer

s (A

ir/N

itrog

en)

X

X

X

X

a an

d b1

a

As a

pplic

able

to m

ediu

m u

sed.

Dril

l Stri

ng

Com

pens

ator

s C

ompe

nsat

or A

ssem

bly

X

X

X

X

b1

a

and

b2

Dril

l Stri

ng

Com

pens

ator

s C

ontro

l Sys

tem

/Con

sole

/Pan

el

X

X

X

X

a an

d b1

a

and

b2

b1 –

Man

ifold

If

hyd

raul

ic o

r pne

umat

ic

cont

rols

, the

n (b

1) a

nd (b

2) a

re

requ

ired,

as a

pplic

able

Dril

l Stri

ng

Com

pens

ator

s H

ydra

ulic

Cyl

inde

rs

X

X

X

X

a an

d b1

a

and

b2

Dril

l Stri

ng

Com

pens

ator

s Pi

ping

Sys

tem

incl

udin

g H

ydra

ulic

/ Pn

eum

atic

Hos

es

X

X

X

X

a an

d b1

a

and

b2

If v

alid

PD

A is

ava

ilabl

e, th

en

AB

S de

sign

revi

ew a

nd A

BS

appr

oval

lette

r are

not

requ

ired

Dril

l Stri

ng

Com

pens

ator

s Pr

essu

re V

esse

ls

X

X

X

X

b1

b2

Dril

l Stri

ng

Com

pens

ator

s Sh

eave

s X

X

X

If v

alid

PD

A is

ava

ilabl

e, th

en

AB

S de

sign

revi

ew a

nd A

BS

appr

oval

lette

r are

not

requ

ired

Dril

l Stri

ng

Com

pens

ator

s W

ire R

opes

X

X

X

X

e

If

val

id P

DA

is a

vaila

ble,

then

A

BS

desi

gn re

view

and

AB

S ap

prov

al le

tter a

re n

ot re

quire

d



TAB

LE 1

(con

tinue

d)

App

rova

l Cod

es fo

r Dril

ling

Syst

ems

and

Equi

pmen

t B

ulk

Stor

age,

Cir

cula

tion

and

Tra

nsfe

r Sy

stem

Equ

ipm

ent

Com

pone

nts

AB

S D

esig

n R

evie

w

AB

S A

ppr.

Lette

r IR

C

MA

C

Surv

ey

at

Ven

dor

CoC

Test

ing

at

Ven

dor

(1, 3

)

Test

ing

On-

boar

d R

emar

ks

Bul

k St

orag

e Bu

lk S

tora

ge T

anks

(Pre

ssur

ized

) X

X

X

X

b1

or c

c

Bul

k St

orag

e Pi

ping

for M

ater

ial T

rans

port

Syst

em

X

X

X

X

b1

a an

d b2

Mud

Ret

urn

Agi

tato

rs fo

r Dril

ling

Flui

d

X

a

Mud

Ret

urn

Che

mic

al M

ixer

s

X

a

Mud

Ret

urn

Deg

asse

r X

X

X

X

a

and

b1

a an

d b2

Mud

Ret

urn

Des

ande

r and

Des

ilter

X

X

X

X

a

a

Mud

Ret

urn

Mud

Tan

k

X

X

X

d

Mud

Ret

urn

Pipi

ng (F

rom

Mud

-Gas

Sep

arat

or/

Poor

Boy

to B

urne

rs o

r Ven

ts)

X

X

X

X

a

Mud

Ret

urn

Pipi

ng

X

X

X

X

a an

d b1

a

and

b2

Mud

Ret

urn

Pum

ps (M

ud)

X

X

X

a

and

b1

a an

d b2

Mud

Ret

urn

Shal

e Sh

aker

s X

X

X

a a

Mud

Ret

urn

Trip

Tan

k

d

Wel

l Circ

ulat

ion

(HP)

C

ircul

atio

n H

ead

X

X

X

X

X

X

a an

d b1

a

and

b2

Wel

l Circ

ulat

ion

(HP)

C

ontro

l Sys

tem

/Con

sole

/Pan

el

X

X

X

X

a a

If h

ydra

ulic

or p

neum

atic

co

ntro

ls, t

hen

(b1)

and

(b2)

are

re

quire

d, a

s app

licab

le

Wel

l Circ

ulat

ion

(HP)

C

harg

e Pu

mps

X

X

X

a an

d b1

a

and

b2

Wel

l Circ

ulat

ion

(HP)

G

oose

neck

, Sw

ivel

X

X

X

X

X

X

a

and

b1

a an

d b2

Wel

l Circ

ulat

ion

(HP)

K

elly

X

X

X

X

X

X

a

and

b1

a an

d b2

Wel

l Circ

ulat

ion

(HP)

K

elly

Bus

hing

X

a

Wel

l Circ

ulat

ion

(HP)

K

elly

Coc

ks, F

low

Con

trol V

alves

, M

ain

Stem

, NR

Val

ve (I

BO

P)

X

X

X

X

X

X

a an

d b1

a

and

b2

See

Not

e 2



TAB

LE 1

(con

tinue

d)

App

rova

l Cod

es fo

r Dril

ling

Syst

ems

and

Equi

pmen

t B

ulk

Stor

age,

Cir

cula

tion

and

Tra

nsfe

r Sy

stem

(con

tinue

d)

Equ

ipm

ent

Com

pone

nts

AB

S D

esig

n R

evie

w

AB

S A

ppr.

Lette

r IR

C

MA

C

Surv

ey

at

Ven

dor

CoC

Test

ing

at

Ven

dor

(1, 3

)

Test

ing

On-

boar

d R

emar

ks

Wel

l Circ

ulat

ion

(HP)

M

ixin

g Pu

mps

X

a

Wel

l Circ

ulat

ion

(HP)

M

ud B

oost

er H

oses

X

X

X

X

X

X

b1

a

and

b2

Wel

l Circ

ulat

ion

(HP)

M

ud B

oost

er R

igid

Lin

es

X

X

X

X

X

X

b1

a an

d b2

Wel

l Circ

ulat

ion

(HP)

M

ud G

as S

epar

ator

/Poo

r Boy

X

X

X

X

b1

a

and

b2

Wel

l Circ

ulat

ion

(HP)

Pi

ping

for C

ircul

atin

g D

rillin

g Fl

uid

to th

e W

ell

X

X

X

X

a an

d b1

a

and

b2

Wel

l Circ

ulat

ion

(HP)

Pu

lsat

ion

Dam

pene

rs

X

X

X

X

b1

a

Wel

l Circ

ulat

ion

(HP)

R

otar

y H

oses

(Kel

ly H

oses

), V

ibra

tory

Hos

es

X

X

X

X

X

X

b1

a an

d b2

Wel

l Circ

ulat

ion

(HP)

Sa

fety

Val

ves a

t Mud

Pum

p X

X

X

X

a

a

– V

erifi

catio

n of

inst

alle

d “p

op-o

ff”

safe

ty v

alve

Wel

l Circ

ulat

ion

(HP)

St

andp

ipe

Man

ifold

X

X

X

X

X

X

b1

b2

Cem

entin

g C

emen

t Pum

p (P

ress

ure

Side

) X

X

X

X

b1

a

Cem

entin

g C

entri

fuga

l Pum

ps (F

or M

ixin

g C

emen

t and

Suc

tion)

X

a

Cem

entin

g C

emen

ting

Man

ifold

X

X

X

X

b1

a

and

b2

Cem

entin

g C

emen

t Fle

xibl

e Li

nes

X

X

X

X

b1

a an

d b2

Cem

entin

g Pi

ping

– C

emen

t Pum

p D

ischa

rge

X

X

X

X

b1

a an

d b2

Cem

entin

g Pi

ping

for M

ixin

g C

emen

t and

Su

ctio

n Li

ne to

Cem

ent P

ump

X

X

X

X

b1

a an

d b2

Cem

entin

g Pu

lsat

ion

Dam

pene

rs

X

X

X

X

b1

a

Cem

entin

g Sa

fety

Val

ves

X

X

X

X

a



TAB

LE 1

(con

tinue

d)

App

rova

l Cod

es fo

r Dril

ling

Syst

ems

and

Equi

pmen

t H

oist

ing,

Lift

ing,

Rot

atin

g an

d Pi

pe H

andl

ing

Equ

ipm

ent

Com

pone

nts

AB

S D

esig

n R

evie

w

AB

S A

ppr.

Lette

r IR

C

MA

C

Surv

ey

at

Ven

dor

CoC

Test

ing

at

Ven

dor

(1, 3

)

Test

ing

On-

boar

d R

emar

ks

Der

rick

Der

ricks

and

Mas

ts

X

X

X

X

X

X

See

8/5v

ii)

Hoi

stin

g C

row

n B

lock

incl

udin

g Su

ppor

t B

eam

s X

X

X

X

a

a

Hoi

stin

g D

eadl

ine

Anc

hors

X

X

X

X

a

Hoi

stin

g D

raw

wor

ks in

clud

ing

Foun

datio

n X

X

X

X

a

a

See

8/5v

iii) f

or d

etai

ls.

Hoi

stin

g D

rill W

irelin

e Spo

oler

s X

X

X

X

a

a

Hoi

stin

g D

rillin

g Li

ne an

d Sa

nd L

ine

X

X

X

X

If v

alid

PD

A is

ava

ilabl

e, th

en

AB

S de

sign

revi

ew a

nd A

BS

appr

oval

lette

r are

not

requ

ired

Hoi

stin

g El

evat

ors

X

X

X

X

e a

Onl

y El

evat

ors,

Link

s, Sp

ider

s (w

hen

capa

ble

of b

eing

use

d as

el

evat

ors)

, and

Saf

ety

clam

ps

(whe

n ca

pabl

e of

bei

ng u

sed

as h

oist

ing

equi

pmen

t) re

quire

pr

oof l

oad

test

ing

for e

ach

prod

uctio

n un

it as

per

Sec

tion

8.6

of th

e A

PI S

pec

8C

All

othe

r equ

ipm

ent c

over

ed

in S

ectio

n 1

of A

PI S

pec

8C

requ

ires d

esig

n ve

rific

atio

n te

stin

g in

acc

orda

nce

with

Se

ctio

n 5

of th

e A

PI

Spec

ifica

tion.

Hoi

stin

g G

ears

for H

oist

ing

Equi

pmen

t w

ith ra

ted

pow

er o

f 100

kW

and

ov

er

X

X

X

X

a a

Hoi

stin

g H

ydra

ulic

Cyl

inde

rs fo

r Ove

rhea

d Li

fting

X

X

X

X

a

and

b1

a an

d b2

Hoi

stin

g Li

nks (

Bell

Nip

ple)

X

X

X

X

e

a Pr

oduc

tion

Test

iaw

API

8C



TAB

LE 1

(con

tinue

d)

App

rova

l Cod

es fo

r Dril

ling

Syst

ems

and

Equi

pmen

t H

oist

ing,

Lift

ing,

Rot

atin

g an

d Pi

pe H

andl

ing

(con

tinue

d)

Equ

ipm

ent

Com

pone

nts

AB

S D

esig

n R

evie

w

AB

S A

ppr.

Lette

r IR

C

MA

C

Surv

ey

at

Ven

dor

CoC

Test

ing

at

Ven

dor

(1, 3

)

Test

ing

On-

boar

d R

emar

ks

Hoi

stin

g Po

wer

Sw

ivel

/Top

Driv

e X

X

X

X

X

X

a

and

b1

a an

d b2

e

– Lo

ad te

st a

nd p

ress

ure

test

(b

1) fo

r pro

toty

pe te

stin

g

Hoi

stin

g R

otar

y Sw

ivel

X

X

X

X

X

X

a

and

b1

a an

d b2

b1 –

Hyd

ro te

st a

t 1.5

× ra

ted

pres

sure

for r

ated

pre

ssur

e of

gr

eate

r tha

n 50

00 p

si.

Hyd

ro

test

at 2

.0 x

rate

d pr

essu

re o

f le

ss th

an 5

000

psi.

Hoi

stin

g Sh

eave

s for

Cro

wn

Blo

ck a

nd

Trav

elin

g B

lock

X

X

X

X

a

a

Hoi

stin

g Tr

avel

ing

Blo

ck in

clud

ing

Gui

de T

rack

and

Dol

ly

X

X

X

X

a a

e –

Test

load

s are

to b

e 1.

5 ×

wor

king

load

Hoi

stin

g Tr

avel

Blo

ck (D

rillin

g) H

ook

X

X

X

X

a a

e –

for p

roto

type

test

ing

only

Hoi

stin

g W

ire R

ope

(Win

ches

) X

X

X

X

e

If

val

id P

DA

is a

vaila

ble,

then

A

BS

desi

gn re

view

and

AB

S ap

prov

al le

tter a

re n

ot re

quire

d

Hoi

stin

g

Wire

line

Uni

t X

X

X

X

a

a

Lifti

ng

Bas

e m

ount

ed W

inch

es

X

X

X

X

a, b

1 an

d e

a, b

2 an

d e

Stat

ic lo

ad te

st a

t 125

%

Perf

orm

ance

test

at 1

00%

B

rake

hol

ding

test

at 1

00%

Lifti

ng

BO

P B

ulkh

ead

Gui

ding

X

X

X

X

a

a

Lifti

ng

BO

P H

andl

ing

Cra

ne

X

X

X

X

a, b

1 an

d e

a, b

2 an

d e

Per C

hapt

er 2

of A

BS

Lifti

ng

Appl

ianc

es G

uide

or A

PI 2

C.

Lifti

ng

BO

P Se

afix

ing

X

X

X

X

Lifti

ng

Cra

ne T

ype

Lifti

ng E

quip

men

t X

X

X

X

a,

b1

and

e a,

b2

and

e Pe

r Cha

pter

2 o

f AB

S Li

fting

Ap

plia

nces

Gui

de o

r API

2C

.



TAB

LE 1

(con

tinue

d)

App

rova

l Cod

es fo

r Dril

ling

Syst

ems

and

Equi

pmen

t H

oist

ing,

Lift

ing,

Rot

atin

g an

d Pi

pe H

andl

ing

(con

tinue

d)

Equ

ipm

ent

Com

pone

nts

AB

S D

esig

n R

evie

w

AB

S A

ppr.

Lette

r IR

C

MA

C

Surv

ey

at

Ven

dor

CoC

Test

ing

at

Ven

dor

(1, 3

)

Test

ing

On-

boar

d R

emar

ks

Lifti

ng

Man

rider

Win

ches

(for

dril

ling

equi

pmen

t ser

vice

) X

X

X

X

a,

b1

and

e a,

b2

and

e

Stat

ic lo

ad te

st a

t 125

%

Perf

orm

ance

test

at 1

00%

B

rake

hol

ding

test

at 1

00%

Em

erge

ncy

low

erin

g 10

0%

Lifti

ng

Pers

onne

l Bas

kets

X

X

X

X

a,

and

e

a an

d e

Stat

ic lo

ad te

st a

t 125

%

Perf

orm

ance

test

at 1

00%

B

rake

hol

ding

test

at 1

00%

Em

erge

ncy

low

erin

g 10

0%

Lifti

ng

Pers

onne

l Ele

vato

rs (f

or d

rillin

g eq

uipm

ent s

ervi

ces)

X

X

X

X

a,

b1

and

e a,

b2

and

e Pe

r Cha

pter

5 o

f AB

S Li

fting

Ap

plia

nces

Gui

de

Lifti

ng

Pipe

Rac

king

Mec

hani

sm

X

X

X

X

a, b

1 an

d e

a, b

2 an

d e

Per C

hapt

er 2

of A

BS

Lifti

ng

Appl

ianc

es G

uide

or A

PI 2

C.

Lifti

ng A

ttach

men

ts

Pade

yes (

Perm

anen

t) X

X

X

e

e –

Test

load

s are

to b

e 2 ×

wor

king

load

Pipe

Han

dlin

g B

ridge

Cra

ne

X

X

X

X

a an

d b1

a

and

b2

b2 –

Bef

ore

inst

alla

tion

of

mas

t/der

rick

Pipe

Han

dlin

g C

atw

alk

Ram

p X

X

X

X

a

and

b1

a an

d b2

If

hydr

aulic

catw

alk

is in

stalle

d

Pipe

Han

dlin

g Fi

nger

Boa

rd

X

X

X

X

a a

Mec

hani

cal s

yste

ms o

nly.

Pipe

Han

dlin

g M

onke

y B

oard

X

X

X

X

a

a

Pipe

Han

dlin

g G

uide

Tra

ck a

nd D

olly

X

X

X

X

a

a

Pipe

Han

dlin

g H

oriz

onta

l to

Ver

tical

Equ

ipm

ent

X

X

X

X

a an

d b1

a

and

b2

Pipe

Han

dlin

g H

ydra

ulic

or A

ir Sl

ips

X

X

a an

d b1

a

and

b2

Pipe

Han

dlin

g H

ydra

ulic

Cat

head

X

a

and

b2

Pipe

Han

dlin

g M

anip

ulat

or A

rms

X

X

X

X

a an

d b1

a

and

b2



TAB

LE 1

(con

tinue

d)

App

rova

l Cod

es fo

r Dril

ling

Syst

ems

and

Equi

pmen

t H

oist

ing,

Lift

ing,

Rot

atin

g an

d Pi

pe H

andl

ing

(con

tinue

d)

Equ

ipm

ent

Com

pone

nts

AB

S D

esig

n R

evie

w

AB

S A

ppr.

Lette

r IR

C

MA

C

Surv

ey

at

Ven

dor

CoC

Test

ing

at

Ven

dor

(1, 3

)

Test

ing

On-

boar

d R

emar

ks

Pipe

Han

dlin

g M

echa

nica

l Mou

seho

le

X

X

X

X

a an

d b1

a

and

b2

If hy

drau

lic m

ouse

hole

insta

lled.

Fi

xed

Mou

seho

le d

oes n

ot

requ

ire ap

prov

al an

d su

rvey

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dlin

g M

echa

nica

l Sta

bbin

g B

oard

X

X

X

X

a

a an

d e

Pipe

Han

dlin

g M

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cket

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Han

dlin

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abbi

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oard

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X

X

a a

and

e

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Han

dlin

g W

ire R

ope

X

X

X

X

e

If v

alid

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A is

ava

ilabl

e, th

en

AB

S de

sign

revi

ew a

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BS

appr

oval

lette

r are

not

requ

ired

Rot

ary

Rot

ary

Tabl

e in

cl. S

kid

Ada

pter

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X

a

a

Rot

atin

g M

achi

nery

R

otat

ing

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hine

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rate

d po

wer

of 1

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ver

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atin

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achi

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R

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Mac

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rate

d po

wer

of l

ess t

han

100

kW

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a

a

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cella

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l Sys

tem

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sole

/Pan

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X

a a

If h

ydra

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or p

neum

atic

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ntro

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hen

(b1)

and

(b2)

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re

quire

d, a

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licab

le

Mis

cella

neou

s H

ydra

ulic

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er U

nit (

HPU

) in

clud

ing

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ps a

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anifo

ld

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a

and

b2

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cella

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on R

ough

neck

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a

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cella

neou

s K

elly

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nner

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X

a

a

Mis

cella

neou

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anua

l Ton

gs fo

r Pip

e H

andl

ing

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Mis

cella

neou

s Po

wer

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s X

X

X

a a

Mis

cella

neou

s Po

wer

Ton

gs

X

X

X

a

Mis

cella

neou

s To

ng S

uspe

nsio

n

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a



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LE 1

(con

tinue

d)

App

rova

l Cod

es fo

r Dril

ling

Syst

ems

and

Equi

pmen

t W

ell T

est

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ipm

ent

Com

pone

nts

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S D

esig

n R

evie

w

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S A

ppr.

Lette

r IR

C

MA

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ey

at

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dor

CoC

Test

ing

at

Ven

dor

(1, 3

)

Test

ing

On-

boar

d R

emar

ks

Mis

cella

neou

s B

urne

r Boo

m

X

X

X

a

Mis

cella

neou

s B

urne

r Pip

ing

X

a

Mis

cella

neou

s C

ontro

l Sys

tem

/Con

sole

/Pan

el

X

X

X

X

a a

If h

ydra

ulic

or p

neum

atic

co

ntro

ls, t

hen

(b1)

and

(b2)

are

re

quire

d, a

s app

licab

le

Mis

cella

neou

s El

ectri

cal S

ubm

ersi

ble

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ps

for O

verh

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ls

(Pre

ssur

e Si

de)

X

X

X

a

and

b1

a an

d b2

Mis

cella

neou

s H

eat E

xcha

nger

s X

X

X

X

b1

b2

Mis

cella

neou

s Pi

ping

Sys

tem

X

X

X

X

b1

a

and

b2

Mis

cella

neou

s Pr

essu

re V

esse

ls a

nd S

epar

ator

s X

X

X

X

b1

b2

Mis

cella

neou

s Pu

mps

(Hyd

roca

rbon

Han

dlin

g)

X

X

X

X

a an

d b1

a

and

b2

Mis

cella

neou

s Pu

mps

(Oth

er)

X

X

a an

d b1

a

and

b2

Mis

cella

neou

s Sa

fety

Val

ves

X

X

X

X

a

Mis

cella

neou

s V

alve

s

X

a

and

b2

Test

ing

as a

ssem

bled

pip

ing

syst

em



TAB

LE 1

(con

tinue

d)

App

rova

l Cod

es fo

r Dril

ling

Syst

ems

and

Equi

pmen

t M

isce

llane

ous

Equ

ipm

ent

Com

pone

nts

AB

S D

esig

n R

evie

w

AB

S A

ppr.

Lette

r IR

C

MA

C

Surv

ey

at

Ven

dor

CoC

Test

ing

at

Ven

dor

(1, 3

)

Test

ing

On-

boar

d R

emar

ks

Con

trol

Dril

lers

Con

sole

X

X

X

X

a

a

Elec

trica

l Con

trol

Syst

ems

Con

trol S

yste

m C

ompo

nent

s X

X

X

X

a

a

Han

dlin

g B

OP

Tran

spor

ter/S

kidd

er

X

X

X

X

a an

d b1

a

and

b2

Pipi

ng

Expa

nsio

n Jo

ints

X

X

X

X

b1

b2

Rot

atin

g M

achi

nery

R

otat

ing

Mac

hine

s with

rate

d po

wer

of 1

00 k

W a

nd o

ver

X

X

X

X

e a

Rot

atin

g M

achi

nery

R

otat

ing

Mac

hine

s with

rate

d po

wer

of l

ess t

han

100

kW

X

a

a



TAB

LE 1

(con

tinue

d)

App

rova

l Cod

es fo

r Dril

ling

Syst

ems

and

Equi

pmen

t N

otes

: 1

If sp

ecifi

ed “

Test

ing

at V

endo

r” c

anno

t be

com

plet

ed a

t ven

dor f

acili

ty, t

he sp

ecifi

ed te

st(s

) can

be

perf

orm

ed a

t shi

pyar

d or

dur

ing

com

mis

sion

ing.

2 A

ll w

ell c

ontro

l com

pone

nts

are

to te

sted

“on

-boa

rd”;

firs

t to

a lo

w p

ress

ure

of 1

.38

MPa

to 2

.1 M

Pa (

200

psi t

o 30

0 ps

i) an

d th

en to

the

rate

d w

orki

ng p

ress

ure,

as

appl

icab

le, (

see

API

RP

53).

3 A

pplic

able

to a

ll eq

uipm

ent a

nd c

ompo

nent

s:

a.

In a

dditi

on to

the

test

ing

spec

ified

in T

able

1 a

bove

, all

test

ing

requ

ired

by d

esig

n co

des a

nd st

anda

rds a

re to

be

perf

orm

ed

a.

If p

roto

type

test

ing

is re

quire

d in

acc

orda

nce

with

the

desi

gn c

ode,

this

mus

t be

perf

orm

ed in

depe

nden

tly fr

om it

em a

. abo

ve fo

r des

ign

verif

icat

ion

Test

ing

Not

es:

Typ

es o

f Tes

ting

Con

ditio

ns o

f Tes

ting

a Fu

nctio

nal T

est

In a

ccor

danc

e w

ith d

esig

n pa

ram

eter

s/de

sign

app

rova

l

b1

Hyd

rost

atic

Tes

t 1.

5 tim

es th

e de

sign

pre

ssur

e, o

r in

acco

rdan

ce w

ith a

pplic

able

des

ign

code

s/st

anda

rds.

b2

RW

P H

ydro

stat

ic T

est

At r

ated

wor

king

pre

ssur

e (R

WP)

of s

yste

ms,

subs

yste

ms,

equi

pmen

t and

/or c

ompo

nent

s.

c Pn

eum

atic

Tes

t In

acc

orda

nce

with

des

ign

code

s/st

anda

rds

d Le

ak T

est

Hyd

rost

atic

test

ing

to o

verf

low

/ven

t hei

ght

e Lo

ad T

est

Test

ing

at 1

00%

SW

L or

as s

peci

fied

unde

r "R

emar

ks"

colu

mn.




Section 5: Drilling System Piping

S E C T I O N 5 Drilling System Piping

1 General This section contains general requirements for piping systems and/or associated components that form part of the drilling systems, as follows:

• Blowout preventer control and closing unit

• Choke and kill

• Diverter

• Well circulation

• Bulk mud and cement: mud processing and conditioning, bulk storage and transfer, cementing, etc

• Well test

• Vent system

• Hydraulic piping: BOP/choke and kill/diverter controls, top drive, pipe handling, cranes, lifting appliances, transporters, etc.

i) Piping systems that are used for both marine and drilling services such as hydraulic piping, air piping, seawater service, potable water, power generation, etc., are to be in accordance with Part 4, Chapter 2 of the MODU Rules.

ii) The manufacturer is to submit to ABS for approval P&IDs, piping specifications, design plans and data, and calculations for each piping system associated with the drilling systems listed above.

iii) Piping component pressure-temperature ratings are to be in compliance with ASME B31.3, API Spec 16C, API Spec 16D, API RP 14E and/or other recognized codes/standards, as applicable.

iv) The above requirements are to be used for all drilling system piping and in conjunction with the specific requirements contained in Section 3 of this Guide for individual subsystems used for drilling systems.

3 Design Criteria

3.1 Piping Systems and Components 3.1.1 Design

i) Piping and piping components are to be designed to withstand the maximum stress that could arise from the most severe combination of pressure, temperature, and other loads or service conditions as referenced in 5/3.1.2 below, and to be in accordance with codes and standards referenced in Subsection 5/1 above.

ii) For high-pressure ratings that are not within the scope of the referenced codes in Subsection 5/1 above, pipe wall thickness calculations demonstrating suitability for the intended service are to be submitted for ABS review.



iii) Pipe stress and flexibility analysis are to be performed in accordance with ASME B31.3 or other recognized design code for all applicable service conditions for the following piping systems:

• Choke and kill system

• High-pressure mud and cement system

• Main hoisting system (hydraulic)

• Well test piping system (permanent)

iv) Expansion joints are not to be used in high-pressure well control piping systems.

v) When used, expansion joints or bellows in piping systems are to be provided with shields to prevent mechanical damage and are to be properly aligned and secured.

3.1.2 Service Conditions The piping design is to account for, relative to the fluid being transported, internal and external pressures, transient vibrational stresses, fluid velocity and associated erosional effects, hydraulic hammer, transient temperature excursions, outside imposed impact forces and pressure pulsations, and low temperature service considerations, as applicable.

3.1.3 Allowances The design wall thickness of all piping is to account for, as applicable:

i) Mill under-tolerances (12.5% of nominal piping thickness, unless otherwise stated in the material specification)

ii) Allowances for threads

iii) Corrosion/erosion allowance (unless an effective coating system is applied) is to be in accordance with specified design code/standard and 2/5.5 of this Guide, as applicable.

iv) Fabrication allowance

3.1.4 Alternative Criteria i) ABS is prepared to consider other applicable design references, alternative design

methodology and industry practice for piping system and piping component designs, on a case-by-case basis, with justifications through novel features as indicated in 1/7.7 of this Guide.

ii) Piping components whose dimensions are not specified by recognized codes/standards, design details including dimensional drawings, stress calculations and material data are to be submitted for ABS review and approval.

iii) The extent of NDE, service temperatures, material ductility and special fabrication methods are also to be considered for alternative design criteria.

3.3 Fittings and Valves All piping components are to meet the applicable piping code and the additional requirements in this section.

3.5 Piping Connections 3.5.1 General

i) Piping and connections with outside diameter of 51 mm (2.0 in.) and above are to be made by butt-weld, flanged or screwed union where the threads are not part of the sealing.

ii) Connections for smaller piping sizes and not intended for corrosive fluids can be welded or screwed and seal welded.

iii) For piping system rated at 20.7 MPa (3000 psi) or above, threaded or NPT connections are not to be used. This is typically applicable to high-pressure mud system, choke and kill system, cement system or well test system.



3.5.2 Socket Welds i) All socket-welding connections are to be identified and specially approved by ABS.

ii) Socket-welding of piping connections intended for corrosive, particularly sour services is not to be used.

3.5.3 Threaded Connections i) Threaded connections are only to be used for instrumentation, vents, drains, or similar

purposes and are not to be greater than 12.4 mm (0.50 in.).

ii) Threaded connections are not to be used in systems subjected to bending or vibrational loads.

iii) Flared or other ABS-approved screwed connectors may be used in higher-pressure service.

iv) All screwed connections are to be evaluated, considering the following:

• Pipe outer diameter and thread allowance

• Fluid type, corrosion and fluid leakage risk

• Transient excursions of vibration, pulsation and pressure

3.5.4 Quick Connect Fittings Hammer lock, hammer union or other quick connect type specialty fittings are to have a rated pressure not less than the pipe system design pressure and are to conform to applicable piping codes or alternative standards.

3.7 Flexible Lines/Hydraulic Hoses Typical uses for flexible lines and hydraulic hoses within the well control and drilling system are:

• Rotary and vibratory hoses

• Cementing hoses

• Riser choke and kill flexible lines, drape hoses, and jumper hoses

• Hydraulic hoses for control functions, fluid power and hydraulic fluid transfers

• Hydrocarbon hoses for well testing

3.7.1 Design – Well Control 3.7.1(a) Well Control

i) Rotary and vibratory hoses for drilling services are to comply with the design, and manufactured in API Spec 7K, and the additional requirements specified in this Guide, and to be suitable for their intended service (temperature, fluid compatibility, etc.).

ii) For rotary and vibratory hoses, ABS requires design verification/prototype testing in accordance with Clause 5 of API Spec 7K.

iii) Riser choke, kill and auxiliary flexible lines (drapes and jumpers) are to comply with the design, material, quality control, and prototype testing, including burst testing requirements specified in API Spec 16C, API Spec 16F, and the additional requirements specified in this Guide.

iv) Drape hoses (moonpool lines) at the telescopic joint are to be able to accommodate the relative movement between the riser and the drilling unit.

v) Jumper hoses for flex/ball joints are be able to accommodate the relative movement between the riser and the BOP stack.

vi) Flexible lines for subsea services are to be designed to withstand the external pressure for the operational depth without deforming.



vii) Hydraulic hoses utilized for well control functions are to comply with the requirements of applicable sections of the MODU Rules (for surface hydraulic control hoses only), API Spec 16D and recognized industry standards, such as SAE, National Fluid Power Association, as applicable.

viii) All flexible lines and hydraulic hoses are to be accessible for on-site inspection.

3.7.1(b) Drilling System

i) Hydraulic hoses utilized for drilling system control and hydraulic fluid transfer are to comply with the requirements of applicable sections of the MODU Rules, recognized industry standards, such as SAE, National Fluid Power Association, as applicable.

ii) Gas decompression is to be considered for all flexible lines and hoses being used for conditions where gases or vapor can be present at pressure.

3.7.2 Fire Resistance i) Flexible lines/hydraulic hoses used for well control and are above the water line are to be

fire-resistant.

ii) All flexible lines located in hazardous areas, irrespective of fluid category, are to be fire-resistant.

iii) Flammable fluids are classified as follows:

• Any fluid, regardless of its flash point, able to support a flame.

• Fuel oil, lubricating oil, and hydraulic oil (unless the hydraulic oil is specifically specified as nonflammable).

iv) Flexible lines/hydraulic hoses located subsea are not required to be fire-resistant.

v) Hydraulic hoses are also to be in compliance with the applicable requirements of 4-2-1/7.25 of the MODU Rules.

vi) Fire resistance tests of flexible lines/hydraulic hoses are to be in accordance with API Spec 16C and API Spec 16D, as applicable.

3.7.3 End Connections End connections for flexible lines are to be designed and fabricated to the requirements of 5/3.1 this Guide and applicable recognized codes and standards.

3.7.4 Isolation Valves Isolation valves are to be provided to prevent potential uncontrolled release of flowing medium from flexible lines to minimize the hazard.

3.7.5 Materials i) Material requirements for flexible lines and hydraulic hoses, including end fittings when

exposed to wellbore fluids or a corrosive/erosive environment, are to be in accordance with Section 5 and Section 6 of this Guide and applicable design codes and standards.

ii) Nonmetallic materials used in the manufacturing of flexible line and/or hydraulic hose assemblies are to be suitable for the intended service conditions such as temperature and fluid compatibility.



5 Materials Materials are to be in accordance with the applicable design codes and standards referenced in 5/1iii) above, and Section 6 of this Guide.

5.1 Toughness Piping component toughness requirements are to be in accordance with Section 6 of this Guide.

5.3 Composite Materials Composite materials where used in drilling piping system applications are to be of fire resistant construction and are to be designed and tested to ASME Boiler and Pressure Vessel Code, Section X.

7 Welding and NDE Welding and NDE are to be in accordance with the applicable design codes and standards referenced in 5/1iii) above, and the requirements of Section 7 of this Guide.


Section 6: Materials for Drilling Systems and Equipment

S E C T I O N 6 Materials for Drilling Systems and Equipment

1 General This section provides the requirements in selecting materials for drilling systems and equipment.

All materials are to be suitable for their intended service conditions and defined by recognized material standard.

3 Selection of Structural Steels Selection of structural steel materials associated with drilling structures is to comply with the following requirements:

i) All materials are to be suitable for their intended service conditions and defined by a recognized standard.

ii) Structural steels utilized for drilling structures are considered to be “structural load-bearing” or “load-bearing” components (primary or secondary, see the MODU Rules).

iii) For guidance on the selection of steel for plates, shapes and structural pipe sections, reference is to be made to recognized standards such as API RP 2A-WSD or Section 3-1-3 of the MODU Rules.

iv) Toughness: Where toughness is to be considered in material selection, the toughness testing criteria in Section 3-1-3 and Appendix 3-1-A3 of the MODU Rules and the ABS Rules for Materials and Welding (Part 2) are to be met as a minimum for the principal structural load-bearing components of derricks, masts and burner booms. If there are more stringent requirements imposed in the application of API RP 2A-WSD or API Spec 4F, then these requirements are to be applied.

v) Bolts and Nuts: Bolts and nuts are to have corrosion characteristics comparable to the structural elements being joined and are to be manufactured and tested in accordance with recognized material standards.

5 Selection of Drilling Equipment Materials Selection of materials associated with drilling equipment and/or components is to comply with the following requirements:

i) Materials for drilling and well control equipment are to be selected in accordance to the applicable design codes with consideration to toughness, corrosion resistance, weldability and to be suitable for their intended service conditions.

ii) All materials are to be defined by recognized standards.

iii) Materials for drilling and well control equipment are categorized as follows:

• Mechanical load-bearing component: Component is under force load, N (lb)

• Pressure-retaining equipment: Equipment or component is typically under pressure load, MPa (psi)

• Piping: Typically under pressure load and external loads (see 5/3.1), MPa (psi)

iv) Materials associated with drilling equipment or components are also to comply with the following specific criteria.



5.1 Material Properties To determine the suitability of a material to withstand design stresses, the ultimate tensile strength (UTS), specified minimum yield strength (SMYS), elongation and reduction of area are to be specified in accordance with recognized material standards.

5.3 Toughness 5.3.1 Mechanical Load-Bearing Component

i) Toughness testing for mechanical load-bearing components is to be performed in accordance with relevant API or applicable recognized standards.

ii) Charpy V-Notch (CVN) impact testing is to be performed at the required temperature in the relevant API or applicable standard or the minimum design temperature (MDT), whichever is lower.

iii) For a specified MDT above 0°C (32°F), Charpy V-Notch impact testing is to be performed at 0°C (32°F).

iv) The absorbed energy requirement is to be in accordance with the relevant API or applicable recognized standard.

v) Material for mechanical load-bearing components not covered by, or not in full compliance with API standards or applicable recognized standards, the following Charpy V-Notch criteria applies:

a) For materials with a specified minimum yield strength (SMYS) of 450 MPa (65 ksi) or below:

1) SMYS (N/mm2)/10 = Minimum Absorbed Energy (ave) (J)

b) For materials with a SMYS greater than 450 MPa (65 ksi) and less than or equal to 690 MPa (100 ksi)

1) Minimum Absorbed Energy (ave) = 45 J (33 ft-lb)

c) For materials with a specified minimum yield strength (SMYS) of greater than 690 MPa (100 ksi), Charpy V-Notch properties are to be submitted for ABS review and consideration.

vi) Other CVN criteria or alternative test data, such as crack-tip opening displacement (CTOD), nil ductility transition (NDT) temperature, or related service experience will be considered if submitted to ABS prior to manufacturing.

vii) It should be noted that other national and international regulatory bodies may have additional requirements for toughness. ABS will include these additional toughness requirements in the scope of the design review and fabrication inspection, as applicable, and/or as requested.

5.3.2 Pressure-Retaining Equipment and Piping i) Toughness testing for pressure-retaining equipment and piping is to be performed in

accordance with the relevant API, ASME or applicable recognized standard.

ii) Toughness testing procedures, size, locations and retesting (as applicable) are to be in accordance with the applicable recognized standard.

iii) Charpy V-Notch (CVN) impact testing is to be performed at the required temperature in the relevant API, ASME or applicable standard or the minimum design temperature (MDT), whichever is lower.

iv) For a specified MDT above 0°C (32°F), Charpy V-Notch impact testing is to be performed at 0°C (32°F).

v) The absorbed energy requirement is to be in accordance with the relevant API, ASME or applicable recognized standard.



vi) Materials for pressure-retaining equipment not covered by, or not in full compliance with API, ASME or applicable recognized standards, the following Charpy V-Notch criteria applies:

a) For materials with a specified minimum yield strength (SMYS) of 450 MPa (65 ksi) or below:

1) SMYS (N/mm2)/10 = Minimum Absorbed Energy (ave) (J), but not less than 27 J.

b) For materials with a SMYS above 450 MPa (65 ksi) to 690 MPa (100 ksi):

1) Minimum Absorbed Energy (ave) = 50 J (39 ft-lb)

2) In addition, lateral expansion opposite the notch is not to be less than 0.38 mm (0.015 in.).

c) For materials with a SMYS above 690 MPa (100 ksi), Charpy V-Notch properties are to be submitted for consideration.

1) In addition, lateral expansion opposite the notch is not to be less than 0.38 mm (0.015 in.).

vii) Other CVN criteria or alternative test data, such as crack-tip opening displacement (CTOD), nil ductility transition (NDT) temperature, or related service experience will be considered if submitted to ABS prior to manufacturing.

viii) It should be noted that other national and international regulatory bodies may have additional requirements for toughness. ABS will include these additional toughness requirements in the scope of the design review and fabrication inspection, as applicable, and/or as requested.

5.5 Corrosion – Hydrogen Sulfide Materials used in well control equipment or components that can potentially be exposed to sour or H2S service are to comply with the following requirements.

i) Materials used in well control equipment and systems that will be exposed to well bore fluids are to be selected within appropriate limits of chemical composition, heat treatment and hardness to resist sulfide stress cracking.

ii) For this purpose, selection of material is to be guided by applicable part of NACE MR0175/ISO 15156: Materials for use in H2S containing environment in oil and gas production.

7 Fabrication Considerations

7.1 Welding Welding of drilling equipment and/or components is to comply with the following requirements:

i) Welding is to be in accordance with the specified design/manufacturing code and Section 7 of this Guide.

ii) Generally, weldments subject to H2S service are not to exceed a hardness of 22 Rockwell C in weld metal or heat-affected zone (HAZ), see NACE MR0175/ISO 15156.

7.3 Forming Forming of materials utilized in drilling equipment and/or components are to comply with the following requirements:

i) In general, for steel components, forming at temperatures around 205°C (400°F) is to be avoided.

ii) Where degradation of properties is unavoidable, complete post forming heat treatment may be required.

iii) Suitable supporting data is to be provided to indicate compliance with the specified properties.



iv) For materials with specified toughness properties that are to be formed beyond 3% strain* on the outer fiber, data are to be provided indicating that the toughness properties meet the minimum requirements after forming.

v) After straining, specimens used in toughness tests are to be subjected to an artificial aging treatment of 288°C (550°F) for one hour.

* For details, see 2-4-1/3.13 of the ABS Rules for Materials and Welding (Part 2).

9 Primary Product Form

9.1 General Wrought and cast products are to be procured in accordance with written specifications that, in addition to property requirements, specify the frequency, location, orientation and types of test specimens.

Specific nondestructive examination requirements may be required for some product forms. See 7/11.3 of this Guide.

9.3 Rolled Products Plates, shapes and bars may be supplied in the as-rolled, thermo-mechanically processed, normalized, or quenched and tempered condition, depending on the intended application.

9.5 Forgings Forged products are to be supplied in a fully worked condition to assure a wrought microstructure and internal soundness. A forging reduction ratio of not less than 3:1 will be considered as meeting this requirement.

Where a net change in the cross section does not occur during a portion of the forging operation, the hot-working ratio representing that portion will be evaluated as a complement to the forging reduction ratio.

9.7 Castings In general, cast products are to be supplied in a heat-treated condition. Samples for testing are to be taken from integrally cast coupons or appropriately designed separately cast coupons.

These coupons are to be subjected to the same heat treatment as the casting.

11 Sealing Materials

11.1 Elastomeric Sealants Materials used for sealing are to be suitable for the intended operating pressures and temperatures.

Age-sensitive materials for critical components are to have a defined storage life and be identified in storage as to month and year of manufacture.

11.3 Ring Joint Gaskets Ring joint gaskets are to be of soft iron, low carbon steel or stainless steel, as required by the design standard.

Gaskets that are coated with a protective coating material such as fluorocarbon or rubber for shipment and storage are to have the coatings removed prior to installation.



13 Materials and Traceability

13.1 Materials All materials used for pressure-retaining equipment, mechanical load-bearing components, and load-bearing equipment are to be furnished with documentation that states the process of manufacture and heat treatment, together with chemical analysis and tests that were applied according to recognized standards.

Test coupons are required for each heat treatment for verification of mechanical properties to the manufacturer’s written specification and/or industry standards.

13.3 Traceability Traceability through the manufacturing process is to be documented on major mechanical load-bearing components and pressure-retaining equipment. The manufacturers are responsible for maintaining this documentation on file and, upon request, are to provide this information to ABS.

The traceability documentation is to include:

i) Certified Materials Test Report

• Chemical and mechanical properties for each heat

• Heat treatment temperatures and time at temperature

• Charpy impact values and temperatures

• Hardness test readings (as applicable to NACE MR0175/ISO 15156)

ii) Manufacturing Processes

• Welding records with all approved qualifications

• Post weld heat treatment

• NDE results

• Hardness test results (as applied to NACE MR0175/ISO 15156)

• Dimensional check results

• Hydrostatic pressure tests


Section 7: Welding and Nondestructive Examination

S E C T I O N 7 Welding and Nondestructive Examination

1 General All welds in the pressure boundary of pressure-retaining equipment and piping systems and welds in mechanical load-bearing and structural components are to be made using approved welding procedures by qualified welders and are to be inspected utilizing approved procedures by qualified technicians.

i) Critical sections of primary components are to be examined for surface and volumetric flaws to the extent specified in the design code, but not to a lesser extent than that specified in this section.

ii) The Surveyor is to be satisfied that all welders and welding operators to be employed in the manufacturing of equipment are properly qualified and experienced in the work proposed.

iii) The Surveyor is also to be satisfied as to the employment of a sufficient number of skilled supervisors to ensure a thorough supervision and control of all welding operations.

iv) Inspection of welds employing methods outlined in this section is to be carried out to the satisfaction of the Surveyor.

3 Specifications Welding Procedure Specification (WPS), corresponding Procedure Qualification Record (PQR), and Nondestructive Examination (NDE) procedures are to be submitted for review as part of the design submittal as required in Subsection 2/7 and Section 4, Table 1 of this Guide.

i) WPS, PQR and NDE procedures are to be developed in accordance with the requirements of the selected design codes for the drilling systems, subsystems, equipment and/or components for the intended service.

ii) The requirements and extent of NDE are to be in accordance with the requirements of the selected design codes for the drilling systems, subsystems, equipment and/or components.

3.1 Welding Procedure Specification A written WPS is to be prepared in accordance with Section IX of the ASME Boiler and Pressure Vessel Code, or ANSI/AWS D1.1 Structural Welding Code, or equivalent, depending on the equipment or component.

i) The WPS is to describe in detail all essential and nonessential variables to the welding process (es) employed in the procedure.

ii) Welding procedure specifications are to be qualified and the PQR documenting the following data is to be made available to the attending Surveyors:

• Maximum hardness values (for well bore fluid service)

• Minimum and average toughness values for weld heat-affected zone and weld metal (absorbed energy or lateral expansion, both by Charpy method, where the base metal is required to be impact tested in accordance with Sections 3 or 6 of this Guide)

• Minimum tensile strength

• Results from other tests required by the applicable code or standard



iii) Where welding equipment and consumables have not been used previously at the manufacturer’s facility or are outside of the essential variable limits defined in the existing WPS or if specifically requested by the attending Surveyor, the WPS is to be qualified by welding procedure qualification process in the presence of the Surveyor.

iv) The qualification process may require the submittal of relative WPS and supporting PQRs to the ABS Technical office for review and agreement.

3.3 NDE Procedures NDE procedures are to be specified and the parameters of test specification (method), extent of examination and acceptance criteria are to be submitted for review and be available to the attending Surveyor.

5 Welder/Welding Operator Qualification Welders and welding operators are to be qualified by qualification tests conducted and evaluated in accordance with the applicable code for each welding process and for each position used in production welding.

Welder/welding operator qualification records are to be made available to the Surveyor.

7 Qualification of Nondestructive Technicians The manufacturers are to certify that personnel performing and evaluating the NDE examinations have been qualified and certified in accordance with their employer’s written practice.

i) American Society for Nondestructive Testing (ASNT) Recommended Practice No. SNT-TC-1A or equivalent is to be used as a guideline for employers to establish their written practice for qualification and certification of their personnel.

ii) Certification documents of NDE technicians are to be made available to the Surveyor.

9 Post Weld Heat Treatment Accurate records of all heat treatments during fabrication, including rates of heating and cooling, hold time and soaking temperature are to be made available to the Surveyor.

Alternative methods of stress relief will be subject to special consideration by ABS where post-weld heat treatment is not a requirement of the applicable manufacturing code.

11 Nondestructive Examination All weldments and other critical sections covered under Subsection 7/1 of this Guide are to be subjected to 100% visual examination and nondestructive examination for surface and volumetric defects in accordance with this Guide or the relevant design code.

Examinations are to be carried out after any postweld heat treatment.

11.1 Extent of Examination for Materials and Welds The extent of NDE for materials and welds is to comply with the following requirements:

i) All highly-stressed areas of forgings and castings of primary components used in well control are to be examined for flaws by methods capable of detecting and sizing significant internal defects.

ii) Methods to detect surface flaws are also to be used in special applications. Substantiation is to be provided for areas exempted from examination in the terms of stress levels, quality control procedures at the foundry, forming or casting procedures, or documented historical data.

iii) Repair welds are to be subject to 100% surface NDE.

iv) All welds of structural members considered special are to be inspected 100% by the ultrasonic or radiographic method.

v) Twenty percent of all welds of structural members considered primary are to be inspected by the ultrasonic or radiographic method.



vi) Welds of structural members considered to be secondary are to be inspected by the ultrasonic or radiographic method on a random basis.

vii) In locations where ultrasonic test results are not considered reliable, the use of magnetic-particle or dye-penetrant inspection as a supplement to ultrasonic inspection is to be conducted.

viii) Welds for mechanical load-bearing components or pressure-retaining equipment are to be examined by nondestructive methods capable of detecting and sizing significant surface and internal defects.

11.3 Methods and Acceptance Criteria The methods for performing the nondestructive examination and the acceptance standards to be used for each type of examination, in general, are to be in accordance with the following, as applicable:

11.3.1 Magnetic Particle Examination i) Methods:

• ASME Boiler and Pressure Vessel Code, Section V Article 7: “Magnetic Particle Examination”

• ASTM E709: “Standard Recommended Practice for Magnetic Particle Examination”

ii) Acceptance Criteria:

• ASME Boiler and Pressure Vessel Code, Section VIII, Div. 1, Appendix 6: “Methods for Magnetic Particle Examination (MT)”

11.3.2 Liquid Penetrant Examination i) Methods:

• ASME Boiler and Pressure Vessel Code, Section V Article 6: “Liquid Penetrant Examination”

• ASTM E165: “Standard Practice for Liquid Penetrant Inspection”


• ASME Boiler and Pressure Vessel Code, Section VIII, Div. 1, Appendix 8: “Methods for Liquid Penetrant Examination (PT)”

• ANSI/AWS D1.1: “Structural Welding Code – Steel” Section 6 Part C”

11.3.3 Radiographic Examination i) Methods:

• ASME Boiler and Pressure Vessel Code, Section V Article 2: “Radiographic Examination”

• ASTM E94: “Standard Guide for Radiographic Examination”

• ASTM E446: “Standard Reference Radiographs for Steel Castings up to 2 in. in Thickness”

• ASTM E186: “Standard Reference Radiographs for Heavy Walled (2 to 4.5 in.) (51 to 114 mm) Steel Castings”

• ASTM E280: “Standard Reference Radiographs for (4.5 to 12 in.) (114 to 305 mm) Steel Castings”


• ASME Boiler and Pressure Vessel Code, Section VIII, Div. 1, Appendix 4: “Rounded Indications Charts Acceptance Standard for Radiographically Determined Rounded Indications in Welds.”

• ANSI/AWS D1.1: “Structural Welding Code – Steel” Section 6 Part C”



11.3.4 Ultrasonic Examination i) Methods:

• ASME Boiler and Pressure Vessel Code Section V, Article 5: “UT Examination Methods for Materials and Fabrication”

• ASTM A388: “Standard Practice for Ultrasonic Examination of Heavy Steel Forgings”

• ASTM E428: “Standard Practice for Fabrication and Control of Steel Reference Blocks Used in Ultrasonic Inspection”

• ASTM A609: “Standard Practice for Casting, Carbon, Low-Alloy, and Martensitic Stainless Steel, Ultrasonic Examination Thereof”


• ASME Boiler and Pressure Vessel Code, Section VIII, Div. 1, Appendix 12: “Ultrasonic Examination of Welds (UT)”

• ANSI/AWS D1.1: “Structural Welding Code – Steel Section 6 Part C”

• API RP-2X: “Ultrasonic Examination of Offshore Structural Fabrication and Guidelines for Qualification of Ultrasonic Technicians”

11.3.5 Hardness Testing i) Methods:

• ASTM E10: “Standard Test Methods for Brinell Hardness of Metallic Materials”

• ASTM E18: “Standard Test Methods for Rockwell Hardness and Rockwell Superficial Hardness of Metallic Materials”

• ASTM E92: “Standard Test Method for Vickers Hardness of Metallic Materials”


• NACE MR0175/ISO 1515: “Materials for use in H2S containing environments in oil and gas production”

13 Record Retention The manufacturer(s) is to maintain the following records after completion, and these records are to be made available to the Surveyor upon request:

i) Weld Procedure Specification

ii) Procedure Qualification Records

iii) Welder/welding operator performance test records, including the date and test results and identification of work assigned to each welder

iv) A record providing traceability and capable of identifying the welders who have carried out welding on particular part

v) Qualification records for all personnel performing nondestructive examinations and evaluating results of examination

vi) Nondestructive Examination records, including radiographs (the manufacturer is to provide a suitable viewer to properly illuminate radiographs)


Section 8: Surveys at Vendor’s Plant During Installation and Commissioning

S E C T I O N 8 Surveys at Vendor’s Plant During Installation and Commissioning

1 General This section pertains to surveys of drilling system, subsystem, equipment, and/or components at the vendor’s manufacturing plant and their installation onboard the drilling unit for system build-up and completion for final trials prior to commencement of drilling operations.

3 Surveys at Manufacture and During Assembly When the Surveyor’s attendance at the manufacturer’s plant and at the assembly site is required by the applicable ABS Rules or this Guide, the manufactured/assembled system and/or equipment will be verified for satisfactory compliance with the codes and/or standards, and the additional requirements of this Guide. See Section 4, Table 1 of this Guide for drilling system, subsystem, equipment, and/or component fabrication survey and testing requirements.

i) It is recommended that a prefabrication or kick-off meeting between the manufacturer/fabricator and ABS-designated Surveyor(s) be set in order to, but not limited to:

• Confirm and/or establish the main point of contacts (PoC) for the manufacturer and ABS

• Review the project quality plans

• Review proposed manufacturing specification - See 2/2.27 of this Guide, as applicable

• Review project manufacturing and delivery schedules

• Review and confirm project “hold-points”

• Review any proposed sub-contractor lists and/or qualifications

• Confirm specification, drawings and/or documentation associated with the manufacturing process

ii) ABS Surveyor’s attendance is typically for the following purposes, but not limited to:

• To confirm that the facilities to manufacture, fabricate or repair drilling system subsystem, equipment, and/or components have and maintain an effective quality control program effectively covering design, procurement, manufacturing and testing, as applicable, and meeting the requirements of a recognized standard applied to their product

• To qualify or verify welder’s qualifications to the extent deemed necessary by the attending ABS Surveyor

• To qualify or verify welding procedure specifications and corresponding weld procedure qualification records to the extent deemed necessary by the attending ABS Surveyor

• To verify material certificates/documentation

• To survey fit-up prior to major weldments

• To survey final weldments

• To witness, as far as deemed necessary, nondestructive examination tests of welds and to review records of nondestructive examinations



• To review records of post-weld heat treatment, in particular for piping subjected to pressurized sour service and subject to NACE MR0175/ISO 15156 requirements

• To verify dimensions are as shown on approved drawings

• To check dimensional tolerances and alignment of mating surfaces

• To witness prototype testing of drilling equipment or components in accordance with the applicable API requirements. For drilling equipment of an existing design, documentation of prototype testing is to be made available to the Surveyor for consideration.

• To witness pressure and/or proof-load testing of equipment and as a unit, as applicable and as specified in the fabrication procedures

• To witness final testing and functional testing of subassemblies and completed units, as specified in the fabrication procedures

• To verify all purged and pressurized systems, motor controllers, SCR banks, consoles and instrumentation and control panels are in compliance with approved drawings

• To carry out other inspections as agreed upon during prefabrication meeting

• To review and approval final manufacturing Data Book and issue final survey report or CoC accordingly, and confirm compliance with associated ABS approval letter or IRC.

iii) The materials test report (MTR) of the following components is to be made available to the attending Surveyor during the manufacturing process. In general, materials associated with equipment and/or components that require Surveyor’s attendance in accordance with Section 4, Table 1, are to have complete traceability with MTR’s. As a minimum, MTR’s are to be provided for the following:

• Materials of pressure-retaining components

• All bolts and nuts for fastening

• Materials of primary load-bearing parts.

• All piping, valves and fittings with an ANSI B16.5 Class 150 or greater

3.1 Testing of Well Control Equipment and BOP’s The testing conducted at the manufacturer’s plant and witnessed by the Surveyor for all well control equipment and BOPs is to include the following:

i) Prototype testing in accordance with API Spec 16A of each design is to be performed in the presence of the Surveyor.

ii) A hydrostatic body or shell test, hydraulic operating system test and closed preventer test in accordance with API Spec 16A. All tests are to be documented by a chart recorder.

iii) Shear ram test to verify shear capacity is required in accordance with Subsection 3/3.1 and API Spec 16A.

iv) The manufacturer is to test well control equipment that incorporates a dynamic mode of sealing, for low-pressure integrity at 2.07 MPa (300 psi).

Additional testing requirements are to be in accordance with Section 4, Table 1 of this Guide.

3.3 Testing of Marine Drilling Riser System and Associated Components Components of the marine drilling riser system such as the connectors, tensioning unit, telescopic joint, service lines, etc. (except risers) are to be thoroughly tested to ascertain their compliance with design requirements and their compatibility in forming the complete system.

i) Hydrostatic testing of components is to be carried out at the manufacturer’s plant or rebuilding.

ii) The number of riser joints tested will be as specified in the approved design of the manufacturer, as required in this Guide. See Section 4, Table 1 of this Guide for additional testing requirements.



3.5 Testing of Drill String Compensation System Individual equipment and/or components of the drill string compensation system are to be tested in accordance with the applicable codes and standards, and Section 4, Table 1 of this Guide.

3.7 Testing of Bulk Storage, Circulating and Transfer Systems Individual equipment and/or components of the bulk storage, circulating, and transfer systems are to be tested in accordance with the applicable codes and standards, and Section 4, Table 1 of this Guide.

3.9 Testing of Hoisting, Lifting, Rotating, and Pipe Handling Systems Individual equipment and/or components of the hoisting, lifting, rotating, and pipe handling systems are to be tested (load test, functional test) in accordance with the applicable codes and standards and Section 4, Table 1 of this Guide.

3.11 Testing of Well Test Equipment Survey of well test system, temporary or permanent, and equipment are to be in compliance with the applicable requirements of this Guide, the ABS Facilities Guide and the ABS Guide for Well Test Systems, and are to include, but not limited to, the following:

i) Installation and testing of well test equipment is to be witnessed by Surveyor upon installation of the equipment.

ii) Surveys onboard will verify that the production test plan and procedures are being observed. As a minimum, tests and inspection are to be as follows:

• Pressure-retaining equipment will be inspected visually and a hydrostatic test performed.

• Arrangements of equipment and piping will be inspected visually to determine accessibility of controls.

• Electrical equipment will be inspected for condition, suitability for operation and effectiveness of controls.

• Surface safety systems will be tested to determine if the pressure, level and temperature transducers are in proper working order.

• Fire-fighting equipment will be inspected for condition and arrangements will be surveyed to determine accessibility of all process areas for fire-fighting purposes.

3.13 Testing of Skid Structures Where an equipment/component is to be mounted on a skid structure, an ABS Surveyor’s attendance is required to verify that the skid structure is in compliance with ABS reviewed structural design calculations as referenced in Subsection 3/23 of this Guide, and to at least carry out the following:

i) Verify material test reports (MTR) of skid materials.

ii) Visual examination of final weldments of skid structure.

iii) Witness load testing of the skid structure lifting lugs or pad-eyes. Load test of the skid is to be carried out at maximum static load the lifting lugs or pad-eyes may be subjected to during the transportation or installation of the equipment/machinery onboard the unit.

iv) Witness surface NDE of skid structure weldments of the lifting lugs/pad-eyes, after completion of the skid structure load test. MT is recommended for NDE methodology for surface flaw detection.

v) Examination of drip pan arrangements (see 3/23.3).



5 Onboard Surveys During Installation Onboard installation tests of all drilling systems are to be verified by an ABS Surveyor and are to be in accordance with ABS agreed test procedures. The following surveys are to be carried out by ABS Surveyors on systems during installation and testing in accordance with Section 4, Table 1 of this Guide.

i) Piping systems are to be visually examined, nondestructively examined and pressure-tested, as required by the MODU Rules or applicable API standards.

ii) Pressure tests conducted on Group I piping systems (refer to 4-2-1/1.5 of the MODU Rules) are to be preferably recorded on test charts for the duration of their tests. Minimum time for holding pressure is to be 15 minutes.

iii) All pressure relief and safety valves are to be tested.

iv) Installed choke and kill systems are to be pressure-tested at rated working pressure and also subjected to a low-pressure test at 2.07 MPa (300 psi). Applicable performance tests are to be carried out.

v) Assembly and installation of drilling derrick is to be examined, to include erection of derrick structure, welding and bolt torqueing, water table, crown block and turn-over sheaves assembly, guide rails for hoisting equipment, derrick mounted equipment and outfitting items, installation and pressure testing of drilling and related piping systems, overall dimensional control, and final alignment and bolting on the drill floor/substructure foundations.

vi) Mud pump operational test is to be carried out in accordance with a test procedure agreed by the attending Surveyor.

vii) Derrick

• Assembled and installed derrick is to be visually examined, including welding and bolting, torqueing, its water table, crown block and turnover sheaves assembly, guide rails for hoisting equipment, derrick mounted equipment, and outfitting items.

• Derrick dimensional control, final alignment and bolting on the drill floor/substructure foundations are to comply with manufacturer’s specifications and tolerances.

• API Spec 4F does not require load test of the derrick structure unless specified in the client’s PO as per the supplementary requirements “Appendix A – SR2” of the API Specification. In this regard, this Guide does not require load testing of the derrick.

viii) Drawwork testing onboard installation:

a) As a minimum, the following tests are to be performed for all drawwork brakes in accordance with the ABS Engineering-approved OEMs drawwork test specifications that are also to include the OEM’s acceptance criteria (see 2/7.27):

1) Rotational check: Verify rotation for both directions.

2) Rotational test: 100% rated drum/motor speed in both directions for a period of at least five minutes. With minimum delay between operations, repeat this step three times or in accordance with OEM specifications.

• Bearing temperature for motor, gearbox and drum are to be monitored and recorded.

3) Brake burnishing test: Burnishing test is to be performed for the primary brake with consideration to brake clamping force, drum speed, RPM, or motor speed.

• Temperature at calipers and motor as monitored and recorded.

• The burnishing results such as percentage of lining contact, bright surface, etc.

• Verification of “gapping”, the distance between the brakes and the brake discs, is to be performed.



4) Brake verification: After the brake burnishing test (item 3 above), individual verification of each caliper is to be performed, as applicable, under drum/motor load.

• Motor amperage and voltage, hydraulic pressure, and loads, as applicable, associated with caliper slippage are to be monitored and recorded.

• Each caliper must demonstrate adequate capacity as designed.

5) Dynamic/Performance brake holding test: Performed at 100% rated load for a period of at least 5 minutes for the primary brake. This test is to include, but not limited to, the following:

• Drawwork is to stop its rotation within the timeframe as specified in the approved OEM’s specifications, including the specified applied voltage and amperage

• Monitor and confirm brake holding capability including the caliper pressure, as specified in the approved OEM’s specification.

• Monitor and record caliper pressure, temperature, and fluid flow.

• Visual inspection of brakes and hydraulic leakage are to be performed.

This test may be carried out by using a reduced number of lines with corresponding rated load and in accordance with the drawworks approved OEM’s testing procedures/specifications.

6) Emergency brake test: Simulate loss of hydraulic supply or primary brake failure Verify hydraulic, or air release spring set is functional. This test is to be performed at 100% rated load.

7) Electromagnetic brake test: Electromagnetic braking system tests are to be performed for compliance with approved OEM’s specifications. Additional provisions of the drawworks electromagnetic braking system are provided in 3/11.3.1xiii).

b) On self-elevating units, deflection testing of the cantilever may also qualify as the static and structural testing of drawworks. Additional brake testing is required to be performed in accordance with 8/5viii)a) above, as applicable.

c) On column-stabilized or surface type units, where a full rated load test may constitute increased risk or a safety concern to the unit or personnel, alternative testing methods such as load testing at a reduced number of lines with corresponding rated load may be considered on a case-by-case basis. Request for such consideration is to be submitted to ABS and agreed upon prior to commencement of the test.

ix) Equipment associated with all hoisting, lifting, rotating, and pipe handling systems are part of the drilling system Classification and are to be tested in accordance with Section 4, Table 1 of this Guide.

x) All drilling systems and equipment are to be checked for proper operation.

xi) Control system and shutdowns are to be tested to the satisfaction of the Surveyor.

xii) All wiring and electrical connections are to be checked for continuity and proper workmanship in accordance with the MODU Rules.

xiii) The database developed and completed during construction is to be verified for correctness, amended as required, and endorsed as being part of the onboard ABS documentation, and used as long as the drilling system is maintained under ABS Classification.

xiv) The completed burner assembly is to be pressure-tested from the flexible line connection flange to the burner head. The adequacy of the boom’s slewing and topping gear is to be demonstrated by testing after the boom’s installation on the drilling unit. The details of the test procedure are to be agreed upon with ABS and witnessed by a Surveyor.



5.1 Testing of Base-mounted Winches and Other Lifting Appliances Testing of base-mounted winches and other lifting appliance are to comply with the following requirements and procedures:

i) Load Test – After installation, the system is to be tested with a load equal to 125% of the rated capacity in the presence of the Surveyor. Satisfactory operation of power drives and brakes is to be demonstrated. After being tested, the system with all its components is to be visually examined for permanent deformation and failure.

ii) Performance Test – Testing in the presence of the Surveyor is to demonstrate that rated line pull can be achieved at rated speed with the outermost layer of wire on the drum.

iii) Brake Holding Test – It is to be demonstrated that the brakes have the ability to stop and hold 100% of the design load. Confirmatory testing to demonstrate the braking effect of variable frequency drive AC motors is to be carried out upon installation onboard.

5.3 Testing of Burner/Flare Boom The adequacy of the boom’s slewing and topping gear is to be demonstrated by testing after the boom’s installation on the drilling unit. The details of the test procedure are to be agreed upon with ABS and witnessed by a Surveyor.

Functional testing of the completed burner assembly is to be carried out by pressure testing from the flexible line connection flange to the burner head.

7 Commissioning Surveys of the Drilling Systems Commissioning of all drilling systems is to be verified by an attending ABS Surveyor and is to be in accordance with ABS agreed test procedures. Commissioning surveys are at a minimum to include verification of the following items by the attending Surveyor during the drilling system trials:

i) Proper hook-up and testing of the entire drilling system equipment and components is completed prior to commissioning. This is to include all tests outlined in Subsection 8/5 of this Guide.

ii) Necessary safety precautions are taken during commissioning, which are to include checks of operational readiness of the fire and gas detection system, fire extinguishing system, ESD systems, unobstructed escape routes, etc.

iii) Necessary communication procedures are established prior to commissioning.

iv) Necessary emergency procedures are readily available to deal with any contingencies such as spillage, fire, and other hazards. Drills prior to commencement of commissioning may be carried out to the satisfaction of the attending Surveyor to confirm readiness of these procedures.

v) Readiness of all utility support systems, including main and auxiliary sources for the drilling system, prior to commissioning. Random start-up and testing of the utility support systems to extent deemed necessary by the attending Surveyor.

vi) Readiness of the purged drilling system equipment/components, and associated alarms and shutdowns, prior to commissioning, and random testing of the purged alarms systems during commissioning, to the satisfaction of the attending Surveyor.

vii) Proper operation of the mud level alarms while the drilling system is running, including random simulation of associated alarms.

viii) Proper operation of the hazardous area access and ventilation system while the drilling system is running, including random simulation of associated alarms and shutdowns.

ix) System’s capability to control the flow of the well affluent in a stabilized manner, without undue control upsets, when drilling medium is introduced into the system.



x) Satisfactory functioning of all drilling systems installed onboard and covered under this Guide. This will include witnessing proper function of the following systems, as applicable, while simulating actual drilling operations to the extent possible and practicable, and to the satisfaction of the attending Surveyor:

• Well control system

• Marine drilling riser system

• Drill string compensation system

• Bulk storage, circulating and transfer system

• Hoisting, lifting, rotating and pipe handling system

• Well test system

• Miscellaneous support systems

xi) Satisfactory testing of all ROV intervention functions on the subsea BOP stack during the stump test and testing at least one set of rams in initial test to the satisfaction of the Surveyor.

xii) Satisfactory functional testing of autoshear, deadman, and EDS systems on the subsea BOP stack during the stump test to the satisfaction of the Surveyor.

xiii) Starting up of the permanent well test system, if applicable, including precautions taken to eliminate the risk of explosion or fire.

xiv) Post-commissioned drilling system is in stabilized and satisfactory functioning order for duration of at least 12 hours.

xv) Satisfactory functioning of the emergency power equipment to ensure proper operations.


Section 9: Surveys After Construction and Maintenance of Class

S E C T I O N 9 Surveys After Construction and Maintenance of Class

1 General The provisions of this section are requirements for the maintenance of Classification of the drilling systems. These requirements are in addition to the provisions noted in other ABS Rules such as Part 6 of the MODU Rules.

i) All surveys (annual and special periodical) are to be carried out in accordance with an ABS agreed In-Service Inspection Program (ISIP) plan developed by the Owner/Operator for periodical inspection and testing of the overall drilling system.

ii) The ISIP plan is to explain how each system and equipment is to be examined and tested during annual and special periodical survey.

iii) Maintenance records of the drilling system, including the ABS-issued MRNs, are to be part of the record kept onboard the drilling unit.

iv) When ABS is authorized to perform surveys on behalf of a governmental authority, or when requested by the Owner/Operator, items as specified by the governmental authority or Owner/Operator will be surveyed. Reports indicating the results of such surveys will be issued.

v) For purposes of this section, the commissioning date of the drilling system will be the date on which a Surveyor issues an Interim Class Certificate for the drilling unit with the CDS notation.

3 Surveys Onshore and Issuance of Maintenance Release Notes During operation of the drilling unit when parts of the classed drilling system equipment are returned ashore for maintenance, repair or modification purposes, it is the responsibility of the Owner/Operator to inform Surveyors of the scope of work at the shore facility/plant.

i) The maintenance, repair, or modification of drilling systems, subsystems, equipment or component is to be in accordance with the OEM’s specifications.

ii) Surveyors are to attend the facility/plant for all required function, load and/or pressure testing carried out on the drilling system equipment prior to their release back offshore to the drilling unit. Tests conducted are to follow guidelines outlined in API standards or equivalent.

iii) Upon satisfactory completion of tests and visual examination, a “Maintenance Release Note” (MRN) is to be issued by the attending Surveyor, subject to satisfactory installation of the component on the drilling unit and examination of the component during the forthcoming Annual Survey.

iv) See Appendix 5 or a sample copy of the “Maintenance Release Note” (MRN) to be issued by Surveyors. All MRNs are to be maintained onboard the drilling unit as part of the Owner/Operator’s maintenance record and for verification by the attending Surveyor during Classification surveys of the unit.



5 Survey of Drilling Systems

5.1 Survey Intervals and Maintenance Manuals/Records All Annual and Special Periodical Surveys of Drilling Systems are to be carried out at the same time and interval as the periodical Classification survey of the drilling unit in order that they are recorded with the same crediting date.

i) An Annual Survey of the drilling systems is to be carried out by a Surveyor within three months before or after of each annual anniversary date of the initial Classification survey.

ii) A Special Periodical Survey of the drilling system is to be carried out within five (5) years of the initial Classification certification survey and at five-year intervals thereafter.

iii) Required surveys are to be completed within three (3) months of their due dates, unless extended by agreement with ABS.

iv) Any part of the drilling system may be offered for survey prior to the due date when so desired, in which case, the survey will be credited as of that date.

v) Annual and Special Periodical Surveys are to be scheduled preferably when Owner/Operator has scheduled an overhaul of the drilling system. Annual Surveys are to be scheduled to coincide with the overhaul and testing of the BOP.

vi) Maintenance records are to be kept and made available for review by the attending Surveyor. The maintenance records will be reviewed to establish the scope and content of the required Annual and Special Periodical Surveys that are to be carried out by a Surveyor.

vii) During the service life of the drilling system equipment, maintenance records are to be updated on a continuing basis.

viii) The Owner/Operator is to inform ABS of any changes to the maintenance procedures and their frequencies as may be caused, for example, by changes or additions to the original drilling equipment.

ix) The Surveyor may determine during the periodic survey if the changes are sufficient to warrant review by the ABS Engineering staff.

5.3 Annual Surveys At each Annual Survey, the Surveyor is to verify the effectiveness of various systems and equipment by visual examination and testing, as appropriate. As a minimum, the following is to be carried out to the satisfaction of the attending Surveyor:

i) Review of Owner/Operator’s maintenance manual and relevant logs/records to confirm that a suitable maintenance program has been followed, periodical testing requirements have been carried out and that any repairs, reconditioning or renewals of well control equipment, BOP controls, riser system, pressure vessels, electrical systems/equipment drilling hoisting system or lifting devices were carried out according to the applicable standards and the requirements of this Guide.

ii) Review of ABS-issued MRNs since initial or last Annual Survey, and examination of this equipment to extent deemed necessary by the attending Surveyor.

iii) Review of ABS Drilling System Database for approved changes made to the drilling system equipment, and examination of this equipment to the extent deemed necessary by the attending Surveyor.

iv) Exposed surfaces of the derrick, drilling hoisting systems, lifting devices, burner booms, stabbing boards, racking platforms and drilling equipment foundations are to be examined and placed in satisfactory condition, as found necessary. The inspection of the derrick and related structural members will include the following:

• The general condition of the structure, especially bent, missing or abraded parts and lost corrosion protection coatings.

• Tightness of bolts.

• Condition of wire ropes and fittings.



v) Examination of all mounting hardware and the structure of base-mounted winches and other lifting devices. Magnetic Particle Inspection (MPI) may be carried out as deemed necessary by the attending Surveyor.

vi) General external examination so far as accessible of the drilling systems, subsystems, equipment and components as noted in 1/7.5 f of this Guide or damage, excess corrosion, fracturing or malfunctions.

vii) Protective covers, insulation, shrouds and protective guards around moving parts are to be found in place and in functional condition.

viii) Derrick walkways and ladders, drill floor and drill system machinery spaces to be surveyed with particular attention to fire and explosion hazards and confirmation that emergency escape routes are not blocked.

ix) External examination of pressure vessels and their appurtenances, including safety devices, foundations, controls, relieving gear, piping systems, flexible lines/hydraulic hoses, insulation and gauges.

x) Examination of safety shutdown devices.

xi) General examination of all electrical and instrumentation systems, including protective devices and cable supports.

xii) Examination of mud and cement systems.

xiii) Examination of the BOP test log and maintenance records.

xiv) Testing of the BOP equipment in accordance with API RP 53:

• Pressure and functional testing

• Control system testing

• Pressure testing if any shear rams were used in an emergency.

xv) Review BOP inspections and maintenance records in accordance with Section 17 (surface BOP’s) and/or Section 18 (subsea BOP’s) of API RP 53.

5.5 Special Periodical Surveys The Special Periodical Survey is to include all items listed under the Annual Survey, and, in addition, the following is to be carried out to the satisfaction of the attending Surveyor:

i) Review of Owner/Operator’s maintenance records to verify periodical testing requirements have been carried out and that any repairs, reconditioning or renewals of well control equipment, BOP controls, riser system, pressure vessels, electrical systems/equipment drilling hoisting system or lifting devices were carried out according to the applicable standards and the requirements of this Guide.

ii) Internal examination and/or thickness gauging of pressure vessels and pressure-retaining components, testing of relief valves and pressure piping systems, as considered necessary by the Surveyor.

iii) Hydrostatic testing of pressure vessels and other pressure-retaining components related to the drilling system to their MAWP.

iv) Hydrostatic testing of drilling system piping systems and flexible lines/hydraulic hoses to their MAWP.

v) Examination and check of insulation resistance of motors that are part of the drilling system.

vi) Examination of rotating drilling machinery to verify suitable operation, free from excessive vibration.

vii) The blowout preventer is to be subjected to a complete performance test and pressure-tested to its MAWP.

viii) Examination of mud and cement pump fluid ends.

ix) Functional testing of derrick gear, drilling hoisting systems and derrick floor lifting devices.



x) Close examination of the condition of welded joints on the derrick and associated structure, including nondestructive testing (including thickness gauging if required) of any suspect areas noted by the attending Surveyor.

xi) Examination of the equipment associated with the well control system and their maintenance records.

xii) Satisfactory functioning of the emergency power equipment to ensure proper operation.

5.7 Continuous Survey Program A continuous inspection program may be arranged with ABS whereby all required surveys are carried out on a continuing basis within a five-year cycle.

5.9 Survey Based on Preventative Maintenance Techniques A properly conducted preventative maintenance/condition-monitoring plan may be credited as satisfying the requirements of Special Continuous Survey.

This plan must be in accordance with Appendix 7-A-14 “Guide for Survey Based on Preventative Maintenance Techniques” of the ABS Rules for Survey After Construction (Part 7).

5.11 Surveys Using Risk-based Techniques A properly conducted Risk-based Inspection plan or Reliability-centered Maintenance Plan may be credited as satisfying requirements of Special Continuous Survey.

The plan must be in accordance with the ABS Guide for Surveys Using Risk-based Inspection for the Offshore Industry or the ABS Guide for Surveys Based on Reliability-Centered Maintenance.

7 Modifications, Damage and Repairs When it is intended to carry out any modifications to the machinery, piping, equipment, etc., which may affect Classification, the details of such modifications are to be submitted for approval and the work is to be carried out to the satisfaction of the Surveyor.

i) When a system certified with ABS has suffered any damage to machinery, piping or equipment, etc., which may affect Classification, ABS is to be notified and the damage inspected by a Surveyor.

ii) If a classed drilling system suffers any damage to its equipment, ABS is to be notified and the damage examined by a Surveyor. Details of intended repairs are to be submitted for approval, and the work is to be carried out to the satisfaction of the attending Surveyor.

iii) Where component parts suffer a premature or unexpected failure, and are subsequently repaired or replaced without Surveyor attendance, details of the failure, including the damaged parts where practicable, are to be retained onboard for examination by the Surveyor during the next scheduled survey/visit.

iv) Alternatively, the component(s) may be taken ashore for examination and testing, as required. If failures are deemed to be a result of inadequate or inappropriate maintenance, the maintenance manual is to be amended and resubmitted for approval.


Appendix 1: Typical Codes and Standards Related to ABS Classification of Drilling Systems

A P P E N D I X 1 Typical Codes and Standards Related to ABS Classification of Drilling Systems

The following codes and standards are applicable and referenced in this Guide.

ABS is prepared to consider other appropriate alternative methods and recognized codes and standards. When alternate codes and/or standards are proposed, comparative analyses are to be provided to demonstrate equivalent level of safety to the recognized standards as listed in this Guide and are to be performed in accordance with 1/7.7 of this Guide.

API Bul 16J Comparison of Marine Drilling Riser Analysis

RP 2A-WSD Planning, Designing and Constructing Fixed Offshore Platforms – Working Stress Design

Spec 2C Offshore Pedestal Mounted Cranes

RP 2X Ultrasonic and Magnetic Examination of Offshore Structural Fabrication and Guidelines for Qualification of Technicians

Std. 4A Steel Derricks

Spec 4F Drilling and Well Servicing Structures

Spec 5D Drill Pipe

Spec 6A Wellhead and Christmas Tree Equipment

Spec 6AV1 Verification Test of Wellhead Surface Safety Valves and Underwater Safety Valves for Offshore Service

Spec 7-1 Rotary Drill Stem Elements

Spec 7B-11C Internal Combustion Reciprocating Engines for Oil Field Service

Spec 7F Oil-Field Chain and Sprockets

Spec 7K Drilling and Well Servicing Equipment

Spec 8A Drilling and Production Hoisting Equipment

Spec 8C Drilling and Production Hoisting Equipment

Spec 9A Wire Rope

RP 9B Application, Care, and Use of Wire Rope for Oil Field Service

Spec 12J Oil and Gas Separators

Spec 12K Indirect-type Oil-Field Heaters

Spec 14A Subsurface Safety Valve Equipment

RP 14B Design, Installation, Operation and Redress of Subsurface Safety Valve Systems

RP 14C Analysis, Design, Installation and Testing of Basic Surface Systems on Offshore Production Platforms

RP 14E Design and Installation of Offshore Production Platform Piping Systems



RP 14F Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Division 1 and Division 2 Locations

RP 14FZ Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1, and Zone 2 Locations

RP 14G Fire Prevention and Control on Fixed Open Type Offshore Production Platforms

RP 14J Design and Hazards Analysis for Offshore Production Facilities

Spec 16A Drill Through Equipment

Spec 16C Choke and Kill Systems

Spec 16D Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment

Spec 16F Marine Drilling Riser Equipment

RP 16Q Design, Selection, Operation and Maintenance of Marine Drilling Riser Systems

Spec 16R Marine Drilling Riser Couplings

RP 16RCD Specification for Drill Through Equipment – Rotating Control Devices

RP 17A Design and Operation of Subsea Production Systems – General Requirements and Recommendations (ISO 13628-1)

RP 17B Flexible Pipe

Spec 17D Subsea Wellhead and Christmas Tree Equipment (ISO 13628-4)

Spec 17E Subsea Production Control Umbilicals (ISO 13628-5)

Spec 17F Subsea Production Control Systems (ISO 13628-6)

Spec 17J Unbonded Flexible Pipe

Spec 17K Bonded Flexible Pipe

RP 17G Design and Operation of Completion/Workover Riser Systems

RP 17H Remotely Operated Vehicles (ROV) Interfaces on Subsea Production Systems (ISO 13628-8)

RP 53 Blowout Prevention Equipment Systems for Drilling Operations

RP 59 Well Control Operations

RP 64 Diverter Systems Equipments and Operations

RP 500 Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2

RP 505 Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1 and Zone 2

Std. 520 Sizing, Selection, and Installation of Pressure-Relieving Systems in Refineries, Part I – Sizing and Selection

Std. 521 Pressure Relieving and Depressuring Systems

Std. 610 Centrifugal Pumps for Petroleum, Petrochemical and Natural Gas Industries

Std. 2000 Venting Atmospheric and Low-Pressure Storage Tanks

RP 2003 Protection Against Ignitions Arising Out of Static, Lightning and Stray Contents



ASME B31.3 Power Piping

Section V Nondestructive Examination

Section VIII, Div. 1 Rules for Construction of Pressure Vessels

Section VIII, Div. 2 Alternative Rules for Construction of Pressure Vessels

ASTM A388 Standard Practice for Ultrasonic Examination of Heavy Steel Forgings

E8 Standard Test Methods for Tension Testing of Metallic Materials

E10 Standard Test Methods for Brinell Hardness of Metallic Materials

E18 Standard Test Methods for Rockwell Hardness and Rockwell Superficial Hardness of Metallic Materials

E92 Standard Test Method for Vickers Hardness of Metallic Materials

E94 Standard Guide for Radiographic Testing

E165 Standard Practice for Liquid Penetrant Inspection

E186 Standard Reference Radiographs for Heavy Walled (2 to 4.5 in.) (51 to 114 mm) Steel Castings

E280 Standard Reference Radiographs for (4.5 to 12 in.) (114 to 305 mm) Steel Castings

E428 Standard Practice for Fabrication and Control of Steel Reference Blocks Used in Ultrasonic Inspection

E446 Standard Reference Radiographs for Steel Castings up to 2 in. in Thickness

E609 Standard Practice for Casting, Carbon, Low-Alloy, and Martensitic Stainless Steel, Ultrasonic Examination Thereof

E709 Standard Recommended Practice for Magnetic Particle Examination

AWS D1.1 Structural Welding Code – Steel

IEC 61508 Functional Safety of Electrical/Electronic/Programmable Electronic Safety-

Related Systems, Part 1 - 6

IEEE C37.06.1 Guide for High Voltage Circuit Breakers Rated on Symmetrical Current Basis

Designated “Definite Purpose for Fast Transient Recovery Voltage Rise Times”

C37.20.6 4.76 kV to 38 kV Rated Ground and Test Devices Used in Enclosures

Std. 45 Recommended Practice for Electrical Installations on Shipboard

Std. 142 Recommended Practice for Grounding of Industrial and Commercial Power Systems

Std. 242 Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems

ISO 19901-1 Petroleum and Natural Gas Industries – Specific requirements for offshore

structures – Part 1: Metocean design and operating considerations-First Edition



NACE MR 0175/ISO 15156 Materials for use in H2S containing environment in oil and gas production

NFPA 70 National Electrical Code

496 Standard for Purged and Pressurized Enclosures for Electrical Equipment

SAE J517 Hydraulic Hoses


SAMPLE

Appendix 2: Sample Manufacturer’s Affidavit of Compliance

A P P E N D I X 2 Sample Manufacturer’s Affidavit of Compliance

ABC Manufacturing Company 12345 Street Avenue City, State, [Zip Code/Postal Code] Country Date: Jan 01, 2011

MANUFACTURER’S AFFIDAVIT OF COMPLIANCE Manufacturer & Address : ABC Manufacturing Company : 12345 Street Avenue City, State (Zip Code)

Customer & Address : XYZ Drilling Corporation 12345 Street Avenue City, State (Zip Code)

Customer PO# : AAA-12345

Description of Equipment : Ram Assembly 5 ½” 18-15M

Equipment Model Number :

Equipment Part/Serial Number : XXX-YYY

Date of Manufacturing :

Equipment Pressure Rating or : Temperature Rating: (min / max) OC Load Rating

Equipment Test Pressure or : Test Load

Date of Pressure Test or Load Test :

Code(s), Standard(s) or Specification(s) Applied : (list all applicable)

This affidavit is prepared by the undersigned, authorized representative of the manufacturer, to certify

that the equipment described above and supplied for this order is in full compliance with respect to the design, assemble, manufacture, and testing of the equipment in accordance with the referenced code(s), standard(s) or specification(s), and is suitable for the intended use in accordance with the referenced design parameters.

This affidavit is prepared by the undersigned, authorized representative of the manufacturer, to certify

that the equipment described above is in compliance with the requirements of the ABS “Guide for the Classification of Drilling Systems”, and is enclosed as part of the equipment delivery/shipment documents.

Signature Name : Title : Date :


Appendix 3: Sample of Independent Review Certificate (IRC)

A P P E N D I X 3 Sample of Independent Review Certificate (IRC)

The following is a sample of ABS Independent Review Certificate (IRC), issued in accordance with Section 4, Table 1.

The contents of the IRC and associated CoC are to be specific to the equipment and its respective design parameters and approval.

Appendix 3 Sample of Independent Review Certificate (IRC)


INDEPENDENT REVIEW CERTIFICATE IRC No.: _________________________ ABS OPN / PID: Date:

This is to certify that the design plans and data for the manufacture of the equipment listed below has

been reviewed and found to be in compliance with the specified codes, standards, or specifications, and the ABS

Guide for the Classification of Drilling Systems.

Manufacturer & Address : ABC Manufacturing Company : 12345 Street Avenue City, State (Zip Code)


Equipment Model No. :

Equipment Part. : XXX-YYY

Date of Manufacturing : Jan 01, 2011

Equipment Design Conditions:

Maximum Rated Working Pressure :

Hydrostatic Test Pressure :

Design Temperature : (min / max) OC

Service Condition :

Operator Rated Working Pressure : Codes, Standards, or Specifications : API 16A Drawing and documentation, as per attached list.

By:

ABS Engineer Principal Engineer Offshore Engineering Department – Machinery Group

This certificate is a representation that the structure, item of material, equipment, machinery or other item covered by this certificate has met one or more of the Rules, Guides standards or other criteria of ABS or of a National Administration and is issued solely for use by ABS, its committees, its clients or other authorized entities. The validity, applicability and interpretation of this certificate is governed by the Rules and Standards of ABS, and ABS shall remain the sole judge thereof. Nothing contained in this certificate or in any notation made in contemplation of this certificate shall be deemed to relieve any designer, builder, owner, manufacturer, seller, repairer, operator or other entity of any warranty express or implied.

Appendix 3 Sample of Independent Review Certificate (IRC)


INDEPENDENT REVIEW CERTIFICATE

DRAWING AND DOCUMENTATION LIST Attachment to ABS Independent Review Certificate (HOE-XXXXXX/2010)

ABS OPN / PID: Date:

Manufacturer : ABC Manufacturing Company : 12345 Street Avenue City, State (Zip Code)



Equipment Part No. : XXX-YYY

Date of Manufacturing : Jan 01, 2011

DRAWING AND DOCUMENTATION LIST

Drawing No. Rev. Drawing Title

RELATED CORRESPONDENCE: IRC No: HOE-XXXXXX/2009 This certificate is a representation that the structure, item of material, equipment, machinery or other item covered by this certificate has met one or more of the Rules, Guides standards or other criteria of ABS or of a National Administration and is issued solely for use by ABS, its committees, its clients or other authorized entities. The validity, applicability and interpretation of this certificate is governed by the Rules and Standards of ABS, and ABS shall remain the sole judge thereof. Nothing contained in this certificate or in any notation made in contemplation of this certificate shall be deemed to relieve any designer, builder, owner, manufacturer, seller, repairer, operator or other entity of any warranty express or implied.


Appendix 5: Sample of Certificate of Conformity

A P P E N D I X 4 Sample of Certificate of Conformity (CoC)

CERTIFICATE OF CONFORMITY

Certificate No.: Independent Review Certificate

ABS OPN / PID: _______________ IRC No.: _________________

Date: ________________________ Issue Date: _______________

This is to certify that the undersigned Surveyor has surveyed the following equipment in accordance with the ABS Guide for the Classification of Drilling Systems. Manufacturer & Address : ABC Manufacturing Company : 12345 Street Avenue City, State (Zip Code)

Description of Equipment : Ram Assembly 5 ½” 18-15M ________________________________________________________


Equipment Part/Serial No. : XXX-YYY

Date of Survey : Jan 01, 2011

Equipment Design Conditions:

Maximum Rated Working Pressure/Load : Design Temperature: (min / max) °C Service Condition : H2S (yes / no)

Equipment Design Code or Standard :

Scope of Survey: __________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

Equipment Testing, as applicable:

Test Pressure / Load : Temperature : Gage Number : Calibration Date : Hold Time :

Drawing or Documentation : _______________________________________________________________ Port of Issue : ___________________________________

Issue by : ___________________________________ _______________________________________ ABS Surveyor Signature

This Certificate evidences compliance with one or more of the Rules, guides, standards or other criteria of American Bureau of Shipping a and i s issued solely for the use of the Bureau, its committees, its clients or other authorized entities. This Certificate is a representation only that the structure, item of material, equipment, machinery or any other item covered by this Certificate has met one or more of the Rules, guides, standards or other criteria of American Bureau of Shipping as of the date of issue. Parties are advised to review the Rules for the scope and conditions of classification and to review the survey records for a fuller description of any restrictions or limitations on the vessel's service or surveys. The validity, applicability and interpretation of this Certificate is governed by the Rules and standards of American Bureau of Shipping who shall remain the sole judge thereof. Nothing contained in this Certificate or in any notation made in contemplation of this Certificate shall be deemed to relieve any designer, builder, owner, manufacturer, seller, supplier, repairer, operator or other entity or any warranty express or implied.


SAMPLE

Appendix 5: Sample Maintenance release Note

A P P E N D I X 5 Sample Maintenance Release Note (MRN)

Report Number: HS03179Port of: Houston

Date: Jan 01, 2011 P.O. No.: AA-BB-CCC

Owner: XYZ Drilling Corporation Address: Name of Drilling Unit: XYZ-001 ABS OPN / VID: 0123456 Supplier & Location: Drilling Rig Equipment Inc. – Houston, Texas

ABS CLASSED DRILLING SYSTEM COMPONENT MAINTENANCE RELEASE NOTE

This is to certify that the undersigned Surveyor to this Bureau, did at the request of the Client, carry out an examination of the below stated drilling system component in accordance with ABS Guide for the Classification of Drilling Systems and other below stated standards.

The component(s) was(were) examined, pressure-tested (as applicable), its function and shutdowns, as fitted, were tested, its maintenance records and documentation package including the nondestructive examination records (as applicable) were reviewed, and considered satisfactory subject to installation on board the above noted drilling unit.

The undersigned recommends that this report be considered as contributing towards demonstration of compliance with the ABS Guide for Classification of Drilling Systems subject to the reservations contained in this report (if any).

The component(s) will be re-examined to extent deemed necessary by the attending ABS Surveyor at time of next due periodical survey of the drilling unit Description of drilling system component : Codes, standards, or specifications : Details of survey :

________________________ ABS Surveyor NOTE: This Certificate evidences compliance with one or more of the Rules, Guides, standards or other criteria of American Bureau of Shipping and is issued solely for the use of

the Bureau, its committees, its clients or other authorized entities. This Certificate is a representation only that the structure, item of material, equipment, machinery or any other item covered by this Certificate has met one or more of the Rules, Guides, standards or other criteria of American Bureau of Shipping as of the date of issue. Parties are advised to review the Rules for the scope and conditions of classification and to review the survey records for a fuller description of any restrictions or limitation on the vessel’s service or surveys. The validity, applicability and interpretation of this Certificate is governed by the Rules and standards of American Bureau of Shipping who shall remain the sole judge thereof. Nothing contained in this Certificate or in any notation made in contemplation of this Certificate shall be deemed to relieve any designer, builder, owner, manufacturer, seller, supplier, repairer, operator or other entity or any warranty express or implied.

ABS Drlling Systems Guide

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