task 6 system conceptual design & analysis report … · the appendices for rpsea project 1502...

RPSEA 08121-1502-01 - TASK 6 FINAL REPORT - VOLUME 2

TASK 6

SYSTEM CONCEPTUAL DESIGN & ANALYSIS REPORT APPENDICES

Document No. 08121-1502-01.06.Final-Vol.2

Coiled Tubing Drilling & Intervention System

Using Cost Effective Vessels

RPSEA 08121-1502-01

January 31, 2011

Charles R. Yemington, PE Project Manager

Nautilus International LLC. 400 N. Sam Houston Pkwy. East, Suite 105

Houston, TX 77060


LEGAL NOTICE

This report was prepared by Nautilus International LLC. as an account of work sponsored by the Research Partnership to Secure Energy for America, RPSEA. Neither RPSEA members of RPSEA, the National Energy Technology Laboratory, the U.S. Department of Energy, nor any person acting on behalf of any of the entities:

a. Makes any warranty or representation, express or implied with respect to accuracy,

completeness, or usefulness of the information contained in this document, or that the use of any information, apparatus, method, or process disclosed in this document may not infringe privately owned rights, or

b. Assumes any liability with respect to the use of, or for any and all damages resulting

from the use of, any information, apparatus, method, or process disclosed in this document.

This is a final report. The data, calculations, information, conclusions, and/or recommendations reported herein are the property of the U.S. Department of Energy.

Reference to trade names or specific commercial products, commodities, or services in this report does not represent or constitute and endorsement, recommendation, or favoring by RPSEA or its contractors of the specific commercial product, commodity, or service.


ABSTRACT

The appendices for RPSEA project 1502 Task 6 final report are bound in this document to add background and detail to the report. The main body of the report includes a summary of the material in the appendices, and In case of conflict, the material in the main report takes precedence over material in the appendices.

Applicable standards were compiled by the team members for their area of specialty and are included here under their respective headings.

Riser analysis by INTECSEA revealed no surprises and no significant problems with the preferred approach to component selection and integration. A summary of analysis results is presented in Section 3.

Functional and interface requirements for a Seafloor Shutoff Device and control umbilical were developed by GMC. The configuration includes provisions to comply with expected regulatory requirements resulting from the MC252 incident. Performance requirements for the instrumentation and control umbilical for the Seafloor Shutoff Device and the tree were based on the number of functions, flow requirements, and signal requirements. The Seafloor Shutoff Device will be further defined by GE Oil & Gas during work on Task 9.

CTES analysed theoretical limits for materials and hydrodynamic considerations for the limits of CT capability for deep water wells and prepared the section on theoretical maximum total depth for CT intervention.


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TABLE OF CONTENTS

1.0 SUMMARY STATEMENT................................................................................................ 8 2.0 APPLICABLE STANDARDS AND REGULATIONS ......................................................... 9

2.1 Coiled Tubing Activity Standards & Regulations .......................................................... 9 2.2 Riser Related Standards & Regulations ......................................................................16 2.3 Seafloor Shutoff Device Related Standards ................................................................18

3.0 RISER ANALYSIS REPORT BY INTECSEA ..................................................................19 4.0 MATERIAL BY GENERAL MARINE CONTRACTORS ...................................................72

4.1 Seafloor Shutoff Device ..............................................................................................72 4.2 Seafloor Shutoff Device Connector Interface to Stress Joint .......................................74 4.3 Deck Equipment & Surface Control System ................................................................76 4.4 Umbilical and Umbilical Junction Box..........................................................................77 4.5 Equipment Interfaces and Rig Up ...............................................................................78

5.0 OPERATING DEPTH LIMIT FOR CT TUBING BY CTES...............................................81


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1.0 SUMMARY STATEMENT The appendices for RPSEA project 1502 Task 6 final report are bound in this document to add background and detail to the report. The main body of the report includes a summary of the material in the appendices, and In case of conflict, the material in the main report takes precedence over material in the appendices.

Applicable standards were compiled by the team members for their area of specialty and are included here under their respective headings.

Riser analysis by INTECSEA revealed no surprises and no significant problems with the preferred approach to component selection and integration. A summary of analysis results is presented in Section 3.

Functional and interface requirements for a Seafloor Shutoff Device and control umbilical were developed by GMC. The configuration includes provisions to comply with expected regulatory requirements resulting from the MC252 incident. Performance requirements for the instrumentation and control umbilical for the Seafloor Shutoff Device and the tree were based on the number of functions, flow requirements, and signal requirements. The Seafloor Shutoff Device will be further defined by GE Oil & Gas during work on Task 9.

CTES analysed theoretical limits for materials and hydrodynamic considerations for the limits of CT capability for deep water wells and prepared the section on theoretical maximum total depth for CT intervention.


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2.0 APPLICABLE STANDARDS AND REGULATIONS This tabular listing was created to provide references to regulations and recommended practices that may be applicable to offshore coiled tubing operations from a small vessel. The listing will be used for subsequent phases of the project. This listing is not all-inclusive, and users should be aware that additional new regulations and practices may be promulgated at any time.

2.1 Coiled Tubing Activity Standards & Regulations American Petroleum Institute - API www.api.org

1. API RP 5C7 Recommended Practice for Coiled Tubing Operations in Oil and Gas Well Services

2. API RP 16ST Coiled Tubing Well Control Equipment Systems 3. API SPEC 5ST Specification for Coiled Tubing – U.S. Customary and SI Units

Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) http://www.gomr.mms.gov/index2.html * Note - Formerly known as the Minerals Management Service

1. OIL AND GAS AND SULFUR OPERATIONS IN THE OUTER CONTINENTAL

SHELF a. CFR Title 30 Part 250

Note - Coiled Tubing operations are mentioned specifically in the following subsections: Subpart F, 250.602, 250.615, 250.616.

2. DEPARTMENT OF THE INTERIOR AUTHORITIES DIRECTLY AFFECTING

OUTER CONTINENTAL SHELF ACTIVITIES

• Overview of OCS Regulations • Exploration Plans • Development and Production Plans • Oil Spill Contingency Plans • Hydrogen Sulfide Contingency Plans • Environmental Information • Air Emissions Information • Archaeological Resources Regulation • Structure Removal • Site Clearance • Permits and Applications

o Wells o Platforms o Production Facilities o Pipelines

http://www.api.org/

http://www.gomr.mms.gov/index2.html

http://www.gomr.mms.gov/homepg/regulate/regs/laws/env_safe.html

http://www.gomr.mms.gov/homepg/regulate/regs/laws/postsale.html#expl

http://www.gomr.mms.gov/homepg/regulate/regs/laws/postsale.html#d%2Bp

http://www.gomr.mms.gov/homepg/regulate/regs/laws/postsale.html#oscp

http://www.gomr.mms.gov/homepg/regulate/regs/laws/postsale.html#hscp

http://www.gomr.mms.gov/homepg/regulate/regs/laws/postsale.html#ei

http://www.gomr.mms.gov/homepg/regulate/regs/laws/postsale.html#aei

http://www.gomr.mms.gov/homepg/regulate/regs/laws/postsale.html#arl

http://www.gomr.mms.gov/homepg/regulate/regs/laws/postsale.html#sr

http://www.gomr.mms.gov/homepg/regulate/regs/laws/postsale.html#sc

http://www.gomr.mms.gov/homepg/regulate/regs/laws/env_safe.html#perapp


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• Lease Stipulations

• Other Environmental and Safety Controls o Oil and Gas and Sulfur Operations in the Outer Continental Shelf--

Document Incorporated by Reference-American Petroleum Institute's Specification 2C for Offshore Cranes

o Notices, Letters, and Information to Lessees and Operators o Conditions of Approval

• Enforcement Measures

o Inspections o Suspension of Operations o Cancellation of Leases o Remedies and Penalties

• Federal Compensation for Damages or Pollution o The Oil Spill Liability Trust Fund o Fishermen's Contingency Fund o Natural Resource Damage Assessment (NRDA) Regulations

• Presale Activities Federal/State Coordination • Geological and Geophysical Exploration Regulations/Coordination • Coastal Zone Management Act Review

3. The listing below contains the NTL's that have been issued to date that are still

active.

http://www.gomr.mms.gov/homepg/regulate/regs/ntlltl.html

2010-N10 November 8, 2010 Statement of Compliance with Applicable Regulations and Evaluation of Information Demonstrating Adequate Spill Response and Well Containment Resources

2010-N09 October 15, 2010 Guidance on Flare/Vent Meter Installations 2010-N08 September 20, 2010 Meter/Tank Status Definitions 2010-N07 September 17, 2010 Outage of Fee for Services due to Fiscal Year-end Closeout

FAQ August 2, 2010 Frequently Asked Questions Information Sheet for Shallow Water Drilling

2010-G07 December 1, 2010 Drilling Windows, Eastern Gulf of Mexico 2010-P06 June 30, 2010 Well Naming and Numbering Standards

2010-N06 June 18, 2010 Information Requirements for Exploration Plans, Development and Production Plans, and Development Operations Coordination Documents on the OCS

FAQ

Effective June 18, 2010

updated August 10, 2010

Frequently Asked Questions Information Sheet for NTL 2010-N06

http://www.gomr.mms.gov/homepg/regulate/regs/stips/stip_ovr.html

http://www.gomr.mms.gov/homepg/regulate/regs/fr010719.pdf





http://www.gomr.mms.gov/homepg/regulate/regs/laws/coa.html

http://www.gomr.mms.gov/homepg/regulate/regs/laws/enforc.html

http://www.gomr.mms.gov/homepg/regulate/regs/laws/osltf.html

http://www.gomr.mms.gov/homepg/regulate/regs/laws/fcf.html

http://www.gomr.mms.gov/homepg/regulate/regs/laws/nrda.html

http://www.gomr.mms.gov/homepg/regulate/regs/laws/presale.html

http://www.gomr.mms.gov/homepg/regulate/regs/laws/gandg.html

http://www.gomr.mms.gov/homepg/regulate/regs/laws/postsale.html#czma


http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/2010NTLs/10-n10.pdf



http://www.boemre.gov/ntls/PDFs/2010-N07_OutageofFeeforService.pdf

http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/Shallow_Water.pdf

http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/2010NTLs/10-g07.pdf

http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/2010NTLs/10-P06.pdf


http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/2010NTLs/10-n06-FAQs.pdf


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2010-G06 September 15, 2010 2011 Gulfwide OCS Emissions Inventory (Western Gulf of Mexico)

2010-P05 February 19, 2010 Decommissioning Cost Report Update 2010-G05 October 15, 2010 Decommissioning Guidance for Wells and Platforms 2010-P04 February 24, 2010 Warning Signs: Pipelines and Power Cables 2010-G04 June 1, 2010 Hurricane and Tropical Storm Effects Report 2010-P03 June 30, 2010 Well Records Submittal 2010-N03 March 25, 2010 Guidelines for Royalty Relief Under 30 CFR Part 203

2010-G03 February 11, 2010 Wells (holes-in-the-ground) Without Assigned MMS API Numbers

2010-P02 February 24, 2010 Standby Testing Requirements During Air Pollution Emergency Episodes

2010-G02 March 3, 2010 Well Records Submittal 2010-P01 February 24, 2010 Hydrogen Sulfide 2010-G01 February 1, 2010 Clarification of Deep Gas Royalty Relief Regulation 2009-G40 January 27, 2010 Deepwater Benthic Communities 2009-G39 January 27, 2010 Biologically-Sensitive Underwater Features and Areas

2009-G36 January 1, 2010 Using Alternate Compliance in Safety Systems for Subsea Production Operations

2009-G35 December 1, 2009 Sub-Seabed Disposal and Offshore Storage of Solid Wastes 2009-G34 December 1, 2009 Ancillary Activities 2009-G33 November 4, 2009 Well Naming and Numbering Standards 2009-G32 November 4, 2009 In-Service Inspection Intervals for Fixed Platforms 2009-G31 October 21, 2009 Hydrogen Sulfide 2009-G30 September 1, 2009 Post-Hurricane Inspection and Reporting

2009-G29 October 13, 2009 Implementation Plan for Transition from North American Datum 27 to North American Datum 83

2009-G28 October 13, 2009 Alternate Compliance and Departure Requests in Pipeline Applications

2009-G27 September 9, 2009 Submitting Exploration Plans and Development Operations Coordination Documents

2009-G26 September 9, 2009 U. S. Air Force Communication Towers 2009-G25 August 25, 2009 Shutting In Producible Wells During Rig Moves 2009-G24 August 14, 2009 Supervisory Control and Data Acquisition Systems 2009-G23 August 14, 2009 Structure Assessment Before Moving a Platform Rig 2009-G21 August 7, 2009 Standard Conditions of Approval for Well Activities 2009-G20 August 6, 2009 Standard Reporting Period for the Well Activity Report 2009-G19 August 5, 2009 Containment for Bolted or Welded Storage Tanks 2009-G18 September 9, 2009 Production Safety Systems 2009-G17 August 4, 2009 Designated Safe Welding Areas on Rigs 2009-G16 June 25, 2009 Global Positioning Systems for Mobile Offshore Drilling Units













http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/2009NTLs/09-G40.pdf























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2009-G15 July 10, 2009 Digital Pipeline Location Data 2009-G14 May 21, 2009 Functional Responsibility of MMS Regulations 2009-N13 December 2, 2009 Inspection Fees for Fiscal Year 2010

2009-G13 May 20, 2009 Guidelines for Tie-downs on OCS Production Platforms for Upcoming Hurricane Seasons

2009-N12 November 20, 2009 Appeals 2009-N11 December 4, 2009 Air Quality Jurisdiction on the OCS 2009-G11 June 1, 2009 Accidental Disconnect of Marine Drilling Risers

2009-N10 October 7, 2009 Directional and Inclination Survey Data Submission Requirements

2009-G10 June 1, 2009 Guidelines for Jack-up Drilling Rig Fitness Requirements for Hurricane Season

2009-N09 November 1, 2009 MMS Policy on Refund Requests for Service Fees 2009-P08 December 16, 2009 Helideck Closures

2009-N08 September 14, 2009 Application and Audit Fees for Requests for Royalty Relief or Adjustment Under 30 CFR Part 203

2009-P07 December 16, 2009 Casing Pressure 2009-G07 May 1, 2009 Location of Choke and Kill Lines on Blowout Preventer Stacks 2009-P06 December 18, 2009 Change of Ownership/Operatorship of Leases and Pipelines 2009-G06 April 22, 2009 Military Warning and Water Test Areas 2009-P05 December 16, 2009 Production Measurement and Verification Program Submittals 2009-G05 April 27, 2009 Approval of Acidizing Operations 2009-P04 October 29, 2009 Decommissioning of POCS Facilities 2009-G04 January 27, 2009 Significant OCS Sediment Resources in the Gulf of Mexico 2009-N04 July 9, 2009 Submitting Semiannual Well Tests Electronically 2009-P03 October 28, 2009 Oil Spill Response Plans 2009-G03 January 27, 2009 Synthetic Mooring Systems

2009-N03 May 12, 2009 Posting the Department of the Interior (DOI) Inspector General's Hotline number at Outer Continental Shelf (OCS) Oil and Gas Facilities

2009-P02 October 7, 2009 Bottomhole Pressure Surveys 2009-N02 February 10, 2009 Timely Submission of Suspension Requests 2009-G02 January 27, 2009 Ocean Current Monitoring 2009-P01 May 18, 2009 Pacific OCS Region Organizational Structure

2009-REN-01 June 22, 2009 Applications for Renewable Energy Leases and Grants and Alternate Use Grants on the U.S. Outer County Shelf

2009-N01 July 9, 2009 Submitting Semiannual Well Tests Electronically

2008-G22 November 19, 2008 Information Guidance for Availability of Well Data and Information Through the Gulf of Mexico Region Online Ordering System

2008-G20 October 20, 2008 Revisions to the List of OCS Lease Blocks Requiring Archaeological Resource Surveys and Reports



http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/2009NTLs/09-N13.pdf


























http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/2009NTLs/09-NO1-REN.pdf





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2008-G19 October 2, 2008 Changes to the Designation of Operator of an OCS Oil and Gas or Sulphur Lease

2008-G17 September 16, 2008 Incident and Oil Spill Reports 2008-G13 July 9, 2008 Electronically Stored Records

2008-N09 October 29, 2008 Extension of Lease and Unit Terms by Production in Paying Quantities

2008-G09 June 1, 2008 Guidelines for Moored Drilling Rig Fitness Requirements for Hurricane Season

2008-N07 August 28, 2008 Supplemental Bond Procedures 2008-G07 June 15, 2008 Managed Pressure Drilling Projects 2008-G06 May 26, 2008 Remotely Operated Vehicle Surveys in Deepwater

2008-N05 August 26, 2008 Guidelines for Oil Spill Financial Responsibility (OSFR) for Covered Facilities

2008-G05 May 1, 2008 Shallow Hazards Program

2008-G04 May 1, 2008 Information Requirements for Exploration Plans and Development Operations Coordination Documents

2008-N03 March 31, 2008 Well Control and Production Safety Training 2008-G03 April 14, 2008 Pollution Inspection Intervals for Unmanned Facilities 2008-N02 March 1, 2008 Outer Continental Shelf (OCS) Inspection Program 2008-P01 August 19, 2008 Electronically Stored Records

2007-G27 October 1, 2007 Assessment of Existing OCS Platforms and Related Structures for Hurricane Conditions

2007-G26 December 15, 2007 Design of New OCS Platforms and Related Structures for Hurricane Conditions

2007-G22 June 25, 2007 Suspensions of Operations for Subsalt and Ultradeep Geophysical Work

2007-G21 June 1, 2007 Conservation Information Documents

2007-G20 May 25, 2007 Coastal Zone Management Program Requirements for OCS Right-of-way Pipeline Applications

2007-G15 May 14, 2007 eWell Permitting and Reporting System 2007-G14 May 7, 2007 Pipeline Risers Subject to the Platform Verification Program

2007-G12 April 4, 2007 Contact with District Offices and the Pipeline Section Outside Regular Work Hours

2007-G09 April 3, 2007 Air Emissions Information for Applications for Accessory Platforms for Pipeline Rights-of-way

2007-G08 April 2, 2007 Using a Motion Compensator when Conducting Coiled Tubing Operations on a Floating Production Platform

2007-G05 March 1, 2007 Well Producibility Determinations 2007-N04 September 26, 2007 Oil Discharge Written Follow-up Reports

2007-G04 February 7, 2007 Vessel Strike Avoidance and Injured/Dead Protected Species Reporting

2007-G03 February 7, 2007 Marine Trash and Debris Awareness and Elimination 2007-N02 March 30, 2007 Revised Assessment Matrix
































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2007-G02 February 7, 2007 Implementation of Seismic Survey Mitigation Measures and Protected Species Observer Program

2006-G21 October 26, 2006 Regional and Subregional Oil Spill Response Plans

2006-G20 October 25, 2006 Mudline Suspension Wells: Dry Tree Tiebacks and Conversion to Subsea Wells

2006-N06 December 19, 2006 Flaring and Venting Approvals 2006-G04 February 22, 2006 Fire Prevention and Control Systems 2006-P03 October 16, 2006 Archaeological Survey and Report Requirements 2006-P02 October 16, 2006 Biological Survey and Report Requirements

2006-P01 October 16, 2006 Shallow Hazards Survey and Report Requirements for OCS Development Operations

2006-G01 February 1, 2006 Royalty Relief for Gulf of Mexico OCS Oil and Gas Leases with Facilities Damaged by Hurricane Katrina or Hurricane Rita

2005-G07 July 1, 2005 Archaeological Resource Surveys and Reports

2005-A03 July 25, 2005 Archaeological Survey and Evaluation for Exploration and Development Activities

2005-P02 June 22, 2005 California District Office: Phone Call Procedures and Hours

2005-A02 July 25, 2005 Shallow Hazards Survey and Evaluation for Alaska Outer Continental Shelf (OCS) Pipeline Routes and Rights-of-Way

2005-G01 January 6, 2005 Monitoring Bypassed Safety Devices

2005-A01 July 25, 2005 Shallow Hazards Survey and Evaluation for OCS Exploration and Development Drilling

2003-G20 January 1, 2004 Gas Volume Statement Requirements

2003-G05 February 15, 2003

Procedures for Submission, Inspection and Selection of Geophysical Data and Information Collected Under a Permit and Processed or Reprocessed by a Permittee or a Third Party

2003-G02 March 3, 2003 Ultimate Recovery Abandonment and Bypassing of Zones

2001-G10 November 28, 2001 Clarification of Eastern Gulf of Mexico Sale 181 Military Areas Stipulation

2000-G17 September 1, 2000 Suspension of Production/Operations Overview 2000-G16 September 7, 2000 Guidelines for General Lease Surety Bonds

NTL 99-G19 September 7, 1999 Downhole Commingling Policies

NTL 99-G06 May 1, 1999 Economic Assumptions for RSVP Deepwater Royalty Relief Model

NTL 99-G05 April 26, 1999 Submittal of Documents for Platforms and Structures

NTL 98-26 November 30, 1998 Minimum Interim Requirements for Site Clearance (and Verification) of Abandoned Oil and Gas Structures in the Gulf of Mexico

NTL 98-19 September 15, 1998 Temporary Abandonment of Wells and Maintenance, Protection, and Removal of Underwater Casing Stubs

American National Standards Institute – ANSI www.ansi.org * Note – These standards are voluntary


http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/2006%20NTLs/06-g21.pdf


http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/2006%20NTLs/06-n06.pdf


http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/2006%20NTLs/06-P03.pdf




http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/2005%20NTLs/05-g07.html

http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/2005%20NTLs/05-a03.pdf



http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/2005%20NTLs/05-g01.html


http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/ntl03-g20.html






http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/ntl99-G19.html



http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/ntl98_26.html

http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/ntl98_19.html

http://www.ansi.org/

Administrator

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Administrator

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1. Z 359.1 Safety Requirements for Personal Fall Arrest Systems, Subsystems, and

Components 2. A14.3 Fixed Ladders 3. B20.2.0-67 Safety Code for Overhead Cranes 4. B20.5-68 Safety Code for Crawler, Truck Cranes

2.2 Riser Related Standards & Regulations ABS 82 - Guide For Building and Classing Floating Production Installations ABS 115 - Guide For the Fatigue Assessment of Offshore Structures DNV-OS-C201 - Structural Design of Offshore Units (WSD Method)

Riser Global Design DNV-RP-C203 - Fatigue Design of Offshore Steel Structures API RP 17G - Recommended Practice for Completion/Workover Risers - Second Edition ISO 13624-1 - Design and Operation of Marine Drilling Riser Equipment - First Edition

Riser Joint Specification API Spec 5D - Specification for Drill Pipe - Fifth Edition API RP 16Q - Recommended Practice for Design, Selection, Operation and Maintenance of Marine Drilling Riser Systems - First Edition API RP 17G - Recommended Practice for Completion/Workover Risers - Second Edition ASNT-TC-1A - Recommended Practice No. SNT-TC-1A and ASNT Standard Topical Outlines for Qualification of NDT Personnel

Flexible Composite Pipe API RP 17J - Specification for Unbonded Flexible Pipe - Third Edition

Fabrication API RP 2A-WSD - Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms, Working Stress Design API RP 2X - Recommended Practice for Ultrasonic and Magnetic Examination of Offshore Structural Fabrication and Guidelines for Qualification of Ultrasonic Technicians API RP 2Z - Recommended Practice for Pre-production Qualification for Steel Plates for Offshore Structures API RP 2FPX - Recommended Practice for Planning, Designing, and Constructing Floating Production Systems API RP 2A - Recommended Practice for Planning, Designing, and Constructing Fixed Offshore Platforms API SPEC 2B - Specification for Carbon Manganese Steel Plate for Offshore Platform Tubular Joints API SPEC 2Y - Specification for Steel Plates, Quenched-and-tempered, for Offshore Structures API SPEC 2W - Specification for Steel Plates for Offshore Structures, Produced by Thermo- Mechanical Control Processing (TMCP) API SPEC 2MT1 - Specification for Carbon Manganese Steel Plate with Improved Toughness for Offshore Structures ASNT-TC-1A - Recommended Practice No. SNT-TC-1A and ASNT Standard Topical Outlines for Qualification of NDT Personnel


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AWS D1.1 - Structural Welding Code, Steel - 22nd Edition AWS QC1 - Specification for Qualification and Certification of Welding Inspectors BS 7448 - Fracture Mechanics Toughness Tests (Part 1 & II)

Testing ASTM A370 - Standard Test Method and Definitions for mechanical testing of Steel Products ASTM A751 - Methods, Practices, and Definitions for Chemical Analysis of Steel Pipe ASTM A941 - Terminology to Steel, Stainless Steel, Related Alloys, and Ferroalloys ASTM E59 - Standard Practice for Sampling Steel and Iron for Determination of Chemical Composition ASTM E4 - Practices for Load Verification of Testing machines ASTM E8 - Standard Test Methods for tension testing of Metallic Materials ASTM E18 - Standard Methods of Tests for Rockwell Hardness and Rockwell Superficial Hardness of Metallic Materials ASTM E23 - Methods for Notched Bar Impact Testing of Metallic Materials ASTM E83 - Practices for Verification and Classification of Extensometers ASTM E92 - Testing Methods for Vickers Hardness of Metallic Materials ASTM E112 - Standard Method for Determining Average Grain Size ASTM E165 - Standard Practice for Liquid Penetrant Inspection Method ASTM E213 - Standard Practice for Ultrasonic Examination of Metal Pipe and Tubing ASTM E350 - Testing Methods for Chemical Analysis of Carbon Steel, Low-Alloy Steel, Silicon Electrical Steel, Ingot Iron, and Wrought Iron ASTM E570 - Standard Practice for Flux Leakage Examination Ferro-magnetic Steel tubular Products ASTM E709 - Standard Practice for Magnetic Particle Examination ISO 13679 - Procedures for Testing Casing and Tubing Connections - First Edition ASTM A131 - Standard Specification for Structural Steel for Ships ASTM A370 - Standard Test Method and Definitions for mechanical testing of Steel Products ASTM A578 - Standard Specification for Straight-Beam Ultrasonic Examination of Plain Clad Steel Plates for Special Applications ASTM E92 - Standard Test Method for Vickers Hardness of Metallic Materials ASTM E1290 - Standard Test method for Crack Tip Opening Displacement (CTOD) Fracture Toughness Measurement ISO 9001 - Quality Management Systems - Requirements - Fourth Edition


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2.3 Seafloor Shutoff Device Related Standards

ISO 13628-4 Subsea Wellhead & Christmas Trees ISO 13628-7 Completion Workover Riser System NACE MR0175/ISO 15156 Materials For Use In H2S-Containing Environments

In Oil And Gas Production API Spec 6A/ISO 10423 Specification For Wellhead And Christmas Tree

Equipment API Spec 17D Specification For Subsea Wellhead And Christmas

Tree Equipment API Spec 16A/ ISO 13533 Specification For Drill-Through Equipment API Spec 17A / ISO 13628-1 Design and Operation of Subsea Production

Systems API Spec 17H / ISO 13628-8 ROV Interfaces on Subsea Systems ASME Section VIII-DIV 2 Boiler & Pressure Vessel Code ASTM A193 Alloy Steel Bolting ASTM A194 Carbon & Alloy Steel Nuts ASTM 269 Stainless Steel Austenitic Tubing for General Use SAE AS 4059 Cleanliness Classification For Hydraulic Fluids AWS D1.1 Structural Welding Code -Steel

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Preliminary Intervention Riser Design Revision A Document Number: 12122301-RPT-RS-0001 Revision Date: Dec. 31, 2010

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THIS DOCUMENT INCLUDING, DRAWINGS, PROCEDURES, SPECIFICATIONS, AND ITS CONTENTS IS THE EXCLUSIVE PROPERTY OF INTECSEA AND IS FURNISHED ON A BASIS, AND WITH THE EXPRESS AGREEMENT THAT IT WILL NEITHER BE USED, SOLD, TRANSFERRED, COPIED, TRACED, PHOTOGRAPHED, NOR REPRODUCED IN A NY MANNER WHATSOEVER IN WHOLE OR IN PART, NOR ANY ITEM HEREIN BE SOLD, MANUFACTURED OR ASSEMBLED WITHOUT THE WRITTEN AGREEMENT OF INTECSEA THE RECIPIENT OF THIS DOCUMENT AGREES NOT TO DISCLOSE TO ANY OTHER PARTY INFORMATION CONTAINED HEREIN, OR NOT TO USE SUCH INFORMATION, EXCEPT FOR THE SPECIFIC PURPOSE INTENDED AT THE TIME OF RELEASE OF THIS DOCUMENT.

A Issued for Internal Review 31 Dec 10 RS JY RMK N / A

Rev Status Date Originator Checker Checker PM Client Project:

RPSEA 1502 Client:

Nautilus Int. LLC Document Title:

Preliminary Intervention Riser Design WPS Project No. Document No.

12155301-RPT-RS-0001 12122301

Nautilus Int. LLC

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TABLE OF CONTENTS

1.0 INTRODUCTION ................................................................................................. 21 2.0 DEFINITIONS ...................................................................................................... 22 3.0 SCOPE ................................................................................................................ 23 4.0 FUNCTIONAL REQUIREMENTS ....................................................................... 24 5.0 RISER DESIGN METHOLOGY .......................................................................... 25 6.0 RISER SYSTEM CONFIGURATION .................................................................. 27

6.1 BUOYANCY MODULES ................................................................................ 30 6.2 STANDARD JOINTS .................................................................................... 30 6.3 SPECIALTY JOINTS .................................................................................... 30

6.3.1 Tension/keel Joints ...................................................................... 30 6.3.2 Crossover Joints .......................................................................... 31 6.3.3 Stress Joint .................................................................................. 31 6.3.4 Coatings and Cathodic Protection ............................................... 31 6.3.5 Instrumentation ............................................................................ 31

7.0 SSR MODELING ................................................................................................. 32 8.0 STRENGTH ANALYSIS ..................................................................................... 33

8.1 GENERAL .................................................................................................. 33 8.2 LOAD CASES ............................................................................................. 33 8.3 DESIGN ENVIRONMENTS ............................................................................ 34 8.4 STRENGTH ANALYSIS RESULTS ................................................................. 35

8.4.1 Tensioner ..................................................................................... 41 8.4.2 SSD and NSMRP Design Loads ................................................. 42

9.0 FATIGUE ANALYSIS ......................................................................................... 43 10.0 SSR HANDLING ................................................................................................. 46 11.0 SSR COST ESTIMATE ....................................................................................... 49 12.0 REFERENCES .................................................................................................... 50 13.0 APPENDICES ..................................................................................................... 51

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Table 6-1: Intervention SSR Riser Properties 27 Table 6-2: Intervention SSR Buoyancy Module Properties 27 Table 8-1: Intervention SSR Design Load Cases 33 Table 8-2: RPSEA Associated Wave Data 34 Table 8-3: Intervention SSR Tensioner Properties 42 Table 8-4: Intervention SSR Seafloor Shut-off Device Design Load Summary 42 Table 8-5: Intervention SSR Near Surface Riser Package Design Load Summary 42 Table 9-1: S-N Curve Parameters 43 Table 9-2: Intervention SSR Wave-induced Fatigue Summary 44

Figure 5-1: Riser Case Matrix State Illustration 26 Figure 6-1: Free Standing Intervention SSR Illustration 28 Figure 6-2: Connected Intervention SSR Illustration 29 Figure 8-1: RPSEA Current Profiles 34 Figure 8-2: Intervention SSR Maximum Von Mises Stress Case C-01 35 Figure 8-3: Intervention SSR Maximum Von Mises Stress Case C-02 36 Figure 8-4: Intervention SSR Maximum Von Mises Stress Case C-03 36 Figure 8-5: Intervention SSR Maximum Von Mises Stress Case C-04 37 Figure 8-6: Intervention SSR Maximum Von Mises Stress Case C-05 37 Figure 8-7: Intervention SSR Maximum Von Mises Stress Case C-06 38 Figure 8-8: Intervention SSR Maximum Von Mises Stress Case C-07 38 Figure 8-9: Intervention SSR Maximum Von Mises Stress Case C-08 39 Figure 8-10: Intervention SSR Maximum Von Mises Stress Case C-09 39 Figure 8-11: Intervention SSR Maximum Von Mises Stress Case C-10 40 Figure 8-12: Intervention SSR Maximum Von Mises Stress Case C-11 40 Figure 8-13: Intervention SSR Maximum Von Mises Stress Case C-12 41 Figure 9-1: Intervention SSR 1-year Loop Current Case C-02 Wave Fatigue Results 44 Figure 9-2: Intervention SSR 1-year Loop Current Case C-02 Wave Fatigue Results 45 Figure 10-1: Intervention SSR Assembly and Deployment Unit 47 Figure 11-1: Intervention SSR Budgetary Estimate 49

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1.0 INTRODUCTION

To meet industry goals of cost reductions and the technical challenges of increasing water depth, alternative riser concepts such as this Self Supporting Riser (SSR) system have become a viable riser option. The SSR systems have been used for early production and full field development in both shallow and deep water. The economic risks associated with using a permanent platform in deep water and with complex or uncertain reservoir performance may in some cases be mitigated by developments utilizing riser towers. The deepwater SSR systems used to date have been costly and need improvements to be well suited to reduction of reservoir or production risks. The SSR system presented in this report is based on technology developed prior to this project that Nautilus and INTECSEA had a major influence on. Nautilus and INTECSEA have developed a novel design of the riser tower that has incorporated several innovative technical features. The concept was initially conceived for riser workover in the later 1980’s and early 1990’s in shallow water Southeast Asia [1]. During the past five years, INTECSEA has further developed the concept through extensive system design and analysis, basin model tests, system component qualification and manufacturing, and installation of a prototype system in the Gulf of Mexico. In 2006, INTECSEA designed a free standing riser concept for early development of marginal fields and went on to successfully install a prototype demonstration free-standing riser (full scale) in 3000 ft water depth in the Gulf of Mexico. Nautilus developed the concept of using the SSR system for the coil tubing (CT) intervention. This report documents the riser analysis as one of the REPSEA JIP work tasks for the CT operation based on the SSR system. The SSR is designed from modular components with standardized connections that can be assembled in any combination to suit a particular application. The system is not a field specific design but engineered to perform thought the GoM for CT operations. The SSR can be installed and recovered by a construction work boat independently from the downhole operations. The riser can be quickly abandoned and left untended, free-standing, when downhole operations are complete or when forced by weather or equipment problems. The intervention vessel is also free to depart at convenient times leaving the riser free-standing. This report provides the background information and analysis results for the preliminary design of the self supporting intervention riser system intended for operations in the Gulf of Mexico (GoM). The primary purpose of this document is to reinforce the technical bases for design by identifying the riser stack-up and report analytical strength and high level wave fatigue performance results.

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2.0 DEFINITIONS

MSL Mean Sea Level AMSL Above Mean Sea Level BMSL Below Mean Sea Level CT Coil Tubing DP Dynamically Positioned GoM Gulf of Mexico JIP Joint Industry Project NSMRP Near Surface Marine Riser Package OD Outer Diameter REPSEA Research Partnership to Secure Energy for America ` SAF Stress Amplification Factor SSD Seafloor Shut-off Device SSR Self Supporting Riser VIV Vortex Induced Vibration

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3.0 SCOPE

This document defines the scope and objective of the design phase. Technical requirements are discussed, systems required for riser development are defined and performance and functional requirements are detailed. Riser design methodology is explained and the global performance analysis is reported. All major riser components are identified and designed. The scope is outlined as follows.

• Riser system description • Riser design methodology • Riser strength analysis • Definition of design loads for interface structures with the buoyancy modules and

SSD and NSMRP • Definition of design loads for specialty joints including tension joints, keel joints,

stress joint and crossover joints This Intervention Riser Design Report serves as the basis for the comprehensive development of the SSR system. It is not intended that this document be all-inclusive with regard to options and detailed specifications for design. Though vessel dynamics are included in the analysis, engineering details regarding the installation and operation vessels are not included.

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4.0 FUNCTIONAL REQUIREMENTS

The self supporting intervention riser system was designed to endure extreme GoM environment conditions in the free-standing and connected state. The system concept was developed based on utilizing qualified mature industry products for the majority of the riser stack-up. The specific functional requirements for the SSR system are itemized below.

• Designed to meet, as a minimum, all regulatory requirements that are applicable for a unit of this type and service

• Designed to tolerate extreme GoM environments in the free-standing and connected state

• Riser system to be comprised primarily of commonly available joints • Capabilities of multiple field deployments for single or multiple fields • Single deployment in the in-place condition for up to 6 month duration • The riser is to be tied back to the SSD • Riser top depth deployed beneath significant wave interaction and high currents • Capable of riser deployment by a relatively small low cost work boat or

construction vessel • The Riser top elevation positioned for shallow access • Buoyancy modules sized to meet vessel handling limitations • The buoyancy modules are to support NSMRP and SSR in intact and damaged

states • Instrumentation for buoyancy load monitoring • Flexibility to expandable the SSR system for deeper fields

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5.0 RISER DESIGN METHODOLOGY

The SSR is a top tensioned riser system designed to support its self weight in the free-standing or connected state. The system was not intended as a site specific design but to be utilized for Coil Tubing (CT) operations throughout the GoM. The riser system was analyzed for 5,000 ft water depth whilst consideration for expanding up to 10,000 ft water depth was incorporated. Riser performance analysis for depths greater than 5000 ft will be performed in the next phase of engineering. The SSR riser system is unique in its ability to be deployed by an installation vessel and left vertically in place without the aid of vessel support. Once the SSR has been installed an Intervention vessel can land a relative short riser extension, including the NSMRP, on top of the SSR to perform CT operations. The intervention vessel can easily disconnect and withdraw the riser extension leaving the SSR intact until operations can once again commence. In order to satisfy functional requirements the riser analysis was divided into two segments, the free-standing state followed by the connected state as illustrated in Figure 5-1. For each state the riser is subjected to a conservative set of environments and physical conditions defined in the load case matrix provided in Section 8.2. The first stage was to identify the applicable industry standard or practice for guidance in the CT intervention SSR design. Based on the maximum anticipated design pressure, standard 6⅝-inch and 7⅝-inch OD (outer diameter) casing and a minimum drift of 4½-inch the standard riser joints were isolated employing governing equations from API RP 17G [1]. The resultant wall thickness translated to Grant Prideco’s S-135 ⅝-inch wall drill pipe and V&M P-110 ¾-inch wall tubing. The 6⅝-inch OD pipe was anticipated for the standard riser joints and the 7⅝-inch OD tubing was anticipated for areas requiring high bending resistance and weldability. For the purpose of this report the 7⅝-inch OD joints are categorized as specialty joints. Corrosion allowance and manufacturing tolerances are included in the preliminary design development. More information on the standard riser joints and specialty joints can be found in Sections 6.2 & 6.3 respectively. After determining the preliminary riser geometry the rise weight was estimated. The riser installed weight was conservatively based on vendor data, nominal wall thickness and 18ppg internal fluid. The buoyancy modules were designed to provide the top tension required to support the installed riser system during the states defined in the load case matrix, as shown in Section 8.2. The size of the buoyancy module was predetermined based on the vessel handling capabilities. A preliminary FEA model of the entire riser system including buoyancy modules was developed and global strength analysis results were produced. The results were used in determining the quantity and elevations of each buoyancy module. The buoyancy system was optimized according to riser strength analysis results. The buoy details can be found in Section 6.1. Global strength analysis cases and results are identified in section 8.0.

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Following the strength analysis is the high level wave fatigue analyses, results for the fatigue study are reported in Section 9.0. Wave fatigue was executed for the waves associated with the 1-year loop current assuming the SSR system was intact. A more in-depth wave and VIV fatigue study is to be executed in the next phase of SSR design.

MSL

Mudline - 5000' BMSL

Riser Extension

Vessel

Buoyancy Modules

Connected

Figure 5-1: Riser Case Matrix State Illustration

MSL


Buoyancy Modules

Free-standing

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6.0 RISER SYSTEM CONFIGURATION

The majority of the riser is comprised of single barrier 6⅝-inch steel drill pipe with gas-tight, pressure rated connections. Transitions from the 6⅝-inch OD drill pipe to 7⅝-inch OD tubing are required to accommodate qualified connectors and specialty joints at area of concentrated stress along the riser string. The 7⅝-inch OD tubing assembly includes the crossover, tension and keel joints. At the base of the riser is a tapered stress joint which is required to mitigate the large bending moments imposed by the near surface currents on the riser drag area and the vessel offsets. A summary of the physical properties for the joints are identified in Table 6-1 and the two riser states are illustrated in Figures 6-1 and 6-2. The buoyancy modules identified in the illustrations support the weight of the riser string and produce enough net buoyancy to resist the environmental forces. Four buoyancy modules with a combined net buoyancy of 496 kips support the free-standing riser system. The buoyancy modules are positioned near the top of the riser stack with approximately 204 ft between each module. The location and quantity of modules was chosen based on the riser global analysis performance results. The buoyancy modules provide enough top tension to support the riser wet weight, 270 kips, and allowance for up to 18ppg internal fluid. More details regarding physical properties and modeling of the riser joints and buoyancy modules are addressed in the subsequent sections. At the top of the free-standing riser is the near surface marine riser package (NSMRP). The NSMRP is assumed to stand 15 ft tall and weigh 17 kips installed. It’s assumed rigidly connected to the upper most buoyancy module with its center of mass 7.5 ft above the top of the module. The drag diameter is conservatively assumed 6 ft for the entire height of the NSMRP.

Table 6-1: Intervention SSR Riser Properties

OD Thickness ID Length Dry Jt. Weight # of Joints σy

(in) (in) (in) (ft) (lbs) (qty) (ksi)Standard Joint 6.625 0.625 5.375 31.5 1454 146 135

Tension/Keel Joint 7.625 0.75 6.125 29.0 1604 4 110Crossover Joint 7.625 0.75 6.125 20.0 1106 10 110Stress Joint Top 7.625 0.75 6.125Stress Joint Base 13.5 3.6875 6.125

Notes:1. σy is the minimum specified material yeild stress

Riser Component

30.0 5350 1 110

Table 6-2: Intervention SSR Buoyancy Module Properties

OD Height ChambersBuoy Dry Weight

Net Buoyancy Intact

Net Buoyancy Damaged

# of Modules

(ft) (ft) (qty) (kips) (kips) (kips) (qty)

Buoyancy Module 14 16 3 32.7 124.1 73.3 4

Riser Component

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MSL


SSD - 4980' BMSL

Crossover Joints -

Standard Joints -

Stress Joint -

Tension/Keel Joints -

NSMRP - 300' BMSL

Buoy - 535' BMSL

Buoy - 756' BMSL

Buoy - 977' BMSL

Buoy - 315' BMSL

Stress Joint - 4950' BMSL

Free-standing SSR

Figure 6-1: Free Standing Intervention SSR Illustration

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MSL


SSD - 4980' BMSL

Crossover Joints -

Standard Joints -

Stress Joint -

Tension/Keel Joints -

NSMRP - 300' BMSL

Buoy - 535' BMSL

Buoy - 756' BMSL

Buoy - 977' BMSL

Buoy - 315' BMSL

Pitch, Roll & Yaw Compensation - 25'

Riser Extension

Tensioner

Vessel Boundry Condition

Stress Joint - 4950' BMSL

Connected SSR

Figure 6-2: Connected Intervention SSR Illustration

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6.1 BUOYANCY MODULES The buoyancy modules are required to support the riser system by maintaining adequate top tension under all expected design conditions. The modules were sized for ease of handling and installation. The quantity, attachment points along the riser length and compartmentalization of the modules was determined through global analysis. Details regarding the physical properties and installed elevations can be found in Table 6-2 and Figure 6-1 respectively. The buoys are assumed to be stiffened plate structures with internal stiffeners, web frames, bulkheads and flats. For the analysis the buoys were modeled to tolerate flooding of a single compartment while still providing sufficient buoyancy to maintain top tension during an extreme event. The buoys are cylindrical in shape with the riser positioned along the vertical axis. The buoy has a hollow center with enough allowance to clear a riser joint. Integral to the module is a mechanical interface for landing and locking onto a specialty joint. The net buoyancy load is transferred through the load interface at the top of the buoy into the riser string. A centralizer assembly at the base of the buoyancy module constrains lateral movement.

6.2 STANDARD JOINTS The majority of the riser string is comprised of standard joints. They are designed for the areas along the riser string with relatively low bending moments but high axial tension loads and pressure differentials. Due to the cost and lead time, standard 6⅝-inch drilling riser joints were preferred for the SSR design. Following the riser design methodology outlined in section 5.0 it was determined that Grant Prideco’s 6⅝-inch OD x ⅝-inch WT grade S-135 drill pipe meets the API RP 17G recommendations. The drill pipe is equipped with gas-tight, pressure rated XT-M connectors. Standard joint physical properties are summarized in Table 6-1.

6.3 SPECIALTY JOINTS Specialty joints are required in high localized stress areas usually at the bottom, top and near mechanical connection points along the riser string. The specialty joints for the intervention SSR system are identified below.

6.3.1 Tension/keel Joints

The combined effect of the tension joints suspend the entire riser weight and provide the pretension to the riser string. Each joint is supported vertically and laterally through a load ring and keel guide that interfaces with a buoyancy module. The tension joint is a heavy wall tubular sections that has a single taper or straight tubular. For the intervention SSR model the tension and keel joint was assumed a continuous tubular joint as indicate in Table 6-1.

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6.3.2 Crossover Joints

The crossover joints are necessary to transition from the tension and stress joints to the standard joints. For the SSR application the crossover joint includes a premium connector to mate with a specialty joint on one end and a XT-M connector on the opposite end.

6.3.3 Stress Joint

The riser bottom stress joint interfaces with the SSD via a tieback connector. The tress joint is a heavy wall, tapered tubular section that has a premium connector welded to its top end. Details regarding the physical properties for the intervention SSR system stress joint are listed in Table 6-1.

6.3.4 Coatings and Cathodic Protection

The SSR buoy coatings will be suited to the functionality of the component being coated, and to the corrosion prevention required to achieve the anticipated service life. Frequent handling of the joints will be considered in the coating and catholic protection system. In addition to being coated the buoyancy modules will be fitted with replaceable anodes.

6.3.5 Instrumentation

The primary purpose of the instrumentation is to provide SSR tension status and to serve as an alarm to ensure the safety and survival of the installation. The in-service monitoring of the SSR system will be by measuring the net buoyancy load at the riser-buoy load interfaces. The load measuring instrumentation will provide regular indication of the fill status of each buoyancy module.

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7.0 SSR MODELING

The current loads are applied to the entire riser string as a static constant load. The inertia coefficient Cm = 1 + Ca is set to 2.0 for elements BMSL. The drag coefficient of the buoys in steady current, referred to as nominal drag coefficient, is assumed to be 1.1. That of the riser is assumed to be 1.2. The tensioner is modeled as a spring element with a stiffness of 15 kips/ft. The various steps involved in the analysis of the SSR are summarized below.

1. Using the software program Flexcom (version 7.9.3 build) an FEA model of the SSR including the buoyancy modules was developed to match the details in Table 6-1 and Table 6-2.

2. The static analysis in the free-standing and connected state is performed to

confirm the stiffness, buoyancy, and installed weight of the riser system. The riser bottom is assumed to have a fixed boundary at the SSD-riser interface. In the connected state the riser is assumed to be connected to the vessel as indicated in Figure 6-2. The riser is unable to translate but free to rotate about the x, y or z axis at the vessel boundary condition.

3. The static solution is used as the starting point for dynamic strength and fatigue

analyses. At this preliminary stage, the regular wave approach was used in the dynamic analysis. For strength analysis a minimum simulation of 10 times the maximum wave period (Tmax) is performed for the load cases described in Table 8-1. A 3 hour random wave simulation is performed in producing fatigue results. The applied currents and associated waves are specified in Figure 8-1 and Table 8-2.

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8.0 STRENGTH ANALYSIS

8.1 GENERAL Riser strength analysis is performed to ensure the integrity of the riser systems during operating, extreme and survival conditions. Section 8.2 presents the design load cases. Section 8.4 presents the results of the time domain dynamic analysis, and the global design loads for riser components and buoyancy-riser interface structures.

8.2 LOAD CASES The riser was designed to satisfy the load cases identified in Table 8-1. The allowable stresses used for the design of the riser components are in accordance with section 6.4.7 of API RP 17G for various conditions. Due to vessel stability limitations it was assumed that the intervention vessel will not be connected to the SSR during a 1-yr winter storm, hurricane or other higher sea states. For the analyses the Intervention operations environment was constrained to the 1-year loop current condition. During the free-standing state the riser is designed to be positioned far enough below the MSL to negate any waver particle interaction and the associated currents at this water depth are considered benign compared to the typical GoM loop currents. Only the conservative environments are considered in the preliminary phase of engineering design. The load case matrix will be expanded to cover a larger range of environments in the next phase of engineering.

Table 8-1: Intervention SSR Design Load Cases Bore Pressure

ID Conditon (psi)C-01 Installation 1-yr Loop Hang-off 0 0.67σy

C-02 Operating 1-yr Loop Nominal Tension 6000 0.67σy

C-03 1-yr Loop Damaged Buoy 6000 0.8σy

C-04 1-yr Loop Damaged Tensioner 6000 0.8σy

C-05 1-yr Loop Shut-in 10000 0.8σy

C-06 1-yr Loop Max Vessel Offset 0 0.8σy

C-07 Operating 1-yr Loop Intact 6000 0.67σy

C-08 10-yr Loop Damaged Buoyancy 6000 0.8σy

C-09 10-yr Loop Shut-in 10000 0.8σy

C-10 100-yr Loop Intact 6000 0.8σy

C-11 100-yr Loop Damaged Buoyancy 6000 σy

C-12 100-yr Loop Shut-in 10000 σy

Notes:1. σy is the minimum specified material yeild stress (ref. Table 6-1)2. A damaged buoy indicates the uppermost chamger of the buoyancy module nearest to the surface is 100% flooded3. A damaged tensioner indicates a 25% decrease in tension from nominal4. Operating pressure is assumed 6,000 psig5. Shut-in pressure is assumed 10,000 psig

Riser State

Inte

rven

tion

Extreme

Free

-sta

ndin

g

Extreme

Survival

Load Case Allowable Stress

Design Environment Description

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8.3 DESIGN ENVIRONMENTS The following current data was extrapolated from the sea state date provided in the RPSEA Project 08121-1502 Task 5 Report [2]. The “Max Loop Current” identified in Section 11.0 of the Task 5 Report was normalized. Based on previous project experience the profiles for each return period were generated. The current profiles and the associated waves are detailed in Figure 8-1 and Table 8-2. Wave data is based on an average derived from internal data collected from previous GoM projects. This environment data is considered reliable for the preliminary development of the SSR system.

Current Profiles(Project: RPSEA)

0

500

1000

1500

2000

2500

3000

3500

4000

4500

50000 1 2 3 4 5 6 7 8 9

Velocity (ft/s)

Dep

th B

MSL

(ft)

1-yr Loop Current

10-yr Loop Current

100-yr Loop Current

Figure 8-1: RPSEA Current Profiles

Table 8-2: RPSEA Associated Wave Data Hmax Tmax(ft) (s)

1-yr Loop 11.2 5.610-yr Loop 11.2 5.6100-yr Loop 11.2 5.6

Environment

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8.4 STRENGTH ANALYSIS RESULTS The following plots illustrate the maximum Von Mises Stress distribution along the riser length for the load case identified in Table 8-1. The plots are in sequence with the load case matrix. The results indicate that the present design is robust enough to endure extreme environments while damaged or at maximum anticipated operating conditions. See Appendix A for details regarding the effective tension, bending moment and riser deflection for each load case. During an intervention vessel DP black-out condition, Figure 8-7, the maximum vessel offset before reaching riser material allowable stress limit is 385 ft from the wellhead. The maximum vessel offset is greatly dependent on the tensioner properties. Assumptions regarding the tensioner physical properties are outlined in Section 8.4.1 and Table 8-3 notes.

CT Intervention Stress Distribution(Free-hanging installation)

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

0 10 20 30 40 50 60 70 80 90

Max. Von Mises Stress (ksi)

Elev

atio

n (f

t)

1-yr Loop Current Allowable

Figure 8-2: Intervention SSR Maximum Von Mises Stress Case C-01

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CT Intervention Stress Distribution(Connected, Operating Pressure)

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CT Intervention Stress Distribution(Connected, damaged tensioner. operating pressure)

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CT Intervention Stress Distribution(Vessel Max Offset)

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RPSEA Intervention Riser Von Mises StressFree-standing, 1-year Loop Current, 6 ksi bore pressure

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atio

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RPSEA Intervention Riser Von Mises StressFree-standing, 10-year Loop Current, 6 ksi bore pressure, Damaged Buoy

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RPSEA Intervention Riser Von Mises StressFree-standing, 10-year Loop Current, 10 ksi Bore Pressure

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RPSEA Intervention Riser Von Mises StressFree-standing, 100-year Loop Current, 6 ksi Bore Pressure, Damaged Buoy

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8.4.1 Tensioner

To prevent the riser from buckling a heave compensation system is necessary to decouple the vessel vertical motion during riser deployment and CT operations. During riser deployment the tensioner must be capable of providing compensation for the wet weight of the riser string, NSMRP, riser extension and the four flooded buoyancy modules. The maximum deployed weight of the riser system is 337 kips. The load case C-01 represents the most onerous design condition when the entire SSR system is soft-hung off at the tensioner. During CT operations the tensioner must provide compensation for the complete riser extension weighing 16 kips. It’s required that the tensioner in the intact and damaged state provide ample tension to support the riser extension. The assumed applied tensioner tension is 60 kips intact and 45 kips in the damaged state. Summarized in the Table 8-3 is the maximum resulting stroke for each load case. The tabulated maximum resulting stroke values are provided for tensioner design purposes.

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Table 8-3: Intervention SSR Tensioner Properties Maximum

Tensioner StrokeID Conditon (ft)

C-01 Installation 1-yr Loop Hang-off 11.2C-02 Operating 1-yr Loop Nominal Tension 5.9C-03 1-yr Loop Damaged Buoy 6.7C-04 1-yr Loop Damaged Tensioner 7.4C-05 1-yr Loop Shut-in 5.4C-06 1-yr Loop Max Vessel Offset 34.6

Notes:1. Tensioner stiffness is assumed 25% of tensioner intact tenson, 15 kips/ft2. The neutral lenghth of the tensioner is assumed 25ft2. Maximum stroke is the tensioner effective stroke beyond it's neutral length

Inte

rven

tion

Extreme

Riser State

Load Case Design Environment Description

8.4.2 SSD and NSMRP Design Loads

Reported in the section is the effective maximum dynamic effective tension and bending moment at the top and bottom of the riser system. The loads reflected in the Table 8-4 and Table 8-5 occur at the stress joint-SSD interface and Riser extension-NSMRP interface respectively.

Table 8-4: Intervention SSR Seafloor Shut-off Device Design Load Summary

Eff. Tension BendingID Conditon (kips) (kip-ft)

C-02 Operating 1-yr Loop Nominal Tension 287 85C-03 1-yr Loop Damaged Buoy 239 85C-04 1-yr Loop Damaged Tensioner 272 99C-05 1-yr Loop Shut-in 287 85C-06 1-yr Loop Max Vessel Offset 350 540C-07 Operating 1-yr Loop Intact 235 217C-08 10-yr Loop Damaged Buoyancy 186 662C-09 10-yr Loop Shut-in 235 670C-10 100-yr Loop Intact 235 1007C-11 100-yr Loop Damaged Buoyancy 187 943C-12 100-yr Loop Shut-in 235 1008Survival

Extreme

SSD Interface LoadsLoad Case

Inte

rven

tion

Free

-sta

ndin

g

DescriptionDesign

EnvironmentRiser State

Extreme

Table 8-5: Intervention SSR Near Surface Riser Package Design Load Summary

Eff. Tension BendingID Conditon (kips) (kip-ft)

C-01 Installation 1-yr Loop Hang-off 319 2.2C-02 Operating 1-yr Loop Nominal Tension 41 52C-03 1-yr Loop Damaged Buoy 41 38C-04 1-yr Loop Damaged Tensioner 26 63C-05 1-yr Loop Shut-in 40 52C-06 1-yr Loop Max Vessel Offset 56 53

Riser State

Load Case Design Environment Description

Inte

rven

tion

Extreme

NSMRP Interface Loads

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9.0 FATIGUE ANALYSIS

The purpose of riser fatigue analysis is to confirm the SSR system has sufficient fatigue life to sustain dynamic loads during the intended CT intervention campaign. Only Wave-induced fatigue damage resulting from the dynamic response to the direct impact of wave and the wave-induced vessel motions is considered in this analysis. The VIV fatigue damage is assumed to be small or suppressed by the fairings or strakes if necessary. A sensitivity check indicated that the riser bending stress increases approximately 6% at the stress joint due to the increase in drag area intrinsic of VIV suppression devices. The wave sea state associated with the 1-year loop was used in the fatigue analysis. The sea states are presented in Table 7-2. The duration of the wave is assumed as 3 hours. The S-N curve approach was used in riser fatigue analysis. DNV S-N B1 curve with SAF=1.05 and SAF=5.0 are considered for the riser pipe body and riser connector fatigue calculation respectively. DNV S-N F3 or F1 curve with SAF=1.2 will be used for riser joint weld fatigue assessment. The S-N curve parameters are listed in Table 9-1.

Table 9-1: S-N Curve Parameters

m1 log a 1 k m2 log a 2 kDNV-B1 4 11.5629 3.6553E+11 5 12.9534 8.9827E+12DNV-F1 3 8.7834 6.0736E+08 5 10.6394 4.3592E+10DNV-F3 3 8.6304 4.2701E+08 5 10.3834 2.4177E+10Note:1. Stress range unit is in ksi

S-N CurveN ≤ 106 N > 106

The fatigue results are summarized in Table 9-2. The numbers show that the crossover joint and tension joint connectors and welds govern the riser fatigue life. The minimum fatigue life for all applied environments occurs at the tension joint connector with an SAF=5.0 using DNV-B1 curve. An SAF of 5.0 is typically conservative for T&C couplings. The actual SAF could be less depending on the coupling design. It is expected the actual riser fatigue lives will be longer than those presented in Table 9-2, since most of the time the operation will be performed under a milder or more benign sea state than those applied in this analysis. The location of peak fatigue damage is indicating in figures 9-1 and 9-2. The peak damage occurs approximately 4760-feet above the SSD within the uppermost tension joint. The fatigue is localized and further design optimization will be performed in the next phase of engineering.

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Table 9-2: Intervention SSR Wave-induced Fatigue Summary

Pipe Body ConnectorsDNV-F1 DNV-F3 DNV-B1 DNV-B1SAF=1.2 SAF=1.2 SAF=1.05 SAF=5

Crossover Jt. 85 58 65046 28Tension/keel Jt. 2 1 150 0Standard Jt. 123 82 107263 41Stress Jt. 12174618 12174618 12174618 6516242

1-yr Loop Current

Riser Joint Environment

Fatigue Life (days)Welds

CT Intervention SSR Fatigue Life(Case C-02)

20

1020

2020

3020

4020

5020

6020

1.E+00 1.E+01 1.E+02 1.E+03 1.E+04 1.E+05 1.E+06 1.E+07 1.E+08

Fatigue Life (Days)

Ele

va

tio

n (

ft)

SAF=1.2 DNV-F1

SAF=1.2 DNV-F3

SAF=1.05 DNV-B1SAF=5 DNV-B1

Figure 9-1: Intervention SSR 1-year Loop Current Case C-02 Wave Fatigue Results

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CT Intervention SSR Fatigue Life(Case C-02)

4620

4670

4720

4770

4820

4870

4920

4970

1.E+00 1.E+01 1.E+02 1.E+03 1.E+04 1.E+05 1.E+06 1.E+07 1.E+08

Fatigue Life (Days)

Ele

va

tio

n (

ft)

SAF=1.2 DNV-F1 SAF=1.2 DNV-F3 SAF=1.05 DNV-B1 SAF=5 DNV-B1

Figure 9-2: Intervention SSR 1-year Loop Current Case C-02 Wave Fatigue Results

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10.0 SSR HANDLING

The joints and buoyancy modules of the SSR are to be assembled and deployed using a unit designed for landing over the moon pool or the rail of a vessel of opportunity. The assembly and deployment unit is shown conceptually in Figure 10-1. As shown, it consists of an integrated assembly with the functions of moon pool cover, tongs, slips, work platform, and overhead frame. The overhead frame has an upper deck with a joint guide, two constant tension winches, and an umbilical guide. Joints may be upended either by a deck crane or by a handling device on the assembly and deployment unit. The base of the deployment unit shall be suitable to set on the deck of a small work boat while at dock. The base shall be suitable for setting over a moon pool no smaller than 14 feet square and no larger than 20 feet square with provisions to distribute the weight of the module and the load that will be suspended through the moon pool. . The base shall have provisions for two vertical “I” beam guide rails to be lowered through attachment assemblies on the base and into the moon pool. The guide rails shall be fixed to the base in a manner suitable to take the side loads associated with guiding buoyancy modules through the moon pool for deployment and recovery. The guide rails shall be “I” beams spaced to suit the guide sleeves on the buoyancy modules. The guide rails shall have provisions for using constant tension winch wires to align the buoyancy modules with the guide rails for recovery. The base shall support horizontal rails on which a split moon pool cover moves to open and close, and shall have a drive system to move the cover. Suitable guards shall be incorporated to protect personnel from injury by moving parts. The cover and base shall include provisions for a hand rail or similar barrier around the moon pool when the cover is not closed.

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TOP VIEW OF INSTALLATION MODULE

Figure 10-1: Intervention SSR Assembly and Deployment Unit

FRONT VIEW

Restraint to secure top of joint 18”

Sheaves for constant tension winches

Umbilical

Constant tension winches

SIDE VIEW

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One side of the split moon pool cover shall include provisions for power tongs attached in position to close around riser joints and thread or unthread the joints with the doors closed. The tongs shall move with the cover so that vertical access to the moon pool is clear when the doors are open. The cover shall also have provisions for a set of split slips to support the suspended riser while the cover is closed. An overhead frame shall be mounted on the base and extend across the moon pool. The overhead frame shall include provisions for stabilizing a joint after a crane positions the joint for threading or unthreading by the tongs. The overhead frame shall have provisions for guiding the umbilicals from reels for deployment along with the riser joints. The overhead frame shall have 2 each 15 ton constant tension winches on an upper deck. Each constant tension winch shall have 1,200 feet of wire. Suitable sheaves shall be located to align the wires from the constant tension winches with the “I” beam guide rails in the moon pool. Clearance between the moon pool cover and the overhead frame shall be adequate for a buoyancy module when the buoyancy module is positioned such that the riser joint which extends vertically through the buoyancy module is in position to be threaded by the tongs while the top of the buoy is below the crossbar.

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11.0 SSR COST ESTIMATE

Summarized in Table 11-1 is the SSR cost estimate. This estimate is preliminary and to be considered for budgetary purposes only. Empty cells indicate unknown information. The cost estimate is update continuously according to project demands.

Item Description Unit Cost Quantity Total Cost (USD) RemarkFoundation 1 Subsea wellheadSDD 1 Subsea Disconnect DeviceBottom Conenctor $420,000 1 $420,000 10K TBC or mechanic connecitonBottom Stress Joint $180,000 1 $180,000 Mechanic tube welded to a bottom connector interfaceCrossover Joints $25,000 8 $200,000 Mechanic tubes, 2 at bottom and 2 at topABC Keel Joint $120,000 1 $120,000 Mechanic tube6-5/8" riser joint 30ft $6,053 138 $835,363 Excluding coatingRiser top Joint and connector $125,000 1 $125,000 Mechanic tube welded to a top connector interfaceRiser Extension $98,427 1 $98,427 Riser Pipe and connectorsNSRP 1 Near Surface Marine Riser PackageRiser installation tool $50,000 1 $50,000 Handling Structure/FrameInstrumentation $30,000 4 $120,000 LMU and Pressure TransducersFairing $120 600 $72,000

ABC $120,000 4 $480,000 Includes main steel and outftting

Riser installation rental 7 Includes equipment and crewNote:1. The following items are not included in the estimate a. Engineering and project support costs b. Installation vessel and removal costs. The vessel cost is included separately in other place of overall cost. c. Operating costs d. Foundation cost. The vessel cost is included separately in other place of overall cost.2. This estimate is based on the design depth of 5,000-feet

ABC + Riser Cost $2,700,790

RPSEA 1502 Riser System Cost Estimate

Total riser $2,220,790

Figure 11-1: Intervention SSR Budgetary Estimate

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12.0 REFERENCES

1. API RP 17G, Recommended Practice for Completion/Workover Risers, Second Edition, July 2006

2. RPSEA Project 08121-1502 Task 5 Report

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13.0 APPENDICES

APPENDIX A – INTERVENTION SSR GLOBAL ANALYSIS RESULTS

Licensed To:Intec Engineering Inc, Houston, TX

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4.0 MATERIAL BY GENERAL MARINE CONTRACTORS

In this evaluation we will illustrate the required additional specifications, above the standard API and MMS requirements.

4.1 Seafloor Shutoff Device

The Seafloor Shutoff Device (SSD) and ROV operation panel will consist of the following main components:

• An adaptor to suit the top of the original connector. • The smaller bore e.g. the annulus line will divert 90 degrees to a 2 1/16” outlet on the

side of the adaptor and the larger bore e.g. the production tubing will continue vertically, tapering up to a 7 1/16” BX flange at the top of the adaptor.

• 2 (7 1/16”) BOP rams studded at the top and bottom capable of shearing 3” coil tubing. • A (4’) spool piece with 7 1/16” BX flange at top and bottom. • A crossover from 7 1/16” BX flange to the lower side of the upper connector hub. • An upward facing mandrel to suit the SSD connector. • 2 spool pieces from side outlets of BOPs to chemical injection valves. • An annulus to Production crossover loop. • Manifold accumulators for storing hydraulic energy (capacity TBD). • Panel mounted ROV valves and hot stabs for recharging the accumulator banks. • 4 (4”) hydraulic gauges to confirm pressure of each accumulator bank. • 3 (2 way) panel mounted ROV valves for functioning the 2 shear rams and the ret. ball

valve. • 3 (4”) gauges to monitor pressure used per function. • 8 hydraulic/ROV override valves will be in place on the panel for the annulus monitor line

and chemical injections.

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Shear Ram Capable of Shearing 3” Coil Tubing, Wire line / Slick Line and Coil tubing with wire

7 1/16” Through Bore

2 1/16” Outlets Both Sides c/w BX Flange

Actuator Locks

Equip Wor king Pres sure

Work ing

Tem p.

Shear Capac ities

Sealing Requiremen

ts

Drift Size

Service Tensile load capacity @

WP

Tensile load capacity @

0psi

Bending @ W/P

Bending @ 0psi

Tree Adaptor

10,0 00p si

0- 250 degr ees f

N/A Gas / Fluid Suit Tree

H2S NACE MR

0175 (+CO2)

1M lbs 1.3M lbs 550 ft-kips 800 ft- kips

4’ Spool Piece

10,0 00p si

0- 250 degr ees f

N/A Gas / Fluid 7” H2S NACE MR

0175 (+CO2)


BOP Rams

10,0 00p si

0- 250 degr ees f

3” coil tubing and

wirelin e

Gas / Fluid 7” H2S NACE MR

0175 (+CO2)


7 1/16” to Upper Mandrel Crossov

er

10,0 00p si

0- 250 degr ees f


0175 (+CO2)


Connect or Hub

10,0 00p si

0- 250 degr ees f


0175 (+CO2)


2” Hydrauli c Valves

10,0 00p si

0- 250 degr ees f

N/A Gas / Fluid N/A H2S NACE MR

0175 (+CO2)

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

Spool Pieces

for Chemic

al Injection

10,0 00p si

0- 250 degr ees f


0175 (+CO2)

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

Spool Pieces

for Choke and Kill

x 2

10,0 00p si

0- 250 degr ees f


0175 (+CO2)

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

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Manifold Accumu

lators

5,00 0psi

0- 250 degr ees f

N/A Fluid N/A Water of glycol base

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

ROV Valves

5,00 0psi

0- 250 degr ees f


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

4”Hydra ulic

gages

10,0 00p si

0- 250 degr ees f


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

The Seafloor Shutoff Device (SSD) will be the lower most point of the Self Standing Riser (SSR) system. Its primary purpose is to isolate the reservoir in the event of an emergency. It is to have the capability of shearing and sealing 3” coiled tubing and/or wireline. The SSD will include a surface or ROV supplied stored energy system in the form of accumulators. Capability is required for immediate controlled shut-in from surface via remote control with override by ROV. All of the components listed will be generic in brand, and requirements will include, but not be limited to geometry requirements, safe working pressures, and trim levels.

For the purpose of this evaluation we assume the original tree completion Lower Marine Riser Package (LMRP) connector and interface plate are available.

The surface controlled Seafloor Shutoff Device (SSD) will interface with the subsea tree mandrel via an adaptor spool connecting to the top of the original LMRP connector. The adaptor will divert the annulus line 90 degrees to a 2 1/16” outlet located on the side of the adaptor; from the outlet the annulus will be routed through a series of valves to allow access to the annulus monitor line and/or crossover into the production bore via the shear rams. The production bore from the adaptor will taper out to the upper 7 1/16” BX flange. The production flange will attach to the studded bottom of the lower BOP shear ram, with a four foot spool piece on top of the BOP. The 4’spool piece will attach to the bottom of the upper shear ram. The upper ram will connect to the upward facing connector hub via a small crossover joint. There will need to be chemical injection valves included for the injection into the BOP below the rams. In normal operation, the SSD will be controlled electrically and hydraulically from surface via the control umbilical; there will also be an ROV panel for emergency secondary control of the SSD. The panel will also include a hot stab ports to supply auxiliary hydraulic energy to the SSD and a second hot stab for injection into the well bore.

4.2 Seafloor Shutoff Device Connector Interface to Stress Joint

In this section we will specify the components needed and cover the connection of the SSD connector to the lower stress joint. The stress joint will be supplied by others. All of the components listed will be generic in brand, and requirements will include, but not be limited to: geometry requirements, safe working pressures and trim levels.

The bottom of the stress joint will interface with a crossover suitable to connect to the top of the 8” full bore retainer ball valve. The 8” ball valve connection will be specified once the valve has been selected; under the ball valve a crossover will be in place to adapt to the SSD connector, leaving sufficient clearance to allow for the indicator on the connector to move throughout its full range of movement.

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The Stress Joint and SSD Connector assembly will consist of: • Lower Stress Joint. • A crossover from the stress joint to an 8” full bore ball valve. • A (8”) full bore (fail as is) ball valve. • A crossover from 8” ball valve to the connector. • A downward facing connector to suit the SSD upper mandrel.

The initial specs for the previously listed the equipment will be as follows: Equipmen t

Working Pressure

Workin g Temp.

Service and seal

Drift Tensile load capacity @ WP

Tensile load capacity @ 0psi

Bending @ W/P

Bending @ 0psi

Stress Joint

10,000ps i

0-250 f H2S NACE MR 0175 (+CO2)

6 5/8”

1M lbs 1.3M lbs 550 ft- kips

800 ft- kips

Stress Joint To 8” Ball Valve Crossover

10,000ps i

0-250 f H2S NACE MR 0175 (+CO2)

6 5/8”


800 ft- kips

8” Full Bore Ball Valve

10,000ps i

0-250 f H2S NACE MR 0175 (+CO2)

6 5/8”


800 ft- kips

8” Ball Valve To Connector Crossover

10,000ps i

0-250 f H2S NACE MR 0175 (+CO2)

6 5/8”


800 ft- kips

Connector to SSD hub

10,000ps i

0-250 f H2S NACE MR 0175 (+CO2)

6 5/8”


800 ft- kips

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4.3 Deck Equipment & Surface Control System The subsea tree and SSD will be controlled from the surface by a common hydraulic power Unit (HPU) and control van. The HPU will supply standard header pressures regulated at the surface. The specifics of the HPU and umbilical reels, as well as their connections, will be as follows: The Electric signal, and hydraulic pressures needed subsea will be supplied from the HPU via the Umbilical system. The HPU is preferably Diesel driven, but if electrically driven it is anticipated that two 440 Volt three-phase electrical supplies, a 120 Volt AC electrical supply will be required. A compressed air supply in the region of 400 CFM @ 100 Psi will also be required.

Hydraulic Power Unit/Control Van: The HPU for will consist of a series of independent accumulated header pressure systems. One system will split into two regulated systems a low pressure 3000psi system and a medium pressure 5000psi system. This will be done by use of regulators, (1) 5k in 3k out, (1) 5k in 5k out. The independent functions (project specific) branch off from these regulated supplies. The 10,000 psi system will be regulated, 10k in and 10k out, and the required independent 10k functions will branch off from this supply. Each of these regulated systems should have auxiliary ports on the bulkhead for testing equipment on surface. Built into this system will be a regulator bypass that will allow the regulators to be bypassed either for maintenance or if high pressure and high flow is required in an emergency.

Electronic Test Unit: The ETU will be located in the HPU control van and will be the surface communication center to establish communications with the subsea control mechanism, and supply electrical power and signals to the subsea equipment. The Subsea production tree will have a standalone electronic control system supplied by the service company to meet project specifics.

Remote Panel/ESD Panel: A master panel will be housed in the HPU and a remote master panel will be housed in the well test supervisor’s location. There will be several ESD panels located strategically throughout the vessel. In the well test area there will be an ESD 1 panel that would allow the well test crew to carry out an ESD1 (Production wing valve close).

Umbilical Reel: The reel shall consist of hydraulic and electric control lines for the Subsea tree, Seafloor Shutoff Device and Coiled Tubing BOP as well as auxiliary ports for chemical injection and Annulus monitoring. There will be an electrical connection on the side if the reel to connect the ETU and a hydraulic stab plate to connect the deck jumper from the HPU. The reel will have gauges and selector valves for associated hydraulic supplies.

Buoyancy charging system: The charging system for the nitrogen buoyancy will be standalone in regards to pump and umbilical.

Deck Jumpers: There will be deck jumpers to conduit hydraulics from the HPU to the desired reels and electrical jumpers from the ETU to the reel and also from the remote panels to the HPU for functioning and Emergency Shutdowns (ESDs).

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The initial specs for the previously listed the components will be as follows:

Equipment Working Pressure

Working Temp. Service Minimum ID

LP hydraulic jumper hoses

6,000psi 0-250 degrees F

Glycol based fluid 3/8”

HP hydraulic jumper hoses


Glycol based fluid ¼”

Chemical injection hoses


Methanol/paraffin/ asphaltene

¼”

High pressure (HP) pumps



Low Pressure (LP) pumps



LP couplers and fittings



HP couplers and fittings



Low pressure Nitrogen pump

0-250 degrees F

Nitrogen ½”

Low Pressure Nitrogen Hoses

0-250 degrees F

Nitrogen ½”

4.4 Umbilical and Umbilical Junction Box The Subsea tree and SSD will be controlled from the surface by a common Hydraulic Power Unit (HPU). The HPU will have the ability to supply a verity of header pressures to allow the system to interface with the required systems. These headers will be controlled by dedicated regulators thereby allowing the system header pressures to be set individually.

The electrical and hydraulic signals will be relayed by means of the umbilical system. The umbilical system will consist of the following components:

• A hydraulic deck jumper from the HPU to the umbilical reel • An electric deck jumper from the HPU to the umbilical reel • A hydraulic/electric reel • An electro / hydraulic umbilical to suit the project depth • An Umbilical Junction Box (UJB) • A Hydraulic Flying Lead (HFL) to suit tree connection • An Electric Flying Lead (EFL) to suit SCM connection

The umbilical junction box (UJB) will have an EFL and HFL suitable that will interface

with and control the subsea tree. The umbilical may be deployed during installation of the SSR and secured to the riser joints. The configuration of the umbilical may be project specific both in terms of functionality and length. It will connect the UJB to the surface control system where there will be a fixed plate; this fixed plate will be the interface between the subsea controls and the intervention vessel controls.

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The electro/hydraulic control system in the UJB will be configured to meet the project requirements. The UJB will be supplied from the surface control system via the umbilical for both electrical and hydraulic supplies. The selected function at surface will send an electrical signal to the electro/hydraulic interface in the UJB and the UJB will then send a electrical signal to the selected control valve housed in the UJB. The control valve in the UJB will then send the hydraulic operating fluid to the selected function. This system will be configured specific to the project prior to deployment of the UJB.

The umbilical system will control the tree and the Seafloor Shutoff Device.

All lines will be non-collapsible and sheathed in a protective cover.

Prior to deployment the lower connector will be made up to the SSD upper mandrel and a full function test will be carried out. Once a successful function test has been carried out the umbilical will be double clamped to the first joint of riser. The system will them be picked up and deployed. During the deployment of the riser the umbilical will be clamped to the riser at regular intervals. Toward the end of the umbilical it will need to be removed from the reel and suspended from the crane. At this point the slack in the umbilical will be looped around the saddles preinstalled to the riser.

The initial specs for the previously listed the equipment will be as follows:

Equipment Working Pressure

Working Temp. Service Minimum ID

LP hydraulic supply hoses



HP hydraulic supply hoses



Chemical injection hoses


Methanol/paraffin/ asphaltene

¼”

Standard hot stab



LP couplers and fittings



HP couplers and fittings



4.5 Equipment Interfaces and Rig Up

The HPU will be filled with control fluid and flushed to a NAS class 6 or better before rig up can begin; once this has be achieved the deck jumpers going to the reel can be connected to the HPU bulkhead and continuity checked thru jumper lines. The deck jumper lines can now be connected to their designated ports on the umbilical reel and flushed. Continuity thru the reel will now be checked before rigging up the stab plate, which will connect subsea and supply the Umbilical Junction Box (UJB) previously covered in section 4.7. Once continuity is proven, and the umbilical flushed to a NAS class 6 or better, the stab plate can rigged up to the bottom of the umbilical and pressure testing of the hydraulic system can take place to confirm the integrity of the mated connections.

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The electrical system will be connected via electrical jumpers; the ETU will be supplied by a standard 120 AC volt system on the rig. Connected to the ETU is a laptop supplied with project specific hardware and software to establish communication with and control the subsea equipment. The ETU will be connected to the umbilical reel via an electrical deck jumper, which will be removable to allow the reel to deploy the umbilical without damage to the deck jumper. Once the deck jumper is connected the electrical continuity from the ETU to the EFL via the umbilical reel and UJB can be confirmed.

The emergency shutdown system (ESD) will consist of an ESD panel integrated into the remote panels and stationed at several locations about the vessel. The remote panels and ESD’s will be powered from the HPU control van via electrical jumpers; when functioned from one of the panels a signal will be sent back to the HPU and the desired valve or sequence of valves will then close by way of air cylinders on the HPU valve panel.

NOV CTES Evaluation of CT Drilling Offshore Alaska

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Coiled Tubing Maximum Vertical Depth

Coiled Tubing Drilling and Interventions System Using Cost Effective Vessel RPSEA RFP 2008 DW 1502

Task 5

November 24, 2009

Prepared by:

Ken Newman, P.E.

NOV CTES 9870 Pozos Lane Conroe, TX 77303 (936) 521-2200 www.nov.com/ctes

http://www.nov.com/ctes

RPSEA RFP 2008 DW 1502 Task 5 of 96

TABLE OF CONTENTS 1 Executive Summary ............................................................................................................ 81 2 Straight CT ........................................................................................................................... 81

2.1 No Pressure at Surface ..................................................................................................... 81 2.2 With Pressure at Surface ................................................................................................... 82

3 Tapered Coiled Tubing ....................................................................................................... 85 3.1 Tapered CT Model ............................................................................................................. 85 3.2 Tapered CT Maximum Depths ........................................................................................... 86

3.2.1 Number of Taper Sections ........................................................................................ 86 3.2.2 CT Grade ................................................................................................................... 87 3.2.3 CT Diameter .............................................................................................................. 87 3.2.4 Surface Pressures and Fluid Densities ..................................................................... 87 3.2.5 Deviation and Friction and Friction Coefficient .......................................................... 87 3.2.6 Margin of Overpull ..................................................................................................... 88

4 Real and Effective Force .................................................................................................... 93 5 Effect of Pressure and Torsion on Axial Stress Limits ................................................... 95

FIGURES Figure 3-1: Example 1-3/4" Tapered String - Cerberus Compared to the Taper Model ........... 88 Figure 3-2: Maximum Depth vs Number of Taper Sections ....................................................... 89 Figure 3-3: Maximum CT Depth vs CT Grade .............................................................................. 89 Figure 3-4: Maximum CT Depth vs CT Diameter ......................................................................... 90 Figure 3-5: Max CT Depth vs Differential Surface Pressure (Different Fluid Weights) ............ 90 Figure 3-6: Max CT Depth vs Differential Surface Pressure (Same Fluid Weights) ................. 91 Figure 3-7: Max CT Depth vs Inclination for Various Friction Coefficient ................................ 91 Figure 3-8: Max CT Depth vs Margin of Overpull ........................................................................ 92 Figure 4-1: Schematic for Real and Effective Force ................................................................... 94


TABLES Table 2-1: Max Depths (ft) for Straight CT in Various Fluids ..................................................... 82 Table 2-2: Max Depths for Straight CT in 0 PPG Fluid ............................................................... 83 Table 2-3: Max Depths for Straight CT in 8.5 PPG Fluid ............................................................ 83 Table 2-4: Max Depths for Straight CT in 10 PPG Fluid ............................................................. 84 Table 2-5: Max Depths for Straight CT in 15 PPG Fluid ............................................................. 84

LEGAL NOTICE: This report was prepared by NOV CTES as an account of work for the client and is intended for informational purposes only. Any use of this information in relation to any specific application should be based on an independent examination and verification of its applicability for such use by professionally qualified personnel. Neither NOV CTES, employees of NOV CTES or any persons acting on behalf of either:

a. Makes any warranty or representation, expressed or implied, with any respect to the accuracy, completeness, or usefulness of the information contained in this report; or b. Assumes any liability with respect to the use of, or for damages resulting from the use of, any information, apparatus, method or process disclosed in this report.


1 EXECUTIVE SUMMARY This report analyzes the maximum depth that coiled tubing (CT) could possibly be

run in vertical wells. It begins with simple straight-wall CT (no variations in wall thickness), with no pressure in the well or the CT at surface, which can be analyzed fairly easily. Next, it adds the complication of surface pressures. Finally, it utilizes the results of a computer model to analyze tapered CT strings in wells with different fluids in the CT and in the well, and with small amounts of wellbore deviation. A parametric study shows how the various parameters impact the maximum CT operating depth.

The results from this study show that well interventions in vertical wells in excess of 30,000 ft deep and possibly even in wells in excess of 40,000 ft deep, are possible if the well is full of a l iquid (assuming liquid will be pum ped through the C T) and i f the di fferential pressure across the C T isn’t too high. H owever, significant drilling operations (cutting a window and sidetracking the well) is probably not feasible at these deeper depths.

For an ac tual intervention a tubi ng forces model such as the OrpheusTM model in CerberusTM should be used with the actual well survey, fluids, etc. to determine feasibility. The pressure that the CT will be tested to before being deployed into the well and possible collapse pressures should also be taken into consideration.

2 STRAIGHT CT

2.1 No Pressure at Surface Consider the simplest case of straight CT hanging in a well with the same fluid inside

and outside the C T, with no i nternal or external pressure at the surface. Th e maximum depth the CT can be run to is determined by the maximum stress acceptable in the CT at surface. T ypically this stress would be 80% of the C T yield stress minus any overpull capability desired. A margin of overpull (MOP) equivalent to 10% of the allowable strength of the CT has been used for this analysis. Equation (2.1) calculates the maximum depth.

( )y

maxfluid

0.9 0.8D

12 0.283231

σ=

ρ −

(0.1)

Where:

0.8 = the maximum allowable stress is typically limited to 80% of the yield stress

0.9 = this allows an MOP of 10% of the maximum allowable force yσ = yield stress of the CT material (psi)

fluidρ = density of the fluid in the well and in the CT (ppg)

maxD = maximum depth (ft)


Results from this equation are given in . Note that these results are independent of the CT diameter and wall thickness. They are also valid for a solid rod or a slickline.

Table 2-1: Max Depths (ft) for Straight CT in Various Fluids

The highest strength CT currently available on a widespread commercial basis has a yield strength of 120 K psi (known as 120 gr ade). According to publ ished manufacturer specifications, straight 120 grade CT can be run to a maximum depth of 25,000 to 33,000 ft, depending on the fluid in the well and in the CT.

2.2 With Pressure at Surface Pressure inside (Pi) and pressure outside (Po) the CT at surface has a direct impact

on the remaining CT strength available for axial pull. This affect is a function of the outside diameter to wall thickness ratio (ζ=D/t) of the CT. Section 4 of this report explains the concept of real and effective force which is needed to understand the effects of pressure. Section 5 of this report presents the equations used to calculate the maximum depth with Pi and Po taken into consideration. The r esulting equation (5.19) is similar to equation (2.1) with the ex ception that Pi and P o are included. Thes e two pressure values can be combined into a single differential pressure (Pi-Po). Since the differential pressure term is squared, it doesn’t matter if it is (Pi-Po) or (Po-Pi). Thus, for purposes of this report ∆P is defined as the absolute value of the difference in the pressure inside and outside the CT at surface. The 80% safety margin and the 10% MOP are included in the same way

The following set of tables (2-2 through 2-5) present the results of equation (5.19) for various differential pressures. Each table is for a different fluid density. Again, fluids of the same density must be inside and outside the CT. Note that this simple calculation approach does not take CT burst and collapse into consideration.

Fluid DensityPPG 70 80 90 100 110 120

0 14,841 16,961 19,081 21,201 23,322 25,4422 15,309 17,496 19,683 21,871 24,058 26,2454 15,808 18,067 20,325 22,583 24,842 27,1006 16,341 18,675 21,010 23,344 25,678 28,0138 16,910 19,326 21,742 24,158 26,573 28,98910 17,521 20,024 22,527 25,030 27,533 30,03612 18,178 20,775 23,371 25,968 28,565 31,16214 18,885 21,583 24,281 26,979 29,677 32,37516 19,650 22,458 25,265 28,072 30,879 33,686

Grade of CT = Yield Stress (Kpsi )


Table 2-2: Max Depths for Straight CT in 0 PPG Fluid

Table 2-3: Max Depths for Straight CT in 8.5 PPG Fluid

Fluid Density = 0 ppg∆Ppsi 10 11 12 13 14 15 16 170 25,442 25,442 25,442 25,442 25,442 25,442 25,442 25,442

1,000 25,410 25,404 25,397 25,390 25,383 25,375 25,366 25,3572,000 25,314 25,290 25,264 25,236 25,205 25,173 25,138 25,1023,000 25,152 25,098 25,039 24,975 24,907 24,833 24,754 24,6704,000 24,925 24,828 24,722 24,607 24,482 24,349 24,206 24,0535,000 24,630 24,476 24,308 24,124 23,926 23,712 23,482 23,2356,000 24,264 24,039 23,792 23,521 23,227 22,909 22,565 22,1957,000 23,825 23,512 23,167 22,788 22,374 21,923 21,432 20,8998,000 23,307 22,889 22,424 21,912 21,347 20,727 20,045 19,2959,000 22,707 22,161 21,552 20,874 20,120 19,281 18,346 17,299

10,000 22,016 21,318 20,533 19,649 18,653 17,525 16,239 14,75311,000 21,226 20,347 19,344 18,200 16,884 15,353 13,534 11,28812,000 20,326 19,226 17,953 16,467 14,704 12,549 9,743 5,34713,000 19,301 17,929 16,306 14,348 11,890 8,511 0 014,000 18,128 16,413 14,316 11,634 7,782 0 0 015,000 16,777 14,610 11,811 7,720 0 0 0 0

D/t values

Fluid Density = 8.5 ppg∆Ppsi 10 11 12 13 14 15 16 170 29,244 29,244 29,244 29,244 29,244 29,244 29,244 29,244

1,000 29,207 29,201 29,193 29,185 29,176 29,167 29,157 29,1472,000 29,097 29,069 29,039 29,007 28,972 28,935 28,895 28,8533,000 28,912 28,849 28,782 28,708 28,629 28,544 28,454 28,3574,000 28,650 28,539 28,417 28,284 28,141 27,988 27,823 27,6485,000 28,311 28,134 27,941 27,730 27,502 27,256 26,991 26,7086,000 27,891 27,632 27,347 27,037 26,699 26,333 25,938 25,5127,000 27,385 27,026 26,629 26,194 25,718 25,199 24,635 24,0228,000 26,791 26,309 25,776 25,186 24,538 23,824 23,041 22,1799,000 26,100 25,473 24,773 23,993 23,127 22,163 21,088 19,885

10,000 25,306 24,505 23,602 22,586 21,441 20,145 18,666 16,95711,000 24,399 23,388 22,236 20,920 19,407 17,647 15,556 12,97512,000 23,364 22,099 20,636 18,928 16,902 14,424 11,200 6,14713,000 22,185 20,608 18,743 16,492 13,667 9,783 0 014,000 20,837 18,866 16,456 13,372 8,945 0 0 015,000 19,285 16,794 13,576 8,874 0 0 0 0

D/t values





1,000 29,999 29,992 29,984 29,976 29,967 29,957 29,947 29,9362,000 29,885 29,857 29,826 29,793 29,757 29,719 29,678 29,6353,000 29,695 29,631 29,561 29,486 29,405 29,317 29,224 29,1254,000 29,427 29,312 29,186 29,050 28,904 28,746 28,577 28,3975,000 29,078 28,896 28,697 28,481 28,247 27,994 27,722 27,4316,000 28,646 28,380 28,088 27,769 27,422 27,046 26,640 26,2037,000 28,127 27,758 27,350 26,903 26,415 25,882 25,302 24,6738,000 27,516 27,022 26,474 25,869 25,202 24,470 23,665 22,7809,000 26,807 26,163 25,444 24,643 23,753 22,763 21,659 20,424

10,000 25,992 25,168 24,241 23,198 22,022 20,690 19,172 17,41711,000 25,060 24,021 22,838 21,487 19,933 18,125 15,978 13,32612,000 23,997 22,698 21,195 19,441 17,360 14,815 11,503 6,31313,000 22,786 21,166 19,251 16,939 14,038 10,048 0 014,000 21,402 19,377 16,901 13,735 9,187 0 0 015,000 19,807 17,249 13,944 9,114 0 0 0 0

D/t values


1,000 32,976 32,968 32,960 32,951 32,941 32,931 32,920 32,9082,000 32,851 32,820 32,787 32,750 32,711 32,669 32,624 32,5763,000 32,642 32,572 32,496 32,413 32,323 32,227 32,125 32,0164,000 32,347 32,221 32,084 31,934 31,773 31,599 31,413 31,2155,000 31,964 31,765 31,546 31,308 31,050 30,773 30,474 30,1546,000 31,490 31,197 30,876 30,525 30,144 29,731 29,285 28,8047,000 30,919 30,513 30,065 29,574 29,037 28,451 27,814 27,1228,000 30,248 29,704 29,102 28,436 27,704 26,898 26,014 25,0419,000 29,468 28,760 27,969 27,090 26,111 25,023 23,809 22,451

10,000 28,572 27,667 26,647 25,500 24,207 22,744 21,075 19,14611,000 27,547 26,405 25,105 23,619 21,912 19,925 17,564 14,64912,000 26,379 24,951 23,299 21,371 19,083 16,286 12,645 6,94013,000 25,048 23,267 21,161 18,620 15,431 11,046 0 014,000 23,526 21,300 18,579 15,098 10,099 0 0 015,000 21,773 18,961 15,328 10,019 0 0 0 0

D/t values


3 TAPERED COILED TUBING

3.1 Tapered CT Model Many CT strings are “tapered”. Thi s means they have a constant outer diameter

(O.D.), but a varying inner diameter (I.D.). Greater wall thicknesses (smaller I.D.s) are used at the top of the s tring where the additional strength is needed, and thinner wall thicknesses are used further down the s tring where the strength isn’t needed and l ess weight is desirable.

To maximize the vertical depth, tapered strings should be designed where the Von Mises stress at the top of each tapered section is the maximum allowable stress (which for this analysis is 80% of the yield stress plus 10% MOP).

Some deviation in a wellbore trajectory is typical. For simplicity a single deviation that applies to the enti re well will be considered for the pu rposes of this analysis. Once there is wellbore deviation, there is friction between the CT and wellbore, and thus a friction coefficient is needed.

The number of variables in this design now includes:

• CT grade (yield stress) • CT OD • Varying wall thicknesses • Internal pressure at surface • External pressure at surface • Fluid density inside the CT • Fluid density in the well • Deviation • Friction coefficient • Margin of overpull

A tapered CT string design model was written taking all of these parameters into consideration. The user specifies these parameters and the “Taper Model™” calculates the deepest possible CT string that meets these parameters. Up to 10 s ections with different wall thicknesses can be included in the design.

As an ex ample, a tap ered string was designed using the Taper Model with the following parameters

• 120 grade • 1-3/4” O.D. • Wall thicknesses: .203, .188, .175, . 156, .145, . 134, .125, . 118, .109, . 095.

Note that typically tapered strings have 7 or less wall thicknesses. • 6,000 psi internal pressure at surface • 5,000 psi wellhead pressure at surface • 10 ppg fluid in the CT • 8.5 ppg fluid in the well • 0 deviation • 0.25 friction coefficient (though this is unused with 0 deviation) • 10% MOP which for .095” wall = 4,742 lb


The resulting maximum calculated CT depth was 46,625 ft. Figure 3-1 shows results from the Taper Model for this case compared to the r esults from the w ell-known, industry accepted, OrpheusTM model in CerberusTM, marketed by NOV CTES. Cerberus calculates the Von Mises stress every 100 ft along the string. The Taper Model only calculates the Von Mises stress at the top and bottom of each CT taper section. For the lower section the two models agree at the end points only. Note that the maximum Von Mises stress at the top of each taper section is 96,000 psi, which is 80% of the yield stress (120,000 psi) and is the maximum allowable stress.

3.2 Tapered CT Maximum Depths The Taper Model was used to perform a parametric study of the various input

parameters.

3.2.1 Number of Taper Sections Typical tapered strings have 4 or 5 sections, though strings have been made with

more sections. The Taper Model allows up to 10 CT taper sections. The example used to validate the taper model in Section 3.1 above was used to deter mine the effec t of the number of taper sections. Thi s example was run with 1 taper section (the 0.203” wall thickness), then 2 taper sections (0.203” and 0.188” wall thickness) etc. up through 10 taper sections (which were used in the or iginal example). The r esults are shown in Figure 3-2. For this example the maximum calculated CT depth increases by nearly 2,000 ft per taper section.

However, selecting fewer tapers with larger variations in wall thickness yields nearly the same result. For this example, 5 CT tapers were used with wall thicknesses of 0.203”, 0.175”, 0.145”, 0.118”, and 0.095”. Thi s configuration yielded a m aximum calculated CT depth of 45,774 ft, which is nearly 9,300 ft deeper than the initial case with 5 closely spaced CT taper sections, and only 850 ft less than the case with 10 C T taper sections. Lar ge changes in wall thickness where sections meet results in a CT manufacturing challenge. The thicker side of the CT taper section must be ground down to avoid an abrupt change in stiffness at the weld. This grinding is done manually.

Practically, the possible range of wall thicknesses should first be chosen based on burst and collapse pressure considerations. This will depend on the pressure testing required before the CT is deployed and the maximum collapse pressure the CT will possibly see. The Taper Model does take burst and collapse into consideration by warning the user if the Von Mises stress exceeds the maximum allowable stress. However, a more accurate plastic hinge collapse model is used by Cerberus when modeling actual CT job scenarios. Once the wall thickness range is determined, the taper section thicknesses can be chosen.

There is a type of C T tapered section called True-Taper®, in which the wall thickness changes linearly through the length of the s ection. This type of tapered section will increase the maximum depth slightly and it eliminates the need to grind the end of one of the strips before welding. It can be modeled in Cerberus, but was not included in the Taper Model.


3.2.2 CT Grade The grade of the CT is the yield stress in Kpsi. Obviously the stronger the CT (the

higher the grade), the deeper it can reach. The same example from figure 3.1 with 10 CT tapers was run for grades 70 through 130. The results are shown in Figure 3-3. Increasing the yield strength causes a linear increase in the maximum depth.

120 grade CT is now commercially available, and work is being done on hi gher grades. For this reason a 130 grade, which is not yet commercially available, was included in Figure 3-3.

3.2.3 CT Diameter Figure 3-4 shows the impact of varying the CT diameter for the standard CT sizes

from 1” to 3-1/2”, for the same example. Of course a 0.203” wall for 1” CT isn’t realistic, nor is a 0.095” wall for 3.5” CT. The CT size will be chosen for other reasons than maximum depth considerations. For the r ange of s izes to most likely be us ed in the fi eld, 1-1/2” through 2”, the change in maximum depth varies by less than 1,000 ft. Thus CT diameter is not as important as other parameters in determining the maximum depth.

3.2.4 Surface Pressures and Fluid Densities As was shown in Section 2.2 of this report, the maximum CT depth is a function of

∆P when the densities of the fl uids in the C T and i n the well are the s ame. Thi s is not entirely true when the densities are different. The s ame example was again considered, varying the pressures at surface. In this example the fluid in the CT has a density of 10 ppg and the fluid in the well has a density of 8.5 ppg. Two sets of model results were calculated to create Figure 3-5. In the first set, the surface pressure in the well (wellhead pressure) was held at zero, and the pressure inside the CT was varied from 0 upw ards, causing a “burst” pressure on the CT. In the s econd set, the pr essure in the C T at s urface (pump pressure) was held at zero and the pressure in the w ell was increased from 0 u pwards, causing a “collapse” pressure on the CT. The curves end when either CT burst or collapse conditions are reached.

A similar set of model results were calculated for the same case except with an 8.5 ppg fluid both in the CT and in the well. These results are shown in Figure 3-6. When the fluid densities are the same, the t wo curves are identical and they reach the po int of C T burst or collapse at approximately the same differential pressure.

Obviously the pressures in the well and the densities of the fluids significantly affect the maximum depth CT can be run into a well.

3.2.5 Deviation and Friction and Friction Coefficient For a real application a detailed well survey would need to be used in a tubing forces

model like Cerberus. For this analysis, a simple constant wellbore deviation was used to better understand the effect of small amounts of deviation in near-vertical well. The same example was used again, with varying wellbore deviation and friction coefficient. The results are shown in Figure 3-7. Small amounts of deviation cause some friction, and thus reduce the maximum CT depth. However, once the deviation increases above about 15 degrees, the amount of CT weight being supported by the wall of the wellbore becomes more significant than the friction, and the maximum depth again increases. Thus there is a “worst case” deviation which varies from 15 to 20 degrees, depending on the friction coefficient.


This analysis does not include the effect of tortuosity in a well, which would reduce the maximum depth that CT could reach. Tortuosity can be included when Cerberus is used to model the well.

3.2.6 Margin of Overpull The margin of overpull (MOP) for this analysis is defined as the amount of force that

can be pulled at the bottom of the CT string if it were stuck. It has been defined as the percentage of the al lowable force for the l ower (smallest) wall thickness. It c an also be measured in pounds force.

Figure 3-8 shows how the maximum depth decreases (for the same example) as the MOP increases. As one would expect, the MOP has a significant impact on the m aximum depth.

Figure 3-1: Example 1-3/4" Tapered String - Cerberus Compared to the Taper Model

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

40 50 60 70 80 90 100

Dept

h (ft

)

Von Mises Stress (Kpsi)

Taper Model

Cerberus

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

0.05 0.15 0.25

Dept

h (ft

)

Wall Thickness (in)


Figure 3-2: Maximum Depth vs Number of Taper Sections

Figure 3-3: Maximum CT Depth vs CT Grade

28,14530,054

31,844

34,65936,479

38,42840,141

41,55943,472

46,625

25,000

30,000

35,000

40,000

45,000

50,000

1 2 3 4 5 6 7 8 9 10M

axim

um D

epth

(ft)

Number of Taper Sections

27,075

30,990

34,902

38,811

42,719

46,625

50,530

25,000

30,000

35,000

40,000

45,000

50,000

55,000

70 80 90 100 110 120 130

Max

imum

Dep

th (f

t)

CT Grade (Yield Stress in Kpsi)


Figure 3-4: Maximum CT Depth vs CT Diameter

Figure 3-5: Max CT Depth vs Differential Surface Pressure (Different Fluid Weights)

47,00247,14446,96646,625

46,192

45,446

44,360

42,94142,50043,00043,50044,00044,50045,00045,50046,00046,50047,00047,500

1.0 1.5 2.0 2.5 3.0 3.5M

axim

um D

epth

(ft)

CT Outside Diameter (in)

30,000

32,000

34,000

36,000

38,000

40,000

42,000

44,000

46,000

48,000

0 2,000 4,000 6,000 8,000 10,000 12,000 14,000

Max

imum

Dep

th (f

t)

∆P (psi)10 ppg in CT, 8.5 ppg in well

Zero Wellhead Pressure

Zero Pump Pressure


Figure 3-6: Max CT Depth vs Differential Surface Pressure (Same Fluid Weights)

Figure 3-7: Max CT Depth vs Inclination for Various Friction Coefficient

35,000

37,000

39,000

41,000

43,000

45,000

47,000

49,000

51,000

53,000

0 2,000 4,000 6,000 8,000 10,000 12,000 14,000M

axim

um D

epth

(ft)

∆P (psi)8.5 ppg in CT, 8.5 ppg in well

Zero Wellhead Pressure

Zero Pump Pressure

44,000

45,000

46,000

47,000

48,000

49,000

50,000

51,000

0 10 20 30 40

Max

Dep

th (f

t)

Degrees of Inclination

Mu = 0.20 0.25 0.30


Figure 3-8: Max CT Depth vs Margin of Overpull

0

5,000

10,000

15,000

20,000

25,00030,000

32,000

34,000

36,000

38,000

40,000

42,000

44,000

46,000

48,000

50,000

0 10 20 30 40 50

MO

P (lb

f)

Max

Dep

th (f

t)

MOP as % Allowable Force at Bottom

Max Depth (ft)

MOP (lbf)


4 REAL AND EFFECTIVE FORCE To understand the effects of pressure, it is necessary to understand the difference

between “real” and “effective” force. Figure 4-1 shows a schematic which helps clarify this concept.

1. The first sketch shows an empty pipe being weighed by a scale (or a weight indicator). The for ce in the walls of the pipe at the top i s the same as the force read by the weight indicator.

2. When fluid is added inside this pipe, the weight increases. If the pipe were immersed in water; the weight would decrease. This weight is known as the “buoyant weight”.

3. When pressure is added to the fl uid inside the pipe, the weight stays the same. However, the axial force in the walls of the pipe increases by the amount of the pressure multiplied by the internal area.

When pressure is applied the “real” force in the walls of the pipe is higher than the “effective” force displayed by the weight indicator. Thus; the real force is the actual force in the walls of the pipe, as could be measured with a strain gauge. The effective force is the force that would exist if there was no pressure at the poi nt the force is being considered. The effective force is the same as the buoy ant weight. The following equations enable conversion back and forth between real and effective force.

a e i i o oF F PA P A= + − (0.2)

e a i i o oF F PA P A= − + (0.3) Where:

Ai = the internal area of the pipe

Ao = the external area of the pipe

Fa = the real axial force

Fe = the effective force

Pi = the internal pressure

Po = the external pressure

Since the ef fective force isn’t real, one may wonder why the effective force should even be considered. There are three reasons effective force is used:

1. Pipe buckling is not affec ted by the internal and ex ternal pressure. The buckling loads (helical and sinusoidal) are effective forces. To determine if a pipe is buckled or not, the buckling loads must be compared to the effec tive force in the pipe.

2. Force modeling is much easier to per form using buoyant weights and effective forces. All models work in this manner. When the stress is desired, at a gi ven point the effec tive force is converted to the r eal force using equation (4.1).


3. The weight indicator on a C T unit and drilling rig measures effective force. Since the point the force is being applied (by the chains or the blocks) is not in the w ell, there can only be i nternal pressure, Pi. T hus according to equation (4.1) the axial force in the pipe is the effective force (weight indicator reading) plus the internal pressure times the i nternal area. Thi s must be taken into consideration when comparing the weight reading to the break strength of the pipe.

The axial stress in the pi pe caused by the real axial force can be c alculated by dividing equation (4.1) by the cross-sectional area of the steel in the pipe wall. This results in the following equation:

e i i o oFa

o i

F PA P AA A

+ −σ =

− (0.4)

Where:

Faσ = the axial stress caused by the axial force

This concept will be discussed further in a later section.

Figure 4-1: Schematic for Real and Effective Force


5 EFFECT OF PRESSURE AND TORSION ON AXIAL STRESS LIMITS This appendix examines the effect of internal pressure and torsion on the yield strength. The Von Mises incipient yield equation combines the three principal stresses (hoop axial, and radial) as follows:

( ) ( ) ( )2 2 2 21y h a h r r a2 3 σ = σ −σ + σ −σ + σ −σ + τ (0.5)

This equation can be solved for the axial stress as:

( ) ( )22 2 31a h r y h r2 43σ = σ +σ ± σ − τ − σ −σ (0.6)

The hoop and radial stresses are calculated using the Lame equations, which can be written as functions of A and B where:

( )

2 2i i o o i i o o

2 2o i o i

PA P A Pr P rAA A r r

− −= =

− − (0.7)

( )( )

2 2i o i o

2 2 2o i

P P r rB

r r r−

=−

(0.8)

Looking at the inside and outside surfaces (r = ri and r = ro) B can be written as:

( )i o i

oo i

P P AB

A A−

=−

(0.9)

( )i o o

io i

P P AB

A A−

=−

(0.10)

Note that A, Bo, and Bi can be written in terms of the D/t ratio, ζ , as follows:

o2rDt t

ζ = = (0.11)

Where D is the outside diameter and t is the wall thickness.

( ) ( )2

i o iA P P P4 1ζ

= − −ζ −

(0.12)

( ) ( )( )

212

o i o

1B P P

1ζ −

= −ζ −

(0.13)

( ) ( )2

i i oB P P4 1ζ

= −ζ −

(0.14)

Note that A is the axial stress caused by the internal and external pressures. Equation (4.3) can be written as:

eFa e

o i

F A AA A

σ = + = σ +−

(0.15)

Where eσ is the stress that would exist if there were no internal and external pressures. According to the Lame equations the stresses can now be written as:

h A Bσ = + (0.16)

r A Bσ = − (0.17) From these 2 equations:

h r 2Aσ +σ = (0.18)

h r 2Bσ −σ = (0.19)


Now the Von Mises equation (5.2) can be rewritten as:

( )2 2 2ya yA 3 Bσ = ± σ − τ + (0.20)

yaσ is used instead of aσ because this is the axial stress at which yielding will occur for the given pressure situation. For this case there is no t orsional shear due to to rque. The highest stress always occurs at the inside surface of the CT. Thus equation (5.16) for the tension case becomes:

2 2ya y iA 3Bσ = + σ − (0.21)

Setting equation (5.11) equal to equation (5.16) yields

2 2ye y i3Bσ = σ − (0.22)

This yeσ is the yield stress at surface if there is no pressure. It can be substituted into equation

(2.1) for yσ to yield:

( ) ( )

( )

42 2y i o 2

maxfluid

30.9 0.8 P P16 1

D12 0.283

231

ζσ − −

ζ −=

ρ −

(0.23)

This equation calculates the maximum depth for straight CT in a well with pressure, as long as the fluid inside and outside the CT has the same density.