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TASK 9

COILED TUBING INTERVENTION SYSTEM

COMPONENT DESIGN REPORT

DOCUMENT NUMBER: 08121- 1502-01-Task 9 Report

Coiled Tubing Drilling & Intervention System

Using Cost Effective Vessels

RPSEA PROJECT 08121-1502-01

April 19, 2011

Charles R. Yemington, PE Project Manager Nautilus International,

LLC. 400 N. Sam Houston Pkwy. East

Suite 105 Houston, TX

77060

RPSEA 08121-1502-01 TASK 9 REPORT

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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.


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ABSTRACT

The Appendices for RPSEA Project 08121-1502-01 Task 9 final report are bound in this document to add background and detail to the report. 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.

Seafloor shutoff device by GE, Vetco Gray. Functional description and technical specifications are presented in the Appendix I.

Functional and interface requirements for control shuttle valves, free standing riser. SSD control system were developed by GMC; listed in Appendix I, section f.

Rolls Royce illustrates a sequence of still frames from animation of riser installation system, pictured in Appendix II.

Huisman provided well intervention system technical specifications along with images of Ross Candies vessel demonstrated in Appendix II, section c.

CTES analyzed theory and validation of fatigue life analysis for deck handling of coiled tubing; analysis of CT utilizing a par abolic arch configuration, along with software modeling inputs theory, and validation; represented in Appendix III, Sections a and b.


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SIGNATURE & DATE STAMP

Signature:

Date: 4-19-2011

RPSEA PROJECT 08121-1502-01 TASK 9 REPORT

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THIS PAGE INTENTIONALLY LEFT BLANK


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REV DATE DOCUMENT STATUS ORIGINATOR CHECKED

0 05/16/2011 Issued for use with comments incorporated C Yemington T. Williams

B 04/19/2011 Issued for RPSEA comment C. Yemington T. Williams

A 01/21/2011 Issued for review and comment C. Yemington T. Williams


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TASK 9 FINAL REPORT

COILED TUBING INTERVENTION SYSTEM

COMPONENT DESIGN REPORT

RPSEA PROJECT 1502-01

TABLE OF CONTENTS

1.0 EXECUTIVE SUMMARY ............................................................................... 8 2.0 GENERAL .................................................................................................... 10

2.1 Scope ........................................................................................................ 10 2.2 Acronyms & Abbreviations ......................................................................... 10

3.0 INTERFACES ............................................................................................... 11 3.1 Riser and Riser Extension Interfaces ............................................................. 11 3.2 CT System Interfaces .................................................................................. 12 3.3 Vessel Interfaces & Deck Arrangements ....................................................... 14

4.0 SEAFLOOR SHUTOFF DEVICE ................................................................... 16 5.0 RISER DEPLOYMENT & MOTION ISOLATION .......................................... 17

5.1 Riser Installation & Recovery Equipment ..................................................... 18 5.2 Motion Isolation System for CT Operations .................................................. 18

6.0 TUBING HANDLING FOR LONGER FATIGUE LIFE ................................... 20 7.0 APPENDIX I -III ........................................................................................... 23


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1.0 EXECUTIVE SUMMARY This report covers the pr imary equipment areas where existing designs must be adapted o r modified to enable small, lower cost vessels to install a Self Supporting Riser (SSR) and deploy Coiled Tubing (CT) through it.

A seafloor shutoff device provides reservoir isolation capability at all times during use of the S SR and CT system. As described here it incorporates all of the k nown reservoir isolation functions found in a t raditional BOP, but it is designed to include only the essential functions so it can be made smaller and lighter for handling onboard a relatively small vessel. It i s designed for use in conjunction with a CT BOP and other well control equipment. The design of the seafloor shutoff device includes provisions to maintain reservoir isolation while any component above it is replaced and this facilitates recovery from component failure or structural failure of the r iser or CT BOP. This arrangement is intended to meet all regulatory and i ndustry requirements for safety and environmental protection, with additional features of faster response and improved maintainability by having near surface controls for functions such as choke and kill.

The second area is equipment to i nstall the SSR from a s mall vessel and i solate the r iser from vessel motions during downhole work. Large vessels such as drilling rigs are routinely fitted with tools to run casing and drill string, but few smaller, lower cost vessels are suitably outfitted. All components of the SSR are designed to be installed from a small vessel with a typical moon pool. Provisions for riser installation presented in this report include an integrated system to handle riser components on deck, thread casing joints together, hang the assembled joints while each new joint is attached, run the buoyancy modules, and connect the riser to the tree.

Riser installation for initial application of the intervention system is expected to be done by a vessel that already has most of the nec essary equipment and can be readily adapted to handl e casing joints and buoys. Designs by Huisman and Rolls Royce Odim, as presented in the Appendix, are most appropriate for outfitting a dedicated installation vessel.

The SSR effectively brings the seafloor close to the surface so any vessel that can intervene in shallow water will be able to work in deepwater by working through a previously installed SSR. A riser extension is not needed if the intervention vessel uses only wireline. Similarly, if the coiled tubing service contractor uses an underwater injector, he can work through the self supporting riser without bringing the riser casing up to the vessel deck.

A motion isolation system is needed when the riser casing is extended up to the deck of the vessel. The required performance of the m otion isolation system depends on the nature of the downhole work and th e magnitude of v essel motion, which in turn depends on vessel size and sea state. Initial applications of the CT intervention system are expected to focus on downhole tasks that can tolerate some heave of the tubing inside the casing and use lower cost motion isolation that is not suitable for work in high sea states.


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For CT operations the injector sits atop the riser extension and is thus stationary with respect to the earth, while the CT coil sits on the deck of the vessel. The relative motion between the coil and the injector flexes and changes the length of the tubing run between them.

The baseline system includes provisions to protect the tubing from fatigue from vessel motions while the deployed tubing is held stationary in the well. Different arrangements of deck equipment were analyzed to determine their relative merits for the fatigue life of this section of tubing. It was found that the c atenary, the parabolic arch, and the arc arrangements can enhance fatigue life by distributing the flexure over a sufficient length of tubing so that fl exure is elastic and not plastic. The preferred arc arrangement accommodates vessel motions and enhances overall tubing fatigue life beyond that seen in the traditional on-shore configuration because it does not bend the tubi ng sharply over the gooseneck. This preferred arrangement is described in this report and the analysis is included in the Appendix. For this arrangement, the analysis shows satisfactory fatigue life for various combinations of CT internal pressure, vessel pitch, and roll motions up to 10 degrees.

It is believed that the items covered in this report, together with the standard technology items described in earlier task reports, make it practical to install the riser and do dow nhole intervention from vessels small enough to meet the project objective of safely reducing the cost of downhole intervention to less than half that of using a MODU.


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2.0 GENERAL

5.1 Scope This report presents work done on aspects of the project that are not well addressed by readily available equipment and methods.

GE Oil and Gas, with support from General Marine Contractors, addressed the need to reduce the size and weight of the seafloor shutoff device while maintaining all of the safety and environmental protection functions of a full feature BOP.

Both Huisman and Rolls Royce Odim addressed equipment to install the riser and work through it from relatively small vessels. Functional requirements of the installation equipment and motion isolation equipment are discussed in the body of this report. Material provided by Rolls Royce and Huisman is included in the Appendix.

CTES division of NOV investigated the relative motion between the CT injector which is stationary with respect to the ear th and the C T coil, which moves with vessel heave, pitch, and roll. Thei r analysis report is included in the Appendix.


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2.2 Acronyms & Abbreviations API American Petroleum Institute

BOEMRE Bureau of Offshore Energy Management

BOP Blow Out Preventer

CT Coiled Tubing

CTES Coiled Tubing Engineering Services, Div of NOV

DP

GOM

Dynamic Positioning

Gulf of Mexico

gpm gallons per minute

GPS Global Positioning System

HPU Hydraulic Power Unit

ICoTA International Coiled Tubing Association

ID Internal Diameter

MODU Mobile Offshore Drilling Unit

OD Outside Diameter

psi Pounds per square inch

ROV Remotely Operated Vehicle

SPE Society of Petroleum Engineers

SSR Self Supporting Riser

SSD Seafloor Shutoff Device

USCG United States Coast Guard


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3.0 INTERFACES Previous task reports defined the interfaces between the equipment covered in this report and the riser, the CT equipment, and the vessel. Those interfaces are summarized in this section.

3.1 Riser and Riser Extension Interfaces If the CT intervention vessel is not equipped for riser installation, the riser can be installed by a light construction vessel and left as shown in Figure 3.1. The riser can be left unattended for extended periods in this configuration. The structural casing segment of the riser extension is shown hung off or ‘wet parked’ on the buoyancy as part of riser installation as an optional configuration. In this configuration the equ ipment is unaffected by surface weather including hurricanes, and is not considered to be a hazard to navigation.

LoopLoop

FIGURE 3.1 SSR AS LEFT BY INSTALLATION VESSEL

The CT intervention vessel can install the emergency disconnection connectors and near surface

Top of SSR is below strongest surface current

Current


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shear and seal device above the buoyancy and then lift and connect the structural casing segment between the vessel and the riser.

Figure 3.2 shows the r iser extension connected between the CT intervention vessel and the s elf supporting riser. The injector is attached to the top of the riser extension, and the motion isolation system allows the vessel to pi tch, roll, and heave while the i njector and riser are stationary with respect to the earth.

FIGURE 3.2 DOWNHOLE CT INTERVENTION USING SSR

The riser extension extends the casing up through the intervention vessel moon pool for connection to the motion isolation system and the injector.

The riser extension may have tension sensing instruments for feedback control of th e motion isolation system. A telescoping section or slip joint may be incorporated into the riser extension to

Buoyancy module

Injector on motion isolation system

Shear, seal, and disconnection umbilicals

Emergency disconnect between near surface shear and seal and the shearing retention valve for the upper part of the riser extension.


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avoid the need for heave compensated mounting of the injector if the planned downhole tasks can be done while the coiled tubing moves up and down in the well in response to vessel heave.

3.2 CT System Interfaces The vessel, riser extension, and motion isolation system are intended to pr ovide a working environment similar to that found ons hore or on a pl atform. Fr om the viewpoint of downhole operations, the incremental length of casing and tubing through the water column and the effect of vessel motion are the primary differences between onshore operations and working in deepwater with the SSR.

The CT reel sets on the deck as shown in Figure 3.2 above. Fatigue life goes down as tubing diameter increases, and flow loss goes up as tubing diameter decreases. For deep applications, the optimum tubing diameter for tradeoff of pressure, flow loss, and fatigue life was found to be 2-3/8 inch to 2-7/8 inch. Length, wall thickness, and diameter determine the weight of the tubi ng, which in turn defines the maximum deck load for the CT reel. The weight of the tubi ng will not normally exceed 100,000 pounds, but for work near the total depth limit the deck load for the reel drive may be near 230,000 pounds when the tubing is filled with fluid. L ighter reels will be adequate for most mobilizations. The tubing reel diameter may be 18 feet or more. The base of the reel drive may be 15 by 21 feet, or larger, to distribute the weight over an adequate area of the deck.

A typical stack-up for CT equipment above the SSR buoyancy is shown in Figure 3.3. The hub shown on the top of the buoyancy module is part of the Self Supporting Riser.

Emergency disconnection segment

Passive structural segment

CT well control equipment

Flange

Telescope, if used

ROV operable connector

Hub

Blind shear retention valve

Injector

Vessel Vessel


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FIGURE 3.3 TYPICAL CT OPERATIONS EQUIPMENT STACK-UP

The emergency disconnection segment of the riser extension can be released to allow the vessel to maneuver in the event of an onboard emergency. It can also be released to protect the riser from excessive tension that will result if the vessel heaves up beyond the working range of the motion isolation system or if DP problems cause the vessel to move to the ex tremes of the s afe working watch circle.

The upper part of the riser extension attaches to the motion isolation system and the CT service contractor’s well control equipment. For CT intervention tasks that do not require downhole tools to be stationary in the well, a telescoping joint in the riser extension can be used as an alternative to heave compensation of the injector.

The system is designed to use conventional arrangement of CT equipment. Appreciation is expressed to Halliburton for preparing and contributing Figure 3.4 which shows a typical arrangement for 10,000 psi Halliburton CT equipment.

FIGURE 3.4 TYPICAL STACK-UP FOR CT EQUIPMENT

Bending guide

Injector

Stripper


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The bending guide limits curvature of the tubing between the reel and the injector and is used to establish and manage entry of the tubi ng into the i njector. The injector supports the dep loyed tubing and in turn is supported by the motion isolation system.

The CT service contractor’s equipment typically includes a CT BOP, a packer stripper, and a l ine for returns. These items can be installed either above or below the s upport point. Ther e are advantages to keeping deck loads low, so it is preferable to install this equipment below the point where the riser extension attaches to the motion isolation system. The slip rams at the bottom of the stack-up are normally engaged to seal around the tubing and to support the tubing if the injector requires maintenance. When used with the self supporting riser, these slip rams can be located below the r iser buoyancy, where they will also support the tubi ng following any emergency disconnection.

3.3 Vessel Interfaces & Deck Arrangements Figure 3.5 shows a typical arrangement for the riser components and installation equipment on the deck of a 260-foot vessel. Additional riser joints and additional buoyancy modules will be required for installation in deeper water. A larger vessel with more deck space and additional accommodations will be required if a single vessel is to install the riser, conduct CT operations, and carry adequate consumables for the downhole work.

Riser Joints Crane Assembly & Deployment System

Gas Umbilical ROV System

Buoys BOPs ROV Vans

Riser Vans

FIGURE 3.5 TYPICAL DECK ARRANGEMENT FOR RISER INSTALLATION


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An objective of the project is to do downhole work with vessels that cost less than half as much as a MODU. Figure 3.6 s hows deck arrangement for a typical but r elatively simple downhole intervention using a 260-foot vessel. The m ost significant aspect of using smaller vessels is that they are subject to greater pitch and roll motions. Isolation of the riser extension from these vessel motions is the primary function of the motion isolation system described in Section 5.2 and in the Appendices.

FIGURE 3.6 TYPICAL DECK ARRANGEMENT FOR CT OPERATIONS


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4.0 SEAFLOOR SHUTOFF DEVICE

The design of the Seafloor Shutoff Device (SSD) is intended to meet all regulatory and industry requirements for emergency reservoir isolation. It incorporates the B OP functions needed at the seafloor, including provisions to s hear and s eal coiled tubing or wireline with stored energy sufficient for close, open, and reclose cycling. A primary design objective is to enhance reliability by keeping it simple and avoiding complexity. The 7-3/8” bore is suitable for pulling crown plugs from horizontal trees having up to 7-inch completion tubing.

The SSD illustrated in Figure 3.7 connects the bottom end of the s elf supporting riser to the subsea tree. The S SD has a 7-3/8" nominal bore, 10,000 psi maximum working pressure valve block with a modified 13-5/8 inch 10,000 psi API flange down and Vetco Gray “TR” style mandrel up. The 1 3-5/8 flange connects to a p roject specific adapter that mates with the client’s tree running tool.

The SSD valve block assembly is arranged in three modular sections. The upper mandrel section has a 7-3/8” 10,000 psi gate valve rated to “fail as is.” The middle section incorporates a dual set of NOV Texas Oil Tools shear / seal rams. The lower section is an adapter between the r ams and the s pecific tree running tool.

The shear / seal ram has a hy draulically operated ram cylinder and wedge type ‘Autolock’ mechanism. The dual set of r ams has a nom inal 7-3/8-in bore with 9-inch 10,000 psi API 6BX flanges top and bottom. The r am cylinder is fitted with position indicators and is capable of s hearing 3-½-in OD coiled tubing with a 0.108 to 0.468 inch diameter logging cable inside and capable of subsequently achieving a blind seal. Additional detail is in the Appendix.

Reservoir isolation capability is also provided by the near surface shear and seal device at the top of the SR and by the CT BOP in the riser extension to the vessel. The CT BOP provides all normal well control functions. This approach provides redundancy and shorter control lines for faster response, and locates most of the active equipment near the surface where it is readily accessible for maintenance.

FIGURE 3.7

SEAFLOOR SHUTOFF DEVICE


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5.0 RISER DEPLOYMENT & MOTION ISOLATION Key requirements for equipment to install the riser and operate through it are in the task reports for Tasks 5 and 6. Thi s section summarizes work done by Huisman and R olls Royce Odim to further define hardware to meet the functional requirements. Material they prepared is included in the Appendices of this Task 9 report.

Safety, reliability, and efficiency in that order are the top pr iorities in the design. Suitable safeguards are required to protect personnel from injury by moving parts. There are to be provisions for hand rails or similar barriers around the moon pool when the cover is not closed.

A design target for the Gulf of Mexico is to work from small vessels, typically 260 feet in overall length, when separate vessels are used for riser installation and CT work. Both the riser installation and the m otion isolation system should be des igned to spread the load over a sufficient area around the moon pool to avoid or minimizing the need to strengthen the associated area of a typical vessel of opportunity.

Equipment for both riser installation and CT work may be integrated into a single package, but scheduling flexibility can be improved and offshore operations costs may be reduced substantially by installing the riser from a vessel that is not necessarily equipped for down hole work, and doing down hole work from a vessel that is not necessarily equipped for riser installation.

Two configurations are presented in the A ppendix. O ne was prepared by Huisman working as a subcontractor, and the other contributed by Rolls Royce Odim acting as a potential supplier. Both configurations present an integrated system that can be used for both riser installation and CT operations. If installation and CT operations are to be done by different vessels, each vessel needs only those elements of the system appropriate to the specific task.

Huisman suggests using a vessel outfitted with a Huisman tower crane. The Ross Candies and the Surf Challenger are mono-hull vessels with Huisman mini towers and are both believed to be operating in the Gulf of Mexico. These vessels need to be fi tted with different moon pool covers, tongs, slips, and deck handling equipment for riser components. H uisman notes that continuous operation of the tower’s heave compensation feature during CT operations will rapidly wear the wire ropes, and suggests modifications to extend the life. The Huisman report does not directly address vessel pitch and roll motions.

The Rolls Royce Odim material in the A ppendix consists primarily of s tills from an animation to show how a system they built previously can be adapted to suit the needs of this project. Rolls Royce proposes to place a spider in the moon pool and a framework above the moon pool to handle the joints, buoyancy modules, and other components of the riser. Rolls Royce shows a trolley system for moving equipment on deck and a moon pool cover with slips and tongs.


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5.1 Riser Installation & Recovery Equipment Riser assembly functions include deck handling of the 25-ton Seafloor Shutoff Device, 20-ton buoyancy modules, and riser joints. Equipment is preferably moved by trolley to avoid swinging loads associated with crane lifts. The equi pment must assemble the riser by aligning joints and threading them with tongs, and then deploy the assembled joints and buoyancy modules through the m oon pool. Guides in the moon pool are required to control the buoyancy modules as they are lowered through the tur bulence in the moon pool during both deployment and recovery. The guide rails are to be spaced to suit the guide sleeves on the buoyancy modules and are to extend down below the keel of the vessel. For SSR recovery, provisions are needed for wires from constant tension winches to align the buoyancy modules guide sleeves with the guide rails before buoyancy modules are recovered through the moon pool. Slips in a split bowl are needed to support the weight of the suspended riser while the cover is closed. The slips are located in a split moon pool cover and must have provisions to prevent release due to inadvertent operation or slippage of the cover sections.

It is intended to use low cost, readily available vessels. Minimizing deck space, deck load, and overall vessel size are therefore important design considerations. Futur e riser handling and assembly systems may be per manently integrated into dedicated vessels, but it is preferred that the first riser assembly system be suitable for rapid mobilization to a vessel of o pportunity. The installation equipment and the m otion isolation equipment should therefore be as small and light weight as is practical. Mobilization should consist primarily of lifting the installation equipment to the deck, fastening it, and connecting the power and c ontrol lines. Ideally the as sembly and deployment equipment can be transferred from the dock to the vessel in only two to three lifts, with additional lifts for the trolley system that moves equipment on deck.

Riser joints, buoyancy modules, and other elements of the r iser can be m obilized on special pallets, bolsters, or racks to simplify the deck handling equipment.


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5.2 Motion Isolation System for CT Operations The SSR allows smaller, lower cost vessels to be used for CT work, but smaller vessels experience greater heave, pitch, and r oll movements which must be ac commodated by the riser / vessel interface equipment. A design target is to work from a 260-foot vessel with 6-foot to occasionally 8-foot significant height for combined waves and swells in the Gulf of Mexico, where the period for swells and waves is typically four to six seconds.

Both self supporting and vessel supported risers are stationary with respect to the earth while the vessel moves with waves and swells. The inertia of the effective mass of the near surface buoyancy of the SSR alters the dynamics of the riser by resisting horizontal acceleration. The riser / vessel interface equipment for an SSR must therefore include provisions to avoid excessive bending moments in the upper part of the riser as the vessel moves in pitch and roll. In this regard it helps to engage the riser to the vessel near the vessel center of motion, typically inside the moon pool. It is also important to support the riser and injector in a manner that leaves the vessel free to pitch and roll without bending the riser. E ngaging the r iser extension in or close to the moon pool also helps avoid clashing between the riser and the walls of the moon pool.

The maximum operating load for motion compensation during CT operations includes the weight of the tubing suspended below the vessel and the weight of the injector and the riser extension, plus any forces exerted by the tubing that runs between the reel and the injector. Dynamic loads due to nonlinearity of the motion isolation system add to the static vertical load which is typically less than 75 tons but may be 150 tons including allowance for the breaking strength of the tub ing. The d esign should not al low transients due to shearing or breaking the tubing to damage the equipment.

The motion isolation system should be designed to work with a wide range of CT injectors, and to provide personnel access to the injector if maintenance is required while the tubing is deployed downhole.

All reasonable steps should be ta ken to r educe the el evation of the i njector. High elevation of the load can adversely affect the stability of a small vessel. Also, access for insertion of the tubing into the injector and for injector maintenance is better if the injector is near deck level. The motion isolation system design shall include provisions for engaging the riser extension as close to the center of vessel motion as is practical, typically below the water line in the moon pool. Minimizing the stack-up height for the CT equipment reduces relative motion between the vessel and the injector.

The power required for heave isolation is proportional to the load and maximum vessel heave and inversely proportional to the time period of the h eave cycle. The heav e cycle for Gulf of Mexico operations is typically six seconds. The load on the platform will change as tubing is run or pulled. The motion isolation system must maintain tension in the riser extension while the weight on the motion isolation system changes. The magnitude and tolerance for this tension is determined by riser analysis. The Task 6 Report defines three ranges of nominal tension and tolerance for normal, above normal, and exceptional vessel motions.

Pitch and roll motions should be isolated by a system that does not require hydraulic or electrical energy from the vessel and prevent clashing between the riser extension and the walls of the moon pool. Introduction of bending moments into the riser extension should be avoided to prevent reduction in the fatigue life of the SSR or the riser extension.


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A telescoping joint in the riser extension can be used as an alternative to a deck mounted motion isolation system. The tel escoping joint allows the injector to be fi xed mounted to the deck of the i ntervention vessel. The deployed tubing moves up and down in the well as the vessel heaves, but this motion is not a concern in relatively low sea states for jobs such as well cleanouts. The telescoping joint approach is not appropriate when vessel heave motion is large or when the lower end of the coiled tubing must be fixed in place as, for instance, in drilling applications.


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6.0 TUBING HANDLING FOR LONGER FATIGUE LIFE An objective of this project is to do downhole work with vessels that cost substantially less than a MODU. Lower cost usually implies smaller vessels, and smaller vessels are subject to greater pitch and roll motions in any given sea state. Thi s section addresses provisions to protect the tubi ng from fatigue due to v essel motions while the deployed tubing is held stationary in the well.

The baseline system includes a preferred equipment arrangement for handling the tubing on deck in a m anner that minimizes the effec t of v essel motions on tubing fatigue life. With these provisions, analysis shows satisfactory fatigue life for various combinations of CT internal pressure pitch and r oll motions up to 10 degr ees. A nalysis shows that the preferred arrangement exerts only reasonable side loading on the top of the riser. It also shows that the pr eferred arrangement enhances overall tubing fatigue life beyond that seen in the traditional onshore configuration by not bending the tubing sharply over the gooseneck.

Both fatigue life of the tubing and stability of t he vessel are improved by keeping the injector close to deck level. Mounting the CT reel on the motion isolation system will eliminate relative motion but will require a larger stabilized platform, and additional power will be needed to c ompensate the weight of the r eel and reel drive, with only a relatively small gain in fatigue life.

CTES created a model that distinguishes between elastic and plastic flexing, and used the model to evaluate different equipment arrangements for handling the tubing between the reel and the injector. Fatigue life is improved by avoiding tension in the tubing segment where the fl exing occurs between the reel and the injector. In the most common arrangement for onshore use this tension is kept high to keep the coil tight on the r eel. The CTES analysis is based in part on using a mini injector to pull the tubing off the r eel so that there is no tension between the reel and the injector.

As an enhancement, over-bend rollers on the reel’s level wind can alternately shape the tubing to the diameter of the reel or the diameter of the arc as the tugging is reeled and unreeled, respectively. This approach keeps the tubing tight on the r eel while reducing tension on the reel and avoiding tension in the arc. Over-bend rollers are similarly used on reel pipe vessels to shape the pipe to t he reel diameter for reeling and then to straighten the pipe as it is laid. This process is common for 8,000 to 10,000 psi pipe with diameter of 10 inches or more, and is comparatively easy for 1.5 to 3-inch tubing. A second set of over-bend rollers can be installed above the injector to straighten the tubing from the radius of the arc as tubing is run into the r iser, and to s hape the tubing to the nominal radius of the arc as tubing is pulled from the riser.

Avoiding tension in the tubing between the reel and the injector also improves the bending moment in the riser and reduces the side load on the injector, thereby simplifying the task of keeping the riser extension centered in the moon pool. The analysis showed that, since the preferred arrangement avoids tension in the tubing between the reel and the injector, side loading on the riser is typically only a few hundred pounds.

The equipment configuration described above is similar to the onshore application shown in Figure 6.1.


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FIGURE 6.1 PARABOLIC ARCH EQUIPMENT CONFIGURATION (LAND)


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The position of the level wind device can be adjusted to accommodate different separation distances between the reel and the injector. Figure 6.2 shows the shape of the a rc with the reel closer to the injector and the level wind closer to the deck.

FIGURE 6.2 SHAPE OF TUBING ARC WITH REEL CLOSE TO INJECTOR

The analysis by CTES was based in part on vessel motions shown in Figure 6.3. The figure shows heave, pitch, and roll data taken onboard a representative 264-foot vessel headed into the weather in seas reported to be thr ee to five feet, occasionally six feet, with wind gusts to 20 knots. As can be seen in the figure, maximum heave was about 2.5 feet while maximum pitch and roll angles were 2 to 2.5 degrees. Data was not recorded, but observations on a similar vessel indicated maximum pitch of appr oximately 9 degrees while headed i nto eight to el even0foot seas associated with a winter front in the Gulf of Mexico.


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FIGURE 6.3 REPRESENTATIVE MOTIONS OF 264 FOOT VESSEL

The period of the motions varies and appears to average about six seconds, or about 10 cycles per minute, which is typical for the Gulf of Mexico.

Examination of the curves in the CTES report (see Appendix) shows an anticipated fatigue life due to vessel motions of several hundred to a thousand hours for pitch and roll of five degrees. Sea state probability varies with season and location, but limiting operations to sea states causing less than 5 degrees pitch and roll for a 260-foot vessel should typically allow operations four to five days a week in the winter, with summer operations interrupted primarily for named storms. Curves, data tables, and more specific information are included in the CTES report Appendix.


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7.0 APPENDIX

I. Seafloor Shutoff Device a. H113890 b. H113663-101 c. H113663-100 d. H113663-17 e. H113663 f. Controls with shuttle valves g. Text and Cost Material

II. Riser Installation & Motion Isolation a. Rolls Royce – sequence of still frames from animation b. Huisman – Well intervention system vessel 2 c. Deck photos of Ross Candies

III. Fatigue life analysis for Deck Handling of Coiled Tubing a. Analysis of CT Utilizing a Parabolic Arch Configuration b. CT Software Modeling Inputs Theory & Validation


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Seafloor Shutoff Device (SSD) · Part No: - H113663-100

Functional Description

The Seafloor Shutoff Device (SSD) is used during Coiled Tubing well intervention phases to provide control of the well. The SSD is installed at the bottom end of the Workover Riser String and connects the subsea tree to the workover riser string. The SSD has a 7-3/8" nominal bore, 10,000 psi MWP (Maximum Working Pressure) valve block with a 13-5/8"-10,000 psi API (American Petroleum Institute) flange (modified) down by Vetco Gray “TR” style mandrel up. The 13-5/8 flange down will be connected to a project specific adapter designed to connect with the client provided tree running tool. The bore configuration is designed to allow free passage of wireline and coiled tubing tools. The 7-3/8” through bore will accommodate the typical 7” crown plug of horizontal trees. The SSD valve block assembly is arranged in three modular sections consisting of the upper mandrel section with a 7-3/8” 10,000 psi gate valve, Fail As Is (FAI). The middle section incorporates a dual set of NOV Texas Oil Tools shear/seal rams. The lower section is an adapter between the rams and the specific Tree Running Tool (TRT) configuration. The NOV Texas Oil Tools Shear/Seal Ram (SSR) has a hydraulically operated ram cylinder and wedge type Autolock mechanism. The dual set of rams has a nominal 7-3/8” bore with 9"-10,000 psi API 6BX flanges top and bottom. The ram cylinder is fitted with position indicators and is capable of shearing 3-1/2" OD coiled tubing with a 0.108 to 0.468” diameter logging cable inside and subsequently capable of achieving a blind seal. The SSRs have dial position indicators. Indication is provided by means of rack and pinion arrangement, the rack being fitted onto the piston rod while the pinion arrangement is housed in the cylinder. The pinion end is attached to an indicator with a calibrated dial; position indicators are viewed by the ROV. The SSD has one Production Isolation Valve (PIV) arranged for Wireline Shear (WLS) which has cut the following during shear tests:

TR Mandrel and Connector

7-3/8” 10M, FAI, WLS Valve

7-3/8” 10M, Shear/Seal Dual Rams

Project Specific Adapter

Typical Tree Running T l


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a) n 2.875” Coiled Tubing x 0.156” WT (Gr HS-90™ CM) with n 0.467” Hepta cable inside b) n 0.467” Hepta cable c) n 0.125” Slick line

The valve is a 7-3/8"-10,000 psi MWP with a hydraulic actuator. The actuator has a linear ROV override and a position indicator. The hydraulic actuator is Fail As Is (FAI) and operates with control pressure of 5,000 psi. The lower adapter is fitted with a 2”-10,000 psi MWP valve to facilitate annulus access. Alternatively, the annulus isolation valve can be assembled to a spool that offers communication between the tree annulus bore and the SSR. The valve and spool arrangement provides for circulation/bullheading of the production tubing if the subsea tree can accommodate. The Annulus Isolation Valve (AIV) is a 2-1/16"-10,000 psi MWP with FSC (Fail Safe Close) hydraulic actuator. The actuator has a linear ROV override and position indicator. The backside of the valve actuator chamber (compensation side) is filled with Marsten Bentley HW 443 (or project specific) water-based lubricant and is linked to a volume compensator (un-pressured accumulator known as a ‘sea chest’). The reverse side of the sea chest is open to ambient seawater pressure. Two check valves, one inlet and one outlet, are mounted to the sea chest manifold. They are designed to prevent any pressure build up from occurring in the compensation system. The SSD valve seat pockets and all sealing surfaces are Inconel 625 clad. The mandrel has a 9"-10,000 psi API 6BX flange which mounts to the SSR block. The mandrel has a 7-3/8” nominal through bore which terminates with a SSD seal pocket at the top. Incorporated into the SSD frame are the following:

ROV Hot Stab Receptacles ROV Cut Lines ROV Docking Panel Protection from Dropped Objects Mounting for Accumulators Guide funnels for standard API guide post features

Technical Specification Maximum Operating Pressure: 10,000 psi Production and Annulus Service: NACE MR-01-75 Hydraulic System Operating Pressure: 5,000 psi - See schematic drawing H113663 Weight (Est.): 41,000 Lbs. Size 144”x135”x169”-See Drawing H113663-100


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Ram Hydraulic Operating Volumes Pair of Actuators including Autolock: SSR Ram Close: 5.95 Gallons (TBC) SSR Ram Open: 7.75 Gallons (TBC) Valve Hydraulic Operating Volumes: 7-3/8” FAI WLS Open 2.20 Gallons 7-3/8” FAI WLS Close 2.20 Gallons 2-1/16” FSC 0.13 Gallon Temperature Range: -20°F to 250°F Lubricants: General: Jet Lube Alco EP-73 Plus™ Valve Gates/Seats: VGS5.3100.1 Hydraulic Controls: Per Project Requirements Fluid Cleanliness SAE AS4059 6B-F Valve Compensation Side: Marsten Bentley HW 443 Bolt Threads: Never-Seez® or Kopr Kote® Handling Equipment: Single Point Lift Cap (A110752-31)

Dedicated Sling Set (H301224-2) Handling Clamp (Shop Use - H110033-1)

Bore-Size (Drift): 7-3/8" Thru Bore with 2-1/16" Outlets

(Lower Adapter configuration dependent) Upper Connection: 16” TR profile mandrel Lower Connection: 13-5/8” 10 API Flange (Modified) (Dependent on TRT interface) Upper Seal Groove: 7-3/8” SSD Seal Pocket Lower Seal Grooves: Based on Specific Intervention SSD Valves/Rams: Shear/Seal Rams (SSR) (Dual Set)

Production Isolation Valve (PIV) Annulus isolation Valve (AIV)

Main Body Material: VGS5.117.1.180, 2-1/4 CR 1 MO, 80 KSI Frame Material: ASTM A36 Bolting Material: ASTM A320 L7 Seal Area Cladding: Inconel 625 Coating Paint (Except Mandrel): VGS6.1.20 (Three Coat Epoxy) Mandrel Coating: VGS6.2.3 (Phosphate)


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Appendix I.

Cost Estimate For Seafloor Shutoff Equipment cost estimates for the seafloor shutoff are listed in Figure 7.1 as refinement of the preliminary estimate included in the Task 6 Report. The seafloor shutoff device meets the requirements described in the Task 6 report, and assumes that the Operator will provide the tree interface connector from the tree running tool or his completion and workover riser.

The cost for equipment to assemble and deploy the riser and the cost for the motion isolation system for downhole work depend heavily on how the specific vessel was previously outfitted. Estimates for these costs are therefore not included in this report.

COST ESTIMATE FOR SEAFLOOR SHUTOFF DEVICE WITH CONTROLS

Item Unit cost Qty Cost

Engineering & project management 500,000 1 500,000

Seafloor shutoff device with shipping frame and test stand 2,883,000 1 2,883,000

Controls package 1,300,000 1,300,000

Hydraulic Power Unit 150,000 1 150,000

Umbilical on reel for seafloor shutoff device & tree with termination assembly & breakaway

2,800,000 1 2,800,000

Subtotal $7,633,000


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Appendix II.

SEQUENCE OF STILL FRAMES FROM ANIMATION OF ROLLS ROYCE

RISER INSTALLATION SYSTEM

Casing joint installation starts. Skate move to centerline of deck

and prepares to receive riser

joints

Joint handler places riser joint on the skate


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Skate presents joint to tower

Elevator accepts upper end of the riser joint


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Elevator upends riser joint and aligns it with previously installed riser joints

Tongs engage riser joint to previously assembled joints


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Elevator lifts string to release slips, lowers string, and hangs new joint in slips

(as seen from operator’s cabin)

Skate is parked and moon pool cover is made ready for buoyancy module


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First buoyancy module moves to approach moon pool

Weight of previously assembled joints is transferred to spider in moon pool,

moon pool cover opens, and rails are swung into place over moon pool


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Buoyancy module moves over moon pool

(uppermost buoy with near surface shear and seal is illustrated here)

Elevator engages top of joint that runs through the buoyancy module


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Elevator lifts buoyancy module, trolley moves back, and moon pool opens

Spider lifts previously assembled string and

weight is transferred to slips in moon pool cover


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Elevator lowers buoy and aligns joint through buoy

with the top of previously assembled string

Joint through buoy is connected to the previously assembled string and elevator lifts weight of string off the slips


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Elevator lowers string through moon pool while guide rails on spider keep the buoy centered in the moon pool until it clears the keel

Injector support frame moves over the moon pool for CT operations


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Appendix II, Section b

Worldwide Lifting, Drilling and Subsea Solutions

Technical Specification Motion Isolation System


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Technical Specification

Motion Isolation System

TABLE OF CONTENTS

1 GENERAL ............................................................................................ 3

1.1 INTRODUCTION 3 1.2 DESCRIPTION 4

2 DESIGN CONSIDERATIONS............................................................... 5

2.1 GENERAL CONSIDERATIONS 5 2.2 RISER INSTALLATION 6 2.3 CT OPERATIONS 6 2.4 LIFTING TOWER PARTICULARS 6

3 SYSTEM OVERVIEW........................................................................... 10

4 SYSTEM LAYOUT AND OPERATIONAL PROCEDURES .................. 11

5 EQUIPMENT DESCRIPTION ............................................................... 12

5.1 MULTI PURPOSE TOWER 12 5.2 SPLITTABLE TRAVELLING BLOCK AND DUAL DRAWWORKS (OPTIONAL) 13 5.3 ACTIVE HEAVE COMPENSATION 14 5.4 PASSIVE HEAVE COMPENSATION 14 5.5 AUXILIARY TROLLEY 15 5.6 AUXILIARY TROLLEY WINCH 16 5.7 CATWALK MACHINE 16 5.8 12MT PIPE HANDLING KNUCKLEBOOM CRANE 17 5.9 SERVICE CRANE 17 5.10 CONTROLS 18 5.11 MOVING HATCH 18 5.12 PIPE MAKE UP EQUIPMENT 19

6 DEMONSTRATION PROJECT ............................................................ 20

Huisman Equipment BV Admiraal Trompstraat 2 3115 HH Schiedam The Netherlands Harbour no. 561

Phone: +31 10 245 22 22 E-mail: [email protected] www.huismanequipment.com

mailto:[email protected]

mailto:[email protected]

Well Intervention System Technical Specification

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1 GENERAL

1.1 Introduction

As is widely known not all available oil is recovered from existing wells. Well intervention can play an important role in prolonging the life of existing fields and increase the total production. However, the current vessels that are capable of doing heavy well intervention (deeper water depths, deep wells) are either too expensive or not readily available. This report describes a system to be installed on a small vessel – but with the same capabilities as larger vessels. Figure 1 depicts the different vessels on the same scale, showing the potential of this new concept.

50,000t displacement drilling vessel

Optimized drilling vessel

1st generation intervention vessel

GOAL – Smaller and more versatile vessels

2nd generation intervention vessel

Figure 1 Well Intervention capable vessels – to scale


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1.2 Description

The Motion Isolation System (MIS) has been designed in accordance to the requirements stated in paragraph 7.2 and paragraph 3.0 of the RPSEA 08121-1502-01 Task 5 Final Report.

The important design parameters are:

Water depth 10,000 [ft] TVD 5,000 – 23,000 [ft] Vessel Heave 10 [ft] Riser 6 5/8” DP [inch] Buoyancy Modules 14 [ft] (diameter) No of Buoyancy Modules 4 [-] Maximum vessel offset 3 [%] Operational 4 [%] Disconnect

The system layout is presented in figure 2.

CT Tool

Surface BOP

Buoyancy Section

Riser Section

SSSD

Figure 2 – System Layout


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2 DESIGN CONSIDERATIONS

2.1 General Considerations

The design was based on the fact that the installation operation should be performed in a safe and efficient manner.

The installation of the free standing riser involves moving a large number of heavy pieces of equipment to and from the moon pool. In order to ensure safe operations the design of the Motion Isolation System (MIS) does not allow for any free swinging load handling. All loads are locked to prevent free motions until the moment that the equipment is run toward the seabed.

To add to safety, work at elevated heights is avoided as much as possible. As a consequence some equipment will be located below the sea level. This is considered an acceptable trade-off.

The height of the lifting tower is determined by taking the following effects in consideration:

- Vessel motion (+/-3m) - Vessel offset (max 3m vertical deflection) - Required maintenance height - Safe lowering to the seabed while in heave compensation mode - Safe retrieval of objects from the seabed - RIII (45”) riser joints - 60’ Slipjoint - Riser expansion due to internal pressure - Running tool length - Height of different pieces of equipment - CT tool length of 25’

When looking at the weights and installation heights it appears that for both the riser installation and the CT jobs the same system can be used in terms of hookload and required lifting height.

# STAGE DESCRIPTION SWL (t) 1 Installation A Lower equipment from Xmas tree up to buoyancy modules 180 2 Installation B Lower equipment from Injector to BOP 40 3 Installation C Install CT Equipment 75 4 Installation D Operate CT + ballasted riser string (overpull = 10t) 125 5 Operational E Riser Tension (pressurized) 50 6 Operational F Riser Tension (depressurized) 140

In this report only one system layout is described to accommodate both operations, CT operations and Free Standing Riser build up.

Exact specifications of equipment are not known in this phase of the project. The specifications have been drawn up in such a manner that a wide range of equipment can be accommodated. The equipment can be designed somewhat more compact when more exact information is available.


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2.2 Riser Installation

The riser installation is a relatively straightforward operation. The advantage of the free standing riser concept is that the final connection can be made using wire instead of dynamic positioning (DP). This is due to the fact that the top of the riser is more than 100 feet below sea level. This greatly simplifies the layout of the handling equipment on the deck, and also simplifies procedures.

In the design threaded couplings are used to connect the different riser sections. The advantage is that readily available equipment can be used.

2.3 CT Operations

The most critical part of the CT operations is the tool change out phase of the operation. In this phase the riser stays connected to the seabed but the CT injector has to move with the vessel; thus there is a relative motion between the two.

There are three options possible:

1. Slipjoint, which can move without pressure and is fully extended with internal pressure (BLAFRO system www.blafro.com ).

2. Fully pressure compensated slipjoint, Which is not currently available, but conceptual designs are already made.

3. CT equipment is connected and disconnected using the active heave compensation system. The riser stays connected to the seabed, but the CT can be lifted a certain distance from the riser. Disadvantages are complex; additional tower height i s needed and there is limited tool height during change out.

For this report the BLAFRO system is used as a base case.

2.4 Lifting Tower Particulars

Main mast hookload (static) 270 [t] 586 [kips] Main mast hookload (dynamic) 200 [t] 440 [kips] Free lifting height main mast (below travelling block) 30 [m] 95 [ft] Lifting speed 30 [m/min] 95 [ft/min] Max Vertical HC motion +/-2 [m] 6.5 [ft] Draw works main mast 1250 [kW] 1,600 [HP] Moon pool Size 7.2x7.2 [m] 23.5x23.5 [ft]

During the concept phase different design options have been considered to lift and move equipment into position. The main design criterion is to hold the load to prevent free swinging motions and the movement from horizontal storage position into vertical position.

When transferring pipe one can use normal pipe handlers with articulated grippers. The difficulties arise when moving the CT equipment from horizontal to vertical position. This equipment is too heavy to handle with standard pipe grippers.

http://www.blafro.com/


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The tower design combines the two functions, load holding and rotation, into one device and is the preferred option.

Considering the heave compensation system, in order to keep the power low, the weight the HC system has to move is to be kept at a minimum. In the tower option this only involves the travelling block, whereas in the platform option this could incorporate the whole platform.

Figure 3 – Different Concept Solutions

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L1Huisman

J TO MOON POOLMOON POOL CENTER 3600 [11'-9.?3"[

FRONT VIEW' LOOKING AFT

SIIE VIH/ LOOKING 56TD

1J045 [42'-9.61"[

Figure 4 -MPT General Arrangement


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2.4.1 Installation on the vessel One of the design criteria of the motion isolation system is its capability of being mounted on vessels of opportunity. The Huisman tower is very well suited for this – provided that some basic preparations have been done.

The tower is completely self-contained: all drives, control systems, etc. are mounted inside the mast. This system makes long term storage easy. Also, the installation on the vessel is simplified because it only requires one single lift.

The mast introduces significant forces into the vessel and these must be accommodated.

There are potential technical solutions: - Dedicated vessel - Generic interface frame welded to the tower - Dedicated interface frame bolted to the tower.

Reviewing the stress plots below, it is clear that the high stresses are confined only to the tower only. The force readily dissipates when flowing into the vessel structure.

Using a dedicated vessel, the vessel structure can be reinforced internally where necessary to accommodate the tower forces.

The intermediate frame should be designed in such a way that any connections to the vessel do not exceed the maximum allowable stresses for the vessel structure. It will require an intermediate frame that has a larger footprint compared to the tower.

Depending on the similarity between available vessels of opportunity, a generic intermediate frame can be used. Otherwise, a different frame for each vessel needs to be made.


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3 SYSTEM OVERVIEW

The main function of the Well Intervention System is the handling and deployment of subsea equipment, e.g., the well intervention package including the High Pressure Riser.

The Huisman Well Intervention System is composed of the following main elements:

• Multi Purpose Tower (MPT), including load motion damping device • Dual draw works • Active Heave Compensation (AHC) • Passive Heave Compensation (PHC) • Catwalk machine • 12mt knuckle boom crane • Control system • Service crane • Skidable moon pool door with hang of assembly interface • 3 Deck skid carts • Pipe Make Up equipment. • Riser Tensioner (not described in this report).

Also necessary is a CT support frame. This is not detailed in this report because it needs to be closely matched to the CT equipment.


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4 SYSTEM LAYOUT AND OPERATIONAL PROCEDURES

The Multi Purpose Tower (MPT) is positioned at the side of the moon pool. This allows for easy access to the firing line. The MPT is the main component of the system and is used to run various pieces of equipment to the seabed. The distance that the travelling block can cover is limited to the height of the tower. Running subsea equipment to the seabed is to be performed using the High Pressure Riser. Slings can be used for the final distance (100 - 200 feet), since they are easier to handle.

Several different deck layouts were investigated:

- port side (PS) - starboard (STB) - Centre

Of these three locations the SB/PS layouts are considered to be the most optimal. There are three main advantages:

1. The skid rails of the carts can continue over the hatch, simplifying the skidding

procedures. 2. Crane access is improved around the tower 3. Riser pipe can now be stored forward of the tower, creating a more efficient use of

deck space.

The MPT is fitted with two trolleys. The main trolley is fixed to the travelling block and travels up and down the tower. The auxiliary trolley travels up and down the MPT by means of its own dedicated winch, and is used to guide equipment that is suspended in the tower. The auxiliary trolley prevents swinging loads and thus provides a safe and controlled way for offshore lifting.

The 12-metric tonne knuckle boom crane is strategically positioned on the main deck and can cover the moon pool area and the firing line. The main purpose of the knuckle boom crane is to handle the tubulars and feed them onto the catwalk machine. Due to its position, the 12-metric tonne Knuckleboom crane can also be used to maneuver small tubulars directly into the firing line. This creates a level of redundancy.

The catwalk machine is positioned on the ships centerline and used for the horizontal transport of tubulars. The catwalk machine receives tubulars from the 12-metric tonne knuckle boom crane and transports them into the firing line where they are handed over the elevator, which is suspended from the travelling block.


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5 EQUIPMENT DESCRIPTION

5.1 MULTI PURPOSE TOWER The Multi Purpose Tower comprises:

• One fully welded box girder structure • Main Trolley (travelling block) • Auxiliary trolley • Service crane • Dual Draw works • Internal access

Crown Block

MPT

The Multi Purpose Tower (MPT) including the integrated crown block is built as a box girder type main structure. The box structure provides both the main load- carrying element and an enclosed environment for the following equipment:

• Passive Heave Compensation cylinders

• Hydraulic Power Unit (HPU) • Electrical cabinets

All integrated equipment is accessible on dedicated floors that can be reached by way of internal stairways. Features

Splittable travelling

block

Moon pool

Trolley

Dual Draw works

- Open firing line allows easy access from three directions

- Small Footprint - Dual draw works on main hoist-+

no slip and cut procedure needed - Active and passive heave

compensation on the travelling block

- Use of Splittable block for increased hoisting efficiency and speeds (optional)

- Auxiliary Trolley to provide controlled handling of subsea equipment

- Service crane on top of MPT

Figure 1: Example of 150 mt MPT as delivered to Helix. Note that the MPT presented in this proposal is only equipped with 3 drums; 2 main drums and one auxiliary hoist drum.


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5.2 SPLITTABLE TRAVELLING BLOCK AND DUAL DRAWWORKS (OPTIONAL)

The Splittable Travelling Block of the Multi Purpose Tower comprises two fixed and four detachable single sheave blocks. Splitting the blocks is a push-button operation and is achieved by detaching a pair of sheave blocks from the main trolley and attaching them to the crown- block. Only when the main trolley is in its upper position can this operation be performed. The picture below shows the travelling block in a 12 falls, 8 falls, and 4 falls configuration.

12 falls reeving

Load

8 falls reeving

Load

4 falls reeving

Load

Reeving diagram with detachable single sheave blocks from12, 8, and 4 falls

The dual draw works that move the travelling block consist of an independent alternating current (AC) electric-driven, double drum system. The dual drum system with two fast lines reduces the overall line speed and reduces line wear. It also provides built-in redundancy due to the fact that if one winch fails the other winch can still operate the travelling block, however at half the original speed.

The dual drum system does not have a deadline anchor and does therefore not require the conventional cut- and slip procedure. When a certain part of the wire is worn out, the complete drill line can be transferred a certain distance from one drum to the other, exposing a different part of the wire to a fatigue sensitive location (e.g., a sheave). After a certain period, the complete wire must be replaced.

Main trolley

Splittable

block

Splittable block and main trolley


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5.3 ACTIVE HEAVE COMPENSATION The Active Heave Compensation (AHC) System actively counteracts the vessels heave motion in order to place subsea equipment on the seabed in a controlled manner.

With AHC the real-time signal of the Motion Reference Unit (MRU) is used as an input signal: no wave or motion prediction methods are used. In response to this signal the E-motors turn the winches so they take in or pay out wire to keep the load at a constant position in relation to the seabed and minimize the differences in line pull. AHC is utilized during installation of subsea equipment. Once the equipment is in place the passive heave compensation takes over.

5.4 PASSIVE HEAVE COMPENSATION After landing the subsea package using the AHC, the passive heave compensation takes over. The vertical motions of the vessel with respect to the seabed are now compensated by the passive heave cylinders.

When the vessel moves upwards, the line pull increases and the cylinders are pulled upwards, paying out wire and reducing line pull. When the vessel moves downwards, the line pull decreases and the cylinders move downwards, hauling in the wire.

The stiffness of the gas-loaded spring system can be adjusted by varying the gas volume that is connected to the passive system. This means that for each load case and for each sea state condition the gas volume can be optimized.

By varying the pressure of the gas, the system can be adjusted to different static loads. The system is correctly set when the compensation cylinder is at the middle of its stroke and the line pull caused by the cylinder is equal to the nominal line pull in the wire.


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Pressure Vessels, gas pressure

Load

Gas Oil Protection System cylinders or Passive Heave Compensator

Medium separator

Rotating winches - Active heave Compensator

5.5 AUXILIARY TROLLEY The auxiliary trolley is driven by its own dedicated winch and provides a means of extra guidance for the packages in addition to the main trolley. The auxiliary trolley can be equipped with an extension frame that can be bolted on or off. Different frames can be attached to guide different sized packages. The auxiliary trolley can travel all the way down inside the moon pool and is utilized for package deployment, package retrieval, and package stack-up operations.


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5.6 AUXILIARY TROLLEY WINCH The trolley winch is connected to the auxiliary trolley with one single wire and requires no back tension facilities. The auxiliary trolley moves on gravity.

The auxiliary trolley winch is a regular drum winch that is mounted in a winch frame inside the MPT.

The trolley winch is fitted with a constant tension control arrangement to avoid slack rope. This arrangement measures the load on the electric drive as a reference for the load.

5.7 CATWALK MACHINE The catwalk machine is positioned on the ship’s centerline and is used for the horizontal transport of tubulars. The catwalk machine receives tubulars from the 12-metric tonne knuckle boom crane and transports them into the firing line, where they are handed over to the elevator, which is suspended from the travelling block. The tubular transport is carried out by the catwalk machine’s conveyor belt. The belt moves the tubulars until the first end of the pipe is in the firing line. The elevator then lifts the pipe. When the pipe is nearly upright the tailing arm on the Catwalk Machine safely guides the tubulars into the firing line.

If required, the catwalk machine can travel as a whole in forward and aft direction to make way for the moon pool hatch.

The Catwalk machine consists of:

- One main frame with wheels - Tailing arm - Conveyor

The catwalk machine is controlled from the control cabin,

Firing line

Tailing arm

Conveyor belt Tubular

Wheels

Catwalk machine


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5.8 12MT PIPE HANDLING KNUCKLEBOOM CRANE The 12-metric tonne Pipe Handling Knuckle Boom Crane consists of a crane house, a main boom, and a knuckle boom that is outfitted with a gripper for tubulars. The driver cabin is mounted on one side of the crane house, while the hydraulic power unit is mounted on the other side of the crane house.

Normally control and operation of the crane and the gripper shall be from a portable wireless remote control panel.

Main hoist On the end of the knuckle boom, a gripper on a slewing device is mounted. The slewing device offers excellent handling of tubulars.

Luffing/slewing Main boom luffing and knuckle boom luffing is done by hydraulic cylinders. The slewing is done by multiple hydraulic motors, gearboxes, and a fully enclosed slew bearing.

The pipe handling crane will be installed on one side of the pipe deck, while designed for the following operations:

• Picking up or placing tubulars on the catwalk machine using the

gripper head • Handing tubulars or taking small tubulars directly out of the

firing line. • General deck-to-deck operations on the deck and main deck area

within reach of the crane

5.9 SERVICE CRANE On top of the MPT a service crane is fitted. This hydraulic foldable marine crane will be powered by a hydraulic power unit (HPU). The crane is outfitted with a hydraulic wire rope winch with a non-rotating wire rope. This winch is also suitable for man-riding. The service crane can be operated with a remote control unit.


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5.10 CONTROLS The Well Intervention MPT will be controlled from a dedicated control cabin. This cabin will be outfitted with windows to have a clear view on the tower, lighting, heating; an AC-unit, a door, and a work desk. Drop-in panels containing all controls associated with the system will be delivered and installed. Also, the necessary screens will be installed to monitor the systems and with views on the winches. The main operator will be seated in a chair without controls. On both sides control desks will be provided with the above mentioned controls.

Drop-in panels for clients can be installed upon request but no provisions are made at this stage.

The Well Intervention MPT will be controlled with a supervisory control and data acquisition, or SCADA, based system and will be completely developed by Huisman. Huisman has ample experience in designing and building SCADA systems.

5.11 Moving Hatch The moon pool hatch is a welded steel structure of approximately 7.3 x 7.3 meters squared. The hatch is able to skid in a transverse direction by means of hydraulic skid units which are mounted on top of two skid rails. The T-type skid rails need to be welded to the deck of the vessel.

The hatch is supported in closed position on support around the moon pool. Therefore the hatch can only support the payload when the hatch is fully closed.

The main functions of the moon pool hatch are: • Support of the payload before it is lowered to the seabed • Closure of the moon pool.

The hatch has one central slot for the main hoist wire. Additional slots can be accommodated as required. The central slot can be closed by two hydraulic operated doors. The remaining moon pool opening of 1 meter diameter can be closed with a manually installed steel cover.

On top of the hatch, two integrated skid rails will be welded for the skidding system. For the central slot a manually installed skid rail will be delivered.

Controls The hydraulic movements of the hatch are fed via a drag chain by an electro-hydraulic power unit, which will be located near to the hatch. On the HPU a basic operator stand is located with the following control functions:

- Lever for Push / Pulling - Lever for Clamping - Main switch for start up and stop of HPU - Emergency stop

Skid rails The steel skid rails are HEM 260-type and the centre-to-centre distance between these rails is 2250 millimeters. The skid rails need to be placed on deck supports (not in Huisman scope of supply).


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5.12 Pipe Make Up Equipment

Huisman advises using an automated pipe make-up tool. A good example of this is the CanRig tool, which is a complete functioning unit including an articulated joint. The advantage of this tool is that it combines several tools into one – which do not have to be mounted/ bought separately.


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6 DEMONSTRATION PROJECT

It is intended to validate the concept of the free standing riser in a short period of time with minimal investments.

There are two vessels working in the GOM on which a MPT is installed: the Ross Candies and the DMT Emerald (now Surf Challenger). Both vessels are capable of running the free standing riser to the seabed.

Ross Candies

Surf Challenger

However, the heave compensation (HC) systems of those towers are not suited for prolonged periods when the HC is switched on (wire fatigue issues). Therefore, CT operations are not possible with these vessels without major modifications.

In principle no major modifications need to be done on the vessels, provided that the installation takes place in calm weather. A skidding system is only needed for the riser pipes. The buoyancy cans are moved into position with the knuckle boom crane. This is not the optimal way of handling – but it saves considerably on equipment cost. If confined to calm weather operations, no retrieval load damping device is needed.

Necessary modifications:

- Strengthen the hatch if necessary - Install riser spider - Install pipe make up equipment - Install Air compressors and hoses for filling up the buoyancy cans

70

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71


RISER INSTALLATION PROCEDURE

Well Intervention System Technical Specification Well Intervention System Technical Specification

72

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73

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74


well Intervention System

SLIP JOINTOPERATION, CT NOT IN OPERATION SLIP JOINT DEPRESSURIZED

75


CT OPERATION: SUP JOINT IS PRESSURIZED OR SURFACE EQUIP IS HUNG ON MPT WITH PHC CODE

76


well Intervention System

77

Appendix II, Section c Deck photos of Ross Candies:

79

9870 Pozos Lane

Conroe, Texas 77303-2178

Phone: (936) 521-2200

Fax: (936) 521-2275

Appendix III.

Analysis of Coiled Tubing Utilizing A

Parabolic Arch Equipment Configuration

Project No. 08121-1502-01

“Coiled Tubing Drilling and Intervention System From a Cost Effective Vessel”

This document provides a summary of the various coiled tubing analysis performed for an equipment configuration utilizing a ‘Parabolic Arch’, instead of the normal coiled tubing reel and gooseneck configuration. The analysis primarily focused on: coiled tubing fatigue life when utilizing a parabolic arch, physical boundary conditions for a stable parabolic arch, and horizontal (side) loads on the moon pool injector as a result of the parabolic arch equipment configuration.

The following input data was utilized for the modeling and various coiled tubing analysis contained in this report.

Input Data

CT Properties Diameter 2.375 in Wall thickness 0.188 in Young’s modulus 27,000 kpsi Yield strength 80 kpsi

Radius of reel 9 ft

Radius of gooseneck 15 ft

Horizontal distance between reel & gooseneck 80 ft

Vertical distance between reel & gooseneck 35 ft

Vessel Motion Heave 2 ft Period of heave 6 sec Period of pitch 6 sec

80

For the coiled tubing Parabolic Arch equipment configuration, it is assumed that a second ‘mini injector’ is installed at the reel, such that the tubing will make a gentle arch shape between the reel and the standard tubing injector located at the moon pool. This mini-injector can be seen mounted on the levelwind device, above the coiled tubing reel on the left-hand side of Figure 2. This gentle arch-like shape helps to maximize the bending radius experienced by the coiled tubing and will serve to extend the fatigue life of the tubing.

The height of the arch is controlled by varying the coiled tubing pay-out/take-up speed of the mini injector vs. the coiled tubing pay-out/take-up speed of the moon pool injector. The injector angles (to vertical) at the reel and at the moon pool are 20 degrees and 0 degrees, respectively. The coiled tubing length shown in the calculation is the length of tubing between the two injectors. Thus, longer lengths of tubing equate to a taller Parabolic Arch.

Figure 2: Parabolic Arch Equipment Configuration (land)

81

Coiled Tubing Fatigue Life when Utilizing a Parabolic Arch

The fatigue life of the coiled tubing was calculated for three horizontal distances: 54 feet, 65 feet, and 80 feet. These values represent varying equipment placement options (distance between mini injector at the reel and moon pool injector) on the deck of the floating vessel. The resulting coiled tubing fatigue life analysis graphs for a scenario with stationary coiled tubing are shown in Figure 3 through Figure 5. The coiled tubing fatigue life damage under this situation is a result of vessel movement, not tubing movement in the wellbore.

As was hoped, the Parabolic Arch equipment configuration significantly extends the coiled tubing fatigue life.

It should also be noted that the calculations presented in this report are somewhat conservative to simplify the analysis, as the position and angle of the mini injector at the reel was locked at 20 degrees, irrespective of Parabolic Arch height. Ideally, this angle should vary slightly depending on the shape/height of the arch.

Under field operating conditions, most coiled tubing units will have the ability to raise and lower the levelwind device (where the mini injector is mounted) to accommodate this angle change at one end of the Parabolic Arch, which would serve to slightly extend the coiled tubing fatigue life under certain scenarios.

Results of the complete Parabolic Arch fatigue life calculation are attached in Appendix A: Parabolic Arch Coiled Tubing Fatigue Life Results on page 102.

82

Figure 3: Stationary Coiled Tubing Fatigue Life

83

(horizontal distance between injectors = 54 ft)

84



85



In addition to the fatigue life calculations, each of the three horizontal equipment placement locations were analyzed with various lengths of coiled tubing, to simulate varying Parabolic Arch heights. This sensitivity analysis was performed to identify the height at which the arch might become unstable, and may have a tendency to fall over to one side. (Note: Under actual operating conditions, a set of stabilizing guy wires would be strung from each side of the reel up to each side of the gooseneck as a safety precaution to help prevent the arch from potentially falling. However, it is still good operating practice to design the system to not have to rely on these guy wires during normal operations.)

For a horizontal equipment placement distance of 54 feet (mini injector to moon pool injector), the arch is stable up to 170 feet of coiled tubing length.

For a horizontal equipment distance of 65 feet between the two injectors, calculations show that the arch will tend to fall to the side when the coiled tubing length reaches 185 feet (see Figure 6, note the displacement in the ‘z’ direction). Thus, a 181-foot tubing length should be considered as the upper limit of a stable Parabolic Arch for this equipment configuration, which corresponds to a maximum coiled tubing height of 56.2 feet above the gooseneck at the moon pool injector.

For a horizontal equipment distance of 80 feet between the injectors, calculations indicated that when the coiled tubing length of the Parabolic Arch approaches 190 feet in length, the coiled tubing shape will want to change to that of a Lazy Arc. Thus, 187 feet should be considered as the upper limit of a stable Parabolic Arch height for this equipment configuration, which corresponds to a maximum coiled tubing height of 54 feet above the gooseneck on the moon pool injector.

86

Horizontal Distance 65 ft; Coiled Tubing Length 185 ft

87

Horizontal Distance 80 ft; Coiled Tubing Length 190 ft

Figure 6: Unstable Parabolic Arch Configurations

A wind load calculation for the Parabolic Arch equipment configuration was also performed. The results of this analysis are summarized in the following graph and table. These values will be used as input for subsequent modeling analysis of side loads to be experienced at the moon pool injector. Also, a wind load of 22 knots was used in the fatigue calculations.

88

Figure 7: Wind Load on Coiled Tubing

89

Table 1: Wind Load on the Coiled Tubing Parabolic Arch

Wind Speed Wind Load on the CT

knots Mph lbf lbf/ft

0 0.00 0.000 0.000

1 1.15 0.000 0.001

2 2.30 0.001 0.003

3 3.45 0.002 0.007

4 4.61 0.003 0.013

5 5.76 0.005 0.020

6 6.91 0.007 0.029

7 8.06 0.010 0.040

8 9.21 0.013 0.052

9 10.36 0.016 0.065

10 11.52 0.020 0.081

11 12.67 0.024 0.098

12 13.82 0.029 0.116

13 14.97 0.034 0.136

14 16.12 0.040 0.158

15 17.27 0.045 0.181

16 18.42 0.052 0.206

17 19.58 0.058 0.233

18 20.73 0.065 0.261

90

19 21.88 0.073 0.291

20 23.03 0.081 0.322

21 24.18 0.089 0.356

22 25.33 0.098 0.390

23 26.48 0.107 0.426

24 27.64 0.116 0.464

The prior coiled tubing fatigue analyses were performed for unique worst-case scenarios where the coiled tubing was held stationary and experienced fatigue damage solely due to movement of the floating vessel. The following table provides an analysis of another more likely scenario, that is the expected fatigue life while performing RIH/POOH operations with the coiled tubing equipment specified earlier in this report and while being used in a Parabolic Arch configuration. This calculation is based on using the large 9 feet. radius reel, which also helps greatly extend CT fatigue life.

Table 2: Trips to Failure for RIH/POOH Coiled Tubing Operations

(utilizing parabolic arch & large reel equipment configuration)

Circulating Pressure

(psi)

Coiled Tubing Trips to Failure

2-3/8” x 0.188 CT // 80 Grade

(parabolic arch & large reel)

1,000 975

2,000 782

3,000 588

4,000 381

5,000 239

91

1. Horizontal Support and Forces Acting at the Moon Pool Injector

The primary coiled tubing injector will be located and structurally-supported at the moon pool of the floating vessel. Thus, an analysis of the estimated horizontal (side) loads that can be expected from the forces associated with supporting the coiled tubing parabolic arch where it begins to contact the gooseneck (above the moon pool injector) was required. This analysis is performed to determine if special reinforcement of the moon pool might be required.

The following supporting forces at the gooseneck were calculated to include a wind loading value on the tubing while it was operating in a Parabolic Arch configuration. The wind loading on the tubing is equivalent to a wind speed of 22 knots.

The calculated forces shown in the following graphs and table are displayed as total (resultant) force, which is then further segmented into a vector force in the vertical plane, and a force in the horizontal plane. The vector force in the horizontal plane equates to the side loads that have been calculated at the moon pool injector. Note that these forces are less than some may anticipate, since the normal amount of reel back tension on the coiled tubing is not present - - it is isolated on the reel side of the reel injector, and thus is not present to add to the side loading on the moon pool injector.

92

Figure 8: Supporting Forces at Moon Pool Injector

(at gooseneck, horizontal distance between reel and gooseneck = 54 ft)



93



Table 3: Supporting Forces at Moon Pool Injector

(includes 22 knot wind speed loading)

Horizontal Distance

(between reel & gooseneck)

CT Length

(between Injectors)

Force In Vertical Plane

Force In Horizontal

Plane

Total Force

ft ft lbf lbf lbf

54 119.5 378.0 32.2 379.4

371.0 32.0 372.4

366.0 31.8 367.4

361.7 31.6 363.1

359.6 31.5 361.0

357.6 31.5 359.0

94

Horizontal Distance


CT Length

(between Injectors)


Force In Horizontal

Plane

Total Force

ft ft lbf lbf lbf

131.5 400.5 46.0 403.1

391.5 46.0 394.2

385.7 46.0 388.4

380.0 46.0 382.8

377.4 46.0 380.2

374.7 46.0 377.5

158 485.8 96.8 495.4

474.7 100.9 485.3

467.5 103.5 478.8

460.4 106.4 472.5

457.0 108.0 469.6

453.5 109.6 466.6

170 538.4 99.7 547.6

525.7 106.4 536.4

516.9 112.7 529.0

507.8 120.3 521.9

503.3 124.0 518.4

498.9 127.8 515.0

65 135 409.5 39.6 411.4

400.9 39.5 402.8

395.3 39.4 397.3

389.9 39.3 391.9

387.2 39.3 389.2

384.6 39.2 386.6

165 487.1 78.2 493.3

95

Horizontal Distance


CT Length

(between Injectors)


Force In Horizontal

Plane

Total Force

ft ft lbf lbf lbf

475.4 80.9 482.2

467.7 82.9 475.0

460.0 85.2 467.8

456.2 86.5 464.3

452.3 87.7 460.7

181 547.8 85.1 554.4

534.2 89.6 541.7

525.1 93.2 533.3

515.0 99.0 524.4

509.9 102.0 520.0

505.0 105.0 515.8

80 170 510.2 70.8 515.1

498.0 72.7 503.3

489.9 74.1 495.5

481.8 75.5 487.7

477.8 76.1 483.8

473.8 76.6 480.0

181 549.4 82.8 555.6

536.8 84.4 543.4

528.3 85.6 535.2

519.8 86.8 527.0

515.5 87.5 522.9

511.3 88.2 518.9

187 571.5 89.5 578.5

560.1 91.1 567.5

551.8 92.2 559.4

96

Horizontal Distance


CT Length

(between Injectors)


Force In Horizontal

Plane

Total Force

ft ft lbf lbf lbf

543.5 92.9 551.4

539.6 93.2 547.6

535.6 93.7 543.7

97

2. Boundary Conditions for a Stable Parabolic Arch

The calculations provided in Table 3 (see prior section) also provides the range of coiled tubing segment length (between the reel injector and moon pool injector) that will provide for a stable Parabolic Arch for each of the three modeled horizontal equipment spacing. Any values that are outside the boundaries of a stable arch configuration are not presented. This analysis considered a physical horizontal equipment spacing (between the centerline of the reel and gooseneck) of 54 feet, 65 feet ,or 80 feet, respectively.

For example, when the horizontal distance between the centerline of the coiled tubing reel and moon pool injector is 65 feet, this analysis determined the parabolic arch will remain stable and provide the desired additional coiled tubing fatigue life for a tubing length range of 135 feet up to 181 feet. Note that this value is the length of tubing that makes up the parabolic arch between the two injectors.

When the coiled tubing length between the reel injector and moon pool injector is allowed to drop below its minimum recommended value, the tubing experiences additional bending events coming on/off the gooseneck and the benefit of additional coiled tubing fatigue life from the Parabolic Arch configuration is lost. Alternatively, if the coiled tubing length between the reel injector and moon pool injector is allowed to grow beyond the maximum recommended length, the arch will become unstable and have a tendency for the Parabolic Arch shape to want to fall into a ‘lazy arch’ shape, which will again negate the extended tubing fatigue life that can be obtained from the Parabolic Arch.

The minimum radius of curvature of the arch and the minimum arch height above the reel injector are shown in the following table.

98

Table 4: Stability Range of Coiled Tubing Parabolic Arch

Horizontal Distance


Minimum CT Length

Maximum CT Length

Minimum Radius of

Curvature of Arch

Minimum Arch Height

(above injector at reel)

ft ft ft ft ft

54 119.5 170 59.8 23.1

65 135 181 64.4 26.7

80 170 187 82.9 29.6

99

3. Nomenclature

The following abbreviations and nomenclature have been utilized in this document:

ft feet

lbf pounds force

POOH pull out of hole

RIH run in hole

100

Appendix A: Parabolic Arch Coiled Tubing Fatigue Life Results

Horizontal Distance


CT Length

(between Injectors)

Internal Pressure

Max. Pitch Angle

Max. Change in Curvature

CT Fatigue Life

ft ft psi deg 1/ft cycles hours

54 119.5 1,000 10 0.0228 24,957 41.6

7 0.0159 88,295 147.2

5 0.0113 291,693 486.2

3 0.0067 1,810,696 3,017.8

2 0.0044 7,840,287 13,067.1

1 0.0021 102,069,463 170,115.8

2,000 10 0.0228 21,632 36.1

7 0.0159 76,532 127.6

5 0.0113 252,833 421.4

3 0.0067 1,569,470 2,615.8

2 0.0044 6,795,781 11,326.3

1 0.0021 88,471,471 147,452.5

3,000 10 0.0228 18,221 30.4

7 0.0159 64,464 107.4

5 0.0113 212,964 354.9

3 0.0067 1,321,981 2,203.3

2 0.0044 5,724,158 9,540.3

1 0.0021 74,520,457 124,200.8

4,000 10 0.0228 14,838 24.7

7 0.0159 52,494 87.5

5 0.0113 173,420 289.0

3 0.0067 1,076,510 1,794.2

101

Horizontal Distance


CT Length

(between Injectors)

Internal Pressure

Max. Pitch Angle


CT Fatigue Life


2 0.0044 4,661,271 7,768.8

1 0.0021 60,683,165 101,138.6

5,000 10 0.0228 11,594 19.3

7 0.0159 41,017 68.4

5 0.0113 135,505 225.8

3 0.0067 841,152 1,401.9

2 0.0044 3,642,176 6,070.3

1 0.0021 47,415,987 79,026.6

131.5 1,000 10 0.0193 44,297 73.8

7 0.0135 157,129 261.9

5 0.0096 520,833 868.1

3 0.0057 3,257,910 5,429.9

2 0.0037 14,251,258 23,752.1

1 0.0018 191,415,720 319,026.2

2,000 10 0.0193 38,396 64.0

7 0.0135 136,196 227.0

5 0.0096 451,446 752.4

3 0.0057 2,823,882 4,706.5

2 0.0037 12,352,664 20,587.8

1 0.0018 165,914,758 276,524.6

3,000 10 0.0193 32,341 53.9

7 0.0135 114,719 191.2

5 0.0096 380,258 633.8

3 0.0057 2,378,586 3,964.3

102

Horizontal Distance


CT Length

(between Injectors)

Internal Pressure

Max. Pitch Angle


CT Fatigue Life


2 0.0037 10,404,779 17,341.3

1 0.0018 139,751,759 232,919.6

4,000 10 0.0193 26,336 43.9

7 0.0135 93,418 155.7

5 0.0096 309,650 516.1

3 0.0057 1,936,919 3,228.2

2 0.0037 8,472,773 14,121.3

1 0.0018 113,802,027 189,670.0

103

5,000 10 0.0193 20,578 34.3

7 0.0135 72,994 121.7

5 0.0096 241,951 403.3

3 0.0057 1,513,450 2,522.4

2 0.0037 6,620,369 11,033.9

1 0.0018 88,921,457 148,202.4

158 1,000 10 0.0156 94,300 157.2

7 0.0109 332,176 553.6

5 0.0077 1,094,370 1,823.9

3 0.0046 6,873,888 11,456.5

2 0.0030 30,954,034 51,590.1

1 0.0014 469,023,285 781,705.5

2,000 10 0.0156 81,737 136.2

7 0.0109 287,923 479.9

5 0.0077 948,575 1,581.0

3 0.0046 5,958,129 9,930.2

2 0.0030 26,830,247 44,717.1

1 0.0014 406,538,631 677,564.4

3,000 10 0.0156 68,848 114.7

7 0.0109 242,520 404.2

5 0.0077 798,995 1,331.7

3 0.0046 5,018,595 8,364.3

2 0.0030 22,599,401 37,665.7

1 0.0014 342,431,797 570,719.7

4,000 10 0.0156 56,064 93.4

7 0.0109 197,488 329.1

5 0.0077 650,634 1,084.4

104

3 0.0046 4,086,720 6,811.2

2 0.0030 18,403,043 30,671.7

1 0.0014 278,847,529 464,745.9

5,000 10 0.0156 43,807 73.0

7 0.0109 154,311 257.2

5 0.0077 508,385 847.3

3 0.0046 3,193,239 5,322.1

2 0.0030 14,379,581 23,966.0

1 0.0014 217,883,014 363,138.4

170 1,000 10 0.0149 110,508 184.2

7 0.0105 372,575 621.0

5 0.0074 1,265,441 2,109.1

3 0.0043 8,646,325 14,410.5

2 0.0027 41,333,766 68,889.6

1 0.0013 578,117,383 963,529.0

2,000 10 0.0149 95,786 159.6

7 0.0105 322,939 538.2

5 0.0074 1,096,855 1,828.1

3 0.0043 7,494,437 12,490.7

2 0.0027 35,827,161 59,711.9

1 0.0013 501,098,894 835,164.8

3,000 10 0.0149 80,681 134.5

7 0.0105 272,015 453.4

5 0.0074 923,893 1,539.8

3 0.0043 6,312,643 10,521.1

2 0.0027 30,177,597 50,296.0

1 0.0013 422,080,909 703,468.2

105

4,000 10 0.0149 65,700 109.5

7 0.0105 221,506 369.2

5 0.0074 752,340 1,253.9

3 0.0043 5,140,483 8,567.5

2 0.0027 24,574,086 40,956.8

1 0.0013 343,707,037 572,845.1

106

5,000 10 0.0149 51,336 85.6

7 0.0105 173,078 288.5

5 0.0074 587,856 979.8

3 0.0043 4,016,618 6,694.4

2 0.0027 19,201,447 32,002.4

1 0.0013 268,562,269 447,603.8

65 135 1,000 10 0.0207 57,314 34,519

7 0.0145 39,937 122,220

5 0.0103 28,395 403,304

3 0.0061 16,878 2,490,994

2 0.0040 11,126 10,708,401

1 0.0019 5,380 136,247,456

2,000 10 0.0207 59,704 29,920

7 0.0145 41,602 105,938

5 0.0103 29,579 349,575

3 0.0061 17,581 2,159,137

2 0.0040 11,590 9,281,797

1 0.0019 5,604 118,096,172

3,000 10 0.0207 62,704 25,202

7 0.0145 43,693 89,232

5 0.0103 31,065 294,451

3 0.0061 18,465 1,818,664

2 0.0040 12,173 7,818,156

1 0.0019 5,886 99,473,657

4,000 10 0.0207 66,494 20,522

7 0.0145 46,334 72,663

5 0.0103 32,943 239,776

107

3 0.0061 19,581 1,480,966

2 0.0040 12,909 6,366,446

1 0.0019 6,241 81,002,943

5,000 10 0.0207 71,350 16,036

7 0.0145 49,718 56,777

5 0.0103 35,349 187,353

3 0.0061 21,011 1,157,182

2 0.0040 13,851 4,974,548

1 0.0019 6,697 63,293,247

165 1,000 10 0.0181 49,893 56,081

7 0.0127 35,116 191,733

5 0.0091 25,067 623,908

3 0.0054 14,922 3,833,102

2 0.0036 9,819 16,583,942

1 0.0017 4,711 216,736,550

2,000 10 0.0181 51,974 48,610

7 0.0127 36,580 166,190

5 0.0091 26,112 540,789

3 0.0054 15,544 3,322,445

2 0.0036 10,229 14,374,581

1 0.0017 4,908 187,862,273

3,000 10 0.0181 54,586 40,944

7 0.0127 38,418 139,984

5 0.0091 27,424 455,512

3 0.0054 16,326 2,798,530

2 0.0036 10,743 12,107,862

1 0.0017 5,155 158,238,383

4,000 10 0.0181 57,885 33,342

108

7 0.0127 40,741 113,991

5 0.0091 29,082 370,931

3 0.0054 17,312 2,278,887

2 0.0036 11,392 9,859,620

1 0.0017 5,466 128,855,972

109

5,000 10 0.0181 62,112 26,052

7 0.0127 43,716 89,069

5 0.0091 31,206 289,834

3 0.0054 18,577 1,780,653

2 0.0036 12,224 7,704,008

1 0.0017 5,865 100,684,154

181 1,000 10 0.0169 46,666 70,868

7 0.0122 33,851 218,004

5 0.0089 24,502 675,699

3 0.0051 14,222 4,535,166

2 0.0033 9,218 20,687,806

1 0.0016 4,337 289,551,901

2,000 10 0.0169 48,612 61,427

7 0.0122 35,262 188,961

5 0.0089 25,524 585,680

3 0.0051 14,815 3,930,978

2 0.0033 9,602 17,931,716

1 0.0016 4,518 250,976,950

3,000 10 0.0169 51,055 51,740

7 0.0122 37,034 159,163

5 0.0089 26,806 493,325

3 0.0051 15,560 3,311,105

2 0.0033 10,085 15,104,074

1 0.0016 4,745 211,400,545

4,000 10 0.0169 54,141 42,133

7 0.0122 39,273 129,609

5 0.0089 28,427 401,722

110

3 0.0051 16,500 2,696,284

2 0.0033 10,695 12,299,482

1 0.0016 5,032 172,146,745

5,000 10 0.0169 58,095 32,921

7 0.0122 42,141 101,273

5 0.0089 30,503 313,893

3 0.0051 17,705 2,106,795

2 0.0033 11,476 9,610,443

1 0.0016 5,399 134,510,253

80 170 1,000 10 0.0200 39,477 65.8

7 0.0140 134,914 224.9

5 0.0101 435,453 725.8

3 0.0060 2,615,130 4,358.5

2 0.0040 10,935,490 18,225.8

1 0.0020 126,289,494 210,482.5

2,000 10 0.0200 34,217 57.0

7 0.0140 116,940 194.9

5 0.0101 377,440 629.1

3 0.0060 2,266,735 3,777.9

2 0.0040 9,478,632 15,797.7

1 0.0020 109,464,839 182,441.4

3,000 10 0.0200 28,822 48.0

7 0.0140 98,500 164.2

5 0.0101 317,922 529.9

3 0.0060 1,909,295 3,182.2

2 0.0040 7,983,953 13,306.6

1 0.0020 92,203,394 153,672.3

4,000 10 0.0200 23,470 39.1

111

7 0.0140 80,210 133.7

5 0.0101 258,889 431.5

3 0.0060 1,554,768 2,591.3

2 0.0040 6,501,456 10,835.8

1 0.0020 75,082,655 125,137.8

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5,000 10 0.0200 18,339 30.6

7 0.0140 62,674 104.5

5 0.0101 202,288 337.1

3 0.0060 1,214,849 2,024.7

2 0.0040 5,080,041 8,466.7

1 0.0020 58,667,313 97,778.9

181 1,000 10 0.0194 43,716 72.9

7 0.0133 161,569 269.3

5 0.0093 581,681 969.5

3 0.0055 3,500,018 5,833.4

2 0.0037 13,783,547 22,972.6

1 0.0020 134,870,549 224,784.2

2,000 10 0.0194 37,892 63.2

7 0.0133 140,044 233.4

5 0.0093 504,188 840.3

3 0.0055 3,033,735 5,056.2

2 0.0037 11,947,263 19,912.1

1 0.0020 116,902,700 194,837.8

3,000 10 0.0194 31,917 53.2

7 0.0133 117,961 196.6

5 0.0093 424,683 707.8

3 0.0055 2,555,347 4,258.9

2 0.0037 10,063,306 16,772.2

1 0.0020 98,468,383 164,114.0

4,000 10 0.0194 25,991 43.3

7 0.0133 96,057 160.1

5 0.0093 345,826 576.4

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3 0.0055 2,080,859 3,468.1

2 0.0037 8,194,706 13,657.8

1 0.0020 80,184,333 133,640.6

5,000 10 0.0194 20,308 33.8

7 0.0133 75,056 125.1

5 0.0093 270,218 450.4

3 0.0055 1,625,920 2,709.9

2 0.0037 6,403,095 10,671.8

1 0.0020 62,653,610 104,422.7

187 1,000 10 0.0184 52,210 87.0

7 0.0133 162,783 271.3

5 0.0091 617,853 1,029.8

3 0.0062 2,363,318 3,938.9

2 0.0039 12,484,349 20,807.2

1 0.0019 144,376,118 240,626.9

2,000 10 0.0184 45,255 75.4

7 0.0133 141,097 235.2

5 0.0091 535,541 892.6

3 0.0062 2,048,470 3,414.1

2 0.0039 10,821,148 18,035.2

1 0.0019 125,141,909 208,569.8

3,000 10 0.0184 38,119 63.5

7 0.0133 118,847 198.1

5 0.0091 451,092 751.8

3 0.0062 1,725,448 2,875.7

2 0.0039 9,114,767 15,191.3

1 0.0019 105,408,356 175,680.6

4,000 10 0.0184 31,041 51.7

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7 0.0133 96,779 161.3

5 0.0091 367,331 612.2

3 0.0062 1,405,059 2,341.8

2 0.0039 7,422,297 12,370.5

1 0.0019 85,835,661 143,059.4

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5,000 10 0.0184 24,254 40.4

7 0.0133 75,620 126.0

5 0.0091 287,021 478.4

3 0.0062 1,097,870 1,829.8

2 0.0039 5,799,558 9,665.9

1 0.0019 67,069,386 111,782.3

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9870 Pozos Lane

Conroe, Texas 77303-2178

Phone: (936) 521-2200

Fax: (936) 521-2275

Email: [email protected]

Coiled Tubing Modeling Inputs, Theory, and Validation

Project No. 08121-1502-01

“Coiled Tubing Drilling and Intervention System from a Cost Effective Vessel”

This document provides an overview of software modeling inputs, theory, and selected validation references for the coiled tubing job modeling software that was utilized in this project. The modeling performed in this project is focused on three main areas: coiled tubing fatigue life calculations, force calculations acting on the coiled tubing, and hydraulics modeling of fluid being pumped down the coiled tubing and returned up the annulus.

1. Fatigue Modeling Inputs

The following inputs are used to model the fatigue life of the coiled tubing:

• Initial fatigue life • CT diameter • CT wall thickness • Location and types of welds • Bending radii (reel diameter and guide arch radius) • Pressure inside CT • Material properties • Number of bending events

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2. Fatigue Modeling Theory

A metallic object subjected to alternating, dynamic stresses above a threshold level can endure progressive changes to its atomic structure with each cycle of loading. This phenomenon, known as fatigue, is associated with cyclic plasticity that causes systematic changes to th e crystalline structure of the metal, resulting in the development of m icroscopic cracks. These tiny cracks propagate incrementally with each cycle, growing in size and l inking to form large cracks that propagate to fracture. The number of cycles required for the crack to nucleate and propagate to failure is referred to as the "fatigue life" of the object.

There is some debate about whether microscopic cracks form and then propagate, or simply propagate from microscopic sizes associated with surface anomalies. However, from an engineering analysis point of view, each cycle of loading is considered to consume some portion of the available fatigue life and adds to a summation of "accumulated fatigue damage." When this quantity accumulates to 100 percent, failure is expected to occur. Estimating the working life (bending cycles or trips) remaining to failure for a CT string is an important part of designing a CT operation.

For the v ast majority of m echanical design problems, the magnitude of c yclic stress in components subject to fatigue is within the elastic limit. This is the portion of the schematic stress-strain curve in Figure 1 labeled "Elastic Region."

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Figure 1 – Elastic vs. Plastic Strain

In such cases, one can estimate the fatigue life of a component from destructive fatigue tests on the material in the component. Non-destructive fatigue tests do not exist. The tests measure the number of cycles to failure at a given stress for the subject material. Since the number of cycles to failure for elastic deformations is extremely high, this fatigue regime is “high cycle fatigue.” Fatigue failure for helicopter blades is in this regime.

If the forces acting on an object cause a combination of alternating high elastic and low plastic stresses, the fatigue regime is “low cycle fatigue.” Fatigue failure in automobile frames is typically in this regime.

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If the reversed stresses are always beyond the elastic limit, an object experiences reversing plastic deformations. This is the portion of the stress-strain curve in Figure 1 labeled “Plastic Region.” Plastic fatigue is a complex and poorly understood problem. However, an object subjected to reversing plastic deformations fails after relatively few cycles. This fatigue failure regime, called ultra-low cycle fatigue, applies to CT.

CT begins its life plastically deformed, because it is wound on a reel. Moreover, each round trip into the well and back plastically deforms (bends) the tubing six times. These bending events are:

1. RIH – unwind and straighten from the reel

2. RIH – bend across the guide arch

3. RIH – straighten in the injector

4. POOH – bend onto the guide arch

5. POOH – straighten from the guide arch

6. POOH - wind back onto the reel

As Figure 2 shows, two-thirds of the bending cycles a CT segment experiences during a round trip are due to the guide arch. This does not mean that two-thirds of the fatigue damage occurs at the guide arch, but it does point to a feature of the surface equipment that can be modified to prolong the working life of a CT string. Note that all of the fatigue damage occurs in the surface equipment; none occurs in the well.

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Figure 2 – Locations of CT Plastic Deformations

The magnitude of plastic deformation with each bending cycle depends on the bending radius, CT dimensions, and m aterial yield strength. Thus, the r adius of the gui de arch and the diameter of the reel have a profound effect on CT fatigue life. Internal pressure during plastic defor-mation amplifies the fatigue damage. In order to es timate the accumulated fatigue damage for a segment of CT, one must know the number of bending cycles and magnitude of plastic deformation and pressure at each cycle.

The CT industry has three different fatigue models to determine the w orking life of CT. These models were developed by:

•Steve Tipton of the University of Tulsa

•Vladamir Avakov of Halliburton

•Nowsco (BJ, now part of Baker Hughes)

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NOV CTES uses Tipton’s model in the Cerberus™ software; Schlumberger uses Tipton’s model for CoilLIFE™ Tubing Analysis Software by Medco; and Maurer Engineering software uses Avakov’s model. The Nowsco model is proprietary to BJ (now part of Baker Hughes).

Advanced fatigue modeling software divides a C T string into manageable segments and applies the fatigue model to each segment in order to determine the distribution of fatigue along the string. Based on the ge ometry of t he surface equipment, the l ocation of the s egment in the CT string, and t he current CT depth, the m odel tracks the po sition of ea ch segment relative to the bending locations. The software activates the fatigue model whenever the segment is between the reel and the stripper and increments the fatigue damage to the segment. Figure 3 below displays a schematic of a fatigue model in operation; the information describing the geometry of the surface equipment is entered into the program.

Figure 3 – Model Segment Tracking

3. Fatigue Model Validation

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Numerous technical papers validate the model predictions for coiled tubing fatigue life; a list of pertinent papers is presented below.

• Tipton, S.M., "The Achilles Fatigue Model," CTES Tech Note, May, 1999.

• Tipton, S.M., "Low-Cycle Fatigue Testing of Tubular Material using Non-Standard

Specimens," Effects of P roduct Quality and D esign Criteria on S tructural Integrity, ASTM STP 1337, R. C. Rice and D. E. Tritsch, Eds., American Society for Testing and Materials, 1998.

• Avakov, V.A., Foster, J.C., and Smith, E.J. “Coiled Tubing Life Prediction”, OTC 7325, 25th Annual Offshore Technology Conference, Houston, May 1993.

• Tipton, S.M. and N ewburn, D.A., .Plasticity and Fatigue Damage Modeling of S everely Loaded Tubing," Advances in Fatigue Lifetime Predictive Techniques, STP 1122, American Society for Testing and Materials, 1992, pp. 369-382.

• Tipton, S.M., .Multiaxial Plasticity and Fatigue Life Prediction in Coiled Tubing," Fatigue Lifetime Predictive Techniques, 3rd Volume, ASTM STP 1292, M.R. Mitchell and R .W. Landgraf, Eds., American Society for Testing and M aterials, Philadelphia, 1995, pp. 28 3-304.

• Tipton, S.M., .Low-Cycle Fatigue Testing of Tubul ar Material using Non-Standard Specimens,. Effects of Product Quality and D esign Criteria on S tructural Integrity, ASTM STP 1337, R. C. Rice and D. E. Tritsch, Eds., American Society for Testing and Materials, 1998.

• Garud, Y.S., Multiaxial Fatigue of Metals, Ph.D., Dissertation, Stanford University, Stanford, California, 1981.

• Tipton, S.M., Fatigue Behavior under Multiaxial Loading in the P resence of a N otch: Methodologies for the Prediction of Life to Crack Initiation and Life Spent in Crack Propagation,. Ph.D. Dissertation, Stanford University, Stanford, California, 1985.

• Kapp, J.A. and Stacey, A., .Analysis of a N otched Four Point Bending Sample Containing Various Residual Stresses,. Analytical and E xperimental Methods for Residual Stress Effects in Fatigue, ASTM STP 1004, R.L. Champour, J.H. Underwood and J.A. Kapp, Eds., American Society for Testing and Materials, Philadelphia, 1988, pp. 65-81.

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4. Forces Modeling Inputs

The following inputs are used to model the various ‘forces’ acting on the coiled tubing:

• Coiled tubing dimensions (OD and ID) and properties • BHA dimensions and properties • Well geometry • Well friction coefficients (µ) • Well temperature profile • Well surveys • Fluid density and rheological properties inside the coiled tubing • Fluid density and rheological properties in annulus • Coil tubing speed (for fluid drag calculations) • Anticipated wellhead pressure • Pump rate and flow path • Well production rate (if applicable) • Stripper/packoff friction • Coiled tubing reel back tension (RBT) •

5. Forces Modeling Theory

Orpheus is a tubing forces model (TFM) written specifically for coiled tubing. The basic TFM calculation is performed by calculating the forces along the length of a coiled tubing string at a specific depth in a well, as the string is being either run into the hole (RIH) or being pulled out of the hole (POOH). This calculation is performed beginning at the downhole end of the coiled tubing string and calculating the forces on each segment of the string, progressing up the string to the surface.

The basic TFM calculation is performed by summing the forces on each segment as discussed above. This is performed with the end of the coiled tubing string at a specified depth. The basic calculation is explained by using a simple example in which a coiled tubing segment is located in a straight, inclined section of a well without fluids or pressures, shown in Figure 4. As is discussed later, the length of the segment can vary from a few feet to the entire length of the well, depending on variations in well geometry and coiled tubing geometry.

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Figure 4 – CT Segment in a straight, inclined section of a well

The vector triangle in Figure 4 illustrates how a weight segment (WS) can be broken into two component forces. FA is the force component in the axial direction (along the axis of the hole). FN is the force component in the normal direction (normal or perpendicular to the axis of the hole). The equations for each of these components are:

The friction force is calculated by multiplying the normal weight component by the friction coefficient µ.

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The real axial force is found by summing the weight component in the axial direction, FA, with the friction caused by the normal component of the weight, FN. Note that the axial component of the weight causes FR to be in tension, which is defined as a positive force. However, the sign of the friction force depends on the direction of motion. When RIH, the friction causes a compressive (negative) force to be added to FR. During POOH operations, the friction causes a tensile (positive) force to be added to FR.

This is the basic calculation for one segment of the coiled tubing. Summing the results from a series of segments from the bottom of the coiled tubing string to the surface yields the axial force acting on the coiled tubing in the well along its length. This force versus length profile is calculated by Orpheus when the “run at depth” function is executed. The calculation for tripping the coiled tubing string in and out of the hole simply repeats the “run at depth” TFM calculation above for many specified depths, stepping the coiled tubing string into and out of the well.

The amount of data calculated during tripping is more than can be easily displayed. Thus, only the forces at surface, commonly known as the “Weight”, are displayed when the “trip in and out” function is used in Orpheus. Each of these values is the result of a TFM calculation along the entire length of the string in the well.

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6. Forces Model Validation

Numerous technical papers validate the model predictions for coiled tubing forces; a list of pertinent papers is presented below.

• Van Adrichem, W. and Newman, K,R.: “Validation of Coiled Tubing Penetration Predictions in Horizontal Wells”, JPT (Feb 1993) 155-159

• Bhalla, K., “Implementing Residual Bend in a Tubing Forces Model” SPE 28303, 69th ATCE, New Orleans, September 1994.

• Chen Y.C. ‘Post Buckling Behavior of a C ircular Rod Constrained within an Inclined Hole”, Master’s Thesis, Rice University, (September 1987).

• Bhalla, K., Walton, I.C., “The Effect of Fl uid Flow on C oiled Tubing Reach”, SPE 36464, 71st ATCE, Denver, October 1996.

• Lubinski, A. Althouse, W., Logan, J., “Helical Buckling of Tubing Sealed in Packers”, Journal of Petroleum Technology, June 1956, 655-670, AIME, 225.

7. Hydraulics Modeling Inputs

The inputs to the hydraulics modeling related to coiled tubing operations include:

• Coiled tubing dimensions (OD and ID) • Coiled tubing depth • BHA dimensions • Nozzle sizes • Well geometry • Well temperature profile • Reel dimensions • Fluid density and rheological properties inside the coiled tubing • Fluid density and rheological properties in the annulus • Pump rate • Anticipated wellhead pressure

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8. Hydraulics Modeling Theory

In order to accurately predict the system pressures in any coiled tubing operation, all the fluid mechanics aspects and parameters must be taken into careful consideration during the mathematical development of a wellbore hydraulics model for coiled tubing applications.

System pressures can be estimated by appropriately accounting for the total pressure losses (∆P) in the coiled tubing and annulus. In general, the total pressure loss is comprised of three components:

• hydrostatic pressure loss (∆Ph), • friction pressure loss (∆Pf), and • acceleration pressure loss (∆Pa).

The magnitude of each of these components is largely affected by fluid properties such as density and viscosity, and the total pressure loss can be accurately predicted only if the fluid properties are evaluated correctly. Moreover, the frictional component of the coiled tubing pressure loss can be further subdivided into two parts: a part that accounts for the friction pressure loss on the reel (ΔPCT) before entering the well, and a part that accounts for the straight tubing losses (ΔPST) in the well.

Experiments have shown that, in general, coiled tubing pressure losses are greater than the corresponding straight tubing pressure losses, and therefore must be accounted for appropriately while determining the total system pressure losses (see validation section below for references to further information).

9. Hydraulics Model Validation

Numerous technical papers validate the model predictions for fluid flow in coiled tubing and pipe; a list of pertinent papers is presented below.

• McCann, R.C. and Is las, C.G.: “Frictional Pressure Loss during Turbulent Flow in Coiled Tubing”, SPE 36345 pr esented at the 1996 S PE/ICoTA North American Coiled Tubing Roundtable, Montgomery, TX (Feb. 26-28, 1996).

• McClain, C. H.: “Fluid Flow in Pipes”, The Industrial Press, New York (1952).

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• Berger, S.A., Talbot, L., and Yao, L.S.: “Flow in Curved Pipes”, Ann. Rev. Fluid Mech., 15 (1983), 461-512.

• Ito, H.: “Friction Factors for Turbulent Flow in Curved Pipes”, Trans. ASME, J. Basic Engg. (1959), 123-134.

• Azouz, I., Shah, S. N., Vinod, P. S., and Lord, D.L.: “Experimental Investigation of Frictional Pressure Losses in Coiled Tubing”, SPE Prod. And Facilities (May 1998), 91-96.

• Hanks, R. W. and P ratt, D. R.: “On the Fl ow of B ingham Plastic Slurries in Pipes and Between Parallel Plates”, Soc. Pet. Eng. J. (Dec 1967), 342-346.

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10. Nomenclature

The following abbreviations and nomenclature have been utilized in this document:

BHA bottom hole assembly

FA axial force component (lbs)

FN normal force component (lbs)

FR real force (lbs)

FF frictional force component (lbs)

ID inner diameter

OD outer diameter

POOH pull out of hole

ΔP pressure loss (lbf/ft2)

RIH run in hole

TFM tubing forces modeling

WS weight of the segment (lb/ft)

Θ well inclination (degrees)

µ friction coefficient (dimensionless)

task 9 coiled tubing intervention system component … · and this facilitates recovery from...

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