QFPIRA00LG9A6072B

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TFE - Matterhorn TC-006072 – B01 March 2004 Page 1 of 171

SUBSEA COMPLETION EQUIPMENT

OPERATION AND MAINTENANCE MANUAL

FOR

TOTALFINAELF

MATTERHORN PROJECT

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DISTRIBUTION LIST

FOR

TOTALFINAELF

MATTERHORN PROJECT

Trey Lynch Cameron

Ricky Coutee Cameron Service Department (2) Cameron WHE Library Cameron Rig Copy Cameron Customer (6 Copies) TFE

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AMENDMENT INSTRUCTIONS The Operation and Maintenance Manual contains general and technical information and should be used in conjunction with any associated Publication referred to in text. The book will, as far as is practicable, be kept to the latest standard by the issue of Amendment Instruction Sheets with amended pages. It is important that these are incorporated immediately upon receipt and that their incorporation is recorded in the Amendment Record (following page). Each bears either a page number or a page number and revision number at the bottom. The addition or deletion of technical matter introduced by amendment action will be indicated by the markers thus ⇒��.⇐ to show where the material has been changed (see note below). These markers will be removed when a subsequent amendment to the leaf is issued and additional markers inserted against the new or amended material. When a Section is issued in a completely revised form, the note �Completely Revised� will appear beneath the Section Title; in this case there will be no markers to indicate these changes. Note: In the event of a change to an illustration, the illustration will also be raised to the next

revision number, ie: A1 to B1 etc. When an amendment is incorporated, the Revision Number, Date, and Signature of the person incorporating the amendment is to be entered on the Amendment Record.

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AMENDMENT RECORD SHEET

Amendment Incorporated By Date

0 Karen Chan-Reumuth September 2002 1 Trey Lynch March 2004

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AMENDMENT INCORPORATED Revision History: Matterhorn Revision Date: March 2004 Amendment Number: 1

Section Page No. Rev. Level Revision Description

All Complete manuals will be provided.

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TABLE OF CONTENTS 1. INTRODUCTION .............................................................................................................. 9 1.1 Purpose................................................................................................................................ 9 1.2 Responsibilities ................................................................................................................... 9 1.3 Safety .................................................................................................................................. 9 2. SYSTEM OVERVIEW .................................................................................................... 10 2.1 Field Location ................................................................................................................... 10 2.2 Field Information .............................................................................................................. 10 2.3 System Description ........................................................................................................... 10 2.4 Well Data .......................................................................................................................... 11 3. SCOPE OF SUPPLY ........................................................................................................ 12 4. SUBSEA COMPLETION EQUIPMENT ........................................................................ 13 4.1 SpoolTree Assembly......................................................................................................... 13 4.1.1 Spool Body / Connector Sub-Assembly ........................................................................... 19 4.1.2 Tree Connector.................................................................................................................. 23 4.1.3 Top Plate / Mechanical Lockdown Assembly .................................................................. 27 4.1.4 Isolation Sleeve................................................................................................................. 30 4.1.5 Injection Valve Block Assembly ...................................................................................... 32 4.1.6 �CM� Actuators (Injection/Annulus)................................................................................ 34 4.1.7 �FLS� Gate Valves (Injection/Annulus)........................................................................... 38 4.1.8 ¾� Hydraulically Operated Gate Valve ............................................................................ 42 4.1.9 ½� 15,000 psi Needle Valves............................................................................................ 43 4.1.10 Tree Hydraulic Components � Flow Schematic ............................................................... 44 4.1.11 Transfer Barrier................................................................................................................. 47 4.2 Tubing Hanger .................................................................................................................. 49 4.3 Tubing Hanger Wireline Plug........................................................................................... 55 4.4 Internal Tree Cap .............................................................................................................. 57 4.5 Tree Debris Cap ................................................................................................................ 59 5. LIFTING REQUIREMENTS ........................................................................................... 61 6. INSTALLATION AND OPERATING PROCEDURES ................................................. 62 6.1 Introduction....................................................................................................................... 62 6.2 General Instructions .......................................................................................................... 63 6.2.1 Pressure Tests.................................................................................................................... 63 6.2.2 Corrective Action.............................................................................................................. 63 6.2.3 Procedural Changes .......................................................................................................... 63 6.2.4 ROV Valve Interfaces....................................................................................................... 64 6.3 Tree Installation ................................................................................................................ 65 6.3.1 Required Equipment ......................................................................................................... 65 6.3.2 Prepare the Tree for Testing on the Rig Prior to Installation............................................ 66 6.3.3 Prepare Bore Protector Running Tool (BPRT) for BP Installation .................................. 66 6.3.4 Prepare Bore Protector (BP) for Installation..................................................................... 67 6.3.5 Install Bore Protector in the Tree...................................................................................... 67 6.3.6 Prepare the TRT................................................................................................................ 69 6.3.7 Function Test of the TRT.................................................................................................. 70

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6.3.8 Prepare the Tree Test Skid................................................................................................ 71 6.3.9 Prepare the Tree ................................................................................................................ 71 6.3.10 Install the Tree on the Stump and Fill Tree ...................................................................... 71 6.3.11 Install the TRT on the Tree............................................................................................... 72 6.3.12 Lock the Tree Connector Onto the Test Stump ................................................................ 74 6.3.13 Prepare the Tree for Testing ............................................................................................. 74 6.4 Test the Tree Prior to Installation ..................................................................................... 75 6.4.1 Test the Working Pressure Integrity of the Tree/Stump Connection, Inboard GT Valve,

Isolation Sleeve External Test .......................................................................................... 76 6.4.2 Test the Outboard Side of the AWV, SCM, SV1, SV2 Valves ........................................ 77 6.4.3 Test the Outboard Side of AMV, AAV, and XOV Valves............................................... 78 6.4.4 Test the Inboard Side of the IWV and the Outboard Side of IMV................................... 79 6.4.5 Test the Inboard Side of the IMV, SCM, and SV2, Outside of the Bore Protector.......... 80 6.4.6 Test the Inboard Side of the SV1 and XOV Valves ......................................................... 81 6.4.7 Test the Inboard Side of the AWV Valve......................................................................... 82 6.4.8 Test the Inboard Side of the AAV, AMV, Bore Protector, and Isolation Sleeve ............. 83 6.4.9 Test the Outboard Side of the GT Valve .......................................................................... 84 6.5 Prepare the Tree for Running............................................................................................ 85 6.5.1 Unlock the Tree Connector............................................................................................... 85 6.5.2 Change Tree Gasket.......................................................................................................... 86 6.5.3 Prepare the Tree for installation........................................................................................ 86 6.5.4 Install Tree Guidance Stab (Stinger) and Make up TRT to Drill Pipe ............................. 86 6.5.5 Tree Installation Checklist ................................................................................................ 88 6.6 Run and Test the Tree ....................................................................................................... 90 6.6.1 Run the Tree...................................................................................................................... 90 6.6.2 Lock Tree to Wellhead...................................................................................................... 90 6.6.3 Test Tree/Wellhead Connection ....................................................................................... 92 6.6.4 Subsea Tree Testing.......................................................................................................... 93 6.6.5 Retrieve TRT and Umbilical............................................................................................. 94 6.7 BOP Stack Installation...................................................................................................... 96 6.7.1 Equipment Required ......................................................................................................... 96 6.7.2 Prepare the BOP for Running ........................................................................................... 96 6.7.3 Run BOP / IWOC Umbilical ............................................................................................ 96 6.7.4 Prepare and Run BOP Test Tool and Perform Stack Test ................................................ 97 6.7.5 Run IWOCS and Connect Hydraulic and Electrical Flying Leads to the Tree ................ 97 6.7.6 Subsea Tree Testing.......................................................................................................... 98 6.8 Complete Downhole Work per Operator Procedures ....................................................... 98 6.9 Bore Protector Retrieval ................................................................................................... 98 6.9.1 Equipment Required ......................................................................................................... 98 6.9.2 Prepare Bore Protector Running / Retrieval Tool............................................................. 98 6.9.3 Retrieve Bore Protector..................................................................................................... 98 6.10 Tubing Hanger Installation ............................................................................................... 99 6.10.1 Required Equipment ......................................................................................................... 99 6.10.2 Run Tubing per Operator Procedures ............................................................................. 100 6.10.3 Prepare the Tubing Hanger Running Assembly for Installation..................................... 100 6.10.4 Prepare the Tubing Hanger for Installation .................................................................... 102

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6.10.5 Make up Tubing Hanger to Tubing String...................................................................... 103 6.10.6 Install THRT and Make up Control Lines to Tubing Hanger......................................... 104 6.10.7 Run and Test the Tubing Hanger .................................................................................... 108 6.10.8 Retrieve THRT / SSTT ................................................................................................... 120 6.11 Internal Tree Cap (ITC) Installation ............................................................................... 121 6.11.2 Prepare Internal Tree Cap (ITC) ..................................................................................... 122 6.11.3 Prepare and Install THRT to ITC.................................................................................... 122 6.11.4 Run and Test the ITC...................................................................................................... 124 6.12 Disconnect IWOCS Umbilical from Tree....................................................................... 129 6.13 Retrieve BOP per Rig Procedures................................................................................... 129 6.14 Install Tree Debris Cap ................................................................................................... 130 6.14.1 Required Equipment ....................................................................................................... 130 6.14.2 Prepare Tree Debris Cap................................................................................................. 130 6.14.3 Run Debris Cap............................................................................................................... 130 6.15 Fill Out Subsea Completion Summary ........................................................................... 130 7. STACK-UP DRAWINGS .............................................................................................. 131 8. RETRIEVAL PROCEDURES ....................................................................................... 132 8.1 Retrieve Tree Debris Cap................................................................................................ 132 8.2 Run, Land, and Test BOP per Rig Procedures................................................................ 132 8.3 Internal Tree Cap Retrieval (ITC)................................................................................... 132 8.4 Retrieve the SSR Wireline Plug...................................................................................... 134 8.5 Retrieving the Tubing Hanger with the Hydraulic THRT.............................................. 134 8.6 Install the Bore Protector and Retrieve the BOP ............................................................ 136 8.7 Retrieve the Spool Tree .................................................................................................. 136 8.7.1 Prepare the TRT and Stinger........................................................................................... 136 8.7.2 Run the TRT and Retrieve the Tree................................................................................ 137 9. RUNNING TOOL AND TEST EQUIPMENT (RENTAL)........................................... 139 10. MAINTENANCE AND INSPECTION ......................................................................... 158 10.1 Introduction..................................................................................................................... 158 10.2 Oils and Lubricants ......................................................................................................... 159 10.3 Routine and/or Storage Maintenance.............................................................................. 159 10.4 Rubber Goods ................................................................................................................. 160 10.5 Tree Assembly ................................................................................................................ 160 10.5.1 General ............................................................................................................................ 160 10.5.2 Tree Connector Assembly............................................................................................... 161 10.5.3 Isolation Sleeve Assembly.............................................................................................. 163 10.5.4 Storage Procedures.......................................................................................................... 163 10.5.5 Periodic Maintenance...................................................................................................... 165 10.6 Tubing Hanger ................................................................................................................ 166 10.7 Internal Tree Cap ............................................................................................................ 167 10.8 Tree Debris Cap .............................................................................................................. 167 11. INTERFACE DRAWINGS............................................................................................ 168 12. SSR WIRELINE TOOLS/ACCESSORIES � PROCEDURES / DRAWINGS............. 169 13. RECOMMENDED SPARE PARTS LIST..................................................................... 170

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1. INTRODUCTION 1.1 Purpose

This manual provides the technical information required for installation and maintenance of the Cameron Subsea Production SpoolTree System for the Matterhorn project.

1.2 Responsibilities It is recommended that a qualified Cameron Service Technician be on site to supervise use.

1.3 Safety This manual is intended to provide complete instructions for safe maintenance, testing, operation, and installation of Cameron�s subsea tree equipment. All rig safety procedures and customer safety policies must be followed and, in general, shall supercede the HSE requirements of this manual. Where conflicts arise, it is appropriate to conduct a job hazard analysis (JHA) with all appropriate personnel to resolve any concerns before proceeding. Safe work practices must be followed during all aspects of equipment use. Work planning meetings should be conducted at appropriate intervals during the work and prior to any new or critical operations. The purpose is to have all personnel involved discuss the possible health, safety and environmental concerns for a particular operation. Suggested JHA meeting points have been identified in this manual and are flagged as: -JHA- .

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2. SYSTEM OVERVIEW 2.1 Field Location

The Matterhorn field is located in the Gulf of Mexico in block Mississippi Canyon 243 (MC243) in 2,810� of water, about 30 miles SW of the mouth of the Mississippi River and about 100 miles SW of New Orleans, Louisiana.

2.2 Field Information

The Matterhorn field is planned to be developed with a 9 slot dry tree floating structure located above the existing exploration well MC243#1. This dry tree structure may be a TLP or a Spar. The structure will not have any drilling capability (except for sidetracks) and all the wells will be predrilled and temporarily abandoned before platform installation. The wells will then be completed with a workover rig (750 HP) installed on the Matterhorn structure. The A6 well will be completed as a water injection well to provide pressure maintenance in support of production on the infield host facility. All the wells except A6 will be tied back to the platform as dry tree completions and will be drilled from a central location, currently planned to be the surface of the exploration well MC243#1. The A6 injector well for the �A� sand will be a subsea well. All wells (including the A6 water injector) will be predrilled with a semi-submersible drilling unit and T&A�d before platform arrival. The A6 well is expected to be the initial well in the drilling program.

2.3 System Description

The well is in approximately 2,900 feet of water and is to be drilled from a floating drilling rig using an 18-3/4� 10,000 psi wellhead system. A side valve or horizontal Christmas Tree will be used to complete the well. Installation of the tree will be diverless and guidelineless (GLL). Remote intervention of the tree during installation and workover will be by a Remotely Operated Vehicle (ROV) Water injection will be through a single flowline from a host facility approximately 5,100 feet from the well. The host facility will be either a Tension Leg Platform (TLP) or a Spar. A jumper will be used to connect the flowline to the tree by means of a vertical connection system that interfaces with a vertical hub installed on both the tree and the Pipeline End Termination (PLET).

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Control of the tree will be by means of a direct hydraulic control system. There will be a controls umbilical, supplied by others, terminated to a stab-and-hinge-over Umbilical Termination Assembly (UTA) that lands on the PLET. The UTA will be equipped with a hydraulic junction plate so that an ROV can connect the subsea tree to the UTA by means of a Hydraulic Flying Lead (HFL) hose bundle jumper. A separate Electrical Flying Lead (EFL) will be provided to tie in analogue transmitters mounted on the WI tree. ROV intervention may be used in the initial installation of flowlines and hydraulic and electric flying leads.

2.4 Well Data

Number of Wells 1 Water Depth 2,900 feet Injection Fluid De-Oxgenated treated Seawater Chlorine 1 ppm Shut in Wellhead Pressure <3,000 psi Injection Pressure <3,000 psi Injection Rate 23,000 BBL/D Materials for pressure containing and controlling equipment conform to the requirements of API 6A Product Specification Level PSL-2.

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3. SCOPE OF SUPPLY

Scope of Supply Drawing � SD-030482-01 General Arrangement Drawing - SD-030318-01 Simplified Flow Schematic � SD-031141-01

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4. SUBSEA COMPLETION EQUIPMENT

4.1 SpoolTree Assembly

The tree is a 5� - 10,000 psi Cameron second-generation spool tree supplied in the following configuration:

• Water Injection Tree � designed to interface with FMC H4 profile wellhead, isolation sleeve designed to seal in the 10-3/4� casing hanger.

The tree is designed to meet the requirements of Product Specification Level (PSL) 2, Material Class EE, Temperature Rating V. The tree is controlled by direct hydraulic power through a tree-mounted hydraulic junction plate. All 5� and 2� injection and annulus valves have the standard Cameron FLS cavity design with CM actuators rated for 3,280� water depth. Hydraulically operated ¾� gate valves are used for chemical injection and annulus wing valves. The two SCSSV hydraulic supply, gasket test, and seal cavity monitor lines are isolated by ½� � 15,000 psi ROV operated needle valves. All tree valves have the provision for ROV override. Interface details are given in Section 6. The tree is run guidelineless on drill pipe using the Tree Running Tool (TRT), which is latched to an internal profile in the top of the spool body. As the tree lands on the wellhead, the isolation sleeve, attached to the bottom of the spool body, is stabbed into the casing hanger in the wellhead housing, isolating the AX/VX gasket and the wellhead hanger assembly. After the tree has landed, the TRT is used to lock the wellhead connector and set the gasket. Injection flow is monitored by one pressure transducer located upstream of the injection master valve. The annulus is monitored by a single pressure transducer located downstream of the annulus master valve.

A vertical hub and receiver structure is provided for diverless connection of the flowline jumper using the CVC jumper system. Information on the flowline connector system is contained in a separate manual. The structural capacity of the top profile of the tree spool (H4 mandrel) is shown on the next page.

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The locking force applied to the actuator ring is translated into a preload between the spool body and connector faces. As the locking force increases, the preload increases. The capacity of a connector is dependent on a large number of parameters. Most of these are obvious, such as the strength and size of the component parts. Because of the complexity of the connectors, there are also a number of factors that are not quite as intuitive. The VETCO SHD connector has a reported preload of 3,750,000 lbf. Using the parameters from the analysis using a Cameron 18-3/4� 10 ksi DWH connector and increasing the preload of 3,750,000 lbf, an additional set of calculations were made to determine how this effects the Cameron connection system. All other factors were the same. The results are in Figure 7A.

Bending Capacity for the 18-3/4" 10 ksi Spool Top with H4 Profile and Connected to Dog and

Window Connector

0

2

4

6

8

10

2 3 4 5 6

Bending Moment, million ft-lbf

Bor

e Pr

essu

re, k

si

T=1E6 lbf

T=2E6 lbf

T=0

Figure 7

T=3E6 lbfT=4E6 lbf

SB1

SB4

SB1

SB6

SB4

SB4

SB2SB1SB1

SB6SB6SB6SB6

SB6SB4SB6SB6

SB6SB4SB4

SB6 SB6 SB6SB6

SB1: spool body path 1, m, mdSB2: spool body path 2, m, mdSB4: spool body path 4, m+b, odSB6: spool body path 6, m, md

Bending Capacity for the 18-3/4" 10 ksi Spool Top with H4 Profile and Connected to Cameron Dog and Window Connector with 3.75M lbf of preload

0

2

4

6

8

10

2 3 4 5 6


Bor

e Pr

essu

re, k

si

T=0E6 lbf

SB1

SB1

SB1: spool body path 1, m, mdSB4: spool body path 4, m+b, odSB6: spool body path 6, m, md

SB6

SB4

SB4

T=1E6 lbf

SB1

SB1

SB4

SB6

SB6

SB1

SB1

SB4

SB6

SB4

T=2E6 lbf

Figure 7A

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Description: CONVERSION ASSEMBLY - 5” X 2”-10M SPOOLTREE (CHOKE REMOVED) Part No.: 2216524-02 P/N Revision: 02 Drawing No.: SK-039745-02 ITEM QTY. PART NO. DESCRIPTION

1 1 CM-004185-01 CUSTOMER SUPPLIED, G2 SPOOLTREE, TFE 2 1 2236700-01 INJECTION FLOWLOOP, 6" OD X 4" ID PIPE; 3 1 2236730-01 ROV PANEL COVER PLATE, MATTERHORN PROJEC 4 1 2147049-02 FLANGE, BLIND, 1/2"-10M W/BX-151 5 4 219066-10-04-31 STUD, DBL ENDED 1.000- 8UNC-2A X 6 1 702003-15-14 RING GASKET, API TYPE BX-151, 316 SST 7 2 702003-16-94 RING GASKET, API TYPE BX-169 8 1 2235488-03 EXTENDED HYDRAULIC PIPING AND COMPONENTS 10 1 702003-15-54 RING GASKET, API TYPE BX-155

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Description: 5” X 2”-10M SPOOLTREE ASSEMBLY (WITH CHOKE) Part No.: 2216524-01 P/N Revision: 01 Drawing No.: SK-039745-01 ITEM QTY. PART NO. DESCRIPTION

0 1 2148860-59 17D PRODUCT DOCUMENTATION PACKAGE 0 1 2148860-60 17D PRODUCT DOCUMENTATION PACKAGE 0 1 610470-65 PRODUCT DOCUMENTATION PACKAGE FOR 0 1 2216533-01 TEST FLANGE, 5-1/8" 10K BX-169 0 1 2216875-01 CONVERSION KIT, TREE RUNNING TOOL 1 1 2216538-01 SUB ASS'Y, SPOOL/CONN./LDG. RING 2 1 2054403-14-02 ASSEMBLY: INJ. WING VALVE BLOCK 3 1 2205459-02-01 ASSY, ADAPTOR FLANGE, 1-13/16"-10K 4 1 2221387-01 INJECTION SPOOL, 6" CVC HUB & 5" 5 1 2216535-01 CROSSOVER FLOWLOOP, 3.50 OD X 2.00 6 1 2216526-01 ASS'Y, TOP PLATE & MECHANICAL LOCK- 7 1 2216537-01 TREE FRAME, INTEGRAL SPOOLBODY, TFE 8 1 2054339-01 SPECIAL GASKET, CIW (SYMMETRIC) 9 1 2221383-01 CHOKE FRAME REWORK, FROM CM-4090-01 10 1 CM-004091-01 CUSTOMER SUPPLIED, CHOKE ALIGNMENT 11 1 2206378-02 3/4" 10K CHEMICAL INJECTION VALVE, 12 2 2027919-02 ALIGNMENT DOG, SPOOL ASSEMBLY 13 1 2216682-01 RECEIVER STRUCTURE, 6" HUB 14 1 2156674-01 WELDMENT, ADAPTER, DWH- H4 FUNNEL- 15 1 CM-004089-01 CUSTOMER SUPPLIED, CHOKE ASSEMBLY, 16 1 2182409-05 CHANNEL F/ MOUNTING ROV PANELS, 17 1 2216847-01 ASSY, ROV PANEL, ANNULUS SIDE, AWV, 18 1 2216849-01 ASSY, ROV PANEL, MIDDLE, SCM, SV1, 19 1 2216851-01 ASSY, ROV HOT STAB PANEL, GT & GR 20 1 2216845-01 ASSY, ROV PANEL, PRODUCTION SIDE, 21 1 2182409-04 BUMPER F/ PROTECTING TRANSDUCERS & 22 1 2055284-05-02 ASSY, BLOCK ELBOW, 5-1/8" API 10K 23 1 2156428-01 PIN, PMT ALIGNMENT 24 1 2206378-01 3/4" 10K CHEMICAL INJECTION VALVE 25 6 2182487-03 WELDMENT, STEM EXTENSION F/ ELECT. 26 6 2155974-04 BOLT, SUPER DUPLEX, .312-18 UNC X 27 6 2709000-02-01 NUT, HVY HEX .312-18 GR 2H ZN PL 28 6 038710-09 SCREW, SOC HD SET .250-20 X .375 29 6 2748429-01 CABLE ASSY., .09 DIA. CABLE W/ EYE 30 12 702511-13-00-06 SCREW, HEX HD MCH #10-24 X .375

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ITEM QTY. PART NO. DESCRIPTION 31 1 2216677-01 HYDRAULIC PIPING SCHEMATIC, 5"-10K 32 1 2147049-02 FLANGE, BLIND, 1/2"-10M W/BX-151 33 4 219066-10-04-31 STUD, DBL ENDED 1.000- 8UNC-2A X 34 2 2201010-03 BLIND FLANGE, 2-1/16" API 10,000 35 12 702586-19-00-27 SCREW, HEX HD CAP 1.000-8 X 2.875 36 2 676641-42 PIN,STRAIGHT KNURL 1.250/1.248 OD X 37 12 2182398-01 WASHER, VERTICAL HUB RECEIVER 38 12 702586-19-00-40 SCR 1.000-08 X 4.000 B7 ZNPL HEX HD CAP 39 42 2709000-10-01 NUT, HVY HEX 1.000-8 GR 2H ZN PL 40 14 702586-19-00-34 SCREW, HEX HD CAP 1.000-8 X 3.500 41 28 702528-24-02 WASHER, 1.00 FLAT TYPE A STL ZN PL 42 1 2141627-01 ASSY, TRANSFER BARRIER 43 1 2142889-01 MANIFOLD, HYDRAULIC BALANCE, 44 2 702586-16-00-54 SCREW, HEX HD CAP .750-10 X 5.500 45 14 2709000-08-01 NUT, HVY HEX .750-10 GR 2H ZN PL 46 1 CM-004088-01 CUSTOMER SUPPLIED, TREE-MOUNTED 47 2 702585-19-00-26 SCR 1.000-08 X 2.750 B7 ZNPL 12 PT CAP 48 12 702586-22-00-56 SCREW, HEX HD CAP 1.125-8 X 5.750 49 36 2709000-11-01 NUT, HVY HEX 1.125-8 GR 2H ZN PL 50 8 681727-09-00-86 STUD, CONT THD, 1.250-8 X 8.75 STL 51 16 2709000-12-01 NUT, HVY HEX 1.250-8 GR 2H ZN PL 52 1 2182409-06 CHANNEL F/ MOUNTING ROV PANELS, 53 1 2216913-01 WELDMENT, POSITION INDICATOR FOR 54 1 CM-004078-01 CUSTOMER SUPPLIED, TREE-MOUNTED HYD 55 8 702586-16-00-32 SCREW, HEX HD CAP .750-10 X 3.250 56 1 CM-004077-01 CUSTOMER SUPPLIED, PRESSURE SENSOR 57 4 702533-01-10-30 STUD, CONT THD .250-20 X 3.000 58 8 2709000-01-01 NUT, HVY HEX .250-20 GR 2H ZN PL 59 1 2221218-01 PLATE, F/ PROTECTING HYD. TUBING, 60 4 702586-16-00-24 SCR 0.750-10 X 2.500 B7 ZNPL HEX HD CAP 61 8 702528-20-02 WASHER, .750 FLAT TYPE A STL ZN PL 62 1 2221279-01 COUNTERWEIGHT BASE 63 4 2221279-02 COUNTERWEIGHT, 88.0 X 37.0 X 2.0 64 4 2182842-02 RETAINER PLATE, COUNTERWEIGHT, 65 4 702533-09-12-20 STUD, CONT THD 1.000-8 X22.000 66 4 702533-09-12-40 STUD, CONT THD 1.000-8 X 24.000 67 5 702003-16-94 RING GASKET, API TYPE BX-169 68 6 702003-15-24 RING GASKET, API TYPE BX-152 69 3 702003-15-14 RING GASKET, API TYPE BX-151, 316 SST 70 1 2013400-54 NAMEPLATE FOR SUBSEA GATE VALVE, 71 1 2013400-56-01 NAMEPLATE FOR GATE VALVES, API 6A 72 6 705786 SCR # 4 X 0.250 18-8 DR RND HD TYPE U

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ITEM QTY. PART NO. DESCRIPTION 73 30 713837 GREASE, 0 TO 350 DEGREES (1 #CAN) 74 3 702003-15-54 RING GASKET, API TYPE BX-155 75 1 2221378-01 ASS'Y, ELBOW, 5-1/8" 10K STUDDED X 76 1 2221380-01 FLOWLOOP, CVC HUB TO CHOKE, 6" OD X 77 1 2221382-01 FLOWLOOP, CHOKE TO TREE ELBOW BLOCK 78 24 702586-22-00-36 SCREW, HEX HD CAP 1.125-8 X 3.750 79 4 702586-19-00-16 SCR 1.000-08 X 1.750 B7 ZN HEX HD CAP 80 8 219070-11-08-51 STUD, DBL ENDED 1.125-8UN-2A X 81 16 2709000-11-11 NUT, HVY HEX 1.125-8 GR 2HM ZN PL 82 1 2221381-01 COUNTERWEIGHT BASE, FRONT SIDE 83 2 2221381-02 COUNTERWEIGHT, FRONT SIDE, 2" THK 84 1 2221381-03 COUNTERWEIGHT, FRONT SIDE 1" THK 85 1 2221381-04 COUNTERWEIGHT, FRONT LEFT, SMALL 2" 95 9 2182419-01 SHIM .031" THICK, G2 TREE FRAME 96 6 2182419-02 SHIM .062" THICK, G2 TREE FRAME 97 6 2182419-03 SHIM .125" THICK, G2 TREE FRAME 98 8 2055673-09 SHIM, TOP PLATE, DIM 'T' = .079 (2. 99 8 2055673-10 SHIM, TOP PLATE, DIM 'T' = .060 +/- 100 4 2055673-12 SHIM, TOP PLATE, DIM 'T' = .236 (6.

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4.1.1 Spool Body / Connector Sub-Assembly

The spool body is rated to 10,000 psi and seals directly to the wellhead housing using an AX/VX gasket. The top of the spool has an 18-3/4� 10,000 psi H4 mandrel wellhead profile with a VX gasket prep. The bottom of the spool body contains internal preparations for mounting the isolation sleeve and four gasket retainer assemblies for the wellhead gasket. The OD of the body contains an acme thread for attachment of the wellhead connector. The injection master, annulus master and annulus access valves are �integral� to the spool body. The injection valve is 5-1/8� 10,000 psi and the annulus valves are 2-1/16� 10,000 psi designated as IMV, AMV, and AAV on the tree panels. All actuator spring chambers have been filled with Marston Bentley HW-525 control fluid and plumbed to a transfer barrier accumulator. The injection wing valve block and adapter flange (annulus block) are bolted to the tree spool body side outlets studded with BX type ring grooves. The spool has two hydraulic outlets for down hole fluid communication (2x SCSSV�s). The spool also incorporates a seal cavity monitor port and gasket test port. All spool outlets are studded with BX type ring grooves. Shoulders and grooves inside the tree body provide the landing and the locking profiles for the tubing hanger and the internal cap. The tubing hanger landing shoulder is specially ported to accept the tubing hanger control stabs and acts as a manifold which provides hydraulic continuity between the production control system and downhole hydraulics for the SCSSV�s.

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Description: SPOOLTREE SUB-ASSEMBLY Part No.: 2216538-01 P/N Revision: C01 Drawing No.: SK-039707-01 ITEM QTY. PART NO. DESCRIPTION

1 1 2216528-01 SPOOLBODY, FIN. MACH., INTEGRAL 2 1 2142406-02 LANDING RING, INTERNAL PRESSURE 3 1 2155843-10-01 LANDING RING, 2 PORTS (B AND C), G2 4 2 2155109-01 PIN, DOWEL, .742 DIA X 1.75 LG, 5 2 2748248-01 METAL FACE SEAL TO FIT .782 DIA X 6 2 702647-11-95 O RING, SIZE AS-568-119 .924 ID X 7 6 2142768-01 CAP SCREW, SPECIAL HEX HEAD, 11/16- 8 4 2055205-02 AX GASKET RETAINER MECHANISM 9 1 2142774-01 ORIENTATION KEY, SPOOL BODY, G2 10 1 702585-12-00-20 SCR 0.562-12 X 2.000 GR B7 ZN 12 PT CAP 11 1 2097932-02-02 ASSY, DWH CONNECTOR, 18 3/4- 10000 12 2 2156678-01 ASSY, ACTUATOR ROD (LOCKING) 13 1 2142119-02 RETAINING RING, SPOOL BODY, W/ LOAD 14 4 2055535-01 ISOLATION NEEDLE VALVE (MONO BLOCK) 15 1 2096075-05-04 SUB-ASSY: 5-1/8"-10K "FLS" VALVE 16 8 2709000-18-41 NUT, HVY HEX 2.000-8 17 4 219070-18-24-01 STUD, DBL ENDED 2.000-8UN-2A X 18 16 219066-10-08-61 STUD, DBL ENDED 1.000- 8UNC-2A X 19 8 219066-08-03-61 STUD, DBL ENDED .750-10UNC-2A X 20 8 2709000-08-11 NUT, HVY HEX .750-10 GR 2HM ZN PL 21 16 2709000-10-11 NUT, HVY HEX 1.000-8 GR 2HM ZN PL 22 16 219065-12-04-41 STUD, DBL ENDED 1.250-8UN-2A X 23 16 2709000-12-01 NUT, HVY HEX 1.250-8 GR 2H ZN PL 24 2 021816-28 DOWEL PIN 1.500/1.495 OD X 3-3/4 LG 26 4 2748080-01 PLUG ASSY, PIN EXPANDABLE FOR .281 27 1 2013400-31 NAMEPLATE FOR SUBSEA GATE VALVE, 28 4 705786 SCR # 4 X 0.250 18-8 DR RND HD TYPE U 29 4 219070-18-12-41 STUD, DBL ENDED 2.000-8UN-2A X 30 4 702515-25-10-12 SCR 0.500-13 X 0.750 SOC HD SET FLAT PT 31 2 2096165-11-02 VALVE CAVITY PARTS, 2.1/16" 10K 32 4 702003-15-14 RING GASKET, API TYPE BX-151, 316 SST 33 2 2054339-01 SPECIAL GASKET, CIW (SYMMETRIC) 34 1 2216531-01 ASSY, ISOLATION SLEEVE VERSION B, 40 1 2748117-01 TOOL, INSTALLATION, FOR LEE PLUG, 41 1 2096051-06 ASSY, 5-1/8 10,000 CM ACTUATOR VE 42 2 2096105-11 ASSY, 2-1/16 5,000 & 10,000 CM 60 2 2012749-01 TEST CAP, 2-1/16 5,000 FLS GV, PREP

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ITEM QTY. PART NO. DESCRIPTION 61 1 2147149-02 TEST CAP, 5-1/8 10,000 FLS GV, 99 1 2734021-01 LUBRICANT, HIGH VISCOSITY SILICONE

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Description: AX GASKET RETAINER MECHANISM Part No.: 2055205-02 P/N Revision: A02 Drawing No.: SK-097464-02 ITEM QTY. PART NO. DESCRIPTION

1 1 2055766-01 INSERT BODY,`AX' GASKET RETAINER 2 1 2055202-01 SLEEVE FOR HYDRAULIC AX GASKET 3 1 2055203-01 PISTON FOR HYDRAULIC AX GASKET 4 1 040310-01-67 SPRING, COMPRESSION, 0.093 DIA 5 2 702645-12-54 O RING, SIZE AS-568-125 1.299 ID 6 1 702645-11-74 O RING, SIZE AS-568-117 .799 ID 7 1 702645-11-04 O RING, SIZE AS-568-110 .362 ID 8 1 702645-11-34 O RING, SIZE AS-568-113 .549 ID

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4.1.2 Tree Connector

The wellhead connector is a Cameron �dog and window� style mechanical connector capable of providing approximately 3.2 million pounds of preload when operated by the TRT. The connector's actuator rod design incorporates two passive secondary lock assemblies, which during testing showed a capacity of 19 kips. See Section 4.1.3 for secondary lock assembly drawings.

This connector uses a 4 degree friction locking taper which requires a co-efficient of friction greater than .07. The use of the secondary locks assures an allowable friction co-efficient of .066. Prior to running the tree, each connector is tested to ensure a minimum coefficient of friction of .10. The connector incorporates four hydraulically operated gasket retainers located in the spool body. The gasket is released by pressurization when using the hot stab designated �GR� on the tree's ROV panel (smaller diameter on hot stab). Supplying chemical injection to the connector as well as applying pressure to help retract the connector dogs as a secondary release feature can also be done through the larger diameter port on the �GT� hot stab receptacle. The connector body contains a female acme thread for attachment to the spool tree body. The structural capacity of the connector is shown on the following page.

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ACTUATORRING

LOCKDOG

WELLHEAD(LOWER BODY)

CONNECTORBODY

BODYRING

GASKET

Bending Capacity for the 18-3/4" 10 ksi Dog and Window Connector with 85 ksi Yield Strength of

Wellhead

0

2

4

6

8

10

2 3 4 5 6 7


Bor

e Pr

essu

re, k

si

T=1E6 lbf

T=2E6 lbf

T=0

Figure 9

T=3E6 lbfT=4E6 lbf

SB4: wellhead path 4, m+b, od

WellheadLower Body

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Description: DWH CONNECTOR ASSEMBLY Part No.: 2097932-02-02 P/N Revision: A01 Drawing No.: SK-098335-02 ITEM QTY. PART NO. DESCRIPTION

1 1 2097930-01 BODY RING, HDW CONN, MECH, H4 2 1 2097946-01 LOCK DOG- SET OF 8, 3 1 2097928-02 ACTUATOR RING, FIN M/C, DWH CONN, 4 1 2055131-01 MOUNTING RING, MECHANICAL DWH CONNE 5 10 2097968-01 CLAMPING PLATE, MECHANICAL DWH CONN 6 20 702585-25-00-32 SCREW, 12 PT CAP 1.250-8 X 3.250 7 20 702586-25-00-30 SCREW, HEX HD CAP 1.250-8 X 3.000 8 8 014443-17 PIN, ROLL -.500 X 1.750 STL ZN PL 9 8 702645-36-12 O RING, SIZE AS-568-361 5.975 ID X 10 1 718097 O RING, SPLICED 26.125 ID X .375 11 1 718096 O RING, SPLICED 27.0" ID X .375 12 1 K098437 FIT.,GREASE 1/2 NPT SAF-VENT 316SST 13 1 2097280-01 VENT ADAPTOR 14 12 702514-33-22 SCR 1.000-08 X 2.000 SOC HD SET STL CD 15 1 2715614 O RING, SPLICED 37.25 ID X .275 16 8 2704588 PLUG, PIPE, HEX SOC. .375 SST 316 17 4 702585-19-00-14 SCREW, 12 PT CAP 1.000-8 X 1.500 18 20 702514-29-21 SCR 0.750-10 X 1.000 CUP PT SOC HD SET 19 4 702514-27-21 SCREW, SOC HD SET .625-11 X 1.000 21 4 2055371-01 ANTI-ROTATION PLATE,

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Description: ACTUATOR ROD ASSEMBLY Part No.: 2156678-01 P/N Revision: B01 Drawing No.: SK-126768-01 ITEM QTY. PART NO. DESCRIPTION

1 1 2156677-01 ACTUATOR ROD-58.15" O.A.L. 2 1 2055098-01 COLLAR 3 4 702514-21-21 SCREW, SOC HD SET .375-16 X 1.000 4 1 2155708-02 M/D, SPACER, ACTUATOR ROD, 5 1 018571-03 PIN, SPRING .187 X .500 420 SST

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4.1.3 Top Plate / Mechanical Lockdown Assembly

The top plate provides protection for the tree valves during installation and workover activities. Two wellhead connector mechanical lockdown assemblies are attached to the underside of this plate. They provide a secondary means of ensuring the �dog-in-window� tree connector remains locked to the wellhead. The assemblies consist of two opposing half clamps that utilize Bellville springs to force them to be always in contact with the actuator rod. This spring force is designed to limit actuator rod movement such that it will occur only when greater than 7,500 lb of axial force from the Tree Running Tool is applied.

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Description: TOP PLATE AND MECHANICAL LOCKDOWN ASSEMBLY Part No.: 2216526-01 P/N Revision: B01 Drawing No.: SK-039736-01 ITEM QTY. PART NO. DESCRIPTION

1 1 2216536-01 TOP PLATE, G2 INTEGRAL SPOOL BODY, 2 2 2055545-08 ASSEMBLY, MECHANICAL LOCKD0WN, 3 8 2055561-01 SPACER LEG- MECHANICAL LOCKDOWN 4 8 702585-16-00-60 SCREW, 12 PT CAP .750-10 X 6.000

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Description: MECHANICAL LOCKDOWN ASSEMBLY Part No.: 2055545-08 P/N Revision: B01 Drawing No.: SK-098375-08 ITEM QTY. PART NO. DESCRIPTION

1 1 2055544-01 BASE PLATE, MECHANICAL LOCKDOWN 2 2 2097987-01 HALF CLAMP- MECHANICAL LOCKDOWN 3 24 2166804-01 SPRING, DISC WITH MOLY COATED 4 4 702528-19-02 WASHER, .625 FLAT TYPE A STL 5 4 702519-27-01-01 NUT 0.625-11 STL ZNPL FLEXLOC HEX LOCK 6 4 2097988-03 SHOULDER SCREW- MECHANICAL LOCKDOWN 7 1 2097989-03 LOCK SCREW W/ SHOULDER - MECHANICAL 8 2 2097990-03 SPACER/ SHEAR STUD- MECHANICAL 9 1 2097991-03 CLAMP BLOCK W/COUNTERBORE -

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4.1.4 Isolation Sleeve

The isolation sleeve is attached to the bottom of the spool body and stabs into the casing hanger when the tree has fully landed on the wellhead and seals with a metal end cap seal. This sleeve acts as the inner pressure barrier, making the wellhead connector's AX/VX gasket and the wellhead seal assembly secondary. The tree isolation sleeve is suitable for an FMC UWD-15 rigid lock wellhead system, sealing into the 10-3/4� casing hanger.

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Description: ISOLATION SLEEVE ASSEMBLY Part No.: 2216531-01 P/N Revision: 01 Drawing No.: SK-039770-01 ITEM QTY. PART NO. DESCRIPTION

1 1 2182341-02 BODY, ISOLATION SLEEVE, 13.0425 2 1 2181072-01 SEAL RETAINER RING, 16.283" NOM 3 1 2182801-01 LOWER SEAL RETAINER, ISOLATION 4 1 2141463-01 ACTUATOR RING, ISOLATION SLEEVE 5 2 2141470-02 RETAINER NUT, SHEAR PIN, 6 2 2156904-01 SHEAR PIN, ACTUATOR RING, 7 2 2748122-01 SPRING, COMP., .360 OD X .045 X 8 4 2141468-01 RETAINER PIN, ACTUATOR RING, 9 1 2141464-01 SPLIT LOCKDOWN RING, ISOLATION 10 1 2045896-03 SEAL, METAL END CAP, 16.275" NOM 11 4 702515-19-10-10 SCREW, SOC HD SET .312-18 X .62" 12 1 2182345-02 METAL ENDCAP SEAL, MALE STAB TYPE, 13 2 2156903-01 SHEAR PIN SLEEVE, ACTUATOR RING,

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4.1.5 Injection Valve Block Assembly

The injection valve block assembly is a single block containing one 5�-10,000 psi and one 2-1/16�-10,000 psi hydraulically actuated gate valves. They function as the injection wing valve and annulus crossover valve designated as IWV and XOV, respectively on the tree panels. The valves use the standard Cameron FLS cavity design and incorporate CM actuators that provide �fail closed� capabilities. The springs used to augment stem-assisted closing of the valve are designed to be sufficient for water depths to 3,280'. All actuator spring chambers have been filled with HW525 control fluid and plumbed to a transfer barrier accumulator. ROV interface and manual override requirements are listed in Section 6. The block allows for mounting the injection pressure sensor and the ¾� chemical injection valve. The 5� IWV on the injection valve block as well as the 5� IMV on the spool body are designated underwater safety valves (USV). See TC-002120-01 Operation and Maintenance Manual. For Design and Operation Parameters of the 5� and 2� Valves and Actuators � See SK-144073-59 and SK-144073-60.

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Description: INJECTION WING VALVE BLOCK ASSEMBLY Part No.: 2054403-14-02 P/N Revision: C01 Drawing No.: SK-097609-13 ITEM QTY. PART NO. DESCRIPTION

0 1 2148860-59 17D PRODUCT DOCUMENTATION PACKAGE, 0 1 2148860-60 17D PRODUCT DOCUMENTATION PACKAGE, 0 1 610470-65 PRODUCT DOCUMENTATION PACKAGE FOR 1 1 2054404-14-02 INJECTION WING VALVE BLOCK ASSY: 2 1 2096051-06 ASSY, 5-1/8 10,000 CM ACTUATOR VE 3 1 2013400-54 NAMEPLATE FOR SUBSEA GATE VALVE, 4 6 705786 SCR # 4 X 0.250 18-8 DR RND HD TYPE U 5 20 713837 GREASE, 0 TO 350 DEGREES (1 #CAN) 6 1 2096105-11 ASSY, 2-1/16 5,000 & 10,000 CM 7 1 2013400-56-01 NAMEPLATE FOR GATE VALVES, API 6A

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4.1.6 �CM� Actuators (Injection/Annulus)

Subsea actuators are designed to provide �fail closed� operation of the relevant gate valve and are controlled by hydraulic supply. For ease of assembly, handling, and maintenance, actuators are designed as separate units that can be detached from their respective valve assembly without having to fully dismantle the actuator, break the valve bonnet/body connection, or disturb the stem packing.

Note: 1. Actuators may only be assembled to their respective valve

assembly after installation of the gate, stem, and bonnet. 2. Prior to installation of the actuator assembly, piston stroke is set by

an adjusting ring installed on the valve (external to the bonnet).

Two ports are provided in the actuator cylinder for OPEN and CLOSE hydraulic connectors. The ports also facilitate venting of air from the system and enable flushing to the required cleanliness standard. All units are flushed to NAS 1638 Class 6 cleanliness standard prior to delivery.

Note: When actuators are cycled (OPEN/CLOSE), volumetric changes take

place in the spring chamber (the volume in the spring chamber reduces on the opening stroke, and increases on the closing stroke). These changes are compensated for by the inclusion of a transfer barrier accumulator in the hydraulic circuit.

The actuator assemblies fitted to the valve blocks are all single acting compact actuators of the rising stem type, with linear override and position indicator. They provide overall control of respective gate valves. Connection to the gate valve is by means of an internally threaded lock ring engaging a corresponding thread on the outer diameter of the bonnet with the actuator rising stem being threaded onto the valve stem.

Contained within the spring housing is the spring and the spring plate. They are held in the housing by the retainer ring which is secured to the spring housing by a lock ring. An o-ring provides sealing between the retainer ring and spring housing preventing ingress of seawater into the spring housing. The piston is fitted through the cylinder (which is seated in the main bore of the spring housing) and carries the rising stem. Sealing between the rising stem and piston is by means of three seal rings, while sealing between piston and cylinder is by means of the piston seal assembly. A scraper ring is also fitted into a groove in the piston and is used to prevent ingress of debris into the actuator internals.

Note: The scraper ring prevents debris reaching the seals, thus preventing

damage to the seals.

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Fitted at the outboard end of the actuator is a stem housing. The stem housing is retained by a clamp ring, which is bolted to the retainer ring. Also at the outboard end is an indicator assembly. Housed within the stem housing and fitted to the outboard end of the rising stem is an indicator inner ring, which is secured in position by a set screw. Installed around the outside of the stem housing an indicator ring is secured by four set screws (fitted through the indicator outer ring and stem housing), to the indicator inner ring.

The indicator assembly provides a positive indication of valve position and is controlled by the piston stroke. The length of piston stroke is adjustable by means of an adjusting ring installed on the bonnet of the gate valve.

Note: The piston stroke is correctly set during manufacturing.

In the event of a control systems failure, the actuator can be overridden by means of a special hydraulic tool being installed onto the stem housing at the front end of the actuator, attached by ROV. The hydraulic tool is then used to exert a force on the end of the rising stem, compressing the spring and opening the valve. If required the valve may be locked in the open position by leaving the tool in place with the hydraulic pressure locked in.

Linear ROV override of the injection and annulus valves is accommodated by a bayonet style interface.

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Description: 5” CM ACTUATOR ASSEMBLY Part No.: 2096051-06 P/N Revision: B01 Drawing No.: SK-096783-06 ITEM QTY. PART NO. DESCRIPTION

1 1 2096058-07 SPRING HOUSING 2 2 2096059-01 LOCKRING 3 1 2096060-01 RETAINER RING 4 1 2096061-11 PISTON (JIC HYDRAULIC PORTS) 5 1 2096062-01-01 CLAMP RING 6 1 2096063-01-01 CYLINDER 7 1 2096064-01 SPRING PLATE 8 1 2054158-27 STEM HOUSING W/LINEAR OVERRIDE 9 1 2062995-04 RISING STEM ASSY. 5.1/8" 10,000 10 1 2054160-01 INDICATER RING - INNER 11 1 2054161-01 INDICATOR RING - OUTER 12 1 2096066-01 SPLIT RETAINING RING 13 1 2027135-16 SPRING COMPRESSION 5" 14 4 2715803 SCREW, HEX HS MCH M8X1.25 PITCH X50 15 12 219065-09-03-01 STUD DE 0.875-09 X 03.000 B7 ZN PL 16 12 2709000-09-01 NUT, HVY HEX .875-9 GR 2H ZN PL 17 12 702515-29-20-12 SCR 0.750-10 X 0.750 CUP PT SOC HD SET 18 2 021810-96 PIN,DOWEL .375/.374 OD X .875 LG 19 1 702515-21-20-10 SCR 0.375-16 X 0.625 CUP PT SOC HD SET 20 2 702645-22-31 O RING, SIZE AS-568-223 1.609 ID X 21 2 718210 BEARING, SPLIT SLEEVE 2.75 ID X 22 3 2730527 SEAL RING, 2.75 ID X 3.50 OD X .413 23 1 718310 SCRAPER RING 2.75 24 1 702645-45-01 O RING, SIZE AS-568-450 10.475 ID X 25 1 2734300-37-01 PISTON SEAL RING, HALLITE 53, 220MM 26 1 702645-45-81 O-RG .275W X 14.475ID 90D NITRILE 28 3 501133-04-05 PLUG, TUBING-HEX 3/8 TUBE SST 29 1 2013400-32 NAMEPLATE F/GV ACTUATORS, ALT:255124-05 30 4 702525-10 SCR # 4 X 0.188 STL DR RND HD TYPE U 32 2 042000-02-23 BACK-UP RING, SIZE 223 1.647 ID X 33 2 200226 PIN, DOWEL- .250 DIA X 1.000 LG 34 1 2205671-01 CONTROL LINE ADAPTOR, JIC 37 DEG 35 1 702645-38-21 O-RG .210W X 12.975ID 90D NITRILE 36 1 2096067-01 END PLATE, SPRING HOUSING 37 1 2730878 PLUG, MALE HEAD N0.8 JIC 37 DEG, 38 1 M584842 PLUG,PIPE,SOCKET HD,1/4,

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Description: 2” CM ACTUATOR ASSEMBLY Part No.: 2096105-11 P/N Revision: B01 Drawing No.: SK-096799-09 ITEM QTY. PART NO. DESCRIPTION

1 1 2096107-03 SPRING HOUSING 2 2 2054178-04 LOCKRING 2 1/16"-10K 'CM' ACTUATOR 3 1 2096108-01 RETAINER RING 4 1 2054180-05 PISTON-LINEAR OVERRIDE. 5 1 2096416-03 CYLINDER. 6 1 2054182-01 SPRING PLATE 7 1 2054199-08 RISING STEM ASSY. 2.1/16" 5K & 10K 8 1 2054184-01 INDICATOR RING - INNER 9 1 2054161-01 INDICATOR RING - OUTER 10 1 2054185-01 SPLIT RETAINING RING 11 1 2027135-17 SPRING - COMPRESSION 12 4 2715803 SCREW, HEX HS MCH M8X1.25 PITCH X50 13 8 191821-14-00-30 SCR 0.625-11 X 3.000 HEX HD CAP GR B7 14 4 702525-10 SCR # 4 X 0.188 STL DR RND HD TYPE U 15 12 702515-29-20-10 SCR 0.750-10 X 0.625 CUP PT SOC HD SET 16 5 702515-21-20-14 SCR 0.375-16 X 0.875 CUP PT SOC HD SET 17 2 702645-11-71 O-RG .103W X 00.799ID 90D NITRILE 18 3 718209 BEARING, SPLIT SLEEVE 1.50 ID X 19 3 2730528 SEAL RING, 1.50 ID X 1.88 OD X .250 20 1 600937-03 SCRAPER RING, 1.500 ROD DIA WYCLIP 21 1 702645-36-01 O-RG .210W X 05.850ID 90D NITRILE 22 1 2714169 PISTON SEAL ASSY.115MM NOM OD ALPHA 23 1 702645-36-91 O-RG .210W X 07.975ID 90D NITRILE 24 1 2205671-03 CONTROL LINE ADAPTOR, 9/16"-18UNF 25 4 501133-04-05 PLUG, TUBING-HEX 3/8 TUBE SST 26 1 2013400-32 NAMEPLATE F/GV ACTUATORS, ALT:255124-05 27 2 042000-01-17 BACK-UP RING, SIZE 117 .799 ID X 28 2 200226 PIN, DOWEL- .250 DIA X 1.000 LG 29 1 2096011-02 SPRING HOUSING END PLATE 30 1 702645-36-51 O RING, SIZE AS-568-365 6.975 ID X 31 1 2054158-28 STEM HOUSING W/LINEAR OVERRIDE 32 1 191882-05 BUSH GUIDE 33 1 2748500-01 O-RING, SIZE AS-568-906 .468 ID X

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4.1.7 �FLS� Gate Valves (Injection/Annulus)

The valves that control the injection and annulus flow are Cameron�s FLS model gate valves. The valve design features are described below to give a detailed picture of these components that are critically important in subsea trees. The FLS model is the latest refinement of the Cameron �F�-Series of valves which have been supplied for production and drilling service since 1958. Metal to Metal Sealing Sealing at gate to seat and seat to body is metal to metal. Seal surfaces on both sides of the seats and gate are lapped to a mirror finish and are verified to be flat within less than 4 helium light bands to ensure gas tight sealing. Lubricant is used to limit wear, friction, and intrusion of contaminants into the valve cavity, not as an aid to sealing. One-piece floating seats and a floating slab gate provide reliable performance through simplicity of operation and a minimum of sealing interfaces. Cavity clearances are carefully controlled to limit the amount of float needed, and modified acme threads at the gate-to-stem connection provide sufficient freedom of movement in all directions to effect a positive downstream seal. Improved Seat Seal Design In addition to the lapped metal to metal seal between the seats and valve body, the �FLS� gate valve incorporates two V-type lip seals on the body sealing face of each seat. These OD and ID seals are each constructed of a pressure energized non-elastomeric lip seal that is spring loaded by an Elgiloy finger spring. Material of the lip seal is carbon filled PEEK or virgin PTFE, depending on the service and application. The OD and ID lip seals perform several functions in the �FLS� valve: Contaminants and debris are excluded from the metal sealing surfaces of the seat and body between the two seals. The spring loaded feature of the seals maintains contact between the gate and seats, wiping the seal surfaces and protecting them from damage due to sand or other contaminants. Body cavity clearance is effectively reduced to zero, while the downstream sealing function of the slab gate design is retained. Sealing integrity is enhanced at very low differential pressures, where low bearing stresses limit the effectiveness of the metal-to-metal seal. The �FLS� seat and seal design was first developed for drilling service, to eliminate damage and erosion of the body seal faces caused by sand, abrasives, and heavy drilling mud.

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Bi-Directional Sealing The �FLS� is a truly symmetric bi-directional design, without a �preferred direction� of operation in this configuration. The seal diameters and bearing areas of the �FLS� seats are designed to prevent trapping of pressure inside the valve cavity, so that the valve can be used with a failsafe actuator with well-pressure-assisted closing without a lower stem or internal porting. Testing has been performed to verify that no pressure locking or starvation occurs with the �FLS� in this application. Stem Packing Stem seal is a non-elastomeric lip seal. This pressure energized seal is constructed of filled PTFE, and is spring energized with Elgiloy finger springs. Sealant injection is neither required nor recommended for the stem seal.

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Description: 5” FLS GATE VALVE SUB-ASSEMBLY Part No.: 2096075-05-04 P/N Revision: A02 Drawing No.: SK-096791-01 ITEM QTY. PART NO. DESCRIPTION

1 1 2096073-04-01 BONNET, 5-1/8"-10K ACTUATED VALVE. 2 1 2054087-05-01 STEM: 5-1/8"-10K ACTUATED VALVE 3 1 2054104-03-01 GATE - 5-1/8" 10K ACTUATED VALVE 4 2 140413-01-71-03 SEAT, 5.1/8" 10000 "FLS" GV 5 2 2147124-07-03 OD FACE SEAL, 6.648 ID, SPLIT RING 6 2 140398-06-01-03 ID FACE SEAL 5.380 ID X 5.646 OD PSL3 7 1 2054118-01-01 PACKING GLAND - 5-1/8" 10,000 8 12 219066-14-07-51 STUD, DBL ENDED 1.500- 8UN -2A X 9 12 220464-20 NUT, ALLEN SOCKET HEAD. 10 1 140170-08-02-04 RING GASKET, 8.694 OD X 8.121 ID X 11 1 2054478-01-01 ADJUSTING RING - 5-1/8" 10,000 12 2 718300 SEAL RING, 2.75 ID X 3.25 OD X 9MM 13 1 718210 BEARING, SPLIT SLEEVE 2.75 ID X 14 6 702515-21-20-10 SCR 0.375-16 X 0.625 CUP PT SOC HD SET 15 1 702645-34-61 O-RG .210W X 04.100ID 90D NITRILE 16 1 691889-31 RING, BACK-UP - 2.752 ID X 3.498 OD 17 1 140232-27-51-03 PACKING, VARIPAK 2.75 ID X 3.50 OD 18 1 2136596-01 ASSY, PRESSURE RELIEF CHECK VALVE. 19 1 2136606-01 GREASE FILLER ASSEMBLY. 20 1 221034-03 CHECK VLV ASSY (get from Leeds) 21 1 M526742 SCR 0.750-16 X 0.375 HOL HEX SET STL 22 2 005930-14 PIPE PLUG HEX HD 1/4"NPT --ST/STL-- 23 1 702645-36-71 O-RG .210W X 07.475ID 90D NITRILE 24 1 707079 PIN, SPIROL .250 X 3.250 SST 25 1 631486-04 REVERSE PRESSURE SUPPORT RING,

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Description: 2” FLS GATE VALVE SUB-ASSEMBLY Part No.: 2096165-11-02 P/N Revision: A02 Drawing No.: SK-096118-11 ITEM QTY. PART NO. DESCRIPTION

1 1 2054085-03-04 BONNET, 2-1/16" 10K ACTUATED VALVE 2 1 2096166-03-01 STEM, 2.1/16" 10K ACTUATED VALVE 3 1 2054112-02-01 GATE, 2-1/16 2,000 - 10,000 CM 4 2 2054117-01-01 SEAT WITH TFL PREP, 2-1/16 2,000 - 5 2 140146-03-01-03 OD FACE SEAL 2.790 ID X 3.063 OD PSL3 6 2 140398-02-01-03 ID FACE SEAL 2.260 ID X 2.525 7 1 2054121-01-01 GLAND, 2-1/16" 10K ACTUATED VALVE 8 8 219066-11-06-11 STUD, DBL ENDED 1.125- 8UN -2A X 9 8 220464-19 NUT, ALLEN SOCKET HEAD, 12 POINT, 10 1 140170-02-01-04 RING GASKET, 4.564 OD X 3.985 ID 11 1 2054122-01 ADJUSTING RING 12 2 713603 SEAL RING, 1.50 ID X 1.88 OD X .250 13 1 718209 BEARING, SPLIT SLEEVE 1.50 ID X 14 5 702515-19-20-06 SCREW, SOC HD SET .312-18 X .375 15 1 702645-33-31 O-RG .210W X 02.475ID 90D NITRILE 16 1 2013133-05 BACK-UP RING, STEM SEAL, 17 1 140232-15-01-03 PACKING, VARIPAK 1.50 ID X 2.25 18 1 2136596-01 ASSY, PRESSURE RELIEF CHECK VALVE. 19 1 2734297-03 FITTING, INJECTION .750-16UNF WITH 20 1 221034-03 CHECK VLV ASSY (get from Leeds) 21 1 M526742 SCR 0.750-16 X 0.375 HOL HEX SET STL 22 2 005930-14 PIPE PLUG HEX HD 1/4"NPT --ST/STL-- 23 1 702645-34-41 0-RG .210W X 03.850ID 90D NITRILE 24 1 700338 PIN, ROLL .250 X 2.000 SST 25 1 631486-01 REVERSE PRESSURE SUPPORT RING,

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4.1.8 ¾� Hydraulically Operated Gate Valve

The Annulus Wing Valve (AWV) is a subsea hydraulically operated ¾� gate valve, rated 10,000 psi working pressure. This valve has been designed and hyperbarically tested to operate at seawater depths to 5,000 ft. The valve has an ROV override of multi-turn (6 turns open to close) operation, and also features positive indication of open and closed positions via an indicator connected to the actuator piston. See ¾� Hydraulically Operated Gate Valve Drawing SK-118590-02.

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4.1.9 ½� 15,000 psi Needle Valves

These valves are used to isolate the SCM, SV1, SV2, and GT lines. These valves require 270 degree of rotation and are manually operated using an ROV. A visual position indication of the valve is provided by a pointer located on the end effector in the ROV bucket. ROV interface and manual override requirements are listed in Section 6. See Isolation Needle Valve Drawing SK-098369-01.

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4.1.10 Tree Hydraulic Components � Flow Schematic

Low pressure tree hydraulic tubing is grade 316L stainless steel and is welded into the control junction plate and connected to the actuators using weld x fitting adapters. Low pressure GR hot stab circuit is 316L stainless steel tubing using Swagelok fittings to connect to both ends. High pressure tubing is 316L stainless steel welded at the control hydraulic junction plate and connected to the valve input ports using Autoclave anti-vibration medium pressure fittings or weld x fitting adapters. High pressure GT hot stab circuit is 316L stainless steel tubing using Autoclave anti-vibration fittings in both ends.

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Description: EXTENDED HYDRAULIC PIPING AND COMPONENTS Part No.: 2235488-03 P/N Revision: 01 Drawing No.: SK-081529-03 ITEM QTY. PART NO. DESCRIPTION

1 20 2704149 HYDRA TBG 316L ST/STL 3/8"OD X 0.065"W 2 1 203724 PLUG, PIPE-THREADED HEX SOC 1/4 3 5 2704082-02 CLAMP, TUBE SST 3/8 OD 2 TUBES

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Description: HYDRAULIC PIPING COMPONENTS Part No.: 2216677-01 P/N Revision: 01 Drawing No.: SK-039708-01 ITEM QTY. PART NO. DESCRIPTION

1 80 2704150 HYDRAULIC TUBING 316L STAINLESS 2 300 2704149 HYDRA TBG 316L ST/STL 3/8"OD X 0.065"W 3 100 718009-09 STN STL HYDR TBG 316L CD SML 4 20 701062 STN STL HYDR TBG 316 CD SML 5 1 2182989-02 TEE, SOCKET WELD, .209 I.D., F/ 6 2 2748447-01 ADAPTER, 9/16" AE MED PRESSURE 7 2 2748142-01 ADAPTER, 9/16" AE MED PRESSURE 8 9 712589 CONNECTOR, TBG MALE .56-18 SAE X 9 1 040548-01-03 UNION, TEE 3/8 TBG,SST 10 3 204887-05-02-22 CONNECTOR,TBG,MALE,1/4"NPT x 3/8"TBG,SWG 11 2 204887-08-05-22 CONNECTOR, TBG MALE 3/4 NPT X 12 1 005930-16 PIPE PLUG HEX HD 3/4 NPT --ST/STL-- 13 5 203444 PLUG, PIPE-THREADED HEX HD 1/2 14 8 204887-05-04-22 CONNECTOR, 1/2 NPT 15 1 2749318-01 ADAPTER, 1/4" NPT X SF-375-CX (.375 16 5 2704082-02 CLAMP, TUBE SST 3/8 OD 2 TUBES 17 5 2704082-03 CLAMP, TUBE SST 3/8 OD 3 TUBES 18 5 2704082-04 CLAMP, TUBE SST 3/8 OD 4 TUBES 19 5 2704082-05 CLAMP, TUBE SST 3/8 OD 5 TUBES 40 1 711706 SEALANT, THREAD - LOCTITE 567,

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4.1.11 Transfer Barrier

All hydraulically actuated valves have the spring side (compensator) plumbed to a common point and then to a transfer barrier. The transfer barrier is plumbed with "by-pass" check valves (normally set at 100 psi). The system is filled per Cameron procedures at tree assembly. If, during operation, there is too much fluid on the spring side of the valve, this fluid will be dumped to sea through the outlet check valve as the valve is opened. In the unlikely event there is not enough fluid on the spring side to allow the valve to close, seawater will be allowed to enter the system through the inlet check valve.

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Description: TRANSFER BARRIER ASSEMBLY Part No.: 2141627-01 P/N Revision: 01 Drawing No.: SK-126356-01 ITEM QTY. PART NO. DESCRIPTION

1 1 2705842-01 ACCUMULATOR, HYD 10.0 GAL, 3000 PSI 2 2 709321 VALVE, RELIEF .50 NPT SST 50 PSI - 3 4 204888-05-04-22 CONNECTOR, TBG FEMALE 1/2 NPT X 4 1 700195 NIPPLE, PIPE-HEX REDUCING 3/4 X 5 1 704492 BUSHING, PIPE 1-1/4 X 1/2 SST 6 1 203440 ELBOW,90 DEG STREET 1/2F X 1/2M 7 2 2705800-01 CROSS, 3/4 NPT FEMALE, SST 316 8 4 204887-05-05-22 CONNECTOR, TBG MALE 3/4 NPT X 9 2 2705795-01 NIPPLE, PIPE HEX SHORT 3/4 X 2.O LG 10 1 711992 STRAINER, 4" DIA X 5.25 LG ST/STL 11 20 2704149 HYDRA TBG 316L ST/STL 3/8"OD X 0.065"W 12 1 675029-44 ELBOW,90 DEG STREET 3/4F X 3/4M 13 1 712283 BUSHING, PIPE 2" X 3/4" SST 14 1 711706 SEALANT, THREAD - LOCTITE 567,

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4.2 Tubing Hanger

Tubing Hanger is supplied as follows:

• Two downhole hydraulic control lines The tubing hanger suspends the production tubing and provides porting for two fluid penetrations that allow communication to SCSSV functions. The tubing hanger has a 5� concentric bore with a 5� side production outlet. The production outlet utilizes Metal End Cap seals to seal to the tree spool bore. The top of the concentric bore contains a common nipple profile for 5.25� SSR wireline plugs and sleeves used during tubing hanger installation, workover and production. The bottom of the hanger body has 5-1/2� VAM ACE 17 lb/ft box connection. The hanger has a 4.795� minimum bore. The top of the hanger is designed to interface with a hydraulically operated tubing hanger running tool. The hanger has a stationary profile engaged by the running tool, which is the main weight carrying connection when handling the hanger and tubing string. During installation, the tubing hanger orients, lands, and locks to the bore of the spool tree. An orientation sleeve with a helix on the bottom of the hanger engages a key in the tree, providing 360 degrees of passive orientation. The hydraulic tubing hanger running tool lands on a shoulder in the spool before the hanger lands. At this point the hanger landing surface and control stab receptacles can be flushed with control fluid. The hanger is then "soft landed" by bleeding pressure off of the running tool soft land function. While running the hanger, the SCSSV control line stabs are protected by a circuit ring. The sleeve and hanger body have special cross porting to allow the control lines to be continuously pressurized and monitored through the hydraulic running tool back to the surface during installation. As the hanger �soft lands�, the circuit ring is pushed upward relative to the hanger, allowing the stabs to engage the landing shoulder in the tree body. Simultaneously, the hydraulic circuit from the surface is blinded and hydraulic control is passed to the tree IWOC umbilical. Once landed, the hanger seal to the tree can be pressure tested from above, followed by internal or external pressure testing of control stabs to verify proper engagement. The hanger is then locked into the tree by energizing a split lock ring with the running tool.

Prior to tubing hanger installation, a wireline retrievable bridging sleeve is installed in the hanger's vertical bore which seals above and below the production outlet to provide a barrier for testing between the production bore gallery seals. Once the tree testing is completed, the bridging sleeve is removed and replaced with a larger bore protection sleeve used to protect critical surfaces during further downhole work. After all downhole operations have been completed, the protection sleeve is retrieved and replaced with a plug which blanks off the vertical bore during production.

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Description: TUBING HANGER ASSEMBLY Part No.: 2216525-01 P/N Revision: B01 Drawing No.: SK-039725-01 ITEM QTY. PART NO. DESCRIPTION

0 1 2055679-01 REDRESS KIT, W/O-RING SEAL F/TUBING 0 1 2142856-04 REDRESS KIT W/PEEK SEALS F/TUBING 0 1 2142858-01 REDRESS TOOLS F/TUBING HANGER 0 1 2748243-01 LIP SEAL, AXIAL FOR .852 DIA BORE 1 1 2055376-10 BODY, FINISH MACHINE, G2 TUBING HGR 6 1 2141655-01 SEGMENTED LOAD RING, ACTUATOR RING 7 1 2141656-01 LOCKING SEGMENTS, F/ T.H. TO HANDLI 8 1 2141657-03 HANDLING RING. 9 1 2141658-01 ACTUATOR RING, TUBING HANGER 11 1 2141660-02 SPACER RING, 5.12 SIDE OUTLET, G2 12 1 2141661-01 RING, UPPER SEAL SPACER, TUBING 13 1 2141662-01 RING, LOWER SEAL SPACER, G2 SPOOL- 14 2 2141663-01 ASSY, SHEAR PIN CARTRIDGE, TUBING 15 1 647438-18-01 SEAL, METAL ENDCAP, 14.250" NOM. 16 1 647438-17-01 SEAL, METAL ENDCAP, 14.490" NOM. 17 1 647438-16-01 SEAL, METAL ENDCAP, 17.656" NOM. 18 1 2141889-01 RING, THREADED RETAINER, G2 SPOOL- 19 1 2141632-13-01 RUNNING/LANDING CIRCUIT RING, PORTS 20 2 2142713-01 SUB-ASSY, UPPER SEAL CARRIER, F/ 21 1 2141675-02 LOCK RING, 10M TUBING HANGER, G2 22 10 2141499-01 LOAD PIN, TBG HGR, G2 SPOOLTREE 23 4 2141891-01 PIN, RUNNING CIRCUIT RING RETAINER, 24 4 2142376-01 SLIDE PIN, RUNNING CIRCUIT SLEEVE, 25 1 2142375-01 KEY, HANDLING RING, ANTI-ROTATION, 26 2 2141634-01 ASSY, CONTROL RECEPTACLE, G2 SPOOL- 28 1 2142680-01 PIN, LOCK VERIFY TRIGGER, F/ G2 29 1 2142434-01 ORIENTATION KEY, G2 TUBING HANGER 30 2 2142682-01 STAB RETAINER CAP, HYDRAULIC 31 2 2155934-01 SUB-ASSY, HYDRAULIC STAB, FOR PEEK 32 1 702645-46-31 O RING, SIZE AS-568-463 16.955 ID X 33 1 702645-45-41 O-RG .275W X 12.475ID 90D NITRILE 34 2 042000-04-54 BACK-UP RING, SIZE 454 12.524 ID X 35 1 702645-45-51 O RING, SIZE AS-568-455 12.975 ID X 36 2 042000-04-55 BACK-UP RING, SIZE 455 13.024 ID X 37 4 702645-11-71 O-RG .103W X 00.799ID 90D NITRILE 38 3 263134-17 PIN, SHEAR, .616/.614 DIA X 1.0 LG 39 3 702515-29-60-62 SCREW, SOC HD SET .750-10 X .625

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ITEM QTY. PART NO. DESCRIPTION 40 2 702505-10-00-10 SCR 0.500-13 X 1.000 SOC HD CAP 41 2 702505-06-00-12 SCREW, SOC HD CAP .375-16 X 1.250 42 2 702505-06-00-04 SCREW, SOC HD CAP .375-16 X .500 43 1 2142336-06 360 DEG,ORIENTATION HELIX,TBG. HGR. 44 5 2141508-01 RETAINER, TH SEAL SPACER, 1.000-8 45 2 2704106 GLAND TBG 9/16 AUTOCLAVE 20000 PSI 46 2 2704208 BLIND PLUG 9/16-20K 47 4 702515-17-20-10 SCR 0.250-20 X 0.625 CUP PT SOC HD SET 52 1 2055683-02 WELDMENT, PROTECTOR, TUBING HANGER, 53 2 702586-22-00-14 SCREW, HEX HD CAP 1.125-8 X 1.500 56 1 2155900-01 RING, UPPER SPACER, FOR USE WITH 57 12 263134-18 PIN, SHEAR, .179/.182 DIA X .270 LG 58 1 2155901-01 RING, SPACER FOR UPPER M/M RLH 61 4 2155290-01 SPACER, F/TUBING HANGER RUNNING

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Description: CONTROL RECEPTACLE ASSEMBLY Part No.: 2141634-01 P/N Revision: B01 Drawing No.: SK-126193-01 ITEM QTY. PART NO. DESCRIPTION

1 1 2141645-01 FLOWTHRU BASE, G2 SPOOLTREE SYSTEM 2 1 2141643-01 SLEEVE, TUBING HANGER, RUN CIRCUIT 3 1 2141644-01 RETAINER STUD, G2 SPOOLTREE SYSTEM 4 1 702645-12-01 O RING, SIZE AS-568-120 .987 ID X 5 1 2748264-01 SPRING, CPRSM, .125 X .970 OD X 3.5 6 2 042000-01-20 BACK-UP RING, SIZE 120 1.018 ID X

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Description: HYDRAULIC STAB SUB-ASSEMBLY Part No.: 2155934-01 P/N Revision: B01 Drawing No.: SK-126632-01 ITEM QTY. PART NO. DESCRIPTION

1 1 2155848-01 BODY, STEPPED STAB CONTROL LINE, 2 1 2155847-01 RETAINER NUT, CONTROL STAB, G2 3 1 2142681-01 SEAL CAP, HYDRAULIC COUPLER, G2 4 1 2142746-05 SPACER, UPPER CONTROL LINE STAB, 5 1 2155846-01 MANTEL, LOWER PEEK SEAL SPACER 6 3 2748243-01 LIP SEAL, AXIAL FOR .852 DIA BORE 8 3 702647-20-85 O-RG .139W X 00.609ID 85D DUROCAM 9 5 2748250-01 BACK UP RING, SIZE 208, VIRGIN PEEK 10 1 702647-11-75 O RING, SIZE AS-568-117 .799 ID X 12 2 2142790-01 SPACER RING, PEEK LIP SEAL, HYDR 13 1 2142381-02 SPACER, PEEK LIP SEAL, HYDRAULIC

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Description: SHEAR PIN CARTRIDGE ASSEMBLY Part No.: 2141663-01 P/N Revision: A02 Drawing No.: SK-096061-02 ITEM QTY. PART NO. DESCRIPTION

1 1 2026808-02 THREADED RETAINER, SHEAR PIN ASSY 2 2 2748121-01 SOCKET HEAD CAP SCREW, #2-56 UNC X 3 1 199361-03 SHEAR PIN HOUSING, SHEAR PIN ASSY 4 1 040310-01-64 ROUND WIRE COMPRESSION SPRING. 5 1 199362-01 SHEAR PIN, 18-3/4 NOM HYD TUBING

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4.3 Tubing Hanger Wireline Plug

A 5.25� SSR wireline plug will be set in the tubing hanger to provide the primary barrier in the vertical bore of the hanger during production. This is a metal sealing plug with an elastomer back up and erosion target. The plug is set in the hanger body by a combination of pressure and downward jarring. Refer to Section 12 for operation and maintenance instructions.

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Description: SSR WIRELINE PLUG ASSEMBLY Part No.: 2156076-01 P/N Revision: A01 Drawing: SSR M446

ITEM QTY. PART NO. DESCRIPTION 1 1 2748033-01 WIRELINE PLUG, 5.25" DIA 2 1 702647-42-71 O RING, SIZE AS-568-427

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4.4 Internal Tree Cap

The Internal Tree Cap (ITC) provides 10,000 psi working pressure isolation over the top of the plugged tubing hanger assembly. Like the tubing hanger, the ITC is run and retrieved through the BOP stack using the tubing hanger running tool. The cap seals and locks into the tree using the same type of mechanism as the tubing hanger.

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Description: INTERNAL TREE CAP ASSEMBLY Part No.: 2182251-02 P/N Revision: A01 Drawing No.: SK-081139-01 ITEM QTY. PART NO. DESCRIPTION

1 1 2155984-04-01 BODY, INTERNAL TREE CAP, W/ NO THRU 2 1 2141497-01 HIGH STRENGTH LOAD SHOULDER, 3 1 2142425-01 RETAINER RING, HIGH STRENGTH, 4 1 2141675-01 SPLIT LOCK RING, HIGH PRESSURE CAP, 5 1 2141502-01 ACTUATOR RING, INTERNAL TREE CAP, 6 6 2141499-01 LOAD PIN, TBG HGR, G2 SPOOLTREE 7 1 647438-15-01 SEAL, METAL ENDCAP, 17.832" NOM. 8 1 2142468-02 SEAL SPACER, 1.532 WIDE F/ MEC SEAL 9 1 2142642-03 SEAL RETAINER RING, INTERNAL TREE 10 1 2155927-01 12 PT CAP SCREW, SPECIAL, 7/8-9UNC- 11 2 2141663-01 ASSY, SHEAR PIN CARTRIDGE, TUBING 12 1 702645-46-52 O RING, SIZE AS-568-465 17.955 ID X 13 1 2155928-01 KEY, RETRACTABLE ORIENTATION, 14 2 702514-17-20-06 SCREW, SOC HD SET .250-20 X .375 15 1 2142670-01 RETAINING SEGMENTS, INTERNAL CAP 16 2 702585-06-00-04 SCREW, 12 PT CAP .375-16 X .500 17 4 2748415-01 SPRING, .720 OD X .112 WIRE X 1.50

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4.5 Tree Debris Cap The Debris Cap is used to cover and protect the tree bore. The cap is non-pressure containing and mechanically set under its own weight. It is installed using an ROV and/or a tugger line from surface. When landed, it latches to the external profile on the top of the tree spool body. The design allows the top of the spool and inside of the cap to be filled with corrosion inhibitor. An overpull of approximately 100 lbs. is required to retrieve the cap.

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Description: TREE DEBRIS CAP ASSEMBLY Part No.: 2181899-04 P/N Revision: 01 Drawing No.: SK-080826-04 ITEM QTY. PART NO. DESCRIPTION

1 1 2165966-01 BODY, DEBRIS CAP 2 1 2165954-03 WELDMENT, R.O.V. LIFTING PLATE WITH 3 1 2165965-01 BOTTOM LIFTING PLATE, 4 3 2055565-03 DETENT PLUNGER, 4.62 LG 5 1 2216064-02 ASSY,HOT STAB RECEPT, 1/4"-NPTDUAL 6 1 2215891-02 ASSY, BLIND DUMMY STAB, DUAL PORT, 7 2 2148353-02 ANODE, 6.00 LG 8 2 713190 CHECK VALVE 9 2 703754 NIPPLE, PIPE-HEX 1/4 10 1 2749268-01 HOSE ASSY, .25" ID X 24" LG, 3000 11 10 2734245-01 WIRE ROPE, 7 X 19, .188 DIA, SST 12 2 712956 WIRE ROPE CLIP, .188 WIRE 13 6 702533-05-10-83 STUD, CONT THD .500-13 X 8.750 14 16 702517-10-01 NUT, HEX .500-13 15 4 2749224-01 WASHER, RUBBER, FOR 1/2" SCREW, 16 4 702528-14-03 WASHER, .500 FLAT TYPE A SST 18-8 17 12 702530-13-04 WASHER, 1/2" EXTERNAL TOOTH LOCK, 18 4 702585-10-00-17 SCREW, 12 PT CAP .500-13 X 1.875 19 4 2709000-05-01 NUT, HVY HEX .500-13 GR 2H ZN PL 20 2 2724119-01 HOSE FITTING, 1/4" MALE NPT 21 0.5 202072-00-02 HOSE, HYDRAULIC, 1/2", 3500 PSI WP, 22 1 2705711-02 STR FITTING HOSE, .25 NPT MALE FOR

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5. LIFTING REQUIREMENTS

Caution: The specified lifting apparatus applies only when moving equipment from one location to another. For subsea installation, the appropriate running tool is to be used. Equipment should be handled and operated with supervision from Cameron personnel while following rig safety procedures.

TREE AND TOOL LIFTING REQUIREMENTS

Item

Part No.

Weight (lbs.)

Lifting Apparatus

Tree Assembly + Bore Protector + Tree Handling Tool

2216524-01 2141626-01 2142462-01

80,000

85 ton shackle on THT

Tree Assembly

2216524-01

76,300

Tree Handling Tool with 85 ton shackle

Tree Handling Tool

2142462-01

2,400

Sling through 85 ton shackle

Tree Test Skid *

2182274-01

11,500

4 legged sling with 4 ton shackle

Tree Running Tool

2055145-12-01

16,500

55 Ton Shackle on TRT Lifting Sub

Tree Guidance Stab + Lifting Cap Assembly *

2182900-01 2182950-01

1,700

Sling Through 9.5 Ton Shackle

Tree Debris Cap

2181899-04

450

Sling Through Lifting Handle

Bore Protector Running Tool

2027776-01

1,200

4-1/2 IF (NC 50) Lifting Sub

Tubing Hanger

2216525-01

2,500

Tubing Hanger Handling Tool

Tubing Hanger Handling & Test Tool

2142721-01

900


Tubing Hanger Running Tool (THRT)

2141700-01

3,600

THRT Handling Tool

THRT Handling/Test Tool

2142736-01

900


Tubing Hanger Emergency Retrieval Tool

2141825-01

2,100


Internal Tree Cap

2182251-02

1,500

Sling Through Actuator Ring

BOP Test Tool

2142424-01

1,200


Boll Weevil Test Tool

2155548-01

1,100

Sling Through 9.5 Ton Shackle

Note: The TRT is to be used only for tree installation, use the tree handling tool for all

other lifts. * Customer Supplied

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6. INSTALLATION AND OPERATING PROCEDURES

6.1 Introduction Tree Installation The Spool Tree assembly, with the bore protector installed, is run with the Tree Running tool (TRT) on drill pipe (4-1/2� API-IF thread). There are two modes of TRT operation - IWOC umbilical and ROV interface. In case of IWOC control umbilical mode, the TRT is controlled from the surface. In ROV interface mode, ROV operates the TRT control panel subsea. The TRT is capable of five functions - Tree Connector-Lock/Unlock, TRT-Latch/Unlatch, and Gripper Latch. Completion / Workover Mode After installation of the tree, the TRT is removed, and the BOP is run, landed and locked on to the top of the tree. The IWOCS control umbilical is run on a tugger line or attached to the BOP / LMRP frame and is connected to the tree�s junction plate and control pod via hydraulic and electrical flying leads. Once the flying leads are connected, surface control of all tree hydraulically operated valves is allowed. The tubing hanger and internal pressure cap are then installed through the BOP after downhole completion activities have been done. Production Mode After BOP removal, the Debris Cap is installed and the production hydraulic and electrical flying leads are connected to the tree. Control of the tree is then passed to the production control system at the platform. The flowline jumper is then installed allowing production to take place.

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6.2 General Instructions

6.2.1 Pressure Tests

(1) Pressure gauges and chart recorders shall be calibrated in accordance with Cameron equipment control procedures.

(2) Timing of any test shall not begin until sufficient time has been allowed for pressure stabilization.

(3) No visible leakage shall be permitted at any time. If leakage should occur, stop the test, bleed pressure to zero psi and take remedial action.

(4) All tests must be charted. All test duration to be 5 minutes. (5) Test fluid for well-wetting bores shall be tap water with a suitable

corrosion inhibitor. Test fluid for control lines shall be HW 525. Cleanliness level requirement of all actuator functions and HP/LP supplies to be NAS 6 or better.

(6) Assembled Actuators and manual Valves have to be flushed to achieve the final cleanliness level equal or cleaner than the required final cleanliness level specified for the components. Note: Cycle each actuator 5 times by opening and closing the outlet valve to actuate the unit to full stroke. Allow pump to continue to run when opening the outlet valve to achieve maximum turbulence and flushing action. The fluid sample is taken by closing the inlet and outlet valves when the actuator is at full stroke and opening the sample valve.

(7) All function control line pressures shall be ≤3000 psi unless otherwise specified.

6.2.2 Corrective Action

(1) Remedial action to correct problems or faults encountered during testing

shall only be undertaken with specific instruction from product engineering.

(2) Customer or its designated representative shall be notified and approve such action if equipment performance has been affected in any way.

6.2.3 Procedural Changes

(1) The order of testing is structured for optimal use of test equipment and

facilities. The order of testing may be changed if it is absolutely clear to all authorized witnesses that the overall intent of the test is not undermined in any way.

(2) Product engineering or Cameron Service Personnel and the customer or their designated representative must approve any deviation, exception, change or addition to this procedure.

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6.2.4 ROV Valve Interfaces

Valve Ident.

Type Override Type

Interface Expected Force to Operate

Max. Override

Force IMV 5�-10M

Gate Valve Linear

ISO Type �C�

121,640 lb 129,590 lb

IWV 5�-10M Gate Valve

Linear

ISO Type �C� 121,640 lb 129,590 lb

XOV 2�-10M Gate Valve

Linear

ISO Type �C� 33,990 lb 35,790 lb

AMV 2�-10M Gate Valve

Linear

ISO Type �C� 33,990 lb 35,790 lb

AAV 2�-10M Gate Valve

Linear

ISO Type �C� 33,990 lb 35,790 lb

AWV

¾�-10M Gate Valve

Rotary (6 Turns)

Class 2 ROV Bucket with .687 Square End Effector

120 ft-lb 200 ft-lb

SCM ½�-10M Needle Valve

Rotary (3/4 Turn)


50 ft-lb 110 ft-lb

SV1 ½�-10M Needle Valve

Rotary (3/4 Turn)


50 ft-lb 110 ft-lb

SV2 ½�-10M Needle Valve

Rotary (3/4 Turn)


50 ft-lb 110 ft-lb

GT ½�-10M Needle Valve

Rotary (3/4 Turn)


50 ft-lb 110 ft-lb

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6.3 Tree Installation NOTE: Landing Ring testing, Bore Protector Installation and Tree Running Tool

Preparation may be done onshore before shipping the subsea tree offshore. 6.3.1 Required Equipment

A. Cameron Supplied Equipment Description Part Number Qty. Tree Assembly 2216524-02 1 Tree Test Skid w 2182274-01 1 Insert 2142491-06 (Dril-Quip) 2182423-01 1 Bore Protector 2141626-01 1 Tree Running Tool 2055145-12-01 1 Hot Stab 2215891-01 1 Tree Handling Tool 2142462-01 1 Bore Protector Running Tool 2027776-01 1 Landing Ring Test Stab 2142827-01 1 Isolation Sleeve Tool 2182907-01 1

B. Controls (Customer) Supplied Equipment

Description Part Number Qty. IWOCS HPU IWOCS Reel & Umbilical IWOCS Jumper Test/Flushing Hydraulic J-Plate (B8H-66100) 1 Test HPU Sensor Test Unit 4-1/2� IF Lift Cap

C. General Test Equipment

Description HPU (Water) HPU (Control Fluid � HW 525) Miscellaneous Hoses and Fittings Chart Recorder Torque Wrench Sockets for Class 1-2 ROV Buckets (for Manual Valves)

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6.3.2 Prepare the Tree for Testing on the Rig Prior to Installation

Test the downhole function tree isolation valves and Tubing Hanger Landing Ring Seals in the spool body.

NOTE: Based on customer requirements, the Bore Protector may be installed in the spool body onshore which prevents flushing the lines offshore. The Landing Ring testing may be done onshore; flushing and testing of the landing ring lines offshore is a customer preference. If flushing is not necessary, omit this step. It is Cameron�s recommendation that flushing is performed.

(1) Remove the tree bore protector if in place. (2) Flush the downhole function lines through the subsea tree. (3) Install the landing ring test stab into the seal pocket. (4) Function the associated tree valve to the position given in the table

below. Apply up to working pressure to the test stab. Vent the line at the junction plate.

Function Valve Position Pressure

SV1, SV2 CLOSED 10,000 psi

(5) Isolate, monitor and hold for 5 minutes. (6) Bleed pressure to zero psi. Repeat pressure test. (7) Repeat test for the remaining seal pockets.

6.3.3 Prepare Bore Protector Running Tool (BPRT) for BP Installation NOTE: Based on customer requirements for flushing, the tree may be supplied

with the bore protector already installed.

(1) Ensure that the four torque pins (See item 2 on Drawing SK-096284-01)

are installed in the tool body. (2) Make up a 4 1/2" IF lifting sub on top of the tool. (3) Retract the spring loaded retrieving dogs on the tool by rotating the four

cams to the �IN� position.

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6.3.4 Prepare Bore Protector (BP) for Installation

(1) Stand the bore protector upright. (2) Remove two sets of shear pins (See drawing SK-126202-01): qty. 4 of

item 6 (shear pin cartridges for lockdown) and qty. 6 of item 16 (anti-setting pins).

(3) Ensure free operation of spring loaded key if equipped. (4) Ensure the bore protector is in the UNLOCKED position (lock ring flush

to the OD of the body). (5) Install spring loaded shear pin cartridges (item 6).

Note: Brass anti-setting shear pins (P/N 2155653-02) are used when the bore protector is installed subsea in place of item 16 (i.e. Teflon anti-setting pins). Each brass shear pin has a shear value of 11 kips. NOTE: Ensure all pins are installed below flush.

(6) Inspect the o-rings (items 8 and 9) for damage. (7) Install the BPRT and engage the J-slots by rotating the tool counter-

clockwise. Verify that the detent balls snap in place.

6.3.5 Install Bore Protector in the Tree

NOTE: Based on customer requirements for flushing, the tree may be supplied with the bore protector already installed.

-JHA- Perform JHA for Bore Protector Installation

(1) Make sure that the Electrical Penetrator is retracted. (2) Open SCM Valve on the tree and vent the line. (3) Run and land Bore Protector in tree.

Note: If installing subsea, verify that the BOP rams and annular are fully open and verify the flex joint angle is less than 1 degree (recommended).

(4) Watch for returns through the AMON/SCM line. This will indicate that the bore protector is within 2 inches of its fully landed position.

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(5) Slowly set off 5-10 kips (70 kips to set subsea with 6 brass shear pins) to weight set the bore protector lock ring. Observe the running tool drop approx. 1.6". Measure the distance from the top of the actuator sleeve of the BP to the top of the Spool Body (36.4 ± .2).

(6) Lockdown and seal integrity may be verified by applying 5,000 psi to the AMON/SCM line.

Steps 7-15 for subsea installation. (7) Pick up (Overpull) approx 15,000 lbs (20,000 max) over the running tool

(string) weight to verify the locking pins are engaged. (8) Slack off overpull. (9) Verify IMV and the downhole line tree valves are closed. (10) Test the seals before the running tool is released by applying 5,000 psi to

the AMON/SCM line and holding for 5 minutes. (11) Rotate 15-20 degrees to the right (clockwise) to disengage the tool from

the bore protector. (12) Lift the tool out of the bore protector 1 to 2 feet. (13) To verify lockdown and the tool disengaged without shearing the pins,

apply 5000 psi to the AMON/SCM line. Hold for 5 minutes. (14) Reduce pressure to zero. (15) Retrieve the running tool.

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6.3.6 Prepare the TRT

The TRT may be deployed in two modes � surface controlled and subsea controlled. In surface controlled mode the IWOC umbilical is deployed and controls are from the surface. In subsea controlled mode, a ROV interface with TRT mounted Cameron control panel and activates TRT functions subsea. For subsea controlled mode, an additional ROV panel must be mounted and tested. Both modes are included in this manual for completeness.

-JHA- Perform JHA for TRT movement, preparation, and lift sub/mandrel makeup.

(1) Inspect the TRT for damage. (2) Flush and purge air from all five TRT functions. (3) Ensure that pipe plugs (item 20 on SK-098341-02) are removed from

the center bore (for access to the running string). Ensure that all other plugs are installed. NOTE: The TRT through bore must be vented to prevent hydraulic lock when installing and removing from the spool tree subsea and to assist in filling the drill pipe.

(4) Remove the 4-1/2� IF mandrel if installed, and install the lift eye nut & shackle. Bottom out the eye nut body, make up the coupling nut approx. 12 turns and tighten the set screws.

(5) If running TRT on IWOCS only (surface controlled mode): Set up and test the TRT umbilical reel as per Controls procedure. Connect the utility umbilical to the TRT manifold block as follows and go to 6.3.7:

FUNCTION MANIFOLD BLOCK

Tree Connector Lock Main Cylinder Extend Tree Connector Unlock Main Cylinder Retract TRT Latch Latch TRT Unlatch Unlatch Gripper Latch Secondary Cylinder

(6) For the Cameron ROV panel:

a. Verify that the compensator is fully charged; purge as much air as possible. Set relief valve to 15 psi.

b. Verify a 1,250 psi pre-charge on the accumulator. c. Verify the portion of latch tubing for emergency ROV cutting.

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6.3.7 Function Test of the TRT

(1) For subsea controlled mode with a Cameron ROV panel: Insert a hot stab with test line into TRT ROV panel hot stab receptacle.

(2) Test all five TRT functions by applying pressure through hot stab line and operating the valves on the ROV panel (See Running Tools Section).

(3) If running TRT with IWOCS only (surface controlled mode): Test all five TRT functions by applying pressure through the utility umbilical.

For either method of running (subsea or surface controlled mode), the functions should be smooth and repeatable. Verify visual markings on TRT components.

Function Pressure Notes Latch (TRT to Tree) 3,000 psi Unlatch (TRT from Tree) 3,000 psi Secondary Cylinder (Gripper Latch)

1,500 psi (3,300 psi max)

1) Use regulated pressure supply or pressure intensification may result. 2) 1,500 psi maximum when tree rods are not in place.

Tree Connector Lock (extend ) 4,270 psi Tree Connector Unlock (retract) 4,270 psi

(4) Prepare the ROV hot stab for the AX/VX gasket test. Note that 10� to

20� of slack must be used to allow the ROV to remove the hot stab from the tree when the TRT is being retrieved.

---ACCUMULATOR

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6.3.8 Prepare the Tree Test Skid

(1) Ensure the test skid is assembled with the correct insert. (2) Inspect and clean the stump gasket prep and seal surfaces of the dummy

casing hanger insert. (3) Connect a test hose with isolation valve to the bottom stump test port

and plug the port on the O.D. of the stump. (4) Fill the stump with fresh water.

6.3.9 Prepare the Tree

(1) Inspect and clean the Tree gasket prep and seal surfaces inside the Spool.

(2) Ensure the top of the Spool is clean and lightly oiled. (3) Ensure the Bore Protector is installed. (4) Check the wellhead gasket condition in the bottom of the tree. If the

gasket is not installed, position the gasket on the test stump. (5) Verify that the connector is unlocked and install the Tree Handling Tool

on the top of the spool body. If the connector is locked, install the TRT, utilize the TRT to unlock the connector, install the tree on the test stump and skip section 6.3.10.

6.3.10 Install the Tree on the Stump and Fill Tree

-JHA- Perform JHA for tree movements and removal of the THT.

(1) Ensure the GT is open and GR and GT hot stabs are not installed. (2) Inspect the tree connector and wellhead gasket and the isolation sleeve

seal (lower or upper, where applicable). (3) Pick up the tree and carefully lower it onto the tree test skid. (4) Remove the Tree Handling Tool if installed. (5) Fill the tree with fresh water. Open the tree valves during filling to

ensure that the valve cavities fill up.

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6.3.11 Install the TRT on the Tree

-JHA- Perform JHA for TRT lift and movement to tree.

Steps 1-6 apply to IWOCS TRT (surface controlled). Steps 7-27 apply to ROV operated TRT (subsea controlled) only. IWOCS-Operated TRT (surface controlled): (1) VENT the Gripper Latch. (2) Apply 3,000 psi to the supply line and RETRACT the tree connector

cylinders. Note: Maximum operating pressure not required. Verify markings that indicate the cylinders are in the retracted position.

(3) UNLATCH the TRT latch mechanism. Verify markings on two override rods that indicate the TRT is in unlatched position.

(4) Pick up the TRT and orient it over the tree, aligning the grippers with the tree actuator rods.

(5) Slowly land the TRT on the Tree. (6) LATCH the TRT to the Tree with 3,000 psi. Verify markings on the

two TRT override rods that indicate the TRT is latched.

CAUTION: Maintain TRT LATCH pressure while handling tree. ROV-Operated TRT with CAMERON Panel (subsea controlled mode):

(7) Remove the dummy ROV hot stab (if in place) from the receptacle on the TRT ROV panel and place it in the parking holder.

(8) Close the isolation valve (mounted on the panel) between the compensating system and the compensating system hot stab.

(9) Place all three valves on the ROV panel to middle position. (10) Install a ROV hot stab with pressure test line into the receptacle. (11) Vent the supply line (smaller diameter port on hot stab) and the return

line (larger diameter port). (12) VENT the Gripper Latch by turning the �GRP� valve to �V� position. (13) Block the Gripper Latch function by turning the �GRP� valve to the

middle position. (14) Turn the �TREE� valve to �U� position and apply 3,000 psi to the

supply line (small dia. port) to RETRACT the gripper assemblies. (15) Verify markings that indicate the gripper assemblies are in retracted

position. (16) Place the �TREE� valve to middle position to block pressure in. (17) Turn the �TRT� valve to �U� position to UNLATCH the TRT latch

mechanism. (18) Verify markings on two override rods that indicate the TRT is in

unlatched position. (19) Turn the �TRT� valve to middle position to block pressure in. (20) Bleed pressure on supply line.

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(21) Pick up the TRT and orient it over the tree aligning the grippers with the tree actuator rods.

(22) Slowly land the TRT on the Tree. (23) Apply 3,000 psi on supply line. (24) Turn the �TRT� valve to �L� position to LATCH the TRT to the Tree. (25) Verify markings on two override rods that indicate the TRT is latched. (26) Turn the �TRT� valve to middle position to block pressure in.

CAUTION: Observe gauge on “TRT” “L” side to verify that the Latch pressure is maintained while handling the tree.

(27) Bleed pressure on supply line.

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6.3.12 Lock the Tree Connector Onto the Test Stump

Steps 1-3 apply to TRT on IWOCS. For ROV operated TRT, perform Steps 4-7 only. IWOCS-Operated TRT (surface controlled): (1) Ensure the Gripper latch is vented. (2) LOCK the tree to the stump by supplying 4,270 +100/-0 psi to the TRT

�tree connector lock� function. (3) Check the marks (connector�s actuator rods or tree brackets) to verify

the tree connector is locked.

ROV-Operated TRT with CAMERON Panel (subsea controlled):

(4) Vent the Gripper Latch by turning the �GRP� valve to �V� position. (5) Turn the �TREE� valve to �L� position. (6) LOCK the tree to the stump by supplying 4,270 +100/-0 psi to the

supply line. (7) Check the marks (connector or actuator rods) to verify the Tree is

locked. 6.3.13 Prepare the Tree for Testing

-JHA- Perform JHA for pressure testing of equipment.

(1) Ensure the tree is filled with fresh water. (2) Ensure the TRT �Connector Lock� pressure is vented. (3) Flush all Tree circuits as directed by the Operator. (4) Ensure that the Transfer Barrier fluid level is full. (5) Install the IWOCS to the tree junction plate. Ensure all umbilical lines

are vented. (6) Function and test the control circuit of each actuator/valve

(independently) by applying 3,000 psi to the control circuit port and verify function by observing stroke of each actuator to the open position. Bleed pressure to zero and verify function by observing stroke of the actuator to the closed position.

(7) During testing, observe IWOCS connection for leaks. (8) Test continuity to the functions at the J-plates during testing. It is

recommended that the IWOC line to free J-plate connection not be broken after testing to assure proper continuity of the tree functions.

(9) Test the pressure/temperature sensors. (10) Close all tree valves.

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6.4 Test the Tree Prior to Installation

(1) Test the tree as described from the following tests. Note: The sequence can be changed as needed and the tests can be grouped together. Also, as many lines use tubing larger than ¼�, the time expected for pressure stabilization may take longer than others.

(2) The test pressure and duration is customer specified. (3) The table below indicates the test side of each valve:

NOTE: As the order of the testing may be changed, ensure that all valves are tested in both directions.

Component / Valve Inside

(Inboard) Outside

(Outboard) IMV 6.4.5 6.4.4 IWV 6.4.4 N/A XOV 6.4.6 6.4.3 AAV 6.4.8 6.4.3 AMV 6.4.8 6.4.3 AWV 6.4.7 6.4.2 GT 6.4.1 6.4.9

SCM 6.4.5 6.4.2 SV1 6.4.6 6.4.2 SV2 6.4.5 6.4.2

Bore Protector 6.4.8 6.4.5 Isolation Sleeve 6.4.8 6.4.1

WH Gasket 6.4.1 ~

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6.4.1 Test the Working Pressure Integrity of the Tree/Stump Connection, Inboard GT Valve, Isolation Sleeve External Test

Test #1 Refer to SD-030495-01 for valve positions.

(1) Open the GT valve and remove GT dummy hot stab. (2) Fill outside of isolation sleeve via the gasket test port on the side of the

test stump. Close the GT valve. (3) Valve Positions:

Test #1 Valve Position Check Off

IMV X IWV X XOV X AAV X AMV X AWV X SV1 X SV2 X SCM X GT X

X=CLOSED ; O=OPEN (4) Remove the cap from the TRT mandrel test port (if installed). (5) Apply pressure up to 10,000 psi to gasket test port for 5 minutes. (6) Monitor the GT hot stab receptacle and the TRT bore for pressure build

up or returns. (7) Bleed pressure to zero psi.

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6.4.2 Test the Outboard Side of the AWV, SCM, SV1, SV2 Valves Test #2

Refer to SD-030495-02 for valve positions.

(1) Valve positions:


IMV O IWV O XOV O AAV X AMV X AWV X SV1 X SV2 X SCM X GT X

X=CLOSED ; O=OPEN (2) Apply customer specified pressure up to 10,000 psi to SV1, SV2,

AMON/SCM for 5 minutes. (3) Monitor the 6� CVC Hub for pressure build up or returns. (4) Bleed pressure to zero psi.

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6.4.3 Test the Outboard Side of AMV, AAV, and XOV Valves

Test #3


(1) Valve positions:


IMV X IWV O XOV X AAV X AMV X AWV O SV1 X SV2 X SCM X GT X

X=CLOSED ; O=OPEN (2) Apply customer specified pressure up to 10,000 psi to AMON/SCM for

5 minutes. (3) Monitor the 6� CVC Hub and TRT/Drill String for pressure build up or

returns. (4) Bleed pressure to zero psi.

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6.4.4 Test the Inboard Side of the IWV and the Outboard Side of IMV Test #4


(1) Valve position:


IMV X IWV X XOV O AAV X AMV X AWV O SV1 O SV2 X SCM X GT X

X=CLOSED ; O=OPEN (2) Apply customer specified pressure up to 10,000 psi to AMON/SCM for

5 minutes. (3) Monitor the 6� CVC Hub and SV1 for pressure build up or returns. (4) Bleed pressure to zero psi.

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6.4.5 Test the Inboard Side of the IMV, SCM, and SV2, Outside of the Bore Protector Test #5


(1) Valve position:

Test #5 Valve Position Check Off IMV X IWV X XOV O AAV X AMV X AWV O SV1 O SV2 X SCM X GT X

X=CLOSED ; O=OPEN (2) Apply customer specified pressure up to 10,000 psi to SV1 for 5

minutes. (3) Monitor AMON/SCM, SV2, and TRT/Drill String for pressure build up

or returns. (4) Bleed pressure to zero psi

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6.4.6 Test the Inboard Side of the SV1 and XOV Valves Test #6


(1) Valve position:


IMV O IWV X XOV X AAV X AMV X AWV O SV1 X SV2 O SCM X GT X


minutes. (3) Monitor AMON/SCM and SV1 line for pressure build up or returns.

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6.4.7 Test the Inboard Side of the AWV Valve Test #7


(1) Valve position:


IMV O IWV X XOV O AAV X AMV X AWV X SV1 O SV2 X SCM X GT X


minutes. (3) Vent/monitor AMON/SCM for pressure build up or returns. (4) Bleed pressure to zero psi.

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6.4.8 Test the Inboard Side of the AAV, AMV, Bore Protector, and Isolation Sleeve

Test #8


(1) Valve position:


IMV X IWV X XOV X AAV X AMV X AWV O SV1 X SV2 X SCM O GT O

X=CLOSED ; O=OPEN (2) Plug gasket test ports on tree test stump. (3) Connect a test line to or plug the TRT test port. (4) Remove dummy hot stab from GT receptacle. (5) Apply customer specified pressure up to 10,000 psi to the TRT test port

or to the spool test port in the stump for 5 minutes. (6) Monitor AMON/SCM and GT receptacle for pressure build up or

returns. (7) Bleed pressure to zero psi.

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6.4.9 Test the Outboard Side of the GT Valve

Test #9


(1) Valve position:


IMV X IWV X XOV X AAV X AMV X AWV X SV1 X SV2 X SCM X GT X

X=CLOSED ; O=OPEN (2) Insert GT Hot Stab (smaller diameter port), vent Gasket Test Port on

stump. (3) Apply customer specified pressure up to 10,000 psi to GT line for 5

minutes. (4) Monitor Stump Gasket Test Port for pressure build up or returns. (5) Bleed pressure to zero psi.

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6.5 Prepare the Tree for Running

6.5.1 Unlock the Tree Connector Steps 1-4 apply to TRT on IWOCS (surface controlled). Steps 5-14 apply only to ROV operated TRT (subsea controlled): IWOCS-Operated TRT (surface controlled): (1) Vent the gripper latch function. (2) EXTEND the cylinder assemblies over the connector actuator rods by

supplying pressure (4,270 psi max.) to the �tree connector lock� function. Note: Do not apply more than 500 psi to the Tree Connector Lock

function if the tree is not landed on a stump; otherwise the tree connector can be damaged.

(3) Latch the grippers to the connector actuator rods by supplying 3,000 psi to the �gripper latch� function.

(4) UNLOCK the connector by supplying 3,000 psi to the �tree connector unlock� function. Verify the connector position markings.

CAUTION: Maintain unlock pressure while landing the tree.

ROV-Operated TRT (subsea controlled):

(5) Apply 500 psi on the supply line.

Note: Do not apply more than 500 psi to the Tree Connector Lock function if the Tree is not landed on stump; otherwise the tree connector can be damaged.

(6) Vent the Gripper Latch by turning the �GRP� valve to �V� position. (7) Turn the �TREE� valve to �L� position to EXTEND the TRT gripper

assemblies over the Tree connector actuator rods. (8) Verify markings that indicate gripper assemblies in extended position. (9) Bleed supply pressure and then turn the �TREE� valve to center

position. (10) Apply 3,000 psi on the supply line. (11) LATCH the grippers to the connector actuator rods by turning the

�GRP� valve to �L� position. (12) Turn the �GRP� valve to center position to block pressure in. (13) UNLOCK the connector by turning the �TREE� valve to �U� position

with pressure on the supply line. Verify the connector position markings. (14) Turn the �TREE� valve to center position to block unlock pressure.

Bleed off pressure on supply line. CAUTION: Observe gauge on “TREE” “U” side to verify that the

Unlock pressure is maintained while landing the tree.

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6.5.2 Change Tree Gasket

-JHA- Perform JHA for tree lift and seal inspection.

(1) Remove the dummy stab from the GR receptacle and place into the parking holder.

(2) Install a Hot Stab with test line into the GR receptacle and apply up to 1,000 psi to the smaller diameter port to release the gasket.

(3) Hold pressure and lift the Tree. Verify the gasket is on the stump. (4) Exchange the gasket on the stump. (5) Carefully set the tree on the stump. Release pressure on the gasket

retainer. (6) Lift tree to verify that the gasket is in place. (7) Inspect the seal (upper or lower, where applicable) on the isolation

sleeve. Install a new one if necessary. (8) Remove the hot stab from the GR receptacle.

6.5.3 Prepare the Tree for installation

(1) If required for relocation to moonpool, remove IWOCS RJP from tree. (2) Verify that the bore protector was properly installed. (3) Ensure that the Transfer Barrier fluid level is full. (4) Open the GT and SCM valves and verify that all other tree valves are

closed. (5) Verify the connector secondary lockdown mechanism is properly

tightened. (6) Ensure pressure cap or crud cap in installed on the flowline hub and are

ROV removable. 6.5.4 Install Tree Guidance Stab (Stinger) and Make up TRT to Drill Pipe

-JHA- Perform JHA for moonpool movements of the tree & drill pipe make-up to the TRT.

(1) Lift tree and move over the moon pool and land the tree on the four legs. Note: Check the Heading to locate the tree over the moon pool.

(2) Vent the �Latch� function of the TRT and apply 3,000 psi to the �Unlatch� function. Note: Verify markings on two override rods that indicate the TRT is in the unlatched position.

(3) Vent the �gripper latch� function to release the connector rods. (4) Remove TRT from Tree. (5) Use the Stinger Lifting Cap to lower the Stinger into the Tree. See

drawing SD-030423-07. Note: For the configuration of the Stinger, see drawing SK-081275-01 and sheet 3 of SD-030423-07.

(6) Place the Central Guide Receptacle on the Spool top and rest the Stinger on it at the centralizer sleeve.

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(7) Remove the Lifting Cap. NOTE: FOR SAFETY PURPOSE, SPECIAL CARE MUST BE TAKEN DURING THIS OPERATION.

(8) Pick up the TRT and make it up to the Stinger. Remove the Central Guide Receptacle. NOTE: FOR SAFETY PURPOSE, SPECIAL CARE MUST BE TAKEN DURING THIS OPERATION.

(9) Re-install TRT to Tree (Section 6.3.9) and unlock the Tree Connector (Section 6.3.10). Perform TRT function test.

(10) Remove the Lifting sub from the top of the TRT. (11) Send the crossover adapter (items 6 and 7 - See TRT latch tool) to the

drill floor. (12) Make up the TRT crossover adapter (mandrel and union nut) to weak

link/drill pipe. (13) Lower the drill pipe and crossover adapter through the rotary table and

make it up to the TRT. Note: Make up Torques (approximate): Union Nut - 300 ft-lb

Set Screws - 80 ft-lb (14) Install the Transponder(s) on drill pipe, if applicable. (15) Make up the weak link/drill pipe to the TRT. (16) Remove the ladder and davit fall protection equipment from the tree.

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6.5.5 Tree Installation Checklist

SPOOL TREE STATUS PRIOR TO RUNNING SUBSEA VALVE STATUS REMARKS / INITIALS

IMV CLOSED IWV CLOSED XOV CLOSED AAV CLOSED AWV CLOSED AMV CLOSED SCM OPEN SV1 CLOSED SV2 CLOSED GT OPEN BORE PROTECTOR INSTALLED AND LOCKED FLOWLINE HUB DEBRIS/ROV CAP

INSTALLED

WELLHEAD GASKET REPLACED ISOLATION SLEEVE NOSE SEAL INSPECTED OR REPLACED GASKET RELEASE (GR) DUMMY HOT STAB

INSTALLED IN PARKING RECEPTACLE

GASKET TEST (GT) DUMMY HOT STAB

INSTALLED IN PARKING RECEPTACLE

HOT STAB FROM TRT CONTROLS (IF APPLICABLE)

GT LINE MADE UP TO LARGE PORT, STOWED ON TRT

CONTROLS INSTALLED ON TRT FLYING LEADS (HYDRAULIC OR ELECTRICAL)

NOT APPLICABLE / INSTALLED / PARKED PER OPERATOR

TREE CONNECTOR UNLOCKED MECHANICAL SECONDARY LOCKDOWNS

ENGAGED

TRANSFER BARRIER FULL WELLHEAD SEAL ASSEMBLY LOCKED & TESTED

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TRT STATUS PRIOR TO RUNNING SUBSEA (SURFACE CONTROL IWOC MODE) FUNCTION STATUS (GAUGE) REMARKS /

INITIALS TRT (TOOL) LATCHED (L) 3,000 PSI

(U) ZERO

TREE (CONNECTOR) (L) ZERO UNLOCKED (U) 3,000 PSI

GRP (GRIPPER ASS�Y) LATCHED (L) 3,000 PSI PRODUCTION BORE TEST FITTING (SIDE)-PLUGGED

VERTICAL HOLE-PLUG REMOVED

TRT STATUS PRIOR TO RUNNING SUBSEA (CAMERON ROV PANEL, SUBSEA CONTROLS) FUNCTION STATUS (GAUGE) REMARKS /

INITIALS TRT (TOOL) LATCHED (L) 3,000 PSI

(U) ZERO

TREE (CONNECTOR) (L) ZERO UNLOCKED (U) 3,000 PSI

GRP (GRIPPER ASS�Y) LATCHED (L) 3,000 PSI PRODUCTION BORE TEST FITTING (SIDE)-PLUGGED

VERTICAL HOLE-PLUG REMOVED

COMPENSATOR BLIND STAB IN RECEPTACLE AND NEEDLE VALVE OPEN

CONTROL EQUIPMENT STATUS PRIOR TO RUNNING SUBSEA EQUIPMENT STATUS REMARKS /

INITIALS

STAB PLATES HFL

PROTECTIVE COVER

INSTALLED

ELECTRICAL

CONNECTORS EFL

PROTECTIVE

COVER INSTALLED

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6.6 Run and Test the Tree

6.6.1 Run the Tree

-JHA- Perform JHA for running drill pipe while installing umbilical in moonpool, if deployed.

NOTE: Care must be taken during running the tree so as not to stop the tree in the splash zone to make up drill pipe connections.

(1) Move rig off location. (2) Verify the tree valve status. (3) Pick up TRT and the tree on drill pipe and remove the support from

beneath the tree. (4) Run TRT and tree in designated safe location. If an umbilical is to be

deployed with the tree, clamp it to the drill string approximately every 50 ft.

(5) Make final ROV inspection of wellhead and tree. (6) When the tree is within 50 feet of landing, move rig back onto location. (7) Verify that the tree connector is in the unlocked position. (8) Record hanging weight: WEIGHT:_____________________ (9) Set drill string compensator for 10,000 lb landing weight. (10) Ensure that the running string is vented. (11) Orient the tree to the desired heading. (i.e. orient the tree flowspool

flange as required for jumper installation.) (12) Slowly lower the tree on to the wellhead and slack off 10,000 lbs. (13) Make final ROV inspection to verify the tree is fully landed to the

wellhead. (14) Slack off tree weight.

6.6.2 Lock Tree to Wellhead

Steps 1-5 apply to TRT on IWOCS. For ROV operated TRT, perform Steps 6-15. IWOCS-Operated TRT (surface controlled): (1) Bleed/vent gripper latch and block TRT latch (3,000 psi). (2) LOCK the wellhead connector with 4,270 +100/-0 psi. Note: Use the ROV to ensure that the tree connector is fully locked. (3) Vent tree connector LOCK. (4) Overpull 50,000 to 100,000 lbs. above hanging weight to test for

lockdown. (5) Release overpull.

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ROV-Operated TRT (subsea controlled):

(6) Remove the dummy ROV hot stab (if in place) from the receptacle on the TRT ROV panel and place it in the parking holder.

(7) Close the isolation valve (mounted on the panel) between the compensating system and the compensating system hot stab.

(8) Install a ROV hot stab with pressure test line into the receptacle. (9) Vent the supply line (smaller diameter port on hot stab) and the return

line (larger diameter port). (10) VENT the Gripper Latch by turning the �GRP� valve to �V� position. (11) Apply 4,270 +100/-0 psi to the supply line. (12) LOCK the wellhead connector with the set pressure by turning the

�TREE� valve to �L� position. Note: Use the ROV to ensure the tree connector is fully locked.

(13) Vent the supply line to vent the tree connector Lock function. (14) Overpull 50,000 lbs. to 100,000 lbs. above hanging weight to test for

lockdown. (15) Release overpull.

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6.6.3 Test Tree/Wellhead Connection

Test #10

(1) Open GT. (2) Vent the running string. (3) Connect the gasket test hot stab to the GT receptacle on the tree. (4) Apply customer specified pressure up to 10,000 psi to GT (hot stab) for

10 minutes (minimum). (5) Monitor connector for leakage using ROV. On the surface, observe for

returns through the running string. (6) Bleed pressure to zero psi. (7) Close the GT valve.

Trouble shooting procedures (contingency) a) Determine if gasket test hose/hot stab is leaking. Monitor for leakage

from the hot stab receptacle. Close the GT valve and monitor for pressure drop.

b) Determine if wellhead gasket is leaking. Monitor for fluid leakage past tree connector, if ROV can access bottom of tree.

If wellhead gasket is leaking, retrieve tree, clean and inspect wellhead gasket prep, replace tree isolation sleeve seal, install appropriate wellhead gasket in tree, re-deploy tree, and retest.

c) Determine if tree isolation sleeve seal is leaking. Conduct reverse pressure test on tree isolation seal. This requires the test pressure on the gasket test port to be bled off, tree running tool to be locked onto the tree, the tree bore pressurized, and pressure outside the tree isolation sleeve to be monitored through the gasket test port. The test pressure will be limited by the pressure rating of the production casing string, storm packer, or cement plug in the well.

If the tree isolation sleeve seal is leaking, retrieve tree and change the isolation sleeve seal (primary or secondary), re-deploy tree, and retest.

GTV GT

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6.6.4 Subsea Tree Testing

Testing may begin after locking the tree to the wellhead, or later, after the TRT is recovered and the BOP has been run. The logistics of testing will depend on several factors such as the operator�s offshore testing philosophy, timing of other equipment installations and IWOCS system limitations. If appropriate:

• Function test the tree valves and confirm functions. • Test the tree control functions (i.e. high & low pressure supply,

electrical, etc.) • Perform the prescribed tree tests (tests #2 through #8)

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6.6.5 Retrieve TRT and Umbilical

Steps 1-13 apply to TRT on IWOCS. For ROV operated TRT, perform Steps 14-31. IWOCS-Operated TRT Only: ROV Requirements: Hot Stab placement Flying lead removal & parking if required

(1) Bleed all pressure from the lines in the umbilical. (2) Remove the hot stab from the GT receptacle and stow on TRT. (3) Stab dummy hot stabs in GT/GR ports. (4) If appropriate, power down any IWOC electrical lines, disconnect

Electrical Flying Leads and any Hydraulic Flying Leads. Place flying leads in the proper parking positions for TRT retrieval.

(5) With the grippers vented, function Tree Connector Unlock to retract the hydraulic cylinders. Observe the connector actuator ring to ensure the connector is not disturbed.

(6) Release the TRT from the tree by supplying 3,000 psi to the TRT "UNLATCH" function.

(7) Lift the TRT off the tree at least 50 feet. ROV to observe stinger disengagement from the spool body during lift off.

-JHA- Perform JHA for retrieval of TRT and umbilical, if appropriate.

(8) Move the rig off location so that the TRT is not over the tree and retrieve the TRT.

-JHA- Perform JHA for breakout of TRT from drill pipe and movement of TRT.

(9) As the equipment is being retrieved, unclamp any umbilicals from the running string and spool it in.

(10) Land the stinger over the support frame and remove it from the TRT (see Drawing SD-030423-07).

(11) Remove the drill pipe adapter from the TRT and lift to the drill floor. (12) Make up the lifting / test sub to the TRT. Pick up tool and set to side. (13) Install debris cap on top of the spool body per customer requirements. ROV-Operated TRT with CAMERON Panel Only: (14) Vent the supply line (small diameter on hot stab) and the return line

(large diameter on hot stab) on the ROV panel. (15) Turn the �TRT� valve on the ROV panel from �L� to �U� position to

UNLATCH the TRT. (16) Apply 3,000 psi to the supply line (small diameter on hot stab) to

UNLATCH the TRT latch mechanism.

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(17) Verify markings on two override rods that indicate the TRT is in UNLATCHED position.

(18) Lower pressure to 200 psi. Note: Lowering the pressure is recommended because this pressure is

being added to the hydrostatic which will be seen at the surface. (19) Turn the �TRT� valve on the ROV panel to middle position to block

pressure in. (20) Bleed pressure and vent the supply line (small diameter on hot stab). (21) VENT the Gripper Latch by turning the �GRP� valve on the ROV panel

to �V� position. (22) Turn the �TREE� valve on the ROV panel to �U� position to bleed

pressure allowing the gripper assemblies to release the rods. (23) Apply 3,000 psi on supply line (small diameter on hot stab) to move the

gripper assemblies to UNLOCKED position. ROV to observe grippers disengagement from the tree rods.

(24) Lower the pressure to 1,500 psi. Note: Lowering the pressure is recommended because this pressure is

being added to the hydrostatic which will be seen at the surface. (25) Turn the �TREE� valve on the ROV panel to middle position to block

pressure in. (26) Bleed pressure on supply line (small diameter on hot stab). (27) Lift the TRT off the tree. Use ROV to observe disengagement from the

Spool body during lift off. (28) Move the rig off location so that the TRT is not over the tree. (29) Retrieve the TRT. (30) Land the stinger over the support frame and remove it from the TRT (see

Drawing SD-030423-07). (31) Remove the drill pipe adapter from the TRT and lift to the drill floor. (32) Make up the lifting sub to the TRT. Trouble shooting procedures (contingency Unlatch) (1) Remove hot stab from the receptacle on the ROV panel. (2) Place �GRP� valve in �V� position. (3) Place both �TRT� and �TREE� valves in either �L� or �U� position. (4) Using ROV cut the tubing (TRT Latch function) routed towards the

perimeter on the right (�U�/�V�) side of the ROV panel. NOTE: This step is done to release the pressure trapped by the pilot-

operated check valve. (5) Using proper lifting gear, pull up the two eyenuts on top of TRT. Verify

unlatch marking on override rods. (6) Retrieve TRT making sure that tool is unlatched.

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6.7 BOP Stack Installation

6.7.1 Equipment Required

Description Part Number Qty. BOP Test Tool 2142424-01 1

6.7.2 Prepare the BOP for Running

Note: It is highly recommended that the inside of the BOP and drilling

riser be thoroughly cleaned at this time. This will help avoid potential operational problems when landing and testing the tubing hanger.

6.7.3 Run BOP / IWOC Umbilical

-JHA- Perform JHA for movement and installation of BOP, controls, etc.

(1) Make up the workover umbilicals to the BOP / LMRP frame while providing sufficient slack so it can be connected to the tree per customer / controls procedures. NOTE: The IWOC umbilical may be run after the BOP has landed using a tugger / guide wire.

(2) Run the BOP per rig procedures. (3) As equipment is being run, deploy the workover umbilical and clamp it

to the riser or lines as required. (4) Run the BOP until it is within 50 feet from the top of the tree. (5) Remove the tree debris cap if installed and inspect gasket prep for

damage or debris. (6) Orient, land, and lock the BOP per rig procedures.

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6.7.4 Prepare and Run BOP Test Tool and Perform Stack Test

Note: This tool must be run with the spool tree bore protector in place.

(1) With the tool in the running position, inspect the metal end cap seal (item 15) for damage. Replace seals as necessary.

(2) If desired, internal seal integrity may be verified. Remove the plug (item 11) and install a test pump adapter (Autoclave p/n 6M44N6) in the 1/4" NPT port in the body (item 1). Pressure test between the Polypak seal (items 13 and 14) to a MAXIMUM of 3,000 psi. Bleed off the pressure and reinstall the plug (item 11).

-JHA- Perform JHA for testing of the BOP.

(3) Run the tool in the hole and land on the bore protector. (4) Slack off a minimum of 10,000 lbs (20,000 lbs recc.) of running string

weight to set the seal. Weight below the tool may be used. (5) Test the BOP per rig procedures to a maximum of 10,000 psi. (6) Retrieve the tool when testing is completed.

6.7.5 Run IWOCS and Connect Hydraulic and Electrical Flying Leads to the Tree

ROV Requirements: Torque Tool per Controls Vendor Requirement. (1) If the umbilical was not run along with the BOP, run the umbilical on a

guide wire system per rig procedure. (2) Verify that all pressure is bled off of the umbilical. (3) Use the ROV to install the flying leads per Controls Vendor Procedure. (4) Function all hydraulically actuated valves open then closed through

IWOCS to ensure continuity per Controls Vendor Procedure. (5) Test pressure and temperature sensors per IWOCS requirements using

portable test box (Note this can be done in conjunction with valve tests).

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6.7.6 Subsea Tree Testing

Test the valves and circuits as described on tree Tests #2 through test #8. Test pressure and duration is to be specified by the customer. Testing may have been performed after locking the Tree to the wellhead or after landing and testing the BOP. The logistics of testing will depend on several factors such as the operator�s offshore testing philosophy, timing of other equipment installations and IWOCS system limitations. Set all of the valves per operator procedures.

6.8 Complete Downhole Work per Operator Procedures

6.9 Bore Protector Retrieval

6.9.1 Equipment Required

Description Part Number Qty. Bore Protector Run/Retrieval Tool 2027776-01 1

6.9.2 Prepare Bore Protector Running / Retrieval Tool

(1) Ensure that the torque pins (item 2) are removed. (2) Extend the spring loaded retrieving dogs by rotating the four cams to the

OUT position.

6.9.3 Retrieve Bore Protector

(1) Verify that the SCM valve is OPEN and AWV is CLOSED. Vent AMON/SCM line via IWOCS.

(2) Make up the bore protector running tool to the drill string and run in to the hole.

(3) Land the tool on the bore protector and set off 5,000 lbs. (4) Equalize pressure on the SCM line with the completion fluid. Pressure

may be increased slowly to assist in removing the bore protector. (5) Overpull 25,000 lbs. to shear the 04 (four) pins in the bore protector.

Note: The maximum theoretical load to shear the 04 (four) pins is

45,000Lbs. The secondary release overpull has to be as high as 116,000 Lbs to shear the 06 (six) pins.

(6) Retrieve the bore protector and close the SCM valve.

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6.10 Tubing Hanger Installation

6.10.1 Required Equipment

A. Cameron Supplied Equipment Description Part Number Qty. Tubing Hanger (TH) 2216525-01 1 5.25" SSR Wireline Plug 2156076-01 1 TH Handling/Test Tool (THHTT) 2142721-01 1 TOOLS FOR WIRELINE PLUG Running Tool 2748031-01 1 Pulling Tool (4� GS) 2748035-01 1 Isolation Sleeve 2748152-01 1 Protection Sleeve (short) 2730423 1 GS Pull/Run Tool (5� GS) 2748036-01 1 Wireline Centralizer 2748156-01 1 TH Running Tool (THRT) 2141700-01 1 (w/ Production Stab Mounted) 2155994-02 1 THRT Handling/Test Tool (THRTT) 2142736-01 1 THRT Pressure Test Skid/Stand 2142094-01 1 Stand for THRT 2142930-01 1 Stand for TH 2142851-01 1 Redress Tools for TH Control Stabs 2142858-01 1 Pup Joint Cap N/A 1

B. Customer Supplied Equipment 4-1/2� IF Lift Cap N/A 1

C. Spares (TH and Plug)

Verify availability of spare parts listed in Section 14.

D. Controls Description Part Number Qty.

Workover Utility Reel (UTP) 1 Adapter joint, slick joint, and 1

Subsea Test Tree (SSTT)

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6.10.2 Run Tubing per Operator Procedures 6.10.3 Prepare the Tubing Hanger Running Assembly for Installation

NOTE: The following procedures are written for the two different types of

SSTT. The Tubing Hanger Running Tool Latch Assist function may be open to the riser (in the case of a direct hydraulic multi-line umbilical system) or ganged together with the Latch function (in the case of an electro-hydraulic system). The procedures refer to �LATCH� only and are applicable to either type of SSTT.

NOTE: Before the tubing string is run, make up the tubing hanger running tool,

adapter joint, slick joint, and safety tree assembly. Flush the line using the THRT stand and test the production bore connections and the control line connections using the THRT test skid. This is normally done at System Integration Testing with the SSTT.

-JHA- Perform JHA for handling of the THRT / SSTT.

A. Make up SSTT to THRT assembly if not previously made up (normally done onshore prior to shipping).

(1) Inspect control stabs provided with SSTT. Replace seals as

required. Grease seals with control fluid compatible grease (ref Oceanic ACL).

(2) WARNING: When making up the THRT to the SSTT, remove the vent stab at the top of the THRT.

(3) Test SSTT and Control System per SSTT supplier procedures. (4) Verify that the THRT / SSTT has been drift tested.

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B. Flushing THRT (normally done onshore)

(1) Remove the flushing port plugs (1/4� NPT) from the THRT piston.

(2) Flush all THRT hydraulic functions to remove any trapped air. (3) Re-install flushing port plugs into THRT.

C. Function & Flush THRT with Optional Pressure Test

(1) Inspect the Lock Monitor poppet assembly on the side of the THRT and ensure proper function.

(2) Function the THRT using the SSTT and control system. (1) Function the Tubing Hanger Lock / Unlock and THRT

Latch / Unlatch a minimum of three times each. (2) Each function should be operated without pressure on any

other function. (3) Finish with the tool in the Unlatched and Locked position.

(3) The THRT functions may be pressure tested as follows (5 minute hold period on each function):

LATCH or LATCH/LATCH ASSIST 3,000 psi UNLOCK 3,000 psi LOCK 3,000 psi LOCK MONITOR / LOCK 3,000 psi SOFT LAND 2,500 psi PRODUCTION BORE (Tool must be in skid) 10,000 psi max. UNLATCH 3,000 psi

(4) To verify the cleanliness level of the downhole lines through the SSTT/THRT, install the THRT into the THRT Test Skid.

NOTE: Flushing is recommended when the downhole control lines are made up to the hanger prior to installing the THRT/SSTT to the Tubing Hanger.

(1) Vent the THRT functions and ensure the THRT is in the Unlatched and Locked position.

(2) Align the THRT key with the skid slot and lower the assembly into the THRT test skid.

(3) Latch the THRT to the test skid. (4) A pressure test up to 10,000 psi may be done on the

downhole lines to test the stab connections. (5) Fluid samples are taken from the side ports of the THRT

test skid. Flush through the downhole lines until the proper cleanliness levels are obtained.

(6) Remove the SSTT/THRT from the skid and return the tool to the Unlatched and Locked position.

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6.10.4 Prepare the Tubing Hanger for Installation

(1) While on the working deck of the rig prior to running tubing, suspend the tubing hanger in the tubing hanger stand over a hole in the rig deck.

(2) Check the following items: A. Verify the control lines were flushed as required. B. If equipped, verify �RLH� seals are in place. C. Inspect all seals. Replace if necessary. D. Inspect the wireline plug sealing area. E. Verify the pup joint was tested as required. F. Tubing Hanger is in the "Unlock" position. G. Verify that the wireline isolation sleeve is installed and tested.

Installation is per SSR International procedures (Section 13). NOTE: Verify the wireline isolation sleeve lock ring is installed

right side up. The lock ring should be below flush and tight fitting around the sleeve.

-JHA- Perform JHA for installation of the THHTT.

(3) Lubricate the THHTT seals and install the THHTT in the tubing hanger.

i. Make up a 4-1/2 API IFTJ lift cap to elevator sub.

ii. Back up the three short jack screws (item 11) until they are flush with the bottom of the actuator ring. Verify hanger is Unlocked.

iii. Carefully align the Control Stabs and anti-rotation key with the tubing hanger seal pockets and slot. Land the THHTT in the tubing hanger on the handling ring (item 8) of the TH assembly.

iv. Screw down the three long screws (item 10) until tight to actuate the latch ring in the hanger actuator ring groove.

v. The THHTT latch ring is visible through the two holes in the hanger vi. Ensure that the Autoclave blind plugs are installed on the bottom of

TH. Using the tubing hanger handling and test tool, test each downhole line to 10,000 psig for 5 minutes (this test is to verify TH pressure integrity before it is on rig floor).

NOTE: this test is optional since the lines and connections will be tested again with the THRT.

(4) Flush the downhole control lines through the THHTT to the appropriate cleanliness levels.

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6.10.5 Make up Tubing Hanger to Tubing String

-JHA- Perform JHA for handling and moving the tubing hanger to the drill floor.

(1) If available, the split landing bowl clamp may be installed to protect the hanger seals during transport.

(2) Run the tubing completion and support the final joint in the tubing slips. (3) The tubing hanger is transported to the drill floor with the THHTT

installed. The tubing hanger is lifted horizontally through the V-door with one strap placed on the end of the tubing hanger pup joint and the other connected to the lift cap.

NOTE: Ensure that the pup joint protector cap or saver sub is installed to avoid damaging the pup joint threads during handling.

(4) Make up the tubing hanger pup joint to the production tubing string. (5) Connect the drill pipe elevator to the THHTT and pick up weight, lift the

string to remove the tubing slips and record the completion weight.

Weight of Tubing and Tubing Hanger Completion Assembly (lbs.)

(6) Test the tubing string as appropriate per Operator procedures.

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6.10.6 Install THRT and Make up Control Lines to Tubing Hanger

The following two procedures (Procedure A and Procedure B) are used to accommodate two different options for making up the downhole lines and installing the THRT/SSTT to the tubing hanger. The procedural order should be followed for the particular option. Option 1: A split landing bowl is not used OR it is preferred to make up the

downhole lines with the THRT/SSTT in place. Follow Procedure A then Procedure B

Option 2: A split landing bowl is used and the downhole lines are to be made

up prior to installing the THRT/SSTT. Follow Procedure B then Procedure A

Procedure A – Make up the THRT/SSTT to the Tubing Hanger

(1) Land the tubing hanger pup joint in the tubing slips. If a landing bowl is

available, place the master bushing over the rotary table and land the tubing hanger on the split landing bowl clamp on the master bushing. Set off entire string weight before removing the THHTT.

(2) Remove the THHTT from the tubing hanger. a. Back up the (3) actuator energizer screws (item 10) approx. 1 inch

and screw in the (3) jack screws to unlatch the THHTT from the TH. b. Remove the tool from the tubing hanger and store away.

(3) Inspect the TH production and control line stab pockets for debris and wipe clean.

-JHA- Perform JHA for handling and installation of the THRT / SSTT.

(4) Pick up the THRT and SSTT assembly and hook up umbilical jumper to the SSTT. Refer to the SSTT supplier�s procedure.

FUNCTION THRT SUBSEA TREE TH LOCK 13 TH LOCK MONITOR 9 TH UNLOCK 14 TH LATCH ASSIST 10 THRT LATCH 11 THRT UNLATCH 12 VENT / TEST RETURN 8 NOT APPLICABLE A SV1 B SV2 C NOT APPLICABLE D NOT APPLICABLE E NOT APPLICABLE F & G SOFT LANDING N/A PRODUCTION BORE N/A

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(5) Lift the running assembly to a convenient working level and remove the stab protector ring. Inspect all stabs and o-rings and coat them with control fluid or Oceanic ACL to prevent contamination.

(6) Ensure the running tool/SSTT functions have been flushed and tested and that the THRT is in the Unlatched and Locked positions.

(7) Ensure SSTT has been tested per the SSTT supplier�s procedures. (8) Ensure downhole lines communications with the correct ports have been

verified. (9) Isolate TH Lock Monitor. Inspect the THRT�s Lock Monitor poppet. (10) Remove the TH shear pin cartridges from the side of the Tubing Hanger

lock actuator ring. (11) Vent the THRT Vent function. (12) Lock in 3,000 psi on the Lock and Unlatch THRT functions. (13) Move the THRT/SSTT assembly directly above the Tubing Hanger.

Align the THRT key with the slot in the TH. Lower the running assembly onto the TH and set off enough weight (10,000 to 15,000 lbs.) to make up o-rings and push down the hanger actuator into the locked position. The TH lock ring will expand.

(14) Vent the TH Lock and Unlock functions.

WARNING: Failure to vent the Lock function will prevent proper latching of the THRT to the TH.

(15) With 10,000 lbs weight on the hanger, function THRT Latch with 3,000 psig, and observe the latch ring move approximately 1.5 inches down. Observe engagement of the THRT lock dogs through the holes in the TH lock actuator ring.

CAUTION: Maintain and monitor pressure (3,000 psi) on the “Latch” function throughout this running procedure until hanger is landed and locked into the spool body.

(16) Function TH Unlock. Verify movement of the TH actuator ring and the THRT outer sleeve moves upward allowing the TH lock ring to contract.

(17) Function TH Lock. Verify the TH lock ring expands properly. Verify pressure increase on Lock Monitor line. Open the isolated Lock Monitor line to purge air and check returns. Vent the Lock function and verify the Lock Monitor gage reads 0 psig. Isolate the Lock Monitor.

CAUTION: The Lock Monitor should remain isolated during the complete operation of the tubing hanger running sequence. Pressure build up will be monitored on the Lock Monitor gage.

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(18) Apply operator specified pressure to a maximum of 8,000 psig down the THRT Vent function. Hold pressure for 5 minutes, bleed to 0 psig and repeat. This will test the following:

a. THRT to TH interface connection (properly latched) b. Pressure integrity of the production stabs, downhole control line

stabs, and o-rings on the THRT. c. THRT to SSTT interface (vent stab is removed)

CAUTION: Do not apply pressure to “Vent” function in any situation where tubing weight is suspended by THRT.

(19) Bleed pressure from the THRT Vent function. Keep vented through remainder of installation.

(20) Pressure test each downhole line through the SSTT by applying customer specified running pressure and hold for 5 minutes. Ensure no leakage.

(21) Function TH Unlock. Verify upward movement of the TH actuator ring and the THRT outer sleeve. Verify TH lock ring contracts until flush with the OD of the TH.

(22) Ensure any trapped air is removed from the soft land system. a. With the soft landing piston in the fully retracted position (collapsed

mode) remove the NPT plug on the side of the soft landing piston to allow leakage to occur.

b. Slowly apply pressure to the soft landing piston to purge air through the NPT plug. DO NOT stroke the soft landing piston.

c. Cut off pressure and with fluid still flowing from the NPT port, reinstall the NPT plug.

(23) Apply 2,500 psig to TH soft landing piston and lock in pressure. Verify piston strokes downward approximately 4.0 inches. Hold for 5 minutes. Verify no leakage is occurring around the NPT plug or any other visible area on the THRT. Then, reduce pressure to approximately 1000 psig plus completion fluid differential head at depth, 3000 psig maximum. a. Example: Density (lb/cu.in.)=fluid density (Sp.Gr) x .0361 b. Differential = fluid density x Water Depth (ft) x 12 c. Soft land pressure = Riser Differential � Control Differential + 1000 d. Example: If riser fluid is 1.33 Sp.Gr., control fluid is 1.07 Sp.Gr.,

and water depth is 1000 ft, soft land pressure is: (1.33 -1.07) x .0361 x (1000 x 12) + 1000 = 1113 psi

(24) Install the TH shear cartridges in the Tubing Hanger lock actuator ring.

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Procedure B – Make Up the Downhole Control Lines to the Tubing Hanger

-JHA- Perform JHA for lifting of the completion and control line terminations.

(1) Pick up the Tubing Hanger at a level to view the bottom of the TH. (2) Place (2) 7/8-9 UNC lifting eyes into the side of the helix. Remove the

(4) torque screws which hold the orientation helix on the hanger body. Lower the helix from the tubing hanger.

(3) Feed the control lines through the helix. Each control line should be wrapped around the tubing per customer's specification to allow for extra play in the control lines in case of re-termination of the lines.

(4) Remove the plugs from the tubing connections in the bottom of hanger. (5) Flow through each downhole line and take fluid samples to verify

conformance to the required NAS cleanliness levels. (6) Cut and prep each downhole control line and terminate each line at the

tubing hanger bulkhead per customer instruction. Refer to Figure below for pictorial representation of the tubing hanger prep location.

PORT FUNCTION CONNECTION

A NOT APPLICABLE NOT APPLICABLE B SV1 9/16� MED. PRESS. AUTOCLAVE C SV2 9/16� MED. PRESS. AUTOCLAVE D NOT APPLICABLE NOT APPLICABLE E NOT APPLICABLE NOT APPLICABLE F NOT APPLICABLE NOT APPLICABLE G NOT APPLICABLE NOT APPLICABLE

ELECTRIC NOT APPLICABLE NOT APPLICABLE

(7) Pressure test each line by applying pressure per customer specification and verify there are no leaks at the bottom of the tubing hanger per customer's requirements for downhole equipment. If applicable, note that F and G are ported together in the TH circuit ring.

(8) For hangers with electrical lines, terminate the electrical line at the underside of the Tubing Hanger and perform electrical tests as required.

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(9) Reattach the helix to the bottom of the tubing hanger with the (4) torque screws. Ensure there is no contact between the helix and the control lines. Remove helix lifting eyes.

6.10.7 Run and Test the Tubing Hanger

(1) When running the tubing hanger, the control lines should be set as follows: a. Isolation pressure on all downhole lines as specified by the

customer. b. Verify pressure is locked in on the THRT soft landing piston.

NOTE: The TH Soft Landing Piston pressure is affected by the difference of the hydrostatic heads of the completion fluid (acting outside of the piston) and the control fluid (acting inside of the piston). Maintain Soft Landing Pressure considering the fluid pressure differential.

CAUTION: Monitor the soft landing piston pressure while running completion down hole. Pressure increases over soft landing pressure (48,000 lbs per 1000 psi) will indicate that the completion has hung up. Soft land pressure must be exceeded to see the pressure build up. Halt all downward motion immediately and take corrective action.

c. Verify THRT Latch is at 3,000 psig. d. Verify THRT Unlock is at 3,000 psig. e. Verify THRT Vent line is vented. f. Verify THRT Lock Monitor function is isolated. g. If applicable, verify the Electrical penetrator at the tree is

retracted. h. If applicable, verify any protective covers for the Electrical

Connector on the side of the hanger have been removed. i. Ensure the BOP�s are full open. j. Verify the spacers in between the running circuit ring and the

Tubing Hanger body have been removed. k. Verify that the TH circuit ring shear pins and Actuator ring shear

pin cartridges are installed.

-JHA- Perform JHA for running the completion string.

(2) Pick up the running assembly and TH. Remove the tubing slips and master bushing or the split landing bowl.

(3) Lower the running assembly through the rotary.

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(4) Run the tubing hanger downhole using the completion string. Monitor the THRT functions for pressure changes and take corrective action. Run the completion 45-70 degrees out of position either direction to visually monitor turning due to helix rotation. Rotation may not be visible at large depths. Note the helix capture angle to assist in engaging the helix when landing the hanger.

NOTE: Great care must be taken to run umbilicals at same rate as the running string and ensure they are properly clamped.

(5) Prior to entering the flex joint on the LMRP, land completion tubing in slips.

(6) Engage motion compensator to 20,000 lbs. Check that riser flex joint is less than 1/2 degree and rig heave is 4 ft. max.

Record total string weight (landing riser, safety tree, THRT, TH and tubing, heave, and flex joint angle).

Total Weight of Completion (lbs) Rig Heave (ft) Estimated Flex Joint

Angle (degrees)

(7) Open AMV and AAV to ensure that a hydraulic lock does not occur. (8) Increase and lock in soft land pressure to 3,000 psig. (9) Lower the completion assembly slowly until the THRT soft landing

piston �hard lands� on the shoulder in the spool body. Hard land the completion assembly with 20,000 lbs. down. Look for rotation of the string to verify orientation helix engagement. If rotation is not seen, the string may be rotated and torque built up to verify position.

CAUTION: Do not set more than 20,000 lbs. down on the soft landing piston during hard land. Maximum capacity of the soft landing sleeve on the THRT is 100,000 lbs.

(10) Bleed down the SCSSV pressure and equalize pressure inside all the downhole control lines to the differential pressure between the completion fluid and the control fluid at depth. (See the soft land piston pressure calculation / example shown previously).

NOTE: Equalizing pressure will maintain seal integrity. Positive pressure differentials of 100 to 500 psi are recommended.

NOTE: This will potentially close the SCSSV. (11) Ensure AMV and AAV are open, and all other valves are closed.

NOTE: This will force flow down to the AMV port, and then up to the riser through the AAV port.

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(12) Flush through the Tree Landing Ring ports.

-JHA- Perform JHA for flushing fluid compatability and pressures.

CAUTION: a. Consult the company representative to ensure that flushing is

done in a way consistent with fluid compatibility and depth. Some completion fluids and control fluids are incompatible and should not be mixed. Methanol, water and injection chemicals may also be incompatible.

b. It is important to adjust flushing pressures and valve opening sequence to prevent back flow through the tree porting control components. Ensure there is an additional 500 psi above hydrostatic on the valves prior to opening and only vent after the valve is closed.

The flushing sequence may be as follows if agreed by the company representative: a. Start with the downhole function tree isolation valves closed. b. Increase the flushing fluid supply pressure to a single downhole

function tree isolation valve to a pressure 500 psi above hydrostatic head at depth.

EXAMPLE: With a completion fluid of 11.1 ppg and a MeOH supply of .7915 SpGr, the pressure variation per foot is .58 psi/ft and .343 psi/ft, respectively. Assuming a water depth of 3000 ft and a 500 psi over balance on the MeOH line, the surface MeOH pressure would be 1,211 psi.

c. Then open the downhole function tree isolation valve for a short interval watching to see that the supply pressure remains overbalanced.

d. Close the valve and repeat. Ensure that the valve is closed before reducing the supply pressure.

e. Repeat flushing for remaining downhole ports. Be sure to account for variations in fluid density and compatibility.

(13) After pumping of fluid is completed, make sure the downhole function tree isolation valves are closed and vent any existing pressure in the lines.

(14) Verify 3,000 psig on the Latch, Unlock, and Soft Landing functions of the THRT. Vent all other functions of the THRT.

(15) Open the IMV and XOV valves and confirm AMV and AAV are open to ensure no hydraulic lock develops when landing the hanger.

(16) Adjust compensators to increase set off weight to 100,000 lbs. (17) Isolate the "Soft Landing" function to allow return fluid to be collected.

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(18) Ensure the downhole functions of the THRT are reduced to hydrostatic pressure. This will keep the differential pressure to a minimum when making the transition from the Stab Seals (from the tubing hanger to the spool body).

(19) Open the SCM valve and confirm that the AMON/SCM line is vented at the surface. As an option, place a pressure gauge on the AMON/SCM line at the surface to monitor pressure build-up and allow venting.

(20) If a pressure gauge was placed on the AMON/SCM line, monitor the pressure build up as soft landing occurs. Vent pressure as needed, close the valve and continue monitoring.

(21) Slowly bleed fluid from the Soft Landing function and collect the fluid until no further returns are seen. Gradually increase set-off weight to a maximum of 100,000 lbs as �Soft Landing� flow tapers off. The total volume of the soft landing piston is approximately 3500 cc (this volume may change due to hose expansion, length, etc.). Keep the Soft Landing function to Vent.

NOTE: Additional indication of hanger landing are: a) the AMON/SCM line will stop flowing and b) the downhole stab pressure will drop.

NOTE: If metal RLH seals are used on the hanger, the total load required to fully set the seals could be up to 225,000 lbs.

(22) After the Soft Landing has occurred, wait for at least one minute. Then slowly set off entire tubing string weight plus up to 50,000 lbs over string weight.

(23) A single downhole stab may be tested in order to verify that the stab seals have engaged the landing ring in the spool body. Open the tree valves SCM and SV1. Apply 5000 psi down SV1 and monitor the AMON/SCM line for returns.

(24) Close AAV. (25) Prepare to Lock the TH into the spool body.

NOTE: If the tubing hanger has metal to metal �RLH� seals, then the BOP may be closed and pressure applied above the tubing hanger to assist in setting the seals (steps 30 -33). Then lock the hanger to the tree.

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(26) Verify TH Lock Monitor is isolated and Unlock is vented. Function THRT Lock to 5,000 psig. Monitor the TH Lock Monitor pressure gauge for a pressure increase to 5,000 psig. Maintain Lock pressure for a minimum of 5 minutes.

NOTE: If the SSTT does not allow for 5,000 psi to be applied to the

Lock function, then the use of 3,000 psi is acceptable. NOTE: Lock pressure must be maintained for 5 minutes to ensure that

the THRT lock piston has fully stroked and locked down the hanger.

NOTE: Do NOT apply pressure below the BOP rams.

(27) To ensure full communication between the Lock and Lock Monitor circuits, vent the THRT Lock function to zero while observing the TH Lock Monitor pressure gauge for pressure decrease. Then apply 5,000 psig to the Lock function while monitoring the TH Lock Monitor pressure gauge for a pressure increase to 5,000 psig.

(28) Decrease the THRT Lock pressure to 3,000 psig. (29) Adjust the compensator for adequate riser tension and test that the tubing

hanger is locked down by pulling 100,000 lbs. over the weight of the riser/tubing hanger completion assembly. Set off the entire string weight plus up to 50,000 lbs.

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(30) Prepare to close the BOP. Increase THRT Latch pressure to counteract the tools’s emergency unlatch feature as follows:

a. In the case where the Latch Assist function is open to the riser by the

SSTT (i.e. direct hydraulic multi-line umbilical control), then the Latch pressure is to be increased to the BOP test pressure plus 500 psi (maximum 10,000 psi).

FUNCTION PRESSURE AREA FORCE Latch 10,000 34.95 Latch Assist Hydrostatic ~ 349,500

Emergency Unlatch Up to 10,000 30.86 308,600

b. In the case where the Latch and Latch Assist functions are ganged

together by the SSTT (i.e. electro-hydraulic system), then 5,000 psi should be applied to Latch and Latch Assist functions.

FUNCTION PRESSURE AREA FORCE Latch Latch Assist 5,000 (34.95+

31.91)=66.86 334,300

Emergency Unlatch Up to 10,000 30.86 308,600

(31) Close the BOP ram on safety tree, ensure SCM is open, and pressure test

the TH upper seal from above to specified pressure by customer up to 10,000 psi for 10 minutes and monitor gauge. Watch riser or the AMON/SCM line for returns. Bleed to zero.

NOTE: The pressure test will assist in setting the Tubing Hanger seals if required. Verify that the tubing hanger has been locked to the spool.

(32) Maintain Latch/Latch Assist pressure and open a BOP choke or kill line valve to prevent accidental pressure buildup.

(33) Reduce Latch pressure to 3,000 psi.

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(34) Tubing Hanger Stabs Seal Test

Test #11 Refer to SD-030495-11 for valve positions. a. Valve Positions:

Test #11

Valve Position Check Off IMV X IWV X XOV X AAV X AMV X AWV X SV1 O SV2 O SCM O GT X

X=CLOSED ; O=OPEN

b. Apply pressure up to 10,000 psi to test per customer requirements through SV1 and SV2 lines.

c. Hold pressure for 10 minutes and monitor gauges. d. Monitor the AMON/SCM line for returns or pressure increases. e. Bleed pressure to zero.

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(35) Tubing Hanger Gallery Seal Test

Test #12 Refer to SD-030495-12 for valve positions. (a) Valve Positions:

Test #12

Valve Position Check Off IMV O IWV X XOV O AAV O AMV X AWV X SV1 O SV2 O SCM O GT X

X=CLOSED ; O=OPEN

(b) Per customer requirements, apply up to 10,000 psi to the AMON/SCM line for 10 minutes to test below the upper TH seal and above the middle hanger seal.

(c) Monitor the SV1, SV2, and riser for returns or pressure increases.

(d) Bleed pressure to zero.

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(36) Tubing Hanger Production Seal Test


Test #13

Valve Position Check Off IMV O IWV X XOV O AAV X AMV X AWV O SV1 X SV2 X SCM X GT X

X=CLOSED ; O=OPEN

(b) Per customer requirements, apply up to 10,000 psi to AMON/SCM for 10 minutes to test below the middle hanger seal and above the lower hanger seal.

(c) Monitor the bore, pressure gauge, and injection pressure transducer for pressure drop.

(d) Bleed pressure to zero.

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(37) If applicable, ensure the electrical penetrator line is not powered / energized. Engage the electrical penetrator by rotating approximately 14 turns to the right with 50 ft-lbs.

(38) If applicable, test DHPT per customer procedures. (39) If downhole operations are to be performed, remove the tubing hanger

wireline isolation sleeve and install the wireline protection sleeve. Perform these operations per SSR International procedures (Section 12).

NOTE: Prior to running protection sleeve in the hole, verify the lock ring is installed right side up by placing a straight edge across the body of the sleeve and the lock ring. The lock ring should be below flush and tight fitting around the sleeve. If this is not the case, remove the lock ring and replace.

(40) Perform any downhole operations and/or flow testing of the well per customer procedure.

(41) Retrieve wireline protection sleeve and install the wire line plug per SSR procedures (Section 12).

NOTE: IMV, XOV, and AWV may be opened with the AMON/SCM line vented to assist in setting the wireline plug.

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(42) Tubing Hanger Wireline Plug Test from Above


Test #14


X=CLOSED ; O=OPEN

(b) Test the wireline plug from the top to test pressure per customer requirements by applying pressure through the tool bore.

(c) Hold pressure to customer's specifications. (d) Monitor the AMON/SCM line for returns. (e) Bleed pressure to zero.

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(43) Test Tubing Hanger Wireline Plug From Below


Test #15


X=CLOSED ; O=OPEN

(b) Test the wireline plug from below by applying allowable tubing shut in pressure per customer requirements to the AMON/SCM line. NOTE: Test pressure is applied above the closed downhole SCSSV.

(c) Hold pressure to customer's specifications. (d) Monitor the tool bore for returns. (e) Bleed pressure to zero.

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6.10.8 Retrieve THRT / SSTT

-JHA- Perform JHA for retrieval of THRT / SSTT and umbilical.

(1) Per customer procedure, prepare to retrieve the THRT/Safety Tree completion assembly.

(2) Ensure the BOP stack is fully open. (3) Regulate Lock function to 1,500 psi. Remove tension between the

THRT and hanger with the compensator. Vent the Latch and function the THRT Unlatch at 3,000 psig. Watch the Unlatch gauge for steady pressure to ensure that the THRT is fully unlatched from the hanger.

(4) Pick up the THRT/Safety Tree assembly above the flex joint. (5) The weight at this time should equal the recorded weight of the entire

completion assembly minus the recorded tubing and tubing hanger weight using the THHTT. The correct weight will verify that the THRT has successfully unlatched from the tubing hanger.

(6) Retrieve THRT/Safety tree completion assembly to surface. (7) Set all of the tree valves per operator procedure. (8) NOTE: At this point, it is advisable to run the tubing hanger wash

tool in order to clean any debris from above the hanger that may hamper landing the internal tree cap.

(9) If the Unlatch function does not operate for any reason, an Emergency Unlatch procedure is provided.

a. For Emergency THRT Unlatch only- set down 30,000 lbs. over string weight. Vent all functions. Apply pressure to TH Lock if control pressure is possible. Close the BOP Ram on Safety Tree Slick Joint and apply 1500 - 2000 psig down the choke and kill lines. Hold for 5 minutes. Pull up on the completion string and strip approximately 3-6 inches through the ram. Bleed pressure, and open the annular.

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6.11 Internal Tree Cap (ITC) Installation

6.11.1 Required Equipment A. Cameron Supplied Equipment

Description Part Number Qty. Internal Tree Cap (ITC) 2182251-02 1 TH Mill & Flush Jetting Tool 2181425-03 1 TH Running Tool (THRT) 2141700-01 1 THRTTT 2142736-01 1 THRT Test Skid 2142094-01 1 Stand for THRT 2142930-01 1

B. Consumable

Verify availability of spare parts listed in Section 13.

C. Controls Description Part Number Qty. Workover Utility Reel - alternative 1 Slick Joint and Adapter Joint - alternative 1

D. Technical Data Quick Reference ITC -OD (max-unlocked): 18.641�

-Max. torque capacity: 22,000 ft-lb -Displaced volume when landing: approximately 1.5 gallons

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6.11.2 Prepare Internal Tree Cap (ITC)

(1) Remove ITC from the pallet. Tree Cap can be lifted using 2X 1-1/4� holes provided in actuator ring. Place in suitable stand and inspect. Wipe any debris from production stab pocket.

(2) Remove protective tape covering the Internal Tree Cap seals. Inspect seals for any damage. Replace if necessary. Reinstall protective tape when complete.

(3) Remove the 2X lock-down shear pin cartridges (3/8� hex socket, item 12) from ITC actuator ring. These will be re-installed just prior to running the tree cap through the rotary table.

(4) Paint the bottom of the ITC for future troubleshooting purposes.

6.11.3 Prepare and Install THRT to ITC

NOTE: Prior to installing the ITC, the riser should be circulated with sea water. The riser should be thoroughly jet washed along with the top of the hanger. Cameron part number 2181425-03 is a jetting tool specially designed to clean the top of the hanger before installing a cap or tying back a running tool.

NOTE: If the ITC has the wireline plug installed prior to running (or the ITC is solid, i.e. no through bore), the running string must be filled with fluid during installation (i.e. weep sub above the SSTT).

NOTE: Ensure 40,000 lbs of string weight is available for seal setting.

-JHA- Perform JHA for handling, movement, and pressure testing of the THRT / SSTT, ITC, and umbilical.

(1) Prepare the THRT to run the Internal Tree Cap (ITC). a. The ITC is typically run using the same SSTT used to install the

Tubing Hanger. b. The SSTT may be removed and a slick joint crossover adapter

installed to the top of the Adapter joint to connect to the work string. Connect the THRT umbilical directly to the Adapter Joint.

(2) Lift the running assembly to a convenient working level and remove the control stabs protector ring (if installed). Inspect all o-rings and coat them with control fluid or Oceanic ACL water based grease.

(3) Verify that the correct lower production stab is installed in the THRT. (4) Prepare to test the running tool functions and verify movement of

assembly components in the following steps. Ensure that the THRT is in the Unlatched and Locked positions.

(5) The downhole control umbilical lines can be plugged and left unattached at the top of the SSTT.

(6) Close TH Lock Monitor "Test" and "Vent" needle valves.

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(7) The Soft Landing function will not be used to run the ITC. The umbilical line for this function may be plugged and left unattached. The piston may be stroked upward or left in its existing position.

(8) Function test the THRT. a) Function the Tubing Hanger Lock / Unlock and THRT Latch /

Unlatch a minimum of three times each. b) Each function should be operated without pressure on any other

function. c) Finish with the tool in the Unlatched and Locked position.

(9) Verify THRT is in the Locked and Unlatched positions. Apply 3,000 psig to the THRT Lock function.

(10) Set ITC on hole cover or stand. (11) Inspect the ITC production and control line stab pockets for debris and

wipe clean. (12) If applicable, visually inspect the wireline plug to ensure it is properly

installed. (13) Remove the ITC shear pin cartridges from the ITC lock actuator ring if

not done previously. (14) Vent the THRT Vent Line. (15) Move the THRT directly above the ITC. Align the THRT key with the

slot in the ITC. Lower the running assembly onto the ITC and set off enough weight (10,000 to 15,000 lbs) to make up o-rings and push down the ITC actuator into the locked position. The ITC lock ring will expand.

(16) Vent the THRT Lock and Unlock functions.

WARNING: Failure to vent the Lock function will prevent proper latching of the THRT to the ITC.

(17) With 10,000 lbs. weight on the ITC, Function THRT Latch with 3,000 psig, and observe latch ring moves approximately 1.5 inches down. Observe engagement of the THRT lock dogs through the holes in the ITC lock actuator ring. WARNING: Maintain and monitor pressure (3,000 psig) on the

"Latch" function throughout the remainder of this running procedure until the ITC is landed and locked into the spool body.

(18) Apply 3,000 psi down the Vent line to verify the THRT is latched to the ITC. Hold pressure for 3 minutes and bleed pressure to zero.

(19) Function TH Unlock. Verify upward movement of the ITC actuator ring, allowing the ITC lock ring to contract.

(20) Function TH Lock. Verify the ITC lock ring expands outward. Verify increase of pressure on Lock Monitor gage. If required, open the isolated Lock Monitor line to purge air and check returns. Vent the Lock function and verify the Lock Monitor gage reads 0 psig. Isolate the Lock Monitor. CAUTION: Tubing Hanger Lock Monitor must remain isolated

during the Internal Tree Cap installation!

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(21) Function TH Unlock. Verify upward movement of the ITC actuator and THRT outer sleeve. Verify the ITC lock ring contracts until flush with the OD of the ITC.

(22) Install the ITC shear cartridges in the side of the lock actuator ring.

6.11.4 Run and Test the ITC

-JHA- Perform JHA for running the ITC and umbilical.

(1) Remove hole cover and Master bushing. (2) Lower the ITC, THRT, and Running Assembly through the rotary.

Suspend the running assembly below the rotary table. (3) When running the internal tree cap, the THRT umbilical reel panel

should be set as follows:

Note: Great care must be taken to run umbilical at the same rate as

work string and that they are properly clamped. (4) Run the internal tree cap down hole using the completion string. Monitor

the THRT Vent line for pressure increase.

NOTE: The drill pipe running string may have to be filled with riser fluid (i.e. weep sub above the SSTT) if the W/L Plug is installed into the ITC or the ITC is of solid construction (i.e. no through bore).

(5) Prior to entering the flex joint on the LMRP, land the running string in slips.

(6) Engage motion compensator to 50,000 lbs. Check that riser flex joint is less than 1/2 degree and rig heave is 3 ft. max.

(7) Open AAV and AWV. Ensure that AMV is closed. (8) Pick up completion string and record the weight.

Recorded Weight of Completion Casing, THRT, and Adapter Joint

(9) Verify flushing fluid compatibility with the Company Representative.

Pump flushing fluid down the AMON/SCM line (through AWV and AAV).

THRT FUNCTIONS Latch 3,000 psig Unlock 3,000 psig Vent Vented Lock Verify Isolated Unlatch Vented Lock Vented

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(10) Monitor AMON/SCM for pressure increase during landing of the ITC. NOTE: The volume displaced by the ITC seals traveling down the seal surface in the spool body is approximately 1.5 gallons.

(11) Remove slips and land the ITC. As AMON/SCM pressure increases, indicating that the ITC seal has started to engage, vent the AMON/SCM line.

(12) The AMV may be opened to assist in flushing out debris. (13) Set off 40,000 lbs to energize the ITC seals. (14) If the ITC has metal RLH seals, close the BOP on the Safety Tree,

increase the THRT Latch pressure and apply pressure above tool down choke and kill to apply 150,000 downward load. Cap seal diameter is 17.82�.

(15) Verify TH Lock Monitor is isolated and Unlock is vented. Function THRT Lock to 5,000 psig. Monitor the TH Lock Monitor pressure gauge for a pressure increase to 5,000 psig. Maintain Lock pressure for a minimum of 5 minutes.

NOTE: If the SSTT does not allow for 5,000 psi to be applied to the

Lock function, then the use of 3,000 psi is acceptable. NOTE: Lock pressure must be maintained for 5 minutes to ensure that

the THRT lock piston has fully stroked and locked down the hanger.

NOTE: Do NOT apply pressure below the BOP rams.

(16) To ensure full communication between the Lock and Lock Monitor circuits, vent the THRT Lock function to zero while observing the TH Lock Monitor pressure gauge for pressure decrease. Then apply 5,000 psig to the Lock function while monitoring the TH Lock Monitor pressure gauge for a pressure increase to 5,000 psig.

(17) Decrease the THRT Lock pressure to 3,000 psig. (18) Open the BOP if previously closed for seal setting. (19) Adjust the compensator for adequate riser tension and test that the

internal tree cap is locked down by pulling 100,000 lbs. over the weight of the riser, THRT, ITC completion assembly. Set off the 40,000 lbs.

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(20) Test the ITC From Below with THRT Engaged

Test #16

Refer to SD-030495-16 for valve positions. (a) Valve Positions:

Test #16

Valve Position Check Off IMV X IWV X XOV X AAV O AMV X AWV O SV1 X SV2 X SCM X GT X

X=CLOSED ; O=OPEN (b) Apply customer specified pressure up to 10,000 psi to the

AMON/SCM line for 10 minutes. (c) Monitor the AMON/SCM line for pressure drops. (d) Bleed pressure to zero.

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(21) Maintain pressure on the Lock function. Function the THRT Unlatch at 3,000 psig. Ensure THRT Latch function is vented. Watch the Unlatch gauge for steady pressure to ensure that the THRT is fully unlatched from the ITC.

(22) Pick up the THRT/Running Assembly above the flex joint.

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(23) Test ITC From Above

Test #17

Refer to SD-030495-17 for valve positions. (a) Valve Positions:

Test #17

Valve Position Check Off IMV X IWV X XOV X AAV O AMV X AWV O SV1 X SV2 X SCM X GT X

X=CLOSED ; O=OPEN (b) Close BOP blind rams and apply up to 10,000 psi per customer

procedure down the choke and kill lines. (c) Stabilize and hold pressure per customer requirements. (d) Monitor the AMON/SCM line for pressure increase or returns. (e) Bleed pressure to zero.

Trouble shooting procedure a. Close the AWV and the XOV and monitor the AP Transducer for

pressure increase.

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(24) Test ITC From Below with THRT Dis-Engaged a. Repeat Test #16 with the THRT/Running Assembly dig-engaged

from the Internal Tree Cap to verify that the ITC is fully locked to the spool body.

-JHA- Perform JHA for retrieval and break out of THRT / Running Assembly.

(25) If testing is successful, bring the THRT/Running Assembly back to the surface. Break down equipment and perform post operational maintenance on the THRT.

(26) If the test fails, apply pressure to the Unlatch and Lock functions on the THRT, open the blind rams, and set the compensator for 5,000 lbs.

(27) Tag off the THRT onto the top of the ITC and rotate until a drop in the completion string is observed and/or torque begins to build. This will ensure the THRT is oriented properly on top of the ITC.

(28) Set off 50,000 lbs. of weight on top of the ITC. (29) Pick up the THRT/Running Assembly above the Flex Joint, and retest

above the ITC. (30) If test fails again, retrieve the ITC per the ITC Retrieval Procedure

(Section 8).

6.12 Disconnect IWOCS Umbilical from Tree

-JHA- Perform JHA for retrieval of IWOCS.

(1) Bleed pressure from the IWOCS umbilical. Power down the electrical lines. (2) Verify that all hydraulic tree valves are CLOSED. Set manual valves per

customer procedures. (3) Use the ROV to disconnect the IWOCS flying leads from the junction plates on

the tree. (4) Park flying leads as required. (5) Retrieve IWOC per rig procedures.

6.13 Retrieve BOP per Rig Procedures

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6.14 Install Tree Debris Cap

Note: In addition to Debris Cap Installation, this procedure allows for injection of corrosion inhibitor into the void between the top of the Internal Tree Cap and the Tree Debris Cap.

6.14.1 Required Equipment

A. Cameron Supplied Equipment

Description Part Number Qty. Debris Cap 2181899-04 1

B. ROV with Hot Stab plumbed to inject corrosion inhibitor at large

diameter port

6.14.2 Prepare Tree Debris Cap

(1) Inspect the three spring pins. (2) Remove dummy stab and connect a hot stab to the injection port. Flush

through using clean control fluid. Verify returns through the hose mounted inside the debris cap. Note: This direction of circulation is for control fluid that is heavier

than salt water. Salt water SG = 1. 025. For fluids lighter than salt water, the 12 " hose mounted inside the debris must be disconnected and connected to the bottom port of the check valve not connected to the injection port.

6.14.3 Run Debris Cap

(1) Run the debris cap, via ROV or tugger line. (2) Land the cap on to the tree orienting it such that the ROV has access to

the hot stab port. Set off weight to assure that the spring pins have correctly set under the tree mandrel profile.

(3) Pump control fluid through the hot stab and observe returns through the check valve.

(4) Remove hot stab and replace with dummy stab. (5) Release tugger from cap if installed. Retrieve to surface.

6.15 Fill Out Subsea Completion Summary

The subsea completion summary at the end of this section should be filled out by Cameron Service Personnel and returned to the Cameron Service Center / Engineering upon completion of this running procedure.

See Subsea Completion Summary � X-253515-01.

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7. STACK-UP DRAWINGS

Tree Stack-Up, Tree Running Tool (H4 Mandrel Profile) SD-030423-02 Stack-Up � BOP Test Tool, Bore Protector, Spool Body SD-030423-01 Stack-Up � Bore Protector, Bore Protector Running Tool, Spool Body SD-030423-04 Stack-Up � THRT, TH, Spool Body, In Soft Landing Position SD-030423-10 Stack-Up � THRT, TH, Spool Body, W/L Isolation Sleeve SD-030423-11 Stack-Up � THRT, TH, Spool Body, W/L Protection Sleeve SD-030423-12 Stack-Up � THRT, TH, Spool Body, 5.25� Plug SD-030423-13 Stack-Up � THRT, TH, ITC, Spool Body SD-030423-14 Stack-Up � ITC, Emergency TH Tool SD-030423-09 Stack-Up � TH w/o Plug, Emergency TH Tool SD-030423-06 Stack-Up � Spool Body, TH, ITC, Boll Weevil Tool SD-030423-05 Tree Landing Sequence SD-031141-02 Tree, TRT, and Stinger Landing SD-030423-03 Tree, TRT w/ Stinger SD-030423-07 Tree w/ Test Stump SD-030423-08

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8. RETRIEVAL PROCEDURES

8.1 Retrieve Tree Debris Cap (1) Run tugger line and/or ROV. (2) Make up line to handle (3/4 diameter bar). (3) Overpull approximately 100 lbs. to retrieve cap. (4) Retrieve the debris cap to the rig.

8.2 Run, Land, and Test BOP per Rig Procedures

The BOP may be tested by running the Boll Weevil test tool and landing it in the internal tree cap. See Section 9 for details of this tool. NOTE: Do not test higher than 10,000 psi on top of internal tree cap.

8.3 Internal Tree Cap Retrieval (ITC)

(1) To retrieve an installed ITC with the hydraulic THRT, the same running

assembly is used as installing the ITC. The running assembly consists of the THRT and Adapter Joint. (If desired, the Safety Tree may also be part of the assembly.)

(2) Function THRT to the �Unlatch� and �Unlock� position (3,000 psig) and verify upward movement of THRT outer lock sleeve.

(3) Function THRT �Lock� and verify downward movement of the THRT outer lock sleeve.

(4) Function THRT �Lock� and �Unlock� two times minimum to remove air, but finish with the tool in the �Lock� position.

(5) Function THRT �Latch�. Verify downward movement of the THRT inner actuator sleeve and expansion of the split latch ring.

(6) Function THRT �Unlatch�. Verify upward movement of THRT inner actuator ring and collapse of the split latch ring.

(7) Function THRT �Latch� and �Unlatch� two times minimum to remove air. Finish with the THRT in the �Unlatch� position.

(8) Verify THRT is in the �Lock� and �Unlatch� position.

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(9) Set the THRT umbilical panel as follows prior to running the THRT:

SCSSV1 and SCSSV2

Vent

Soft Land Vent Vent Vent Latch Vent Unlatch 3,000 psig Lock 3,000 psig Unlock Vent Lock Monitor Isolated

(10) Lower the retrieval assembly down hole. Space out riser joints such that the

THRT assembly will be a safe distance above the flex joint prior to making up the final riser joint.

(11) Make up the final riser joint. Unreel the THRT umbilical to give sufficient slack when THRT is landed on top of the ITC.

(12) Engage motion compensator. Check that the riser flex joint angle is less than ½ degree and rig heave is 4 feet maximum. Record the total string weight__________

(13) Land the THRT on the ITC; setting off only 5,000 pounds using the compensators.

(14) Rotate the completion casing to find the orientation slot in the top of the ITC. A visual drop in the completion string and/or a torque build up will indicate the slot has been located.

(15) Set off 50,000 lbs. on top of the ITC. (16) Observe THRT �Lock Monitor gauge increase to 3,000 psi. This means that the

THRT has fully landed on top of the ITC. (17) Vent THRT �Lock� and �Unlatch� functions. Wait 30 seconds. (18) Vent �Unlatch� and apply 3,000 psi to THRT �Latch�. (19) Verify latch with 10,000 lbs. overpull.

CAUTION: 3,000 PSI MUST BE MAINTAINED ON THE THRT �LATCH� FUNCTION AT ALL TIMES.

(20) Open AWV and AAV valves. Vent AMON/SCM line on junction plate. (21) Vent �Lock� and apply 3,000 psi to THRT �Unlock�. (22) Close the THRT �vent� line. (23) Overpull up to 150,000 lbs. to unseat ITC and lift ITC/THRT/Adapter Joint

assembly to a safe distance above the flex joint. Pressure may be applied down AMON/SCM line with AWV and AAV open and AMV closed to help unseat the ITC.

(24) Verify 3,000 psig is on the THRT �Latch� function. (25) Bring the completion assembly to the surface and rig down the THRT, Adapter

Joint, completion casing, umbilical, and ITC. Perform post operational maintenance on the THRT.

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8.4 Retrieve the SSR Wireline Plug

Retrieving the SSR plug requires steps 1-19 of the Tubing Hanger Retrieval Procedure for the hanger plug then follow SSR procedures in Section 12.

8.5 Retrieving the Tubing Hanger with the Hydraulic THRT

The BOP may be tested by running the Boll Weevil test tool and landing it in the tubing hanger. See Section 9 for details of this tool. (1) To retrieve an installed tubing hanger with the THRT, the same running

assembly is used as installing the tubing hanger. The running assembly consists of the THRT and Adapter Joint. (If desired, the Safety tree may also be part of the assembly.) Ensure stabs are installed in ports B and C and lower production stab assembly (2155994-02) is installed in THRT.

(2) Function THRT to the �Unlatch� and �Unlock� position (3,000 psig) and verify upward movement of THRT outer lock sleeve.

(3) Function THRT �Lock� and verify downward movement of the THRT outer lock sleeve.

(4) Function THRT �Lock� and �Unlock� two times minimum to remove air, but finish with the tubing hanger running tool in the �Lock� position.

(5) Function THRT �Latch�. Verify downward movement of the THRT inner actuator sleeve and expansion of the split latch ring.

(6) Function THRT �Unlatch�. Verify upward movement of THRT inner actuator ring and collapse of the split latch ring.

(7) Function THRT �Latch� and �Unlatch� two times minimum to remove air. Finish with the THRT in the �Unlatch� position.

(8) Verify THRT is in the �Lock� and �Unlatch� position. (9) Set the THRT umbilical panel as follows prior to running the THRT.

SCSSV1 and SCSSV2

Vent

Soft Land Vent Vent Vent Latch Vent Unlatch 3,000 psig Lock 3,000 psig Unlock Vent Lock Monitor Isolated

(10) Lower the running assembly down hole. Space out riser joints such that the

THRT assembly will be a safe distance above the flex joint prior to making up the final riser joint.

(11) Make up the final riser joint. Unreel the THRT umbilical to give sufficient slack when THRT is landed on top of the tubing hanger.

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(12) Engage motion compensator. Check that the riser flex joint angle is less than ½ degree and rig heave is 4 feet maximum. Record the total string weight__________

(13) Land the THRT on the tubing hanger; setting off only 5,000 lbs. using the compensators.

(14) Rotate the completion string to find the orientation slot in the top of the tubing hanger. A visual drop in the completion string and/or a torque build up will indicate the slot has been located.

(15) Set off 50,000 lbs. on top of the tubing hanger. (16) Observe THRT �Lock Monitor� gauge increase to 3,000 psi. This means that

the THRT has fully landed on top of the tubing hanger. (17) Vent THRT �Lock� and �Unlatch� functions. Wait 30 seconds. (18) Vent �Unlatch� and apply 3,000 psi to THRT �Latch�. (19) Perform a 10,000 lbs. overpull to verify latch. (20) Latch/vent integrity may be verified by applying up to 5,000 psi down Vent

function. Vent function must be vented after test. (21) Vent production string by opening IMV, XOV, AWV and venting AMON/SCM

line on junction plate. (22) Vent tubing annulus by opening the AMV and AAV. (23) Perform any necessary down hole operations and retrieve the wireline plug from

the production bore per SSR instructions in Section 12. Run wireline protection sleeve or isolation sleeve as appropriate. NOTE: Prior to running protection sleeve (or isolation sleeve) in the hole verify the lock ring is installed right side up by placing a straight edge across the body of the sleeve and the lock ring. The lock ring should be below flush and tight fitting around the sleeve. If this is not the case, remove the lock ring and replace.

(24) Vent �Lock� and apply 3,000 psi to THRT �Unlock�. CAUTION: 3,000 PSI MUST BE MAINTAINED ON THE THRT “LATCH” FUNCTION AT ALL TIMES WHILE TRIPPING THE TUBING HANGER OUT OF THE HOLE.

(25) Open SV1, SV2, SCM, IMV, XOV, AAV, AMV, and AWV valves. Vent SV1, SV2, and AMON/SCM lines.

(26) Overpull completion and string weight 20,000 lbs. Apply and maintain 2,500 psi on the soft Landing piston. Wait 2 minutes after applying pressure.

(27) Close the THRT �Vent� line. (28) Apply and maintain pressure to the SV1 and SV2 per customer�s specifications

to open the down hole SCSSV�s. Observe the Vent gauge for pressure increase. An increase in pressure may indicate a leak in the Control line stabs in the bottom of the THRT.

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(29) Lift TH/THRT/Adapter Joint assembly to a safe distance above the flex joint. Record weight. The weight recorded should be the weight of the THRT, Adapter Joint, and the completion casing plus the weight of the tubing hanger and tubing string. This weight was recorded in Section 6 of the running procedure.

Weight of Tubing and Tubing Hanger

Completion Assembly (lbs.)

(30) Verify 3,000 psig is on the THRT �Latch� functions and that SV1 and SV2 are

holding pressure. Verify there is no pressure build-up on the THRT �Vent� function gauge.

(31) Bring the completion assembly to the surface and rig down the THRT, Adapter Joint, completion casing, umbilical, and tubing hanger. Perform post operational maintenance on the THRT.

8.6 Install the Bore Protector and Retrieve the BOP

Note: The Bore Protector is required to be in place when stabbing the stinger on bottom of the TRT into the spool tree. Also if it is required to perform downhole work at this stage, then install the Bore Protector per Sections 6.

8.7 Retrieve the Spool Tree

8.7.1 Prepare the TRT and Stinger

(1) Inspect the TRT for damage. (2) Ensure that the pipe plug (item 20 on SK-098341-01) is REMOVED from the

bottom center of the TRT latch tool body as shown in Section A-A. This will provide communication through the drill string to the tree bore. The other similar pipe plugs must remain installed to contain operating pressure.

(3) Set up and test the workover unit with utility reel umbilical as per the workover unit manual. Connect the jumpers from utility umbilical to the TRT and test the tool functions. The functions should be smooth and repeatable. Note: Do not apply more than 1500 psi to the Gripper Latch function without connector rods in place. This can damage the grip fingers.

(4) Skid the tree trolley in the moonpool under the rotary table. (5) Place the Stinger Support Frame P/N 2215836-01 on the tree trolley. See SD-

030423-07. (6) Use the Stinger Lifting Cap to transport the Stinger to the moonpool. Rest the

Stinger on the Stinger Support Frame at the centralizer sleeve. (7) Remove the Stinger Lifting Cap.

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(8) Pick up the TRT to the moonpool and make it up to the Stinger. Caution: For safety purpose, special care must be taken during this

operation. (9) Pick up the TRT to allow removal of the Stinger Support Frame. Rest the TRT

with Stinger on the tree trolley. (10) Remove the lifting sub from the top of the TRT. (11) Send the crossover adapter (items 6 and 7 � see TRT latch tool SK-098341-01)

to the drill floor. (12) Make up the TRT crossover adapter (mandrel and union nut) to drill pipe. (13) Lower the drill pipe and crossover adapter through the rotary table and make it

up to the TRT. Make up Torques (approximate) - Union Nut: 300 ft-lb Set Screws: 80 ft-lb (14) Apply 3,000 psi to the TRT �Unlatch� function to UNLATCH the TRT latch

mechanism. (15) Verify markings on two override rods that indicate the TRT is in UNLATCHED

position. (16) VENT the �Gripper Latch� function. (17) Apply 3,000 psi to the tree connector �Unlock� function to keep the gripper

assemblies in UNLOCKED position.

8.7.2 Run the TRT and Retrieve the Tree (1) Ensure that the production control umbilical is vented and disconnected from

the tree junction plate. (2) Ensure that the bore protector is installed. (3) Run TRT with Stinger, ensuring correct TRT/Tree Heading. Use the ROV half

way down and check that the tool is UNLATCHED and the cylinders are RETRACTED.

(4) With the guidance of the Stinger, land the TRT on the Tree and set off 5,000 lb. (5) Vent the TRT �Unlatch� function. LATCH and TRT to the tree by supplying

3,000 psi to the TRT �Latch� function. (6) Verify markings on two override rods that indicate the TRT is latched.

MAINTAIN “LATCH” PRESSURE DURING RETRIEVAL. (7) Open the GT needle valve and place the dummy hot stab in the parking

receptacle. Also, place the GR/AAV dummy hot stab in the parking receptacle. (8) EXTEND the two gripper assemblies over the connector rods by supplying

3,000 psi to the connector �Lock� function. (9) Verify markings that indicate gripper assemblies in extended position. (10) LOCK the grippers to the connector rods by supplying 3,000 psi to the �Gripper

Latch� function. Maintain this pressure.

(11) UNLOCK the connector by venting the connector �Lock� function and supplying 3,000 psi to the connector �Unlock� function.

(12) Verify markings that indicate connector unlocked.

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(13) Pull straight up and retrieve TRT/Spool Tree assembly approximately 20 ft clear of wellhead.

Note: The pulling has to be done straight so the stinger can properly guide and protect the wellhead gasket from the nose on bottom of the isolation sleeve.

(14) Move rig to a designated safe location and retrieve TRT/Spool Tree assembly. Note: Use the ROV half way up and check that the tool is LATCHED and the

cylinders are RETRACTED. Also care must be taken to ensure that tree is not stopped going through the splash zone.

(15) Land the TRT/Spool Tree on support beams in the moonpool area, directly below the rotary.

(16) Apply 3,000 psi to the TRT �Unlatch� function while venting the �Latch� function to UNLATCH the TRT.

(17) Verify markings on the override rods that indicate TRT in unlatched position. (18) Vent the �Gripper Latch� function to release the grippers. (19) Remove the drill pipe adapter from the TRT and make up the lifting sub. (20) Lift up TRT with Stinger and place the Central Guide Receptacle (2180749-01)

on the Spool top and rest the Stinger on it at the centralizer sleeve. (21) Loosen the setscrews and unscrew the coupling nut to separate the TRT from

Stinger. Set TRT on deck. (22) Install Stinger Lifting Cap to remove Stinger from Tree. Remove Central Guide

Receptacle. (23) Lift Spool Tree using the tree handling tool and set on deck.

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9. RUNNING TOOL AND TEST EQUIPMENT (RENTAL)

Tree Handling Tool 2142462-01 SK-126219-01 Tree Running Tool 2055145-19 SK-098343-19 SK-098343-15 TRT Hydraulic Latch Tool 2055231-01 SK-098341-01 Landing Ring Test Stab 2142827-01 N/A Dual Port Hot Stab 2215891-01 SK-039550-01 Bore Protector 2141626-01 SK-126202-01 Bore Protector Running/Retrieval Tool 2027776-01 SK-096284-01 BOP Weight Set Test Tool 2142424-01 SK-126274-01 Tubing Hanger Torque Sleeve 2155206-01 SK-126644-01 Tubing Hanger Running Tool 2141700-01 SK-069795-01 Tubing Hanger Handling Test Tool 2142721-01 SK-126342-01 Tubing Hanger Emergency Retrieval Tool 2141825-01 SK-126278-01 THRT Handling/Test Tool 2142736-01 SK-126346-01 THRT Pressure Test Stand 2142094-01 SK-126398-01 Tubing Hanger Wash Tool 2181425-01 SK-126919-01 Boll Weevil Test Tool 2155548-01 SK-126528-01 Isolation Sleeve Installation Tool 2182907-01 SK-081274-01 X-232328-02 X-232490-02 X-205567-03

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Description: TREE HANDLING TOOL Part No.: 2142462-01 P/N Revision: C01 Drawing No.: SK-126219-01

ITEM QTY. PART NO. DESCRIPTION 1 1 2142463-01 BODY WITH LIFTING EYE, TREE HANDLING TOOL 2 1 2142464-01 CLAMP SEGMENTS, TREE HANDLING TOOL 3 4 2142465-01 LOCKSCREW, TREE HANDLING TOOL 4 1 2749643-01 SHACKLE, ANCHOR, 3.00 X 3.25 PIN DIA, 85 TON 9 4 2709000-17-01 NUT, HVY HEX 1.875-8 STL ZN PL

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Description: TREE RUNNING TOOL Part No.: 2055145-19 P/N Revision: 01 Drawing No.: SK-098343-19, SK-098343-15

ITEM QTY. PART NO. DESCRIPTION 1 1 713522 ACCUMULATOR, HYD 2.5 GAL 5000 PSI 2 4 702502-02-00-05 SCREW, HEX HD CAP .250-20 X .625 3 1 2185737-01 ASSEMBLY, ROV PANEL FOR THE 4 1 2055145-17 ASSY, TREE RUNNING TOOL, SPOOLTREE 5 1 2235514-01 HYDRAULIC SCHEMATIC, TREE RUNNING TOOL W 6 4 702586-22-00-50 SCREW, HEX HD CAP 1.125-8 X 5.000 7 4 2709000-11-01 NUT, HVY HEX 1.125-8 GR 2H ZN PL 8 1 2235991-01 2.5 GALLON ACCUM. MOUNTING BRACKET 9 1 2749933-01 U-BOLT, ROUND BEND, .500 X 11.00 X 9.75 10 2 2709000-05-01 NUT, HVY HEX .500-13 GR 2H ZN PL 11 12 702586-22-00-30 SCREW, HEX HD CAP 1.125-8 X 3.000

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Description: TRT HYDRAULIC LATCH TOOL Part No.: 2055231-01 P/N Revision: D02 Drawing No.: SK-098341-01

ITEM QTY. PART NO. DESCRIPTION 1 1 2055232-01 CENTRE BODY, HYD LATCH TOOL 2 1 2055235-01 LOWER BODY, HYD LATCH TOOL. 3 1 2156300-01 LOCK SEGMENTS, TREE RUNNING TOOL 4 1 2045671-02 ACTUATOR RING, HYD LATCH TOOL. 5 1 2045191-02 SEAL RING, HYD LATCH TOOL. 6 1 2045156-03 MANDREL, HYD LATCH TOOL. 7 1 2045157-03 COUPLING NUT, HYD LATCH TOOL. 8 1 2045154-02 SEAL SUB, HYD LATCH TOOL. 9 2 2055234-01 OVERRIDE ROD, HYD LATCH TOOL. 10 2 2748767-01 SEAL RING, PISTON T SEAL TO FIT 11 2 702645-45-41 O-RG .275W X 12.475ID 90D NITRILE 12 1 702645-45-61 O-RG .275W X 13.475ID 90D NITRILE 13 2 702645-46-41 O-RG .275W X 17.455ID 90D NITRILE 14 4 702645-31-71 O RING, SIZE AS-568-317 .912 ID X 15 2 042000-04-54 BACK-UP RING, SIZE 454 12.524 ID X 16 8 042000-03-17 BACK-UP RING, SIZE 317 .950 ID X 17 2 042000-04-56 BACK-UP RING, SIZE 456 13.524 ID X 18 2 2704897-01 EYE NUT, 1.250-7 UNC GALV STL G400 19 1 2055279-01 KEY - HYD LATCH TOOL. 20 8 203724 PLUG, PIPE-THREADED HEX SOC 1/4 21 6 701983 SPRING PLUNGER, .625-11 X 1.500 LG 22 12 702515-21-20-12 SCREW, SOC HD SET .375-16 X .750 23 2 702505-10-00-16 SCR 0.500-13 X 1.750 SOC HD CAP 24 6 2045687-01 STOP, SPRING PLUNGER, TRT CENTER 25 1 2055233-01 MOUNTING NUT, HYD LATCH TOOL. 26 2 702585-16-00-12 SCREW, 12 PT CAP .750-10 X 1.250 27 12 702515-17-21 SCREW, SOC HD SET .250-20 X 1.000 29 1 708250 THREAD PROTECTOR, 4.500 API IF-TJ 30 1 2156329-01 THREAD PROTECTOR, 5.655" 4 TPI STUB 35 1 702645-34-72 O RING, SIZE AS-568-347 4.225 ID X 36 1 042000-03-47 BACK-UP RING, SIZE 347 4.278 ID X 37 1 702501-10-00-12 SCR 0.500-13 X 1.250 GR 5 ZN HEX HD CAP 38 1 2748768-01 SEAL RING, PISTON T SEAL TO FIT

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Description: LANDING RING TEST STAB Part No.: 2142827-01 P/N Revision: C01 Drawing No.: (No Drawing)

ITEM QTY. PART NO. DESCRIPTION 1 1 2142820-01 TEST STAB FOR CONTROL LINE REC 2 2 702645-20-81 O RING, SIZE AS-568-208 .609 ID X .139 W 3 2 2748250-01 BACK UP RING, SIZE 208, VIRGIN PEEK MATERIAL

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Description: DUAL PORT HOT STAB Part No.: 2215891-01 P/N Revision: 01 Drawing No.: SK-039550-01

ITEM QTY. PART NO. DESCRIPTION 0 1 2215891-99 O-RING KIT, DUAL PORT HOT STAB 1 1 2215847-01 BODY, HOT STAB, DUAL PORT, 10,000 2 1 2215876-01 COMPLIANT HANDLE, HOT STAB 3 1 2215848-01 NOSE, HOT STAB 4 2 702645-31-81 O RING, SIZE AS-568-318 .975 ID 5 2 702645-32-31 O RING, SIZE AS-568-323 1.287 ID 6 2 2706572-01 PLUG, MALE, PLASTIC, 1/4NPT, SERRAT 7 2 711752 PIPE PLUG, 1/8" 316 S/S 8 1 702502-06-00-26 SCREW, HEX HD CAP .375-16 X 2.750 9 1 2749695-02 LOCKNUT, HEX FULL HT .375-16 SST 10 2 500594-04 PLUG, TAPERED DUST .24 - .30 OD 11 0.1 711706 SEALANT, THREAD - LOCTITE 567 12 1 702505-06-00-05 SCREW, SOC HD CAP .375-16 X .625 13 .02 667172-02-29 ADHESIVE, LOCTITE 242 MED STR

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Description: BORE PROTECTOR Part No.: 2141626-01 P/N Revision: 02 Drawing No.: SK-126202-01

ITEM QTY. PART NO. DESCRIPTION 0 6 2155653-02 SHEAR PIN, G2 BORE PROTECTOR, NAVAL 1 1 2141648-01 LOWER BODY, BORE PROTECTOR, G2 2 1 2141649-01 UPPER BODY, BORE PROTECTOR, G2 3 1 2141669-01 ACTUATOR SLEEVE, BORE PROTECTOR, 4 1 2141675-03 LOCK RING, SPLIT, BORE PROTECTOR, 5 4 2141499-02 LOAD PIN, TUBING HANGER, 6 4 2141663-01 ASSY, SHEAR PIN CARTRIDGE, TUBING 7 6 021812-94 PIN, DOWEL .436/.432 OD X 1.750 LG, 8 1 702645-45-61 O-RG .275W X 13.475ID 90D NITRILE 9 2 702645-46-31 O RING, SIZE AS-568-463 16.955 ID X 10 1 702645-45-81 O-RG .275W X 14.475ID 90D NITRILE 11 6 2123753-01 LOAD PIN 12 2 2155677-01 TAB, G2 BORE PROTECTOR 13 1 2155676-01 ANTIROTATION KEY, G2 BORE PROTECTOR 14 2 702583-06-00-04 SCREW, 12 PT CAP .375-16 X .500 15 2 2748379-01 SPRING, CPRSN .065 X .720 OD X 16 6 2155653-01 SHEAR PIN, G2 BORE PROTECTOR,TEFLON 17 4 2026808-04 THREADED RETAINER, SHEAR PIN ASSY

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Description: BORE PROTECTOR RUNNING/RETRIEVAL TOOL Part No.: 2027776-01 P/N Revision: B02 Drawing No.: SK-096284-01

ITEM QTY. PART NO. DESCRIPTION 1 1 2027777-01 BODY, BORE PROT. RUN/RETRIEVAL TOOL 2 4 646886-02 TORQUE PIN, 1.688 OAL, W/.861 LONG 3 4 262688-01 SUPPORT DOG, WEAR BUSHING RUN/RET 4 4 021812-30 PIN, DOWEL .501/.498 OD X 2.000 LG, 5 4 018583-08 SPRING, COIL COMPRESSION, 1-1/8 OD 6 4 048877-01 SCR SOC HD CAP SPECIAL 7 4 006039-22 BALL, .750 DIA SST 440 8 4 048878-01 SLEEVE,BALL RETAINER, FOR RUNNING 9 4 018510-04 SPRING,COMPRESSION 23/32 OD X 10 4 696674-06 CAM, WR. BUSH. RUN. TOOL 15.50 LONG 11 4 018572-64 RETAINING RING, SPIROLOX- INT FOR 12 1 708250 THREAD PROTECTOR, 4.500 API IF-TJ 13 1 709421 SUB, DRILL PIPE API NC50 IF PIN X 14 1 709415 THREAD LOCKING COMPOUND, BAKERLOK 15 1 2748388-01 NIPPLE, DRILL PIPE, API NC50 16 1 706824 THREAD SEALING COMPOUND, BAKERSEAL 18 1 006050-49 THREAD PROTECTOR, 4.500 API IF-TJ

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Description: BOP WEIGHT SET TEST TOOL Part No.: 2142424-01 P/N Revision: 02 Drawing No.: SK-126274-01

ITEM QTY. PART NO. DESCRIPTION 1 1 263102-01 BODY, WT SET TEST TOOL, 18 3/4" HOUSING 2 1 2142423-01 LOWER BODY, MODULAR TREE WEIGHT SET TEST TOOL 3 1 263093-01 UPPER MANDREL, STM-15 WT SET TEST TOOL 4 1 2142422-01 LOWER MANDREL, MODULAR TREE WEIGHT SET TEST TOOL 5 1 263092-01 SEAL-RING, STM-15 WT SET TEST TOOL 6 1 263116-01 COLLAR, STM-15 WEIGHT SET TEST TOOL 7 1 263121-01 RELEASE RING, STM-15 WT SET TEST TOOL 8 16 263120-01 RELEASE DOG, STM-15 WEIGHT SET TEST TOOL 9 10 702515-31-51-04 SCREW, SOC HD SET , .875-9 X 1.250 SST FULL DOG PT 10 16 702515-25-51-04 SCREW, SOC HD SET .500-13 X 1.250 SST FULL DPG PT 11 2 203724 PLUG, PIPE-THREADED HEX SOC 1/4 SST 316 B16.11 12 2 702640-42-71 O RING, SIZE AS-568-427 4.725 ID X .275 W 90D /MS-1004 13 2 714148 SEAL RING,11.00 ID X11.75 OD X .375 LG POLYPAK MOLYTHANE 14 2 714129 SEAL RING,14.00 ID X14.75 OD X .375 LG POLYPAK MOLYTHANE 15 1 605894-12 SEAL RING, 18-5/8-15M SPECIAL FOR 16 6 702514-21-21 SCREW, SOC HD SET .375-16 X 1.000 STL CUP PT 17 2 702585-06-00-14 SCREW, 12 PT CAP .375-16 X 1.500 STL /A193 GR B7 18 1 2018062-01 MANDREL COLLAR, STM-15 WT SET TEST TOOL 19 8 702585-16-00-64 SCREW, 12 PT CAP .750-10 X 6.500 STL /A193 GR B7 20 1 2018293-01 OUTER RING, BODY, WT. SET TEST TOOL 18 3/4" HSG 21 1 708250 THREAD PROTECTOR, 4.500 API IF-TJ BOX 22 1 006050-49 THREAD PROTECTOR, 4.500 API IF-TJ PIN 23 1 2142447-01 LOAD RING, MODULAR TREE WEIGHT SET TEST TOOL

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Description: TUBING HANGER TORQUE SLEEVE Part No.: 2155206-01 P/N Revision: B01 Drawing No.: SK-126644-01

ITEM QTY. PART NO. DESCRIPTION 1 1 2155205-01 PROTECTION AND TORQUE SLEEVE 2 4 2709000-11-01 NUT, HVY HEX 1.125-8 STL ZN PL 3 2 219065-11-07-01 STUD, DBL ENDED 1.125-8UN-2A X 7.00" 4 1 2142721-01 ASSY, TUBING HANGER HANDLING/TEST TOOL

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Description: TUBING HANGER RUNNING TOOL Part No.: 2141700-01 P/N Revision: 01 Drawing No.: SK-069795-01

ITEM QTY. PART NO. DESCRIPTION 1 1 2141701-01 BODY, TUBING HANGER RUNNING TOOL 2 1 2098620-02 SPLIT LOAD RING, G2 THRT 3 1 2098619-02 LOWER STOP RING, G2 THRT 4 1 2098621-02 UPPER STOP RING, G2 THRT 5 1 2124409-02 PIN, ALIGNMENT, G2 THRT 6 1 199391-03 LOCK DOGS, G2 THRT 7 1 2026976-02 CONTROL LINE STAB MANDREL, ELECT. 8 12 190344-05 CONTROL STAB MANDREL 9 1 199402-05 SPLIT LATCH RING, G2 THRT 10 1 2141685-01 RETAINING NUT, TUBING HANGER 11 1 2141647-01 LATCH ACTUATOR PISTON, TBG HGR 12 1 2141677-01 SOFT LANDING PISTON, TBG HGR 13 1 2141679-01 SOFT LANDING SLEEVE, TBG HGR 14 1 2141681-01 KEY, TBG HGR RUNNING TOOL, G2 SPOOL 15 1 2141686-01 BACK-UP RING, THRT, G2 SPOOLTREE 16 1 2141690-01 LOCK ACTUATOR RING, TBG HGR RUNNING 17 1 2141691-01 PISTON, ACTUATOR LOCK, TBG HGR 18 1 2141693-01 EXTENSION SLEEVE BODY, TBG HGR 19 1 2142716-01 POPPET HOUSING, TUBING HANGER 20 1 2142717-02 POPPET, TUBING HANGER RUNNING TOOL 21 1 2142718-01 STAB SUB, UPPER PRODUCTION, TUBING 22 1 2155994-01 ASSY, LANDING RING AND STAB SUB 23 6 2141743-01 SEAL SLEEVE, THRT LOWER STAB, G2 24 6 2141744-01 BODY, THRT LOWER STAB, G2 SPOOLTREE 25 6 2141748-01 FLOW SHAFT, THRT LOWER STAB, G2 26 5 702645-45-81 O-RG .275W X 14.475ID 90D NITRILE 27 10 042000-04-58 BACK-UP RING, SIZE 458 14.524 ID 28 5 702645-45-51 O RING, SIZE AS-568-455 12.975 ID 29 10 042000-04-55 BACK-UP RING, SIZE 455 13.024 ID 30 7 702645-38-01 O RING, SIZE AS-568-380 11.475 ID 31 14 042000-03-80 BACK-UP RING, SIZE 380 11.528 ID 32 1 702645-46-01 O-RG .275W X 15.475ID 90D NITRILE 33 2 042000-04-60 BACK-UP RING, SIZE 460 15.524 ID X 34 1 2142823-01 STOP RING, TUBING HANGER RUNNING TO 35 8 702514-21-20-10 SCREW, SOC HD SET .375-16 X .625 36 3 702645-38-11 O-RG .210W X 11.975ID 90D NITRILE 37 6 702645-44-61 O RING, SIZE AS-568-446 8.475 ID

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ITEM QTY. PART NO. DESCRIPTION 38 12 041327-16 BACK-UP RING, SIZE 446 8.524 ID 39 2 702645-44-41 O-RG .275W X 07.725ID 90D NITRILE 41 2 042000-03-81 BACK-UP RING, SIZE 381 12.028 ID 42 11 702505-02-00-04 SCR 0.250-20 X 0.500 SOC HD CAP 43 12 702505-06-00-22 SCR 0.375-16 X 2.250 SOC HD CAP 44 6 702640-01-31 O RING, SIZE AS-568-013 .426 ID 45 12 042000-00-13 BACK-UP RING, SIZE 013 .455 ID 46 12 702640-00-71 O RING, SIZE AS-568-007 .145 ID 47 1 702645-12-11 O RING, SIZE AS-568-121 1.049 ID 48 2 042000-01-21 BACK UP RING, SIZE 121 1.081 ID 49 31 702645-12-01 O RING, SIZE AS-568-120 .987 ID 50 25 042000-01-20 BACK-UP RING, SIZE 120 1.018 ID 51 1 702645-01-11 O-RG .070W X 00.301ID 90D NITRILE 011 52 2 042000-00-11 BACK UP RING, SIZE 011 .327 ID 53 3 702645-21-01 O RING, SIZE AS-568-210 .734 ID 54 6 042000-02-10 BACK UP RING, SIZE 210 .766 ID 55 42 702645-20-61 O RING, SIZE AS-568-206 .484 ID 56 84 2748250-10 BACK UP RING,SIZE 206, .518 ID 57 7 002504-09 PLUG, PIPE 1/4" SST 18-8 Y52008-00010501 58 2 702585-14-00-12 SCREW, 12 PT CAP .625-11 X 1.250 59 4 702514-29-21 SCR 0.750-10 X 1.000 CUP PT SOC HD SET 60 8 702504-14-00-05 SCREW, SOC HD CAP .625-11 X .625 61 4 005940-99 SCREW, SOC HD SET .250-20 X .625 62 4 702501-10-00-06 SCREW, HEX HD CAP .500-13 X .750 63 1 712406 SPRING, CPRSN .063 X .480 OD 64 6 2748257-01 SPRING, COMPRESSION, .067 WIRE 65 4 2054285-01 PIN, TUBING HANGER RUNNING TOOL 66 1 2054287-03 PROTECTOR, TUBING HANGER RUNNING 67 1 002504-05 PLUG, PIPE-THREADED HEX SOC 1/8 68 4 005940-11 SCREW, SOC HD SET .375-16 X .625 69 6 2142840-01 BLANKING PLUG, UPPER, CONTROL LINE 70 6 2142841-01 BLANKING PLUG, LOWER, CONTROL LINE 71 1 2142719-02 STAB SUB, LOWER PRODUCTION, NEWFIEL 72 1 2142719-03 STAB SUB, LOWER PRODUCTION, JANICE 73 1 2181097-01 ASSY, LOCK VERIFY PLUG, THRT 75 1 2182458-01 BODY, STAB SUB, LOWER PRODUCTION 76 1 2155994-02 ASS'Y, STAB SUB & CENTRALIZER 78 1 2142719-04 STAB SUB, LOWER PRODUCTION, JANICE 79 1 2165804-01 SUBASSY, BORE REDUCTION SLEEVE 80 1 041259-69-01-10 S SEAL RING - 9 NOM. OD

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Description: TUBING HANGER HANDLING TEST TOOL Part No.: 2142721-01 P/N Revision: E01 Drawing No.: SK-126342-01

ITEM QTY. PART NO. DESCRIPTION 1 1 2142672-01 BODY, TUBING HANGER HANDLING TOOL, 2 1 2072186-03 ASSY, MANDREL, 4-1/2" ADAPTER, NON- 3 1 2123722-01 LOCK RING, TUBING HANGER HANDLING 4 6 2142673-01 MALE STAB, TUBING HANGER HANDLING 6 1 2142674-01 ACTUATOR RING, TBG HGR HANDLING 7 6 018572-65 RETAINING RING, SPIROLOX, EXT FOR 8 1 2123723-02 KEY, TUBING HANGER HANDLING TOOL, 9 1 702585-16-00-10 SCREW, 12 PT CAP .750-10 X 1.000 10 3 702586-18-00-26 SCR 0.875-09 X 2.750 B7 ZN HEX HD CAP 11 3 702586-19-00-24 SCREW, HEX HD CAP 1.000-8 X 2.500 12 6 702645-02-31 O RING, SIZE AS-568-023 1.051 ID X 13 12 042000-00-23 BACK-UP RING, SIZE 023 1.080 ID X

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Description: TUBING HANGER RETRIEVAL TOOL Part No.: 2141825-01 P/N Revision: J01 Drawing No.: SK-126278-01

ITEM QTY. PART NO. DESCRIPTION 0 1 2155607-01 ASSY, TEST PLUGS FOR HYDROSTATIC 0 1 2155607-02 ASSY, TEST PLUGS FOR HYDROSTATIC 0 1 2155607-03 ASSY, TEST PLUGS FOR HYDROSTATIC 0 1 2142492-01 ASSY, 5.25" NOM X 35" LG SEAL STAB, 0 1 2142603-01 ASSY, 5.25" NOM X 40" LG SEAL STAB, 0 1 2155142-01 ASSY, 4.767" NOM X 40" LG SEAL STAB 0 1 2156843-01 ASSY, 6.7"NOM X 41.125" LG SEAL 0 1 2182716-01 ASSY, 4.00" NOM X 41.56" LG 1 1 2142438-01 BODY, TUBING HANGER RETRIEVAL TOOL 2 1 2142494-01 MANDREL, TUBING HANGER RETRIEVAL 3 1 2142441-01 SPLIT LOCK RING, TUBING HANGER 4 1 2142440-01 ACTUATOR SLEEVE, TUBING HANGER 5 4 2045346-01 ACTUATOR RETAINER SCREW, TUBING 6 1 2142439-01 RETAINER STAB, TUBING HANGER 8 1 2045226-01 CENTRALIZER RING, TUBING HANGER 9 1 2045355-01 UPPER CENTRALIZER SPLIT RING, 10 1 2045356-01 LOWER CENTRALIZER SPLIT RING, 11 4 2142442-01 RETAINER SET SCREW, TUBING HANGER 12 2 702645-42-61 O RING, SIZE AS-568-426 4.600 ID X 13 4 702585-16-00-40 SCREW, 12 PT CAP .750-10 X 4.000 15 1 2098343-01 SPACER RING, CENTRALIZER, TUBING 16 1 2156972-01 KEY, ORIENTATION, SPRING LOADED F/ 17 1 702505-06-00-40 SCR 0.375-16 X 4.000 SOC HD CAP 18 4 713999 SPRING, CPRSN- .072 X .600 OD X

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Description: THRT HANDLING/TEST TOOL Part No.: 2142736-01 P/N Revision: 01 Drawing No.: SK-126346-01

ITEM QTY. PART NO. DESCRIPTION 1 1 2142735-01 BODY, HANDLING TOOL, THRT 2 1 2141685-01 RETAINING NUT, THRT 3 4 702515-29-11 SCREW, SOC HD SET .750-10 X 1.000 SST 4 1 041008-12-75-62 RETAINING RING, SPRIROLOX-EXT 5 2 702640-38-11 O RING, SIZE AS-568-381 11.975 ID 6 14 2749058-01 ADAPTER, 3/8 MED PRESS SF375CX 7 2 2705676-07 EYEBOLT, FORGED-SHLDR PATT .875-9 8 4 042000-03-81 BACK-UP RING, SIZE 381 12.028 ID X 12.394 9 1 703231 CONNECTOR, TBG MALE 1/4 NPTF X 3/8 TBG 10 14 2711279-01 CAP, TBG, 3/8" OD M/P, 20,000 PSI, 316 SST 11 1 2181292-01 ADAPTER MANDREL, NC50 (4.5 IF) API IF BOX 12 1 2181293-01 KEY, ANTI-ROTATION, ADAPTER MANDREL 13 1 702505-06-00-07 SCREW, SOC HD CAP .375-16 X .875 SST 316 14 1 708250 THREAD PROTECTOR, 4.500 API IF-TJ BOX 50 14 2730462 3/8" MEDIUM PRESSURE AUTOCLAVE

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Description: THRT PRESSURE TEST STAND Part No.: 2142094-01 P/N Revision: D01 Drawing No.: SK-126398-01

ITEM QTY. PART NO. DESCRIPTION 1 1 2142971-01 BODY, PRESSURE TESTING STAND 2 1 2142972-01 BASE, PRESSURE TESTING STAND 3 1 2142973-01 CUP, PRESSURE TESTING STAND 4 12 702583-10-00-14 SCREW, 12 PT CAP .500-13 X 1.500 5 1 2749744-01 SCREW, HEX HD CAP .750-10 X 2.500 6 4 2748288-01 BOLT, EYE, 1"-8 X 1.06 LG 7 4 W0106192 BOLT EYE .75-10X.88LG SS 8 6 702526-02-14 SCREW, SOC HD SHLDR .312D X 1.500

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Description: TUBING HANGER WASH TOOL Part No.: 2181425-01 P/N Revision: C01 Drawing No.: SK-126919-01

ITEM QTY. PART NO. DESCRIPTION 0 1 2749095-01 WRENCH FOR INSTALLING SMITH SERIES 70 NOZZLES 1 1 2181433-01 BODY, MILL & FLUSH TOOL, G2 TUBING HANGER SYSTEM 2 10 2749093-01 ASSY, NOZZLE FOR JETTING HEAD WITH 1/4" ID X 1"-12UNS 3 10 2749094-01 BLANK, NOZZLE FOR JETTING HEAD SMITH SERIES 70 4 10 702645-21-51 O RING, SIZE AS-568-215 1.046 ID X .139 W 90D 5 6 2749105-01 MAGNET, PERMANENT, 8 POLE POT, 2.5 DIA. X 1.25 6 6 2749104-01 EYEBOLT, WITH NUT, DROP FORGED, .375-16 X 6 LG 7 1 2216697-01 BODY; SUB ADAPTER F/ 'G2' MILL AND FLUSH TOOL

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Description: BOLL WEEVIL TEST TOOL Part No.: 2155548-01 P/N Revision: 01 Drawing No.: SK-126528-01

ITEM QTY. PART NO. DESCRIPTION 0 1 2749869-01 ADAPTER SUB, API 6-5/8 FULL HOLE PIN X 4 1 1 2155549-01 BODY, BOLL WEEVIL TEST TOOL 2 1 2748462-01 PUP JOINT, 8.00 OD X 5.00 +/- .015 ID X 36.00 3 2 702645-38-11 O RING, SIZE AS-568-381 11.975 ID X .210 W 90D 4 1 2156902-01 ASSY, LIFTING SUB, 6-5/8" API FH PIN 5 1 K132207 PLUG, PIPE-THREADED HEX SOC 1/4 6 1 709415 THREAD LOCKING COMPOUND, BAKERLOK 7 0 2156244-01 ASSY, DRILL PIPE X-OVER, 6-5/8" FH X STUB

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Description: ISOLATION SLEEVE INSTALLATION TOOL Part No.: 2182907-01 P/N Revision: A02 Drawing No.: SK-081274-01, X-232328-02, X-232490-02, X-205567-03

ITEM QTY. PART NO. DESCRIPTION 1 1 2182909-01 STAND, ISOLATION SLEEVE TOOL 2 1 2142813-01 ACTUATOR SETTING RING, ISOLATION 3 1 2182906-01 PLATE, ADJUSTABLE LANDING, 4 4 2142818-01 RETAINER PIN, ISOLATION SLEEVE TOOL 5 4 2142819-01 RETAINER NUT, ISOLATION SLEEVE TOOL 6 4 2748122-01 SPRING, COMP., .360 OD X .045 X 7 4 2142818-02 RETAINER PIN, ISOLATION SLEEVE TOOL 8 4 2215420-01 PLATE, ADJUSTABLE LANDING, 9 2 2142812-01 RETAINER SCREW, ISOLATION SLEEVE 10 1 2142826-01 ADAPTER RING, ISOLATION SLEEVE 11 4 702514-25-20-08 SCR 0.500-13 X 0.500 CUP PT ZNPL SOC HD 12 4 713302 SCREW, SOC HD SET .375-16 X .500 13 16 702585-14-00-30 SCREW, 12 PT CAP .625-11 X 3.000 14 1 2166688-01 RETAINER RING, ACTUATOR PISTON 15 1 2166657-01 ACTUATOR PISTON - ISOLATION SLEEVE 16 3 702645-38-71 O-RG .210W X 17.955ID 90D NITRILE 17 1 702645-38-81 O RING, SIZE AS-568-388 18.953 ID X 18 12 2709000-10-01 NUT, HVY HEX 1.000-8 GR 2H ZN PL 19 1 2166692-02 HYDRAULIC PIPING & SCHEMATIC - 20 4 702586-19-00-60 SCREW, HEX HD CAP 1.000-8 X 6.000 21 1 011849-01 EYE, LIFTING 2-1/8" DIA FOR 1-1/8" 22 1 2182908-01 ADJUSTABLE LOAD PIN, ISOLATION 23 1 2142824-01 ADAPTER, ACTUATOR RING SETTING TOOL 24 8 702581-19-00-34 SCR 1.000-08 X 3.500 HEX HD CAP STL CD 25 1 2142825-01 CENTRALIZER, ISOLATION SLEEVE, SG-5 26 1 2156904-01 SHEAR PIN, ACTUATOR RING, 27 1 2141470-02 RETAINER NUT, SHEAR PIN, 28 1 2156903-01 SHEAR PIN SLEEVE, ACTUATOR RING, 29 1 2142834-98 SPARE PARTS KIT, ISOLATION SLEEVE

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10. MAINTENANCE AND INSPECTION

10.1 Introduction

Maintenance is an IMPORTANT consideration of equipment usage. Correct application of preventative maintenance will greatly enhance equipment reliability and service life. Any faulty/damaged equipment must be reported IMMEDIATELY to TFE with a view to repairs being carried out prior to its next usage. Major refurbishment will be carried out as required by TFE / Cameron Service Department (rental tools) and is outside the scope of this book. This Section details FIELD maintenance and storage procedures deemed necessary to prolong equipment service life and maintaining efficient usability of Cameron supplied equipment. Maintenance of equipment will be broken down into three sections as follows: Routine Maintenance - Performed each time the equipment has been used and

retrieved to the surface. Applicable also to equipment normally retained on the surface.

Storage Maintenance - Performed whenever equipment is to be removed from

service for any lengthy period. Note: In many instances, routine maintenance and storage maintenance are identical. Where this is the case only routine maintenance is described. Periodic Maintenance - Performed at intervals as specified by TFE / Cameron

Service Department.

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10.2 Oils and Lubricants

The following is a table of preferred/recommended oils and lubricants for lubrication of Cameron supplied equipment:

Product

Type

Uses

Hydraulic Fluid

HW525

Control Fluid

Grease

Shell Water resistant chassis grease or suitable equivalent

Used on equipment externals when running or storing.

A light mineral oil, Ensis or suitable equivalent.

Used for preservation of equipment internals during storage.

Oil

Servo CK 352

Corrosion Inhibitor

Preservation Wax

Seal-Peel.

For preservation of rubber goods during long term storage.

10.3 Routine and/or Storage Maintenance

(1) All equipment should preferably be stored in a warehouse environment which is not subject to extremes of temperature or blown dirt and should be supported on wooden beams. If equipment must be stored outside, it should be supported on wooden beams and covered with a properly secured tarpaulin or other suitable sheeting.

(2) Where possible, prior to storage, equipment should be placed in its provided transit boxes.

(3) If equipment is being placed into storage for any lengthy period, it may be considered an ideal opportunity to carry out periodic maintenance, where applicable.

(4) The following instructions pertain to Cameron supplied running/test tools and other equipment that is normally retained on the surface after subsea installation is complete.

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10.4 Rubber Goods

(1) This information applies to natural rubber and products such as Nitrile, Copolymer and Neoprene. (A) Store rubber products inside a cool, dark, dry storage area, preferably on

wooden shelves.

Note: DO NOT place rubber products on top shelves near galvanized roofing.

(B) Leave rubber parts in a relaxed condition. DO NOT stretch or hang O-rings and seals.

(C) Use sealed containers (use wax or a surface coating such as Seal-Peel if storage time is for more than six months).

(D) Ensure there is no electrical machinery or high voltage equipment near the rubber products and that drafts do not carry the atmosphere from such equipment to the storage area.

(E) Ensure that no heaters, stoves or hot air blasts are near the rubber products.

Note: Liquid hydrocarbons cause swelling or shrinking of rubber products.

(2) After storage and prior to installation:

(A) Inspect the item, ensure it does not have a hard skin or bark like

appearance. (B) Stretch and bend the item and ensure there are no cracks. (C) If in doubt, perform a hardness test as follows:

h Perform the hardness test with the rubber item at 70 deg F to 100 deg F (21 deg C to 38 deg C).

h If the hardness is 15 points more than the acceptable hardness of the item, DO NOT use the item.

10.5 Tree Assembly

10.5.1 General

Every time the equipment is recovered to the surface, each assembly must be thoroughly washed with clean fresh water or steam cleaned (as applicable), to remove any debris/sea water or other corrosive element from the equipment. Special attention must be paid to box/pin joint ends, gasket preparations, mandrels/seal sub pockets and any other areas where debris may become trapped.

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When equipment is clean, inspect for damage (repair/report as applicable), touch up paintwork as necessary, wipe grease over all exposed surfaces/spray oil over all internals as required and prepare for next operation, i.e. running, storing, etc. The following paragraphs describe specific instructions for individual equipment. Replacement of seals, O-rings, gaskets etc, will not be performed during routine or storage maintenance procedures. These items will be replaced when preparing equipment for running.

10.5.2 Tree Connector Assembly

(1) Routine Maintenance (A) As the connector is being retrieved form the wellhead, provided

the hydraulic hoses are still connected, operate the connector several times during the trip to the surface to flush out any debris that might be trapped behind the actuator ring. This could save a lot of effort after the connector is placed on the floor or the test stump.

(B) When the connector is brought topside, it should be visually inspected for any damage or debris it may have picked up during its last operation. At this time the CIW AX/VX gasket should be removed and the ring groove visually inspected for damage. When it has been ascertained that there is no damage to the groove, the groove should be thoroughly coated with grease. A new CIW AX/VX gasket should not be reinstalled until the connector is ready to be run on the next job.

(C) Set the connector on the floor or test stump. Lower or remove the outer skirt. Then, with the connector first in the open and then the closed position, wash out with a water hose any debris that is visible.

CAUTION - Keep arms and hands clear of the actuator ring.

(D) Spray oil or wipe grease on may exposed studs to reduce

corrosion and facilitate removal at a later date. NOTE - Just prior to putting the connector back into service, the

actuator ring I.D. and segment O.D. must be clean and free of any dirt, grease or oil.

(E) Operate the connector several times and note the required

pressure to move the actuator ring. Any time this pressure exceeds 500 psi, the connector should be removed from service, and a periodic maintenance operation performed immediately.

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(2) Storage Maintenance

The following steps are recommended if this connector is to be removed from service for any length of time and stored. This, of course, would be the ideal time to perform periodic maintenance if it is anywhere near due. The following steps are recommended for storage and maintenance:

(A) Thoroughly clean every part that is accessible and when it is dry,

wipe it down with grease or oil. This will prevent corrosion and/or scale buildup.

(B) Remove the CIW AX/VX gasket and inspect the groove for any

damage and then grease it with a good, heavy grease. (C) Spray oil on the I.D. of the connector and on the O.D. (With the

outer skirt lowered or removed). Be sure that all surfaces EXCEPT the I.D. of the actuator ring and the 4 degree tapers of the dogs are greased or oiled as much as possible to prevent corrosion or rust.

NOTE - Just prior to putting the connector into service, the actuator ring

I.D. and dog 4 degree and tapers must be clean and free of any dirt, grease or oil.

(D) If the connector is stored outside it should be protected as well as

possible to keep it out of the weather. (E) When the connector is thoroughly cleaned and greased and/or

oiled (See Note in C), and the CIW AX/VX gasket is removed, it is a good safety practice to actuate the connector to the closed position so that the actuator ring does not inadvertently come down at some later date.

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(3) Periodic Maintenance

Periodic maintenance should be performed every 1-1/2 to 2 years, depending on when the connector can best or most conveniently be spared from service. At this time the connector should be completely disassembled, cleaned, and inspected for any signs of pitting, galling, or abnormal wear and then reassembled with new rubber goods and any new parts that may be required. This will insure trouble free operation.

10.5.3 Isolation Sleeve Assembly

Routine/storage maintenance for the isolation sleeve assembly is as follows:

(1) Thoroughly wash the stab assembly with clean fresh water. (2) Inspect assembly for damage. Repair/report damage accordingly. (3) Inspect lower body stab seal, retainer ring, and set screws. Replace as

necessary. (4) Inspect upper body stab seal. Replace as necessary. (5) Apply grease to all exposed areas and remove to storage.

10.5.4 Storage Procedures

Storage maintenance procedures for equipment not covered in this part are identical to the relevant routine maintenance procedures described previously. The following steps are recommended if a valve assembly is to be removed from service for any lengthy period. This would be an ideal time to perform periodic maintenance. Prior to storing, proceed as follows:

(1) Valve Assemblies

(A) Thoroughly clean every accessible part using clean fresh water.

When dry, wipe down with grease or oil. This will prevent corrosion or scale build up.

(B) Remove gasket and inspect gasket preparation for damage. When it has been ascertained that the gasket preparation is in a satisfactory condition, grease with heavy grease.

(C) Install plugs in all ports to prevent ingress of dirt and debris. (D) Remove all test fluids from bores and grease the valve

thoroughly. (E) Treat valve bores with Servo CK 352 inhibitor or suitable

equivalent.

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Note: If the valve is to be stored outside (although this should not be detrimental to the valve), it is advisable to wrap it in a plastic sheet (or other suitable weatherproof material) to keep it as clean as possible.

(2) 2-1/16�, and 5-1/8� Actuator Assemblies

Prepare the actuator assembly for storage as follows:

(A) Install plugs in openings of actuator and ensure actuator is full of

hydraulic fluid. (B) Tighten plugs in hydraulic fittings and remove actuator to

storage.

Note: If the actuator is to be stored outside (although this should not be detrimental to the equipment), it is advisable to wrap it in a plastic sheet (or other suitable weatherproof material) to keep it as clean as possible.

(3) Elastomer Storage

Storage of Elastomer products is as follows: (A) All elastomers are to be stored in opaque boxes at ambient

temperature in a clean dry environment away from electric motors and fluorescent lights.

(B) Elastomer stock is to be rotated to ensure that shelf life requirements of materials are not exceeded.

(C) Information about cure dates, shelf life requirements and storage recommendations is to remain with each shipment of elastomer materials until that shipment supply is exhausted.

(D) All spare parts and equipment stored in the original packing or on shelving shall be reviewed every six months for evidence of damage or surface corrosion. If surface corrosion is evident then the parts should be cleaned (no mechanical cleaning allowed) to remove surface corrosion and re-coated with an approved rust preventative.

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10.5.5 Periodic Maintenance

(1) Gate Valves and Actuator Assemblies

Troubleshooting

(A) In the event of failure of an actuator in service, it is recommended that it be overhauled, topside, by a qualified Cameron Service Engineer.

Troubleshooting - Gate Valves

(Actuated and Manual)

Symptom Cause Action Fluid leaks past Gate/seat assembly.

Gate/seat assembly is worn. Replace gate/seat assembly.

Fluid leaks around stem packing.

Stem packing is worn. Replace stem packing.

Bonnet gasket is worn. Replace bonnet gasket. Fluid leaks at bonnet flange. Bonnet or body ring groove is damaged.

Return valve to Cameron for repair.

Fluid leaks from bonnet grease fitting.

Plug & gland, Check valve or grease fitting is worn.

Replace plug & gland, check valve or grease fitting as appropriate.

High torque required to operate manual valve.

Gate and stem threads have lost lubricant.

Lubricate gate And stem through bonnet grease fitting.

Downhole equipment will not pass through open actuated valve.

Valve gate improperly aligned. Remove valve actuator and adjust gate position by setting gate valve adjusting ring as per relevant procedure.

Troubleshooting � Actuators

Symptom Cause Action

Actuator fluid leaks around rising stem.

Rising stem seals leak. Replace cylinder head-to-rising stem seals.

Actuator fluid leaks past piston through cylinder.

Piston-to-cylinder seal or piston-to-stem seal leaks.

Disassemble actuator and replace piston-to-cylinder seal and / or piston-to-stem seal.

Actuator fluid leaks around cylinder / spring retainer plate.

Cylinder / spring retainer seals leak.

Disassemble actuator and replace cylinder / spring retainer seals.

Actuated valve does not close. Pressure remains in actuator cylinder.

Bleed off actuator pressure.

Excessive friction on gate. Hydrates or ice in valve body. Warm valve body to melt hydrates or ice *. Lubricate valve.

* Warm valve(s) as follows:

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(B) Fully close faulty valve or an adjacent bore valve to prevent flow through faulty valve.

(C) Allow valve to warm to ambient temperature to melt ice / hydrates.

(2) Actuator Assemblies

All subsea actuators are designed to provide fail-close operation of gate valves and are controlled by a 3,000 psi nominal hydraulic supply. The attached valve manual, Cameron TC-2120-01 OPERATION AND MAINTENANCE MANUAL, CAMERON FLS GATE VALVES WITH CM ACTUATORS THAT MEET API 6A USV REQUIREMENTS (SEE SECTION 4), describes the field maintenance appropriate for the 5� Injection Valve Block.

CAUTION: DO NOT attempt to disassemble this actuator any

further than described in the attached handbook without advice from Cameron Service Department.

(3) Transfer Barrier System Filling Procedure

Refer to procedure X-192202-01 and drawings SK-069099-01, SK-069099-02, SK-069099-03, and SK-069099-04 at the end of this section.

10.6 Tubing Hanger

Every time the equipment is recovered to the surface, each assembly must be thoroughly washed with clean fresh water or steam cleaned (as applicable), to remove any debris/sea water or other corrosive element from the equipment. Special attention must be paid to box/pin joint ends, seal sub pockets and any other areas where debris may become trapped. When equipment is clean, inspect for damage (repair/report as applicable), wipe grease over all exposed surfaces/spray oil over all internals as required and prepare for next operation i.e., running, storing, etc. Replacement of seals, O-rings etc, will not be performed during routine or storage maintenance procedures. These items will be replaced when preparing equipment for running.

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10.7 Internal Tree Cap

Every time the equipment is recovered to the surface, each assembly must be thoroughly washed with clean fresh water or steam cleaned (as applicable), to remove any debris/sea water or other corrosive element from the equipment. Special attention must be paid to any areas where debris may become trapped.

When equipment is clean, inspect for damage (repair/report as applicable), wipe grease over all exposed surfaces/spray oil over all internals as required and prepare for next operation i.e., running, storing, etc. Replacement of seals, O-rings, gaskets etc, will not be performed during routine or storage maintenance procedures. These items will be replaced when preparing equipment for running.

10.8 Tree Debris Cap

Routine/storage maintenance for the spool tree debris cap assembly is as follows:

(1) Thoroughly wash the spool tree debris cap assembly with clean fresh water. (2) Inspect spool tree debris cap for damage. Repair/report damage as appropriate. (3) Inspect spring plunger. Replace if broken. (4) Remove to storage.

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11. INTERFACE DRAWINGS

FMC Rigid Lock Stack Down Wellhead System 1012DM1076933 ENSCO �7500� BOP System SV5446-A ENSCO �7500� BOP Internal Dimensions 5447-MSS ABB Tree Mounted Hydraulic Junction Plate BBH-46600-072 ABB 12-Way Parking Plate BDK-46001-072 Tronic Electrical Harness T18322 Tronic Electrical Harness Mounting Detail 3T16813 ABB Control Equipment Interface Dimensions SD-030317-01 Slick Joint / G2 THRT Interface SD-020609-01 G2 THRT Landing in TH and ITC SD-030394-01 G2 THRT with 36� Spacer Landing in TH and ITC SD-030394-02

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12. SSR WIRELINE TOOLS/ACCESSORIES – PROCEDURES / DRAWINGS

SSR Wireline Equipment Manuals

Description: WIRELINE RENTAL TOOLS

PART NO. DESCRIPTION 2748031-01 SSR PLUG RUNNING TOOL F/5.250" 2748035-01 PULLING TOOL F/ 5.25” SSR PLUG (3-1/2” GS) 2748036-01 7" GS PULLING/RUNNING TOOL 2748152-01 ISOLATION SLEEVE, LANDS/LOCKS IN TH 2730423 PROTECTION SLEEVE 2748156-01 SSR WIRELINE CENTRALIZER 2748151-01 DUMMY SPACER FOR 5.250" WIRELINE TREE ISOLATION PLUG

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13. RECOMMENDED SPARE PARTS LIST

NOTE: A workover operation in this section is defined as the necessary downhole work that requires the retrieval of the installed ITC, SSR plug, and Tubing Hanger from the tree assembly. Start-Up refers to the initial installation of equipment after all on-shore tests (SIT) are completed.

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ASSEMBLY (Qty.) DESCRIPTION Workover

Qty. Start-Up

Qty.

2216525-01 Tubing Hanger (1)

2141663-01 Shear pin cartridge 2 647438-18-01 14.25" MEC seal 1 1 647438-17-01 14.49" MEC seal 1 1 647438-16-01 17.656" MEC seal 1 2142713-01 Upper seal carrier ----- ----- 702645-12-41 .103 w X 1.237 ID o-ring 2 702645-11-51 .103 w X 0.674 ID o-ring 2 702645-21-11 .139 w X 0.796 ID o-ring 2 2 042000-01-24 Back up ring, 1.268 ID X 1.440 OD 4 042000-01-15 Back up ring, .702 ID X .874 OD 4 2155934-01 Hydraulic stab sub-assy ----- ----- 2748243-01 Lip seal 4 4 702647-20-85 .139 w X 0.609 ID o-ring 4 4 2748250-01 Back up ring, size 208 6 6 2142790-01 Spacer ring, peek lip seal 2 2142381-02 Spacer, peek lip seal 2 263134-17 Shear pin, .616/.614 DIA. 3

2156076-01 5.250" TH SSR plug (1)

2155159-01 Expendable spares ----- ----- 2748038-01 O-ring for 5.250" DIA plug, Wiper 1 2748039-01 O-ring for 5.250" DIA plug, Packing 1 2748041-01 Vee packing ring f/ 5.250" 2 2748040-01 Vee packing ring f/ 5.250" WLP 6 2748037-01 Metal seal ring 1

2182251-02 Internal Tree Cap (1)

647438-15-01 17.832" MEC seal 1 1 2141663-01 Shear pin cartridge 2

Tree Gasket

2235142-01 Gasket, CIW Spherical x H4 (symmetric), SST 1 1

2216531-01 Isolation Sleeve (1)

2156904-01 Shear pin 2 2045896-03 MEC seal, 16.275" nom bore 1 2182345-02 MEC seal, 13.042" nom bore 1 1

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