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Concept

“The selection for DWLWI should be made on the simplicity of the module, incorporating light weight & smaller dimensions thus providing flexibility in deployment, operations, maintenance & reliability,

Ultimately in the current climate, low cost to the client”.

LIGHT SUBSEA WELL INTERVENTION SYSTEM

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Document Compiled by Scott Byrne Page | 3

1. Introduction 03

2. Subsea Intervention 04

3. Types of LWI Well Work 04

4. Subsea Intervention Vessels & Categories 12

5. Subsea Intervention Systems 13

6. Subsea System Deployment Systems & Methods 14

7. Well Completion Equipment 17

8. Subsea Well Construction Sequence 30

9. Subsea Tree Change Out Sequence 31

10. BOP & Tree Valve Operations & Principles 32

11. Barrier Testing & Philosophy 36

12. Running Tools & Connectors 37

13. Documentation 39

14. Intervention System Capabilities 40

15. System Proposal 49

16. Deployment Methods & Interface 51

17. System Hydraulics 54

18. Master Process Flow Chart 55

19. Equipment & Components 55

20. Mechanical System 61

21. Hydraulic System 63

22. System Modular Components 68

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1. Introduction

The document is to provide the reader with a basic overview/Introduction to Subsea Well Intervention & will explain the basic fundamentals of the well equipment, well intervention principles & procedures before going on

to present the LWI System proposal.

The proposal/design feed is to construct a cost effective subsea Intervention system for the major oil producers to conduct LWI maximizing well performance & safety, minimising cost & time.

The system would introduce improved safety, increased reliability, ease of maintenance at extremely low cost. The design provides a ‘plug-and-play' configurability for offshore operations. Multiple options can be available, reliable

"Simplistic" hardware and full redundancy is built in to the design. Deployment depths from 50m to 3000m. The system would eliminate the use of MODU for simple operations in a fraction of the cost & time.

With over 18 years working in the Oil & Gas industry from practical to management, specialising in the subsea LWI sector gaining extensive experience on a vast range of subsea operations including;

BOP Service & Maintenance, BOP Operations & Well Control Document composition, Project execution, Personnel coordination & Operational management.

Projects attributed to, include;

Through Tubing Intervention, X-Tree Installation & Recovery, Well Start Up & Commissioning. Well Abandonment SURF, IRM & Commissioning. Wire-line operations. Sub Surface Safety Valve Installation repair & testing. PLT logging runs, Zonal Isolations, Water Shut Off (Plug & Re-Perforation). Artificial Lift principles including the completion side pocket mandrel & Gas lift valve installation/recovery. Well Stimulation, Acid treatments, Scale Squeeze & Well Kill.

Other:

Two barrier policy. Plugs (Mechanical & Fluid), Packers, Tree Valves, Tubing Hanger, AX/VX Environmental seal testing, Annulus & Production Tubing pressure envelopes.

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2. Subsea Well Intervention:

A means of accessing a Subsea well whilst still maintaining two separate barriers from the environment.

Riser-less Subsea Intervention:

A means of accessing a Subsea well whilst still maintaining two separate barriers from the environment without fixed riser to surface.

Light Well Intervention:

Normally carried out from a dynamically positioned purpose-built intervention vessel to perform the following operations: logging, gauging, plugging, re-perforating and various downhole pumping operations to reduce flow restrictions. Cost effective intervention alternative

Traditionally subsea well intervention has been performed from drilling rigs, an automatic extension of their role in drilling and completing wells. But the sky-high rates resulting from the offshore boom of recent years have made

such operations very expensive, while rig availability has been limited. The increasing water depths also mean that it has been necessary to develop alternative technology and more cost

effective systems to access these deepwater wells.

Worldwide there are more than 5,000 subsea wells. In order to increase oil recovery from these wells there is a demand for an efficient subsea light well intervention service. This includes repair, scale removal, installation and manipulation of mechanical devices (valves, plugs, screens etc.), perforations and re-perforations, zone isolation, fluid sampling, PLT, chemical treatment, well abandonment etc. Light Well Intervention technology reduces the intervention cost to roughly 1/3, enabling more intervention work and resulting in better exploitation of subsea

wells. The long term objective is to increase the oil recovery on subsea wells from an average of 45% to 55%.

Cost saving is the main driver for performing LWI operations from a monohull vessel, when compared to the same operations being performed from a drilling rig. These operations can be performed from a monohull DP-2 or 3

vessels whilst maintaining well control and access to the well bore via a subsea Intervention system.

Reducing the cost of such operations is the principal driving force behind the development of the LWI technology. Thus enabling cost effective intervention operations into existing subsea wells resulting in additional production

volumes from mature subsea fields at highly competitive costs for the incremental volumes of oil.

The technology allows access into the wellbore under full pressure and without taking hydrocarbons back to the vessel. All equipment to connect to and control the subsea well is deployed from the lower cost dynamically

positioned monohull vessel without using a drilling or workover risers and anchors. 3. Types of LWI Well Work

In some older wells, changing reservoir conditions or deteriorating condition of the completion will necessitate

various types of Riser-less well intervention. The work is varied in its complexity and has multiple offshoots of what can be offered & executed. The items below are the basic categories services come under.

Pumping Well integrity (WIT) Tree Service Hydrate Removal X-tree Installation & Recovery Commissioning Plug and abandonment Wireline

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Pumping (Diagram on Page 47)

Is the simplest form of intervention as it does not involve installing hardware into the well itself. Frequently it simply involves connecting up to the X-tree and pumping the chemicals into the well.

Extract from previous pumping program:

Due to the Production Riser integrity being in question, there is no route to complete the required well integrity testing by the FPSO.

To avoid the wells being deviated on a single deviation, the Vessel will complete this testing. This will also isolate the well from the flow-line and allow flushing of the 6km flow-line and subsequent flexible riser of all hydrocarbons, through to the FPSO

processing facilities, to enable the team to then complete the graduated pressure test of the flexible riser to confirm integrity.

1. Transit to Well.

2. DP Trials/Obtain clearance to enter 500m zone, move over well.

3. Well Handover, Obtain Permit.

4. Deploy ROV and Carry out ROV Survey.

5. Remove Debris Cap, Clean marine growth.

6. Deploy and latch 4 Guide wires.

7. Skid in TCRT, check seals. Deploy TCRT. Test against PBT/ABT.

8. Fit LAOT to PSV and function open.

9. Confirm barriers.

10. Recover TC. Skid out of derrick.

11. Skid in / Intervention System/TRT. Deploy Intervention System/TRT. Pressure test.

12. Run 2" Hose and hook on to Package and pressure test

13. Subsea Open PMV and PSV. Equalize and open the TRSSSV to establish the CITHP.

14. Close TRSSSV, bleed off 90 % of last known CITHP and conduct 30 min LOT.

15. Apply pressure above TRSSSV to 90% CITHP.

16. Close PMV and bleed remaining pressure to vessel and inflow test PMV for 10 mins

17. Contingency: Open PMV and inflow test LMV for 10mins.

18. Open AMV and ASV to establish the CIAHP.

19. Close AMV and bleed remaining pressure to vessel and inflow test AMV for 30 mins.

20. Close the XOV and pressure test to 300/4000psi for 5/30mins.

21. Flush flowline (6 km).

22. Close and pressure test PFV to 300/4000psi for 5/10mins.

23. Contingency: Close PWV and pressure test to 300/4000psi for 5/10mins.

24. Close PSV and pressure test to 300/4000psi for 5/10mins.

25. Close ASV and pressure test to 300/4000psi for 5/10mins.

26. Recover 2" Hose.

27. Install Lift/Test Mandrel & Complete Suspension Tests.

28. Recover Intervention System /TRT to vessel, recover guidewires, skid TRT out of derrick.

29. Skid in TCRT & Deploy

30. Land out Tree Cap on hub latch & test

31. Recover running tool & complete As Left Survey

32. Transit to Port

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Well Integrity Testing

Where pressure exists for testing, a differential pressure shall be applied across the valve being tested by blowing down the flow line or downstream fixed volume to the minimum pressure practical. Where it is not possible to blow down the flow line fully, the minimum pressure differential (ΔP) at the start of test shall be 1.2 times the Allowable Leak Rate by valve size as stated above. Note : The reasoning behind this rule is that the purpose of leak testing valves is to assess their likely performance in

the worst case scenario; for a Christmas Tree valve this is isolation of the well in case of a flow line rupture. In a failure situation, a greater pressure differential would exist across the valve than under test conditions; so a “pass” under test conditions demonstrates integrity. A “fail” under these conditions will also have occurred before the valve has equalised; therefore this method is deemed to be a valid test method.

Where no well pressure exists in lieu of testing, the valve shall be cycled and maintained in accordance with manufacturer’s instructions; this shall be deemed a test ‘Pass’. Note: Whenever a SIT is carried out in conjunction with a WIT, the valves will be tested using applied pressure above

LMV, if fitted, or UMV. The decision not to set a Two-Way Check Valve below the tree (which would give information on the integrity of the lowest Master Valve) is based on a Risk/ Cost/ Value judgement; the value of knowing the result of the Master Valve’s status is outweighed by the effort/ cost of achieving a valid test. In risk term this judgement leads to a rating of C2 on the PDO Risk Matrix.

In situations where CITHP is > 0 but corresponding to < 1.2 x Allowable Leak Rate, pressure equalisation across the valve within the test period will be deemed a test ‘Fail’ as it demonstrates condition degradation. The Pressure Measurement Method can be either by Pressure Build-up within an enclosed volume or by Bleed-off from an enclosed volume. Note: When a valve test is carried out it is vital to maintain a small positive pressure in the cavity to be tested, this to

ensure

a. that there is no zero error on the gauge

b. that the cavity to be tested is already filled with fluid

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Tree Service & Maintenance

The complexity of Wellhead & X-tree maintenance can vary depending on the condition of the wellheads. Scheduled annual maintenance may simply involve greasing and pressure testing the valve on the hardware. Sometimes the down-hole safety valve is also pressure tested Extract from Maintenance program: Routine maintenance entails greasing the valve stem bearings and filling the valve with sealant or grease as applicable, each time the valve is routinely leak tested. It is recommended that this is carried out immediately after the SSSV leak test while the X-Tree is de-pressurised. The OPERATION should be used in conjunction with the OEM operation and maintenance procedures. Valve Lubrication:

Asset Valve Sealant Type Body Filler Bearing Grease

Platform Name X-184 (5k) X-195 (10k) N/a CI-14 or TF-41

Platform Name X-184 Prod X-195 Ann N/a CI-14 or TF-41

Platform Name X-184 N/a CI-14 or TF-41

Platform Name X-184 N/a CI-14 or TF-41

Valve Sealant Injection:

Max Per Seat 2 1/6” 5 1/8” 6 3/8”

Pump Strokes 18 100 225

Weight of Sealant 1.5 oz 10.8 oz 22 oz

Stem bearings can be greased while the valve is in the open or closed position, or under pressure.

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Xmas Tree Installation & Recovery

The Subsea XT can require change out at any time in the life of field. This can be for a variety of reasons. One of the more complex operations conducted by LWI if dual inset barriers/plugs are to be installed & tested then full Tree control is required. However, the operation can be quite simplistic and time efficient if there is no requirement to install any hardware in to the well. The Tree can be recovered by EDP/LRP or LWI Utilising AHC Crane, Moonpool LARS, Main AHC Winch & 4 Guide wires for the more hostile locations.

Extract from X-Tree Operations:

1. Recover Protective Cap

2. Recover Tree Cap

3. Deploy Intervention Package

4. Install 2 Barriers/Plugs Minimum

5. Disconnect Flowline Jumpers & Flying Leads

6. Recover Tree

7. Deploy & Test Replacement Tree

8. Remove the temporary Barriers

9. Connect the Jumpers & Flying Leads

10. Flow Test the Well

11. Recover Intervention Package

12. Run Tree Cap

13. Commission Well from Platform/FPSO

14. Install Protective Cover

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Commissioning:

A service provided to “start up” the newly installed components, confirming the interface between host & equipment is as required & specified by manufacturer. Hydraulic/Electrical communications & Valve

operations are captured during this phase.

Extract from Valve Tests/Commissioning:

Commissioning Valve Table

valve status survey ROV Valve status & As Left:

Valve Position Result Valve Position As Left Valve Timings

AMV Closed Closed AMV Closed Closed 2.5 sec to Open. 2 Sec to Close.

ASV Closed Closed ASV Closed Closed NA

AWV Closed Closed AWV Closed Closed 1.5 sec to Open. 2 Sec to Close.

CCVA 50% Open 50% Open CCVA X% Open 50% Open NA

CCVC 50% Open 100% Open CCVC X% Open 100% Open NA

CCVD 50% Open 50% Open CCVD X% Open 50% Open NA

CIV-A Closed Closed CIV-A Closed Closed 0.2 sec to Open. 0.5 Sec to Close.

CIV-B Closed Closed CIV-B Closed Closed 0.2 sec to Open. 0.2 Sec to Close.

CIV-C Closed Closed CIV-C Closed Closed 0.2 sec to Open. 0.5 Sec to Close.

CIV-D Closed Closed CIV-D Closed Closed 0.1 sec to Open. 0.5 Sec to Close.

IWC1 Open Closed IWC1 Closed Open NA

IWC2 Open Closed IWC2 Closed Open NA

IWCR Open Closed IWCR Closed Open NA

GT Closed Closed GT Closed Closed NA

ME1A Closed Closed ME1A Closed Open NA

ME2A Closed Closed ME2A Closed Open NA

ME3A Closed Closed ME3A Closed Open NA

MESA Closed Closed MESA Closed Open NA

MIV-1 Open Open MIV-1 Closed Closed 0.5sec to Shut. 0.5sec to Open.

MIV-2 Open Open MIV-2 Closed Closed 0.2sec to Shut. 0.5sec to Open.

MIV-3 Open Open MIV-3 Closed Closed 0.2sec to Shut. 0.5sec to Open.

MIV-A Closed Closed MIV-A Closed Closed 0.2sec to Shut. 0.5sec to Open.

MIV-B Closed Closed MIV-B Closed Closed 1 sec to Open. 2 Sec to Close.

PMV Closed Closed PMV Closed Closed 6 sec to Open. 9.5 Sec to Close.

PSV Closed Closed PSV Closed Closed NA

PVV 1 Closed Closed PVV 1 Closed Closed NA

PVV 2 Closed Closed PVV 2 Closed Closed NA

PWV Closed Closed PWV Closed Closed 6 sec to Open. 13 Sec to Close.

PCV 50% 50% PCV 0% 20% open 50% to 0% 69

SCSSV Closed Open SCSSV Closed Open NA

SLV Closed Closed SLV Closed Closed 0.2sec to Open. 0.5sec to Close.

TCT Closed Closed TCT Closed Closed NA

TCV Closed Closed TCV Closed Closed NA

THAAC Closed Open THAAC Closed Closed NA

THAAO Closed Open THAAO Closed Closed NA

TIV Closed Closed TIV Closed Open NA

XOV Closed Closed XOV Closed Closed 1 sec to Open. 1.5 Sec to Close.

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Plug & Abandon

Traditionally plugging and abandoning (P&A) of suspended subsea wells have been done by drilling rigs. Over the last few years’ subsea wells have been successfully plugged and abandoned and wellheads recovered using mono

hull DP vessels. Extract from previous Abandonment program:

The Vessel was mobilized with the onboard deployment system that incorporated a 35-ton heave-compensated

main winch, compensated guidelines, deck skidding, and moon-pool cursor systems. The project-specific tooling used for the abandonment included cementing spread, subsea controls skid, subsea top

drive, tubing cutter, cement injection tool, and the wellhead cutter. Once the assembly arrived on location, the subsea control skid was deployed, ROV connected the controls and

cementing hoses to the subsea tree using the special hub receptacles installed previously. After the wells were re-killed using water and brine, a 1,640-ft (500-m) cement plug was displaced into the annulus followed by a 6,560-ft

(2,000-m) cement plug that was bullheaded into the tubing with a MODU. Once the plugs were pressure tested successfully, the corrosion cap was removed and the subsea top drive run and

landed on the tree. Following the successful removal of the tree, wire-line was run open water & disconnected the tubing hanger plug

prior to cutting the tubing 197 ft (60 m) below the hanger. The cutting tool severed the tubing, after which the tools were recovered and the subsea top drive re-run to unlock and pull the tubing hanger.

With the wells killed, cement plugs were placed in the annulus and tubing. After the tubing was cut 197 ft below the tubing hanger, the winch deployed the tree running tool, which successfully latched onto and unlocked the tree.

After that, the tree was lifted off the wellhead and placed on the seabed for wet storage. At this point, the wellhead was exposed, with the 9 5/8” casing open. Government regulations required the annulus to be plugged, so a cement plug was installed. A proprietary cement injection tool was deployed to 197 ft below the

wellhead where it punched the 9 5/8” casing and squeezed a 131-ft (40-m) cement plug in the 9 5/8”. to 13 3/8” annulus.

With the top hole cement plug operation complete, the crew deployed the proprietary wellhead cutter severance system and severed all of the casings in a single pass. The entire well abandonment operation was completed as

programmed in eight days.

Showing the moon-pool VDS & AHC Weight system The TGB/Well Head & Conductor cut 10m below seabed

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Wireline: (A means of entering a live well maintaining pressure control whilst conducting down-hole maintenance operations)

(With Lubricator Spool & Open Water Latch System)

Slickline: Wireline (cabling) operations may be used for fishing, gauge cutting, setting or removing plugs, deploying or removing wireline retrievable valves, and memory logging.

Braided line: Wireline (cabling): is more complex than slickline due to the need for a grease injection system in the rigup to ensure the BOP can seal around the braided contours of the wire. It also requires an additional shear-seal BOP as a tertiary barrier as the upper master valve on the X-tree can only cut slickline. Braided line includes both the core-less variety used for heaving fishing and electric-line used for logging and perforating.

Extract From previous Wireline program:

1. Confirm barriers. 2. Recover TC. Skid out of derrick. 3. Skid in / Intervention System/TRT. Deploy Intervention System/TRT. Pressure test. 4. Subsea Open PMV and PSV. Equalize and open the TRSSSV to establish the CITHP. 5. Rig up Slickline and drift well to HUD

Recover WRSV on Slickline Deploy Slickline c/w brush and clean nipple profile Deploy WRSV on DHSV Carrier (DHSVC) Test WRSVPerform Gas Lift change out x 4 Perform MPLT on well

6. Close TRSSSV, bleed off 90 % of last known CITHP and conduct 30 min LOT. 7. Apply pressure above TRSSSV to 90% CITHP. 8. Close PMV and bleed remaining pressure to vessel and inflow test PMV for 10 mins 9. Contingency: Open PMV and inflow test LMV for 10mins. 10. Open AMV and ASV to establish the CIAHP. 11. Close AMV and bleed remaining pressure to vessel and inflow test AMV for 30 mins. 12. Close the XOV and pressure test to 300/4000psi for 5/30mins. 13. Close PSV and pressure test to 300/4000psi for 5/10mins. 14. Close ASV and pressure test to 300/4000psi for 5/10mins. 15. Recover 2" Hose. 16. Install Lift/Test Mandrel & Complete Suspension Tests. 17. Recover Intervention System /TRT to vessel, recover guidewires, skid TRT out of derrick.

(“Guns”) Run on E-Line braided wire for pay zone re-perforation

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4. Subsea Intervention Vessels & Categories

Interventions are commonly executed from light/medium vessels or mobile offshore drilling units (MODU) for the

heavier interventions such as snubbing and work-over. The common module for light & medium interventions is the Mono-hull due to cost & efficiency, for example; it can take up to 5 weeks or more to mobilize a MODU & the rate

approx 500’000GBP + per day. Versus Mono-hull that can be mobilized in 7 days at an approx day rate of 100’000 to 300’000GBP.

Categories are: Cat-A Light Intervention, Cat-B Medium Intervention & Cat-C Heavy Intervention

Cat A, Havilla Harmony

Cat A, Normand Clough

Cat A, Bourbon Perodot

Cat B, Seawell

Cat B, Well Enhancer

Cat B, Skandi Constructor

Cat B, Island Frontier

Cat B, Island Constructor

Cat B, Skandi Aker

Cat C, Jack Up

Cat C, Drill Ship

Cat C, Semi Sub

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5. Subsea Intervention Systems (Basic Closed loop Hydraulic to Advanced Multiplex Hydraulic Control)

The selection for DWLWI should be made on the simplicity of the module, incorporating light weight & smaller

dimensions providing flexibility in deployment, operations, maintenance & reliability. Ultimately in the current climate, low cost to the client.

1. 7” Bore Dual Trip 2. 5” Bore Single Trip 3. 7” Bore Dual Trip

One of the first intervention systems built which lead to the build of the system in use now (picture 5) We constructed the LRP from the principles of a VXT. Primarily for the North Sea but was later mobilized for international projects & Deployed from various vessels

System 2 was a direct hydraulic package based on the design of the first module. The improvements were the overall size, weights, functionallity & the fact it was single trip deployment.

System 3 was built & operated in Austrailia the first of the MUX units. With added fiber optic/electro hydraulic fetures pushed the dayrate/rental of the equipment & increased the risk of downtime/falure

4. 4” Bore Single Trip 4. System fully stacked for SIT 5. 7” EDP/LRP/SIL

Constructed for Petro Vietnam deployed from a Semi Submersible.

System was successfully used to lock open 2 SCSSV

The latest in Intervention systems, now costly to run & maintain.

6. Upper Riser Assembly 7. Pre Deployment Checks 8. Moonpool Deployment

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6. Subsea Deployment Systems & Methods

Deployment methods can be utilized via AHC crane, moon-pool, /derrick or VDS

(Purpose Built Vessel Deployment System).

Derrek with LARS Derrek with LARS VDS AHC Crane

Vessel Deployment System (VDS) was specifically designed to allow subsea intervention & Abandonment to be conducted from a vessel of opportunity. We ran this type of deployment system from several vessels international The VDS creates an over-stern moon-pool work area with integral lifting frame and skidding system or can be positioned over a moon-pool. The system allows the deployment of subsea equipment, guide lines and pod lines. The lifting frame provides heavy lift capability and a facility for deployment of pod and guidelines to be connected to subsea hardware for intervention work. The skidding system allows equipment packages to be moved safely on the deck to and from the moon-pool. This allows deployment and recovery operations to be undertaken without the use of a deck crane. The VDS has several features which set it apart from conventional A-Frames. These include the moonpool area, a heave compensation system, lifted load containment by use of cursor frames and on deck transportation via a skidding system. The VDS is also collapsible for in-gauge road transportation. The VDS was designed to integrate with other Well Ops proprietary systems.

Benefits are:

No lifting on deck

Lifted Loads Constrained

Heave Compensation Guide & Pod Lines

Moon-pool Style operations on a typical OSV

Provides cost effective rig-less well intervention

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Heave Compensation

The purpose of AHC is to keep a load, held by equipment on a moving vessel, motionless with regard to the seabed. Commercial offshore cranes usually use a Motion reference unit (MRU) or pre-set measurement position detection to detect the current ship displacements and rotations in all directions. A control system, often PLC or computer based, then calculates how the active parts of the system are to react to the movement. The performance of an AHC system is normally limited by power, motor speed and torque, by measurement accuracy and delay, or by computing algorithms. Choice of control method, like using preset values or delayed signals, may affect performance and give large residual motions, especially with unusual waves. State of the art AHC systems are real time systems that can calculate and compensate any displacement in a matter of milliseconds. Accuracy then depends on the forces on the system, and thus the shape of the waves more than the size of the waves. Electric winch systems In an electric winch system, the wave movement is compensated by automatically driving the winch in the opposite direction at the same speed. The hook of the winch will thus keep its position relative to the seabed. AHC winches are used in ROV-systems and for lifting equipment that is to operate near or at the seabed. Active compensation can include tension control, aiming to keep wire tension at a certain level while operating in waves. Guide-wires, used to guide a load to an underwater position, may use AHC and tension control in combination.

Hydraulic winch systems Hydraulic cranes can use hydraulic cylinders to compensate, or they can utilize a hydraulic winch. Hydraulic "active boost" winches control the oil flow from the pump(s) to the winch so that the target position is reached. Hydraulic winch systems can use accumulators and passive heave compensation to form a semi-active system with both an active and a passive component. In such systems the active part will take over when the passive system is to slow or inaccurate to meet the target of the AHC control system. AHC cranes need to calculate the vertical displacement and/or the velocity of the crane tip position in order to actively heave compensate a load sub-sea.

Principle

The main principle in PHC is to store the energy from the external forces (waves) influencing the system and dissipate them or reapply them later. Shock absorbers or drill string compensators are simple forms of PHC, so simple that they are normally named heave compensators, while "passive" is used about more sophisticated hydraulic or mechanical systems. A typical PHC device consists of a hydraulic cylinder and a gas accumulator. When the piston rod extends it will reduce the total gas volume and hence compress the gas that in turn increases the pressure acting upon the piston. The compression ratio is low to ensure low stiffness.

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Active Heave Compensation & MRU (Motion Reference Unit)

MRU Sequencer

Hydraulic Oil

Hydraulic Nitrogen Illustration by S. Byrne

MRU

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7. Well Completion Equipment

Provides optimum flowing conditions Protects casing Downhole emergency isolation Permits downhole chemical injection Permits downhole measurement Isolates producing zones Provides Artificial Lift Facilitates well kill & Dual Direction circulation Allows for the installation of various tooling plugs gauges & chokes via wireline

Well Types

Well Type 1 High Pressure Well - >20,000 kPa (Actual CITHP) or high GLR (>300:1 gas to liquid ratio) or high H2S (>500ppm)

Well Type 2 Free Flowing low pressure Oil Well - < 20,000 kPa

Well Type 3 Gas-lift Well

Well Type 4 Steam Injection well

Well Type 5 Sub-hydrostatic pumped well, minimum one casing string with or without packer

Well Type 6 Water Injection / Disposal Well (with tubing)

Well Type 7 Water Disposal Well (no tubing)

Well Type 8 Suspended Wells (not listed as separate Well Type in the Well Failure Model)

Upper Completions: Upper completions establish a safe and efficient path for access to the wellbore and for the production of hydrocarbons from the reservoir to surface, there are many types of upper completions but they can be grouped according to the number of reservoirs that are to be produced. Single zone & multiple zones: Lower Completions Lower completion is the interface between the wellbore and the reservoir section. Its main functions are: Ensure long term integrity of the wellbore. Allow establishment of effective communication between the reservoir and the wellbore (ie, Open hole / cased perforated). Address the specific reservoir characteristics and requirements such as sand control or selective production in order to ensure that productivity is maximized. Provide whenever practically possible full access to the reservoir in order to monitor and improve well/reservoir performance.

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Completion Schematic :

Depth AHBDF (ft) Depth TVDBDF (ft) Schematic Description Min ID

Permanent Datum 18 3/4" Dual Tubing Hangar AF Profiles

5.5’’ 2’’

Top of Conducter Housing 36’’

36” to 30” X-Over

30” to 20” X-Over

20” to 13 3/8” X-Over

13 3/8” to 10 3/4” X-Over

10 3/4” to 9 5/8” X-Over

Annulus WEG 2’’

10k ID SCSSSV 5.5’’

MI/CI Sub 5.5’’

DHPT Guage 5.5’’

Pip Tag/CCL 5.5’’

DHPT Guage 5.5’’

Pip Tag/CCL 9 5/8 ‘’

SPM GLV 01 5.5’’

SPM GLV 02 5.5’’

SPM GLV 03 5.5’’

SPM GLV 04 5.5’’

Pip Tag/CCL 9 5/8 ‘’

SSD 5.5’’

Permanent Packer Mid Element

9 5/8 ‘’

Liner Hangar 7’’

5” to 4.5” X-Over

Pip Tag/CCL 4.5’’

100 Deviation

Pip Tag/CCL 4.5’’

Zone 01 TCP Firing head top of perforations 4.5’’

Sand Screens

Lower Perforations

Pip Tag/CCL 4.5’’

Sand Screens 4.5’’

Zone 02 perforations

Lower Perforations

Pip Tag/CCL 4.5’’

Sand Screens

Zone 03 perforations 4.5’’

Lower Perforations

Pip Tag/CCL 4.5’’

180 Deviation

Sand Screens

Zone 04 Bottom of perforations 4.5’’

Production WEG 4.5’’

Liner Float Collar 7’’

Liner Reamer Shoe 7’’

Illustration by S. Byrne

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Well Data Supplied by Client Prior To Interventions:

The information below is detrimental to the intervention procedures providing up to date information in document composition

tooling selection & test procedures:

Well Identification SSS Oil LTD

Field / Block SCOTT- 21/25

Well Name (Legal Wellbore Name) 21/25-S4z (Scott P7s1)

Well Category Producer / Water Injector

Producer

Coordinates Longitude: 33 deg 49 min 52.489 sec E Latitude: 77 deg 16 min 30.485 sec N

Well Data

Water Depth 300 ft MSL

Tree (type, rating) Vetco MS-700 – 15K psi

Production Casing (size, wt, depth) 10 ¾” 73.2 lb/ft P-110 from 377.5 to 1434 ahbdf 9 5/8” 53.5 lb/ft from 1434 to 13310 ahbdf

Liner (size, wt, depth) 7” 32 lbs/ft –perforated from 13093 to 15369 ahbdf

Production Tubing (size, wt, depth) 5 ½” 20# 25Cr from 375 to 1327 ahbdf 5 ½” 17# 25 Cr from 1327 to 13052 ahbdf 4 ½” 13.5# 13 Cr from13052 – 13389 ahbdf from 13389 to 15332 TCP perforating guns

Max Deviation and depth 91 Deg @14235 (ahbdf)

MAASP 365 bar/ 5293psi

MINDAP 5 Bar/73psi

Well Information

Expected Reservoir Pressure Mid 6010 psia at 10363 tvdss

Flowing Tbg Head Pressure 46 - 60 bar /580– 870psi(depending on choke position) well will be closed in

Closed In Tbg Head Pressure 170bar/ 2465psi

Expected Reservoir Temperature 133 Deg C

Flowing Tbg Head Temperature 126 Dec C

Closed in Tbg Head Temperature 10 Deg C

Expected H2S Not expected (separator range – 0 –14 ppm)

Expected CO2 Separator range 0 – 3 % vol

Deposits expected: Scale/Type of scale

Possible calcium sulphate well currently above MIC levels from last

Deposits expected: Asphaltenes Not expected

Expected Flow Rates Oil / Gas / Water

Well will not be flowing – Oil 4000 bbls, water – 28000bbls – gas 3MMscf

Annulus Pressure 141 Bar /2045psi(Well Flowing – gas lifted)

Type of Annulus Fluid Inhibited Freshwater

TRSSSV type(s) and operating pressure

BYRNE 5 ½” SP-2 TRSSSV (4.625” RQ)

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Completion Equipment Continued:

The wellhead transfers the casing and completion loads to the ground via the surface casing providing a seal system & valves to control access to the tubing/annulus. It is made up of one or more casing head spools, the tubing head

spool, the hanger & the Xmas tree. The function of the tubing hanger is to transfer the weight of the tubing to the wellhead and to contain the casing -

tubing annulus fluid. There are five types of tubing hanger system in common use.

Tubing hanger system:

A VXT utilizes a conventional tubing hanger, which has a main production bore and an annulus bore. The tubing hanger is located in the wellhead. However, in an HXT, the tubing hanger is a mono-bore tubing hanger with a side outlet through which the production flow will pass into the PWV. Because the tubing hanger in the HXT is located in the tree body, it needs the crown plugs as the barrier method. An internal tree cap is the second barrier located above the crown plug. If dual crown plugs are designed in a tubing hanger system, an internal tree cap is not used.

Packer:

The production packer is mechanical device designed to provide a sealed area between the casing ID. and the tubing OD. The packer is also equipped with a slip system that ensures that it is firmly anchored to the casing/ liner. Depending on the well, packers are used for one or more of the following reasons: To provide a sealing safety barrier at the bottom of the tubing as near the productive

zone as possible. This is required to protect the production casing from the corrosive elements of the reservoir products and from any high pressures experienced during operations such as well killing or stimulation.

To facilitate well workover of damaged tubing without exposing the production zone to

damaging fluids. To provide a tubing anchoring point to minimise tubing movement. To assist in well killing operations by providing a positive safety barrier near the

reservoir; which will result in the requirement for lower specific gravity and kill weight brines.

To improve vertical flow conditions and prevent erratic flow and heading cycles. To separate pay zones in the same well bore completed in multiple layer reservoirs. To pack off perforations rather than squeezing cement (bridge plugs). To facilitate gas lift or hydraulic power fluid to lift reservoir fluids. To install a casing pumps. To minimise heat losses by use of empty annulus or thermal insulator

Pressure integrity assurance to the liner top. To isolate casing leaks. To facilitate temporary well service operations (eg, stimulations, squeezes) or well

testing with Drill String Stem DST.

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Subsurface Safety Valves:

Safety valves are a critical component of a completion and its design; the selection process requires a clear understanding of the working environment and potential changes through the life of the well.

Subsurface safety valves (SSSVs) are installed below the wellhead to prevent uncontrolled flow of hydrocarbons. In the worst case, when the wellhead has suffered severe damage, the SSSV may be the only means of preventing a blow-out. The correct design, application, installation and operation of this equipment is fundamental to the safety of the well. SSSVs should be considered for all wells capable of natural flow. In many locations government regulations require the use of SSSVs. Government regulations dictate, QA/QC to comply with API-14A operation and testing of valves. However, the design must adhere to local operating company requirements and appropriate governmental regulations regardless of which geographic location and should be applied to each specific application.

SSSVs can either be surface controlled or subsurface controlled. Subsurface controlled valves are controlled by well pressure, by the flow itself or as a result of a pressure differential caused by the flow. This type of valve’s dependency on well conditions as a means of control; makes them inherently less reliable than surface controlled valves, and their application is therefore limited. Surface controlled subsurface safety valves (SCSSV) are normally closed, and they are usually held open by an external pressure applied from surface. Some SCSSVs are controlled by electric, electromagnetic or acoustic signals. However, by far the most common form of control is hydraulic pressure applied from surface via a control line. When the hydraulic pressure is lost, the valve is closed by means of a spring acting on the closure mechanism. In order to close the valve, this spring must overcome the hydrostatic pressure in the control line. Each SCSSSV therefore has a maximum safe setting depth. This aspect of SCSSSV design is covered in more detail later in this section. Regulations in most offshore locations require the use of SCSSSVs.

Prior to opening any SSSV or valves on a Subsea Tree, pressure has to be equalized

above the closed valve.

The volume of fluid required will be calculated & then the volume to increase pressure to the specified CITHP (Closed in Tubing head pressure)

Prior to opening any valve a pressure differential of up to 10% above must be applied. This eliminates any kick, potential hydrate formation or lifting the toolstring if one is present in the bore.

Example: Tubing ID = 4.892 x 4.892 = 23.9 x SCSSV at 509ft = 12181.2 / 1029.4 = 11.83bbls

Or ID2 x Depth/Height/Feet / 1029.4 = 11.83bbls

Amount to increase by 500psi

MD Factor of Saltwater .0000035 x 11.83bbls x 500psi = .20bbl

All the information can be found on the well schematic, Calculations are usually taken from RKB (Rotary Kelly Bushing) or BRT (Below Rotary Table) to MSL (Mean Sea Level) then TVD/MD

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Subsea Trees:

designed to allow ease of tie-in to the tubing spool/wellhead, umbilical connections (hydraulic/electric), etc Facilitate connection of tie-backs, flow-lines, etc. in underwater conditions Control and safety valves need to be operated via Umbilical lines.

Function requirement:

Direct the produced fluid from the well to the flow-line (called production tree) or to canalize the injection of water or gas into the formation (called injection tree). Regulate the fluid flow through a choke (not always mandatory). Monitor well parameters at the level of the tree, such as well pressure, annulus pressure, temperature, sand detection, etc. Safely stop the flow of fluid produced or injected by means of valves actuated by a control system. Inject into the well or the flow-line protection fluids, such as inhibitors for corrosion or hydrate prevention

VXT(Vertical) Dual Bore HXT (Horizontal) Spool

VXT(Vertical) Dual Bore Schematic HXT (Horizontal) Spool Schematic

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Vertical Diagram:

The master valves are configured above the tubing hanger in the vertical Xmas tree (VXT). VXTs are applied commonly and widely in subsea fields due to their flexibility of installation and

operation. The production and annulus bore pass vertically through the tree body of the tree.

Master valves and swab valves are also stacked vertically. The tubing hanger lands in the wellhead, thus the subsea tree can be recovered without having to

recover the down-hole completion.

PSV

PWV

PCV

PMV

PLMV

AMV

AWV

ASV

XOV

Gripper Rods

Production & Annulus

Stingers

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Dual Bore VX/AX Gasket Profiles: