Sentree 7 Manual

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Large-Bore

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photo-Contents

Introduction . . . 1

Conventional Christmas tree . . . 1

Horizontal Christmas tree . . . 2

SenTREE* 7 system . . . 3

Applications . . . 3

Benefits . . . 3

Features . . . 3

SenTREE 7 Basic String . . . 5

Certifications . . . 6 Modular configurations . . . 8 Flowhead . . . 10 Lubricator valve . . . 12 Bleedoff valve . . . 14 Retainer valve . . . 16 Helical latch . . . 18 Flapper valve . . . 20 Ball valve . . . 22

Accessories and Project-Specific Assemblies . . . 25

Saver and crossover sub . . . 27

Packoff sub and space-out sub . . . 27

Spacer sub . . . 28

Ported slick joint . . . 29

Fishing Assemblies . . . 31

Post-shear retrieval tool . . . 31

Post-unlatch retrieval tool . . . 33

Commander* Control Systems . . . 35

Commander hydraulic control system . . . 35

Commander telemetry control and monitoring system . . . 38

Equipment . . . 40

Emergency shutdown . . . 41

Design and philosophy requirements . . . 41

Operational philosophy . . . 41

Shutdown philosophy . . . 42

Valve position indication philosophy . . . 42

Subsea accumulator module . . . 42

Subsea control module . . . 44

Subsea spanner joint . . . 46

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Introduction

Advances in technology with the introduction of the horizontal subsea Christmas tree were fol-lowed by the development by Schlumberger of the SenTREE* 7 fullbore 73_{⁄8-in. subsea safety} system.

This sixth book in the Schlumberger Testing Services set describes both the basic SenTREE 7 string and project-specific accessories and assemblies. Commander* control systems used with the SenTREE 7 system are also reviewed.

The SenTREE 7 well control system is the primary subsea safety device used on floating ves-sels during completion, workover and intervention operations on subsea wells through horizontal and concentric Christmas trees. It enables shutting in the well and disconnecting the landing string subsea. In completion mode the SenTREE 7 subsea completion and test tree (SCTT) is connected directly above the tubing hanger running tool (THRT). The SenTREE 7 system also provides multiple hydraulic and electrical feed throughs for operating the THRT and function testing the completion tools below.

Conventional Christmas tree

In a conventional Christmas tree, the valves are situated in a vertical bore (Fig. 1). The Christmas tree is run after the completion and interfaces with the tubing hanger. Workover of the well requires killing the zone and pulling out of the completion. These operations lose pro-duction time as well as risk damaging the formation.

Kill line Production line

Tubing hanger

Annulus master valve Production

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Horizontal Christmas tree

The horizontal valve assembly of the horizontal Christmas tree provides an unobstructed verti-cal path to the completion. Because horizontal Christmas tree valves are external to the vertiverti-cal bore (Fig. 2), wireline tools no longer must be run through gate valves, which greatly reduces the risk of damaging the tree components. Production and annulus valves are contained on the exte-rior of the spool in miniblocks. Connected to the blocks are flow loops for production, crossover and circulation functions.

The horizontal Christmas tree saves operating time and cost while providing increased safety:

■ Drilling operations can be conducted through the tree.

■ The completion is landed inside the tree and can be recovered without disturbing the subsea Christmas tree.

■ The system uses a conventional drilling riser, which eliminates the completion riser.

■ Operational cost savings are numerous over conventional tree operations.

Figure 2. Horizontal Christmas tree.

Production wing valve

Annulus wing valve

Wellhead

Annulus master valve Crown plugs

Production master valve

Tree cap

Annulus access valve

Annulus crossover valve

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SenTREE 7 system

The SenTREE 7 system is an essential safety device for every intervention performed from a floating vessel. It performs three key functions:

■ contains well pressure (dual valves)

■ facilitates emergency disconnect

■ maintains well integrity.

Applications

■ Positive well control

■ Well operations management

■ Subsea completions

■ Well cleanups

■ Well testing

Benefits

■ Modular design for optimum positioning of slick joint

■ Safe running of tubing hangers and completion

■ Crown plug passage

■ Positive well control through dual-valve closure

■ Fluid retained in workover landing string, not released to riser

■ Quick unlatch

■ Unlatch while under 200,000-lbf [890-kN]tension

■ Bleedoff valve vents below retainer valve for safe disconnect

■ Deepwater helical latch for easy reconnection

Features

■ Fail safe closed with pump-through facility

■ Cuts 2-in. [51-mm] OD, 0.157-in. [4-mm] wall thickness, 80-ksi [551,580-kPa] yield coiled tubing

■ Ten hydraulic and four electrical feed throughs

■ Ball valves that hold 10,000 psi [689 bar] from above or below

■ Hydraulic unlatch with backup features

■ Injection porting below lower valve or between valves

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SenTREE 7 Basic String

The SenTREE 7 system (Table 1) incorporates a fail-safe valve system and latch connector to shut in a subsea well and enable quick disconnection from the well when operating from a float-ing drillfloat-ing vessel. The large (73_{⁄8-in.) bore facilitates the deployment of tubing hanger plugs and} tree cap plugs that are used with horizontal trees.

Table 1. SenTREE 7 System Specifications

SenTREE 7 Basic String

Service H2S and CO2

Working pressure (psi [bar]) 10,000 [689]

Test pressure (psi [bar]) 15,000 [1035]

Min temperature rating (°F [°C]) –20 [–29] Max temperature rating (°F [°C]) 325 [163]

Tensile load (lbf [kN]) 1,000,000 [4450] Tensile load at working pressure (lbf [kN]) 400,000 [1780]

Max OD (in. [mm]) 18.56 [471]

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The SenTREE 7 modular design maximizes the system’s flexibility to adapt to a variety of a blowout preventers (BOPs) and allow for future adaptations. As shown in Fig. 3, the SenTREE 7 system consists of

■ saver and crossover sub (project specific)

■ ported packoff sub (project specific)

■ space-out sub (project specific)

■ bleedoff module

■ retainer valve

■ spacer sub (project specific)

■ helical latch

■ flapper valve

■ ball valve

■ ported slick joint (project specific).

An optional lubricator valve can be positioned a nominal distance below the rotary. The project-specific components are discussed in “Accessories and Project-Specific Assemblies.”

Certifications

■ Design verification by Det Norske Veritas (DNV) to American Petroleum Institute (API) Specification 6A

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Saver sub to landing string crossover

Ported packoff sub

Space-out sub with high-pressure

hose set and protection shroud

Bleedoff valve and retainer valve

Spacer sub with high-pressure

hose set and helical latch

Flapper valve

Ball valve

Ported slick joint with THRT interface

Tubing hanger running tool

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Modular configurations

Each SenTREE 7 system is adapted to function in the BOP stack in which it is run. The modular configuration readily enables tailoring the system to fit even “super-short” BOP stacks.

The SenTREE 7 system can be run in either of the following configurations.

■ SenTREE 7 76-in. configuration

The ball and flapper valves are run together with the latch connected to the flapper valve (Fig. 4). The bottom ball valve turnbuckle allows project-specific slick joint makeup. The length of the 76-in. [193-cm] assembly is accommodated between the lower and upper pipe rams with the latch mandrel (spacer sub) across the shear rams. The lower pipe rams seal across the slick joint. The upper blind/shear rams close above the flapper if the latch is not connected.

Retainer valve

Ball valve Spacer sub

Ported slick joint Tubing hanger running tool Latch connector Flapper valve Bleedoff valve Space-out sub Packoff sub

Production line Annulus line

Horizontal tree BOP stack

Annular rams

Shear rams

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■ SenTREE 7 36-in. configuration

The flapper and ball valves are run separately (Fig. 5). The integral slick joint run between the flapper and ball valves is ported for the ball hydraulics and electronics. The ball valve is set below the pipe rams and can be run with a conventional hanger assembly or THRT. The length of the assembly accommodated between the middle and upper pipe rams is 36.108 in. [91.71 cm].

Figure 5. SenTREE 7 36-in. configuration.

Retainer valve Ported joint Spacer sub Ball valve Tubing hanger running tool Latch connector Flapper valve Bleedoff valve Space-out sub Packoff sub

Production line Annulus line

Horizontal tree BOP stack

Annular rams

Shear rams

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Flowhead

The 10,000-psi working pressure flowhead (Fig. 6 and Table 2) provides a 73_⁄₈_{-in. bore throughout} the subsea landing string.

Features

■ Fail-safe actuator on production and kill lines

■ Holds 10,000 psi from above or below

■ Hydraulic operator on the master valve (fail as is with manual override)

■ Hydraulic operator on the swab valve (fail as is with manual override)

■ Dynamic swivel

Table 2. Flowhead Specifications

Service H2S and CO2

Test pressure (psi [bar]) 15,000 [1035] Min temperature rating (°F [°C]) –20 [–29]

Max temperature rating (°F [°C]) 250 [120]

Coiled tubing cutting 2.0-in. [51-mm] OD, 0.157-in. [4-mm] wall thickness, 80-ksi [551,580-kPa] yield

Tensile load (lbf [kN]) 1,400,000 [6240]

Tensile load at working pressure (lbf [kN]) 700,000 [3120] Min ID (in. [mm]) 7.375 [187]

Master valve 73_⁄₈_{-in. hydraulic actuator, fail as is}

Swab valve 73_⁄₈_{-in. hydraulic actuator, fail as is}

Flow valve (ESD interface) 51_⁄₈_{-in. hydraulic actuator, fail-safe closed}

Kill valve (ESD interface) 51_⁄₈_{-in. hydraulic actuator, fail-safe closed}

Flowline G-52 HUB

Kill line G-52 HUB

Length (ft [m]) 15.9 [4.8]

Width (in. [mm]) 77 [1955]

Depth (in. [mm]) 69 [1750]

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Figure 6. Flowhead.

Hydraulic-operated swab valve (fail as is) with manual override

Hydraulic-operated master valve (fail as is) with manual override 10-in. handling sub

Dynamic swivel Production line Kill line

or production line Coflex support

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Lubricator valve

The lubricator valve (S7LV) (Fig. 7 and Table 3) is a surface-operated hydraulic valve that is run one or two joints below the flowhead during well operations. It reduces the amount of surface equipment by enabling use of the top of the landing string as a lubricator for the introduction of tools that require a surface lubricator (e.g., conveyance by wireline, slickline, coiled tubing or pumped into the well).

The lubricator valve is connected by a two- or three-line hose bundle to a surface-operated console. The third line can be used for injecting hydrate inhibitor, such as glycol or methanol, just below the valve. Because it is a pump-through valve, it can be pressure tested from above (with hydraulic pressure maintained in the ball closure line) or below.

Features

■ Tested and qualified to maximum pressure and temperature

■ Holds 10,000 psi from above or below

■ Closing ball valve cuts up to 2-in. OD, 0.157-in. wall thickness, 80-ksi yield coiled tubing

■ Pump-through capability at less than 500-psi differential from above

■ Chemical injection below or at valve level

■ Fail as is

Table 3. Lubricator Valve Specifications

S7LV

Service H2S and CO2

Working pressure (psi [bar]) 10,000 [689] Test pressure (psi [bar]) 15,000 [1035]

Min temperature rating (°F [°C]) –20 [–29]

Max temperature rating (°F [°C]) 325 [163] Tensile load (lbf [kN]) 1,000,000 [4450]

Tensile load at working pressure (lbf [kN]) 400,000 [1780] Max OD (in. [mm]) 12.5 [317]

With centralizer (in. [mm]) 16.1 [409] Min ID (in. [mm]) 7.375 [187]

Length (in. [m]) 83.3 [2.17]

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Figure 7. Lubricator valve.

Centralizer (eccentric or concentric)

“Ball open” line

“Ball closed” line

Below-ball chemical injection line Ball valve

Antirotation key and retainer Centralizer mandrel

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Bleedoff valve

If a retainer valve is run with the SenTREE 7 system, a bleedoff valve (S7BO) (Fig. 8 and Table 4) is run on top of the retainer valve to bleed off the trapped bore pressure between the flapper valve and the retainer valve. The bleedoff valve is also opened during a relatching operation to prevent the squeezed volume from building to a significant pressure level.

The SenTREE 7 bleedoff valve cartridge is the same valve used in the SenTREE 3 system.

Features

■ Two shear pin valves incorporated to apply annular pressure to assist ball valve closure and unlatching in emergency situations when the control umbilical is damaged

■ Optional indicator switch for valve position

Table 4. Bleedoff Valve Specifications

S7BO

Service H2S and CO2

Working pressure (psi [bar]) 10,000 [689] Test pressure (psi [bar]) 15,000 [1035]

Tensile load at working pressure (lbf [kN]) 400,000 [1780] Max OD (in. [mm]) 18.56 [471]

Min ID (in. [mm]) 7.375 [187] Length (in. [mm]) 14.5 [368]

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Figure 8. Bleedoff valve.

Stinger hydraulic or optional quick-disconnect coupling

Bleedoff valve cartridge

Shear pin valve (SPV)

Bore seal sub

Retainer valve or spacer sub Space-out sub

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Retainer valve

The retainer valve (S7RV) (Fig. 9 and Table 5) prevents the release of hydrocarbons from the landing string into the riser—and subsequently to the sea—if an emergency disconnect occurs during well operations. The retainer valve is a necessary system component for deepwater and gas wells. It is not required for some shallow-water applications, but can be configured as a deep-set lubricator valve where appropriate.

Features

■ Holds 10,000 psi from above or below the ball

■ Cuts up to 2-in. OD, 0.157-in. wall thickness, 80-ksi yield coiled tubing

■ Fail-safe closed, non-pump-through capability (optional pump-through configuration)

Table 5. Bleedoff Valve and Retainer Valve Specifications

S7BO and S7RV

Service H2S and CO2

Test pressure (psi [bar]) 15,000 [1035]

Tensile load at working pressure (lbf [kN]) 400,000 [1780]

Max OD (in. [mm]) 18.56 [471] Min ID (in. [mm]) 7.375 [187]

Length (in. [m]) 56.2 [1.43] Weight (lbm [kg]) 3635 [1649]

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Figure 9. Bleedoff valve and retainer valve. Bleedoff valve Hydraulic ports Secondary-function shear valve Telemetry position switch (optional) Electrical telemetry feed through Bleedoff valve Retainer valve

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Helical latch

The helical latch connector module (S7HL) (Fig. 10 and Table 6) is the main connection and disconnection point for the subsea well control system. The latch connector enables rapid disconnect of the string below the blind rams in the BOP if rapid drift-off of a floating vessel occurs.

Features

■ Can unlatch with 200,000-lbf tension

■ Smooth remote latching and unlatching ensured by orientation helix

■ Backup hydraulic unlatch

■ Optional indicator switch for latch position

■ Post-shear J-slot fishing profile and post-shear retrieval tool with matching J-slot

Table 6. Helical Latch Module Specifications

S7HL

Service H2S and CO2

Length†_{(in. [mm])} _{32.4 [823]}

Weight (lbm [kg]) 770 [349]

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Figure 10. Helical latch. Position switch (optional) Self-aligning skirt (180° rotation) Electrical telemetry feed through

Shear pin (antirotation safety device)

Hydraulic connector

Operating piston

Latch ring dog Shear sub

Electrical telemetry cable

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Flapper valve

The SenTREE 7 flapper valve module (S7FV) (Table 7) is the secondary subsea safety valve during the completion or intervention of a subsea well. It consists of a surface-controlled, fail-safe closed 73_⁄₈_{-in. ID flapper valve (Fig. 11).}

Features

■ Holds 10,000 psi from below

■ Fast-response fail-safe close

■ Pump-through capability at less than 1000-psi differential from above (optional non-pump-through configuration)

■ Soft-opening flapper (Valve remains closed until the pressure across it is equalized.)

Table 7. Flapper Valve Module Specifications

S7FV

Service H2S and CO2

Length (in. [mm]) 28.9 [734]

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Figure 11. Flapper valve module.

Flapper valve

Piston Contact switch (optional)

Seal retainer

Electrical line

Hydraulic line

Ball valve module Helical latch

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Ball valve

The SenTREE 7 ball valve module (S7BV) (Table 8) is the primary subsea safety valve during the completion or intervention of a subsea well. It consists of a surface-controlled, fail-safe closed 73_⁄₈_{-in. ID ball valve (Fig. 12) that can cut up to 2-in. coiled tubing.}

The project-specific slick joint can be placed below the ball valve module or between the flapper and ball valve module.

Features

■ Holds 10,000 psi from below

■ Holds 10,000 psi from above with 10,000 psi on closed line

■ Fast-response fail-safe close

■ Cuts up to 2-in. OD, 0.157-in. wall thickness, 80-ksi yield coiled tubing

■ Pump-through capability at less than 1000-psi differential from above (optional non-pump-through configuration)

Table 8. Ball Valve Module Specifications

S7BV

Service H2S and CO2

Working pressure (psi [bar]) 10,000 [689] Test pressure†_{(psi [bar])} _{15,000 [1035]}

Min temperature rating (°F [°C]) –20 [–29]

Max OD (in. [mm]) 18.56 [471]

Min ID (in. [mm]) 7.375 [187] Length (in. [mm]) 34.6 [879]

Weight (lbm [kg]) 2230 [1012]

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Figure 12. Ball valve module. Ball valve Piston Spring Contact switch (optional) Seal retainer Electrical line Hydraulic line Turnbuckle

Ported slick joint Flapper valve module

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Accessories and

Project-Specific

Assemblies

Some components of the SenTREE 7 well control system are project specific. As such, they must be custom manufactured and certified. As shown in Fig. 13, the SenTREE 7 project-specific components are

■ saver and crossover sub

■ ported packoff sub

■ space-out sub

■ spacer sub

■ ported slick joint.

These accessories meet the specifications of the main components of the SenTREE 7 basic string (Table 1).

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Figure 13. Project-specific accessories for the SenTREE 7 system.

SenTREE 7 valves and latches Project-specific

components

Saver and crossover sub

Ported packoff sub

Bleedoff valve and retainer valve Helical latch Flapper valve Ball valve Tubing hanger running tool Ported slick joint

Spacer sub Space-out sub

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Saver and crossover sub

The uppermost component of the SenTREE assembly connects it to the landing string.

Packoff sub and space-out sub

The space-out sub connects the retainer valve to the upper string and positions the packoff sub across the BOP annular rams of the rig (Fig. 14).

Skirt Hydraulic hose Mandrel Antirotation key Packoff sub Space-out sub Sealing area

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Spacer sub

The spacer sub (Fig. 15) is located across the BOP shear rams for the purpose of emergency dis-connect shearing. The sub is attached to the bottom of the retainer valve with a spacer adapter. It is also used as the mandrel for the helical latch. The sub design is based on detailed informa-tion about the BOP stack and shear ram capabilities.

High-pressure hydraulic line

Shear area

To helical latch To retainer latch

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Ported slick joint

The ported slick joint (Fig. 16) is a clean-sealing face for closing the pipe rams to provide annu-lus control during well flowback. It also serves as a crossover between the SenTREE SCTT and the third-party THRT, with control and function of the THRT achieved through the integral inter-nal hydraulic through ports and electrical feed through. The configuration of the bottom connection depends on the THRT specifications and BOP configuration.

Figure 16. Ported slick joint.

Hyraulic seal stab

Nut Lock screw Split ring assemly

Electrical feed through

THRT Ball valve module

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Fishing Assemblies

Post-shear retrieval tool

As a last resort in an emergency, the spacer sub can be sheared by the BOP shear rams. The project-specific spacer sub must be matched with a BOP stack that can shear it. After this oper-ation is performed, the post-shear retrieval tool (S7PSRT) (Fig. 17 and Table 9) must be used to unlatch the helical latch module and pull it out of the hole. The tool retrieves only the lower sheared sub and latch module. After it is lowered over the helical latch module with the locat-ing profile in the latched position, the landlocat-ing strlocat-ing is rotated clockwise to disconnect the latch.

Table 9. Fishing Assembly Specifications

S7PSRT S7MRT S7BMRT

Service – NACE MR-01-75 NACE MR-01-75

Working pressure (psi [bar]) – 10,000 [689] 10,000 [689] Min temperature rating (°F [°C]) –20 [–29] –20 [–29] –20 [–29]

Max temperature rating (°F [°C]) 325 [163] 325 [163] 325 [163] Torque capacity (ft-lbf [N·m]) 60,000 [81,300] 60,000 [81,300] 60,000 [81,300]

Tensile load (lbf [kN]) 300,000 [1340] 1,000,000 [4450] 1,000,000 [4450]

Tensile load at working pressure (lbf [kN]) na 400,000 [1780] 400,000 [1780] Max OD (in. [mm]) 16 [406] 18.5 [470] 18.56 [471]

Min ID (in. [mm]) 11 [279] 4 [102] 4 [102]

Length (in. [m]) 64.5 [1.64] 50.0 [1.27] 63.0 [1.60]

Weight (lbm [kg]) 5083 [913] 963 [437] 2013 [913]

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Figure 17. Post-shear retrieval tool.

Fishing profile Crossover sub

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Post-unlatch retrieval tool

The post-unlatch retrieval tool (S7MRT) (Fig. 18 and Table 9) is used to relatch on the lower part of the SenTREE 7 SCTT and retrieve that complete string if the latch assembly fails. The S7BMRT version can be used to bleed off checked hydraulic coupler nipples to relieve pressure. The tool can also be used as a test cap for the flapper valve module.

Figure 18. Post-unlatch retrieval tool.

Lock ring Centralizer Crossover sub Shear pin Mandrel Centralizer piston

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Commander Control Systems

Two different Commander control systems are used for the SenTREE 7 system:

■ hydraulic control system with a large umbilical to the surface for water depths not exceeding 5000 ft [1524 m]

■ telemetry control and monitoring system with a single small umbilical for deepwater (up to 10,000 ft [3048 m]) and fast response time.

Control system disconnect times are as follows:

■ hydraulic system response time is dependent on the water depth

■ telemetry system response time is less than 15 s.

Both Commander systems allow the injection of chemicals (e.g., hydrate or corrosion inhibitors) either above or below the ball valve. The injection is made with the hose connection at the spacer sub.

Commander hydraulic control system

The Commander hydraulic control system (Fig. 19) is used to operate the SenTREE 7 system in water depths up to 5000 ft. The system comprises the following major components:

■ hydraulic power unit (HPU) (Fig. 20 and Table 10)

■ umbilical reel (Fig. 21 and Table 10)

■ various deck jumpers

■ remote panels.

Table 10. Hydraulic Power Unit and Reel Specifications

HPU Reel

Reel capacity (21-hose bundle) (ft [m]) 5500 [1670]

Footprint (ft [m]) 9.5 × 7.5 [2.9 × 2.3] 12.5 × 10.5 [3.8 × 3.2]

Height (ft [m]) 9 [2.7] 9 [2.7]

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Figure 19. Commander hydraulic control system of the SenTREE 7 system.

Rig power

Hydraulic power unit Umbilical Flowhead Retainer valve Tubing hanger running tool Latch assembly Slick joint Valve assembly Chemical injection Umbilical reel

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Figure 21. Reel.

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Commander telemetry control and monitoring system

The Commander telemetry control and monitoring system (Fig. 22) provides surface and subsea control of the SenTREE 7 equipment, THRT, surface-controlled subsurface safety valve (SCSSV), smart well functions, lubricator valves and surface flowhead. Almost instantaneous response is achieved by the PC-based operator interface, which generates control signals that are multi-plexed and transmitted subsea via the surface-to-subsea umbilical cable. The signals are decoded subsea to operate solenoid control valves, which direct hydraulic fluid to the SenTREE 7 and THRT functions as required. An integrated autonomous fail-safe sequence ensures that the SenTREE 7 system will be shut in upon loss of the umbilical (i.e., loss of communications or elec-trical or hydraulic power from the surface).

The Commander telemetry system provides the following functions and features:

■ subsea hydraulic supplies, electrical power and telemetry

■ control of all SenTREE 7 and tubing hanger functions with pressure readback

■ control of up to 24 subsea hydraulic functions, 5 subsea control module internal hydraulic functions and 12 surface hydraulic functions

■ monitoring of approximately 255 data points at an update rate of 15 Hz

■ monitoring information for all equipment status data, pressures, valve positions, etc.

■ programmable emergency shutdown (ESD) capability

■ fully sequenced autonomous fail safe in case of umbilical loss

■ shutdown sequence completion within 15 s

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Figure 22. Commander telemetry control and monitoring system of the SenTREE 7 system.

Rig power

Rig communication system

Emergency shutdown panel Emergency shutdown panel Emergency shutdown panel Flowhead Subsea accumulator module Subsea control module Spanner joint Retainer valve Tubing hanger running tool Latch assembly Valve assembly Slick joint Umbilical reel Umbilical

Hydraulic power unit

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Equipment

The Commander telemetry system comprises the following equipment (Table 11), which is mounted both on the drilling vessel and deep within the riser, just above the BOP:

■ HPU: hydraulic supplies for both surface and subsea functions

■ flowhead control panel (FCP): interface between the surface control unit and the surface flowhead and lubricator valves

■ surface control unit (SCU): operator interface and electrical power and communications for all surface and subsea equipment

■ subsea accumulator module (SAM): storage for all hydraulic accumulation subsea

■ subsea control module (SCM): control and monitoring of all subsea functions, including ESD and fail-safe routines

■ subsea spanner joint (SSJ): flexible spacer joint for positioning the control system compo-nents in the riser, above the flex joint.

Table 11. Commander Telemetry System Specifications

Commander Terlemetry System

Service H2S and CO2 per NACE MR-01-75

Riser fluid service Stabilized brine or drilling mud Max water depth (ft [m]) 10,000 [3048]

System operating pressure

Low (psi [bar]) 5,000 [345]

High (psi [bar]) 10,000 [690]

Max riser hydrostatic pressure (psi [bar]) 5000 [345] Temperature range (°F [°C]) 32–200 [0–93]

Max tensile load at working pressure (lbf [kN]) 700,000 [3120] Max subsea tensile load

At 0 psig (lbf [kN]) 1,000,000 [4450] At 10,000 psig (lbf [kN]) 400,000 [1780]

Subsea torque capacity (ft-lbf [N·m]) 40,000 [54,200]

System type Multiplexed electrohydraulic Operating hydraulic fluid Castrol Transaqua®_{HT200 (or similar)}

Cleanliness National Aerospace Standard (NAS) 1638 Class or better

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Hydraulic power, electrical power and telemetry signals from the surface are sent to the subsea equipment via an electrohydraulic umbilical deployed on a pneumatically driven reel. Hydraulic fluid is stored subsea at two pressures: 10,000 and 15,000 psi above hydrostatic pressure in the SAM. The 5,000-psi supply is regulated from the 10,000-psi supply within the SCM.

Mounted directly below the SAM, the SCM contains a subsea electronic module, solenoid-operated valves, flowmeters, filters, relief valves and pressure transmitters, all of which are mounted within a pressure-compensated enclosure. The subsea electronics module receives telemetry signals from the SCU, decodes them and then operates the appropriate solenoid-operated valves to direct fluid to the subsea actuators. The subsea electronics module also sends monitoring information (e.g., pressure, temperature, valve status) to the SCU for display.

Emergency shutdown

ESD of the system is implemented from the SCU ESD panel or from any of three remote panels strategically located on the vessel. Four levels of ESD are available with the Commander telem-etry system:

■ ESD4: Close the flowhead production wing valve.

■ ESD3: Per ESD4 and close the ball valve.

■ ESD2: Per ESD3 and close the flapper valve and retainer valve.

■ ESD1: Per ESD2 and open the bleedoff valve and unlatch the subsea completion and test tree. If communications and the electrical and hydraulic supplies to the SCM are lost, the solenoid-operated valves in the system automatically close following a predefined fail-safe sequence. The fail-safe sequence vents all SCTT close functions after closure of the valves and also vents the latch function.

Design philosophy and requirements

Operational philosophy

The master control station (MCS) within the SCU is the interface for the control and monitoring of all surface and subsea equipment. Each valve operation, with the exception of the ESD sequences, is input at the keyboard by the MCS operator. The MCS communicates with the SCM via the Schlumberger cable telemetry system (CTS).

HPU output pressures and reservoir levels are monitored by the MCS. The HPU is a self-con-tained unit, operating independently of the MCS, with internal control circuits that control the HPU pumps.

The MCS has the following functionalities:

■ control of all SCM control valves and position display inferred from the pressure transducers

■ control of all FCP valves and position display inferred from the pressure transducers

■ status display of ESD signals from the SCU ESD panel, remote ESD panels and rig control system

■ continuous monitoring and display of all pressure transducers, temperature transducers, return flowmeters, SCTT valve position switches, and surface and subsea equipment status parameters.

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Shutdown philosophy

Shutdown signals are generated from the rig-mounted ESD panels or from the rig control system. On receipt of an ESD signal, the surface circuit closes the necessary surface valves and simulta-neously transmits the ESD signal to the dual-redundant ESD electrical timer circuits in the SCM. The dual-redundant electrical timer circuits initiate sequenced closure of the subsea valves. If power to the SCM is lost, the subsea battery unit (SBU) within the SAM provides the required power for valve operations.

The four levels of ESD available with the Commander telemetry system are listed in the “Emergency shutdown” section. The Commander telemetry system is a fail-closed system in response to the loss of electrical power or communications and the loss of hydraulic pressure to the SCM (i.e., umbilical failure).

Valve position indication philosophy

Integrally mounted position switches on the SCTT are used to monitor the position of the valves. The position monitoring of all other subsea valves is inferred from the pressure transducers on each function line along with the last command position of the valve.

Subsea accumulator module

The SAM (Fig. 23 and Table 12) comprises a National Association of Corrosion Engineers– (NACE-) specification central mandrel with eight 20-ft long piston accumulators arrayed around it. The upper connection hub of the SAM provides the threaded interface to the landing string and the termination point and bend strain relief for the subsea umbilical. A saver sub is included to prevent damage to the threads.

The umbilical terminates in two quick-connect hydraulic couplings and a seven-way Schlumberger downhole electrical connector. All hydraulic lines on the SAM are American Society for Testing and Materials (ASTM) A-269 316L stainless steel. The connections are all welded; compression fittings are not used.

Hydraulic fluid is stored at two pressures—nominally 5,000 and 10,000 psi—in six off low-pressure (LP) and six off high-pressure (HP) piston-style accumulators. Sufficient LP accumulation is provided to enable a complete “close-open-close and unlatch” operation of the SCTT without replenishment from the surface. HP accumulation is used for THRT testing and to enhance the coiled tubing cutting ability of the SCTT.

The SAM also contains the SBU and a reservoir accumulator for the storage of hydraulic fluid before venting to the riser.

Table 12. Subsea Accumulator Module Specifications

SAM

Service H2S and CO2per NACE MR-01-75

Mandrel working pressure (psi [bar]) 10,000 [690]

Max tensile load

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A threaded attachment hub secures the SAM to the SCM below.

Subsea control module

The SCM (Fig. 24 and Table 13) is the heart of the Commander telemetry system, controlling and monitoring all subsea functions, including ESD and fail-safe routines. The module is fully pres-sure compensated in an oil-filled enclopres-sure. The SCM comprises a NACE-specification central mandrel, around which all SCM components are mounted within the pressure-compensated, oil-filled housing. The major SCM components are as follows:

■ 24 off 3w/2p solenoid-operated control valves

■ 34 off pressure transmitters

■ 2 off flowmeters

■ 2 off temperature transmitters

■ 6 off hydraulic filters

■ 2 off subsea electronics modules (1 multiplex and 1 direct electrical).

The subsea electronics modules are based on the standard Schlumberger downhole electron-ics enclosure (1 atm). They are rated to 20,000-psi [1380-bar] external pressure and 300°F [149°C].

All electrical components and connectors are rated to withstand 5000-psi hydrostatic head. Hydraulic tubing runs are at a minimum and are all welded. Compression fittings are not used.

Threaded attachment hubs secure the SCM to the SAM above and the SSJ below.

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Table 13. Subsea Control Module Specifications

SCM

Mandrel test pressure (psi [bar]) 15,000 [1035]

Component hydrostatic pressure rating (psi [bar]) 5000 [346] Max electrical working temperature (°F [°C]) 200 [93]

Max tensile load

At 0 psig (lbf [kN]) 1,000,000 [4450] At 10,000 psig (lbf [kN]) 400,000 [1780] OD (in. [mm]) 18.56 [471] ID (in. [mm]) 7.375 [187] Length (ft [m]) 18 [5.5] Weight (lbm [kg]) 6280 [2849]

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Oil fill

Valve controls Upper connector hub to accumulator module

Lower connector hub to spanner sub

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Subsea spanner joint

The SSJ (Fig. 25 and Table 14) is a flexible spacer joint for positioning the control system com-ponents in the riser, above the flex joint. It is essentially a NACE-specification central mandrel with upper and lower attachment hubs. The overall length is 15–25 ft [4.6–7.6 m], depending on the details of the riser flex joint and the results of joint flexure stress analysis.

All-welded tubing runs carry the hydraulic and electrical signals through the SSJ to the SCTT. The hydraulic and electrical connectors are the same as those used on the SCM and SCTT.

At the lower end of the SSJ is a 135_⁄8_{-in. casing hub that allows the annular BOP to seal. At the} upper end is a hydraulic manifold that houses THRT-specific hydraulic valves and the components necessary for special tubing hanger functions.

The SSJ is secured by threaded attachment hubs to the SCM above and to the subsea completion tree below.

Table 14. Subsea Spanner Joint Specifications

SSJ

Mandrel working pressure (psi [bar]) 10,000 [690]

Mandrel test pressure (psi [bar]) 15,000 [1035] Max tensile load

At 0 psig (lbf [kN]) 1,000,000 [4450] At 10,000 psig (lbf [kN]) 400,000 [1780]

Max torque (ft-lbf [N·m]) 40,000 [54,200] OD (in. [mm]) 18.56 [471]

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Sealing area Centralizer

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Subsea umbilical cable

The 11,500-ft [3500-m] long three-core electrohydraulic umbilical (Fig. 26 and Table 15) that connects the surface equipment to the SCM has the following components:

■ Schlumberger armored heptacable

■ two 6.3-mm ID × 12,500-psi working pressure, nylon P40–lined thermoplastic hoses.

The components are within a 0.16-in. [4-mm] thick polyethylene sheath.

Table 15. Subsea Umbilical Cable Specifications

Umbilical

Umbilical OD (in. [mm]) 1.50 [38]

Umbilical length (ft [m]) 11,500 [3500]

Max tensile load (lbf [kN]) 500 [2] Hose ID (in. [mm]) 0.25 [6.35]

Hose working pressure (psi [bar]) 12,500 [860]

Figure 26. Subsea umbilical cable.

Hydraulic line 1 Hydraulic line 2

Outer sheath Nonmetallic filler

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Subsea-controlled functions

The major innovation provided by the Commander telemetry system control of the SCTT is that all surface and subsea hydraulic and electrical functions are monitored and controlled from a single interface in the SCU. The operator interacts with the MCS and displays on screen (Fig. 27) all commands and the status of each component, with the option of overriding the normal preset sequences. The operator also controls and monitors the functions of the SenTREE 7 equipment and client-specified commands to the THRT and any through-tree functions.

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The MCS controls a total of 30 subsea hydraulic functions, including 10 through-SCTT func-tions for the THRT (Table 16).

Table 16. Subsea-Controlled Functions

SCTT Functions

Ball valve Open (LP)

Close (LP or HP)

Flapper valve Open (LP) Close (LP)

Retainer valve and bleedoff valve close Open and bleedoff valve close (LP)

Retainer valve Close (LP or HP) Bleedoff valve Open (LP)

SCTT latch Latch (LP)

SCTT Unlatch (LP)

Typical Through-Tree Functions

Tubing hanger Lock (LP) Unlock (LP)

THRT Latch (LP)

Unlatch (LP)

Tubing hanger soft landing Extend (LP)

Tubing hanger test HP

Common vent LP

Lock monitor LP

Tubing hanger vent and return LP

SCSSV Open (LP or HP)

Defined functions 3 spare

2 Schlumberger defined

Chemical injection Variable Smart well functions Project specific

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Subsea-monitored functions are listed in Table 17. Sensor monitoring of the actual valve posi-tion is an opposi-tion:

■ ball valve closed

■ flapper valve closed

■ retainer valve closed

■ SCTT latched.

Surface-controlled and -monitored functions are listed in Tables 18 and 19, respectively.

Table 18. Surface-Controlled Functions

Flowhead

Flowline valve Open

Kill line valve Open Flowhead swab valve Open or close

Lower master valve Open or close Lubricator valve Open, close

Four spare functions Project specific

Table 17. Subsea-Monitored Functions

Subsea supply pressure HP

10,000-psi ESD pressure HP1

10,000-psi service pressure HP2 5,000-psi ESD pressure LP1

5,000-psi service pressure LP2

24 off subsea function pressures Project specific

4 spare pressure transmitters Project specific

Flowmeter SCTT return manifold Tubing hanger return manifold

Temperature gauge Mandrel Dielectric oil

Chemical injection pressure Variable

Table 19. Surface-Monitored Functions

Hydraulic supply pressure HP, LP

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Surface control unit

The SCU is a standard Schlumberger offshore logging unit (Table 20), air purged and suitable for use in a hazardous area classified as Zone 2 (for a description of classified zones, see “Safety” in the Well Testing Services book of this set). The rugged, all-welded aluminum construction has insulated panels and good shock isolation. The air-conditioned office environment is equipped with a desk, shelving, storage cabinets and viewing window.

Table 20. Surface Control Unit Specifications

SCU

Temperature range (°F [°C]) – 4 to 115 [–20 to 46]

Length × width (ft [m]) 7.6 × 7.0 [2.3 × 2.1] Height (ft [m]) 9.8 [2.99]

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The SCU contains the MCS for operator interface to the control system (Fig. 28). This Windows NT®_{4.0–based system has a graphical status and control user interface. Clear} point-and-click mimic displays facilitate control and monitoring of surface and subsea equipment. The MCS communicates with the subsea equipment via the Schlumberger CTS high-speed telemetry link. It controls and monitors the surface functions through the FCP and monitors the status of the three remote panels.

The SCU features a dual-redundant uninterruptible power supply (UPS), which provides con-ditioned rig power to the system. Each unit provides a minimum of 30 min of battery reserve power at 6000 VA if rig power is lost.