03a_safety_systems

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225 Schlumberger Drive Sugar Land, Texas 77478

All rights reserved. No part of this book may be reproduced, stored in a retrieval system, or transcribed in any form or by any means, electronic or mechanical, including photo-copying and recording, without prior written permission of the publisher

SMP-7086-3

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Introduction

This third book in the Schlumberger Testing Services set is divided into two sections. The first describes well control equipment for offshore and land testing operations. The second sec-tion describes well test design, safety considerasec-tions and the features and selecsec-tion of surface equipment. Regardless of the downhole conditions and well location, Schlumberger equipment and techniques meet the critical need for reliable well control.

When drilling operations are conducted from a floating vessel (a semisubmersible or drill-ship), the stack of subsea pressure-control equipment typically has the following arrangement: ■ _{one or two annular blowout preventers (BOPs) at the top of the stack}

■ _{one or two BOPs equipped with blind/shear rams}

■ _{two or three BOPs equipped with pipe rams to close on drillpipe or test strings.}

The riser, which brings the mud back to the surface, is landed on top of the BOP stack with a hydraulic connector that allows disconnection (Fig. 1). The BOPs and the hydraulic connector are controlled hydraulically from the surface through hoses running in bundles outside the riser.

During testing, the drillstring running through the BOP stack well is full of oil or gas. If it becomes necessary to cut pipe and pull the drilling vessel off location, the well is held in control only by the blind/shear rams, which may be damaged from cutting the pipe. In this scenario, reentry is impossible because of pressure below these rams. To avoid this set of circumstances, a subsea test tree is inserted into the test string.

A subsea test tree system was originally developed to enable well testing operations from an offshore floating rig. The subsea test tree contains valves and a latch that allow fast disconnec-tion of the vessel from the BOP stacks when there is rough weather, dragging or loss of anchor, or failure or malfunction of a dynamic positioning system. The subsea test tree system is the pri-mary safety device and provides fast-acting and reliable means to

■ _{isolate the landing string from the test string} ■ _{prevent discharge of its contents into the riser} ■ _{disconnect the landing string from the test string.}

The disconnection sequence is as follows: 1 Close the valves in the subsea test tree.

2. Close the retainer valve and bleed off the pressure between the valves. 3. Unlatch from the subsea tree valve assembly.

4. Pull the subsea tree latch and the string above it clear of the BOP stack. 5. Close the BOP blind rams.

6. Disconnect the riser.

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Figure 1. BOP stack with riser connected (left) and disconnected (right). Riser Hydraulic connector BOP stack Blind rams

Subsea test tree valve assembly

Subsea test tree latch Retainer valve

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Schlumberger developed the riser sealing mandrel (RSM) (Fig. 2 and Table 1) as an additional safety device to meet the requirements of Hazard and Operability (HAZOP) studies during deep-water well testing operations.

With the increase in water depth, a gas or hydrocarbon leak in the landing string close to the subsea test tree (i.e., leak from inside tubing to the riser) can develop a high-volume gas kick at the surface. To safely control and divert this volume, the RSM is located at the level of the diverter BOP below the rig floor, and the diverter BOP is closed on it.

All the umbilical hoses are well protected, and the seal around them is ensured with specially designed rubber hose sealing elements.

Features

■ _{The 9.5-in. OD and the modular design enable using the RSM with most BOP sizes and} configurations.

■ _{The rig-up time is shortened with easy-to-install protective plates and specially designed} rig-up tools.

■ _{The protective capacity (26 hose-sealing elements) allows it to be used with various umbilical} hoses:

5 hoses 1 ×2 in. 2 ×11_⁄₄_in. 2 ×3_⁄₈_in.

6 hoses 1 ×11_⁄₂_in. 2 ×₁1_⁄₄_in. 1 ×_{1 in.} 2 ×3_⁄₈_in.

Riser Sealing Mandrel

Table 1. Riser Sealing Mandrel Specifications

Unit RSM

Service H2S

OD in. [mm] 9.5 [241]

ID in. [mm] 3.75 [95]

Working pressure psi [bar] 10,000 [690]

Working temperature °F [°C] –20 to 250 [–30 to 120]

Make-up length ft [m] 30 [9.1]

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Figure 2. Riser sealing mandrel. Umbilical Hose-sealing elements Protective plates A A′ Section A–A′

(sealing elements are compressed) 9.5 in.

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Johnston-Schlumberger was the pioneer in subsea systems with the introduction of the E-Z Tree* retrievable well control system in 1975. In the mid-1990s, Schlumberger launched a project to redesign the subsea test tree system to meet the latest industry requirements:

■ _{ability to close the shear rams with the latch in place}

■ _{latest study requirements (HAZOP) for deep-sea operations incorporated} ■ _{ability to close two BOP pipe rams around the slick joint}

■ _{ability to close two shear rams.}

Following a very successful field test period, the SenTREE* 3 system (EZTM) was commer-cialized at the end of 1997.

The SenTREE 3 test tree (Fig. 3) is hydraulically controlled from the surface and consists of a dual fail-safe ball valve and flapper valve and a connector (latch) that is landed in the BOP stack. Its modularity (Fig. 4) enables placement of the slick joint either below the valve assem-bly or between the latch and valve assemassem-bly to match even very short BOP stack configurations. A set of unique features (verified and approved by Det Norske Veritas) makes the SenTREE 3 system the preferred tree for all standard tests and the first choice for deep-sea and high-pressure, high-temperature (HPHT) operations.

Features

■ _{Reduced length and modularity} – 46-in. standard configuration – 16- and 32-in. split configuration

■ _{HPHT tested and qualified to full pressure and temperature range} ■ _{Ability to unlatch at full tension, with an angle of up to 6°}

■ _{Backup mechanical unlatch (5 turns)}

■ _{Latch fishing profile and dedicated fishing tool} ■ _{Chemical injection below or at valve level}

With the standard control section, the SenTREE 3 tree is operated through an umbilical hose that consists of three hydraulic control lines. At the surface, the hose is connected to an air-driven hydraulic power unit (control console). The specially designed deep-sea control systems available are described subsequently in this section.

When a chemical injection hose or a four-line umbilical hose is run, the SenTREE 3 system allows injection of chemicals (such as hydrate or corrosion inhibitors) either above or below the ball valve.

SenTREE 3

Test Tree System

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Figure 3. SenTREE 3 standard configuration. Riser BOP stack Blind rams Pipe rams Annular BOP Shear rams Pipe rams Retainer valve Valve assembly Shear sub Slick joint Adjustable fluted hanger Bleed-off valve Latch assembly Spanner joint

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Figure 4. SenTREE 3 modular split configuration. Retainer valve Valve assembly Shear sub Slick joint Adjustable fluted hanger Bleed-off valve Latch assembly Spanner joint Riser BOP stack Pipe rams Annular BOP Shear rams Pipe rams Shear rams

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SenTREE 3 components

The SenTREE 3 test tree system includes the following components: ■ _{valve assembly (EZTV)}

■ _{latch assembly (EZTH)} ■ _{retainer valve (RETV)} ■ _{spanner joint.}

Valve assembly

The SenTREE 3 valve assembly (EZTV) (Fig. 5 and Table 2) consists of two hydraulically operated fail-safe valves. The main valve is a ball type; the second is a flapper valve. This combination has proved to be the most reliable fullbore subsea system.

Sequential valve closure ensures that the flapper valve closes only after the ball valve is closed. The delay allows wireline or coiled tubing (CT) to clear the flapper after being cut by the lower ball assembly.

The pump-through facility of the valve assembly permits well control if hydraulic control is lost. Positive differential pressure applied from above opens a flow area for well kill operations that is equivalent to a 11_⁄₄_{-in. line.}

Table 2. SenTREE 3 Valve Assembly Specifications

Unit EZTV-DA

Service H2S per NACE MR-01-75

Design temperature °F [°C] –4 to 350 [–20 to 177]

OD in. [mm] 13.0†_[330]

With centralizer 16.1 [409]

ID in. [mm] 3.0 [76]

Test pressure (body psi [bar] 22,500 [1550]

only, valves open)

Max tensile load at 90% lbf at 0 psi [kN at 0 bar] 520,000 [2310]

yield and 350°F [177°C] lbf at 15,000 psi [kN at 1035 bar] 255,000 [1130]

Injection line working pressure psi [bar] 15,000 [1035]

Bottom connection 5-in. 4 S.A. box

Wireline cutting capability Up to 5_⁄₁₆_{in. (no assistance required)}

[Up to 7.9 mm (no assistance required)]

CT cutting capability Up to 11_⁄₂_in.×_{0.156 in. (hydraulic assistance 5000 psi)}

[Up to 38 mm ×3.9 mm (hydraulic assistance 345 bar)]

Max torque ft-lbf [N⋅m] 7500 [10,200]

Length in. [mm] 32.2 [818]

Weight with centralizer lbm [kg] 1124 [510]

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Figure 5. SenTREE 3 valve assembly.

Ball valve Flapper

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Latch assembly

The latch assembly (EZTH) (Fig. 6 and Table 3) is the upper part of the subsea tree and connects the landing string to the valve assembly. If hydraulic control is lost, the latch can be disconnected mechanically. Two shear keys, which break at a known torque value, connect the latch body to the shear sub. Figure 7 shows the combined latch and valve assemblies of the SenTREE 3 test tree system.

Table 3. SenTREE 3 Latch Assembly Specifications

Unit EZTH-DA

OD in. [mm] 12.5 [318]

With centralizer 16.1 [409]

ID in. [mm] 3.0 [76]

Test pressure psi [bar] 22,500 [1550]

Max tensile load lbf at 0 psi [kN at 0 bar] 520,000 [2310]

at 90% yield and 350°F lbf at 15,000 psi [kN at 1035 bar] 255,000 [1130]

Top connection 5-in. 4 S.A. pin

Length in. [mm] 16.0 [406]

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Figure 6. SenTREE 3 latch assembly.

Latch dog

Skirt Piston

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Latch dog Latch profile Latch assembly Valve assembly

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Retainer valve

The retainer valve (RETV) (Fig. 8 and Table 4) can be run above the SenTREE 3 latch assembly to retain the fluids trapped in the landing string after disconnecting from the SenTREE 3 valve assembly. When disconnecting, the retainer valve prevents the uncontrolled release of hydro-carbons from the landing string into the riser and the sea. When testing wells in deep water or when testing high-pressure gas wells, use of the retainer valve is a safety and environmental requirement.

The RETV is controlled hydraulically in sequence with the subsea test tree. An integral bleed-off valve (BOV) vents the trapped pressure between the retainer valve and the test tree to the riser before unlatching. The RETV uses the same ball valve mechanism as the SenTREE 3 system and is capable of cutting 1.5-in. CT. Hydrocarbons in the landing string can be reversed out as the RETV ball valve is pumped away from its seat with greater pressure below the valve. The RETV is a fail-safe valve when closed, but in case of control line failure, the RETV ball valve can be opened by closing the annular BOP on the spanner joint and pressuring up below.

Features

■ _{Fail-safe closure}

■ Ability to cut 1.5-in. ×_{0.15-in. CT with pressure assist} ■ _{Integrated bleed-off valve}

■ _{Pump-through facility with the spanner joint} ■ _{Pressure tests from above}

■ _{Reverse circulation (U-tube)} ■ _{Ports for high-rate injection}

Table 4. SenTREE 3 Retainer Valve Specifications

Unit RETV-DA

OD in. [mm] 13.0 [330]

ID in. [mm] 3.0 [76]

Test pressure (valves open) psi [bar] 22,500 [1550]

Connection 5-in. 4 S.A. box with lock key

Max torque ft-lbf [N⋅m] 15,000 [20,300]

Overall length including ft [m] with 5-ft spanner 10.6 [3.2]

spanner joint ft [m] with10-ft spanner 15.6 [4.7]

Overall weight including lbm [kg] with 5-ft spanner 2000 [910]

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Figure 8. SenTREE 3 retainer valve. Ball valve Pins Seal retainer

BOV Open BOV Closed

Ball cage

Piston Ball spring

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Spanner joint

The spanner joint (Fig. 9 and Table 5) sits on top of the retainer valve and allows closing the annular BOP. This safety feature was introduced in 1997. The spanner joint was developed to fulfill the following functions:

■ _{enable closure of the annular BOP on the landing string to pressurize the annulus to open the} ball valve if hydraulic controls are lost

■ _{enable, through the hydraulic block manifold, the operating sequence of the SenTREE 3} system and the RETV valves

■ _{protect the control hoses when closing the BOP.}

Table 5. Spanner Joint Specifications

Unit Spanner Joint

Design temperature °F [°C] –4 to 350°F [–20 to 177]

OD in. [mm] 10.75 [273]

ID in. [mm] 3.0 [76]

Test pressure psi [bar] 22,500 [1550]

Connection 5-in. 4 S.A. box with lock key

Max torque ft-lbf [N⋅m] 15,000 [20,300]

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Figure 9. Spanner joint. Skirt Hydraulic sequencing manifold Centralizer Hydraulic hose Retainer valve

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Accessories

Figure 10 shows the SenTREE 3 components in both a short configuration and a standard con-figuration. The spanner joints, retainer valve and shear sub extensions are required in both configurations.

EZSJ-FA

Integral slick joint 46-in. configuration with ported line

EZH-IA Integral bottom sub/hanger with ported lines EZSJ-DA Slick joint 16-in. configuration with ported lines

EZHP-DA Hanger ported line

EZH-DB Hanger nonported EZSJ-GA Slick joint with ported line EZSJ-HA Slick joint nonported High-strength shear sub Shear sub extensions RETV-DA

Spanner joints

Crossover

Super short configuration Standard configuration

Standard shear sub EZHR-A Slim 2.5-in. ID nonported line Retainer valve Riser sealing mandrel

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The type of subsea control system used to operate the subsea test tree depends on the water depth. Schlumberger has developed three systems (Fig. 11) to accommodate different depths and optimize the disconnect time of the latch assembly:

■ _{standard system for depths to 1500 ft [457 m]}

■ _{deep-sea hydraulic system for depths from 1500 to 4500 ft [457 to 1372 m]} ■ _{electrohydraulic system for depths from 4,500 to 10,000 ft [1372 to 3048 m].}

Subsea Control Systems

4500 ft

Deep-Sea Hydraulic System

Use only with moored vessel SenTREE 3 system + RETV Hydraulic pod Accumulator

Console Reel Reel

10,000 ft

Deep-Sea Electrohydraulic System

Always use with dynamically positioned vessels Electro-hydraulic pod HPU EPU SenTREE 3 system + RETV 1500 ft Standard System Console Reel SenTREE 3 system + RETV Surface accumulator can be used to decrease

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Disconnect times

The disconnect time for any hydraulic system depends on the landing string configuration, on whether a retainer valve is used and on the umbilical hose length.

The downhole hydraulic pod system with surface accumulator was tested and qualified both onshore and offshore. Using the SenTREE 3 system and RETV, the complete cycle (close, bleed-off and disconnect) times are 41 s at 4400 ft [1341 m] and 52 s at 7400 ft [2255 m].

The electrohydraulic pod with 8500 ft [2591 m] of umbilical hose was also tested and qualified both onshore and offshore. Using the SenTREE 3 system and RETV, the complete cycle (close, bleed-off and disconnect) time is 10 s at water depths to 8500 ft.

Standard system features

The standard system (Fig. 12 and Table 6) intended for SenTREE 3 operation in shallow water depths to 1500 ft comprises

■ _console ■ _reeler

■ _{hose bundle, 4500-ft long.}

A hydraulic logic diagram for the standard control system used with the SenTREE 3 system is shown in Fig. 13. A diagram for use with the SenTREE 3 system and retainer valve is shown in Fig. 14.

Table 6. Standard Control System Reeler and Console Specifications

Unit Reeler Console

Reeler motion Air driven

Reeler capacity three-hose bundle ft [m] 4500 [1370]

Footprint ft [m] 10.5 ×6.9 [3.2 ×2.1] 2.9 ×2.0 [0.9 ×0.6]

Height ft [m] 6.6 [2.0] 3.8 [1.2]

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Figure 12. SenTREE 3 system with standard control system. 1500 ft SenTREE 3 system Console Reel Retainer Spanner joint

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Figure 13. Hydraulic logic diagram for standard control system used with SenTREE 3 system. B A C CI Latch Unlatch Unlatch Latch Close Open Ball valve Chemical injection Flapper valve Close Open Close Open Close Open Latch connector

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Figure 14. Hydraulic logic diagram for standard control system used with SenTREE 3 system with retainer valve. Close Open Latch Unlatch Unlatch Latch Close Open Ball valve Chemical injection Flapper valve Close Open Close Open Close Open Latch connector Close Open Close Open HF CI Retainer valve BOV Open Close C B A CI Spanner joint Chemical injection Vent to annulus Sequence valve

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Deep-sea hydraulic system

The deep-sea hydraulic system (Fig. 15 and Table 7) is for operation of the SenTREE 3 system in medium water depths, between 1500 and 4500 ft. The system comprises

■ _{deep-sea console}

■ _{accumulator surface unit} ■ _reeler

■ _{hose bundle, 4500 ft long} ■ _{hydraulic control pod.}

Table 7. Deep-Sea Hydraulic System Component Specifications

Unit Pod

Service H2S

OD in. [mm] 13.0 [330]

ID in. [mm] 3.0 [76]

Mandrel working pressure psi [bar] 15,000 [1035]

Mandrel test pressure psi [bar] 22,500 [1550]

Max tensile loadlbf at 0 psi [kN at 0 bar] 520,000 [2310]

lbf at 15,000 psi [kN at 1035 bar] 255,000 [1130]

Connection 5 in. 4 S.A. box up ×pin down

Accumulator Surface Unit

Working pressure psi [bar] 5000 [345]

Capacity gal [L] 2 ×13 [2 ×50]

Nitrogen pressure psi [bar] 2600 [180]

Footprint ft [m] 8.2 ×2.0 [2.5 ×0.6]

Height ft [m] 2.2 [0.7]

Weight lbm [kg] 1430 [650]

Reeler

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Figure 15. SenTREE 3 system with deep-sea hydraulic control system. 4500 ft SenTREE 3 system Retainer Spanner joint Hydraulic pod Accumulator surface unit Console Reel

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Deep-sea electrohydraulic system

The deep-sea electrohydraulic control system (Fig. 16 and Table 8) is for remote control of the SenTREE 3 system in water depths to 10,000 ft.

The system is designed for a closure and unlatching time of 10 s at any water depth. A single umbilical hose is used for all functions, including two surface readout lines for the pressure and temperature monitoring sub. The system comprises

■ _{surface control unit}

■ _{umbilical hose and air-driven reeler}

■ _{deep-sea pod (hydraulic accumulators and solenoid valves).}

Table 8. Deep-Sea Electrohydraulic System Component Specifications

Unit Pod

Service H2S

OD in. [mm] 14.5 [368]

ID in. [mm] 3.0 [76]

Mandrel working pressure psi [bar] 15,000 [1035]

Mandrel test pressure psi [bar] 22,500 [1550]

Length ft [m] 22.4 [6.8]

Connection 5-in. 4 S.A. box up ×pin down

Reeler and Surface Control Unit

Reeler capacity three-hose bundle ft [m] 10,000 [3050]

Footprint ft [m] 13.5 ×8.5 [4.1 ×2.6]

Height ft [m] 8.9 [2.7]

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SenTREE 3 system Electrohydraulic pod and accumulator

Reel Retainer Surface control unit T and P surface readout 10,000 ft Spanner joint

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Drift-off analysis

Drift-off analysis defines the disconnect philosophy and establishes the times required for dis-connection of stack components in the subsea test tree.

As an example, consider a drift-off analysis for North Sea conditions, where a complete dis-connect is required in 37 s or less, including pull-off from the BOP stack. This leaves 20 s for the complete sequence. Of the three control systems, only the electrohydraulic system is capable of making these disconnect times. In the analysis in Fig. 17, the subsea test tree must close, disconnect and clear the riser connector before the emergency disconnect sequence (ESD) procedure can begin.

Figure 17. Deep-sea drift-off analysis example. 9 8 7 6 5 4 3 2 1 0 Elapsed time (s) Start emergency disconnect 37-s SenTREE disconnect 25-s disconnect Riser disconnect Drilling Testing 0 20 40 60 80 100

Storm environment: 1-knot current, 55-knot wind

Vessel offset (% water depth)

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Subsea pressure and temperature carrier

The subsea pressure and temperature carrier (EZGC) (Fig. 18 and Table 9) is used to monitor pressure and temperature at the subsea tree level. The well effluent pressure and temperature are recorded in surface readout or recorder mode.

This sub is recommended for use in HPHT tests, particularly to measure temperature at the BOP level and to ensure that the maximum temperature rating of the BOP elastomers is not exceeded. The other application is for hydrates control, especially during deep-sea operations.

Two UNIGAGE* H-Sapphire* pressure gauges are included with the tool. One gauge should have a high-resolution thermometer for direct effluent temperature measurement.

Table 9. Subsea Pressure and Temperature Carrier Specifications

Unit EZGC-A

Service H2S

OD in. [mm] 7.9 [200]

ID in. [mm] 3.0 [76]

Working temperature °F [°C] 375 [190]

Make-up length ft [m] 10.6 [3.2]

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Figure 18. Subsea pressure and temperature carrier.

UNIGAGE H-Sapphire SRO module

Direct temperature reading Jumper cable

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During offshore testing where slickline, wireline or CT operations are performed, it may be advantageous to use a valve that limits lubricator height above the flowhead. The lubricator valve (LUBV), usually located about 90 ft below the flowhead, enables the upper part of the string to be used as a lubricator. The LUBV is a balanced system and remains in the position in which it was last placed (open or closed) (Fig. 19). If the valve is closed, however, application of 1800-psi differential pressure from above allows pump-through to kill the well. The LUBV can be pressure tested from above (with hydraulic pressure maintained in the closed line); the valve contains an equalizing device to remove any differential prior to opening.

The LUBV can be used alone or as a backup for a conventional lubricator system. It is a surface-operated hydraulic valve that is run on tubing or drillpipe during testing operations (Table 10). It is normally run in conjunction with the SenTREE 3 system and its retainer valve or with an E-Z Valve* device. The LUBV can be actuated as many times as required for wireline operations. Conversely, the SenTREE 3 or E-Z Valve products are safety devices and should be actuated only in emergencies.

Lubricator Valve

Table 10. Lubricator Valve Specifications

Unit LUBV-CC LUBV-CCB

Service H2S H2S

Working pressure psi [bar] 15,000 [1035] 10,000 [690]

Working temperature °F [°C] –4 to 350 [–20 to 175] –4 to 350 [–20 to 175]

Fail-safe ClosedClosed

Pump-through differential psi [bar] 1800 [125] 1800 [125]

Max tensile loadlbf at 0 psi [kN at 0 bar] 520,000 [2310] 520,000 [2310]

lbf at 15,000 psi [kN at 1035 bar] 255,000 [1130] 255,000 [1130]

Shearing wireline capability Up to 15_⁄_{32-in. [11.9 mm]}

Shearing CT capability 11_⁄_4-in.×15_⁄₃₂_{in. wall [32-mm}×_{11.9-mm wall]}

Connection (box/box) 5-in. 4 S.A. 5-in. 4 S.A.

Length ft [m] 5.0 [1.5] 5.0 [1.5]

OD in. [mm] 8.25 [210] 8.25 [210]

ID in. [mm] 3.0 [76] 3.0 [76]

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Figure 19. Lubricator valve. Double check valve Hydraulic fluid Ball valve

Valve Open Valve Closed Injection Line

Bottom plug Injection point

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The E-Z Valve (EZV) retrievable well control safety device is designed for installation in the BOP stack of a jackup or land rig during well testing when there is no unlatch facility (Table 11). The pipe rams close around a slick joint above the valve, protecting the annulus, while the E-Z Valve ball closes to secure the well at BOP level.

The E-Z Valve device is normally closed by a spring and nitrogen pressure and is opened by hydraulic pressure applied from a console on the rig floor (Fig. 20). The valve is designed pri-marily to hold pressure from below, but it can be pressure tested from above to 5000 psi with normal hose and console or to 7500 psi with a high-pressure set. A hydrate inhibitor such as glycol or methanol can be injected below the valve.

E-Z Valve closure can also be assisted by hydraulic pressure, enabling the ball to cut wireline or 11_⁄₄_{-in. CT in an emergency. Standard and two optional installations are shown in Fig. 21.}

E-Z Valve Retrievable

Well Control Valve

Table 11. E-Z Valve Specifications

Unit EZV-CC

Service H2S

Working temperature °F [°C] –4 to 350 [–20 to 175]

Fail-safe Closed

Shearing wireline capability Up to 15_⁄₃₂_{in. [11.9 mm]}

Shearing CT capability Up to 11_⁄₄_{in. [32 mm]}

Pump-through differential psi [bar] 1800 [125]

N2precharge psi [bar] 1200 [83]

Connection (box/box) 5-in. 4 S.A.

Body length ft [m] 3.8 [1.1]

Valve only length ft [m] 5.0 [1.5]

Slick joint length ft [m] 5.7 [1.7]

E-Z Valve system length ft [m] 16. [5.1]

OD in. [mm] 8.25 [210]

ID in. [mm] 3.0 [76]

Slick joint and valve weight lbm [kg] 1230 [560]

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Figure 20. E-Z Valve operation. Hydraulic fluid Nitrogen and spring Ball valve

Valve Open Valve Closed Valve Closed with Assistance Injection Line Double check valve Injection point Bottom plug Slick joint

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Figure 21. E-Z Valve installation options. C

B A

Option 2 (only from 95_/₈_{-in. casing)}

Option 1 Standard Installation Slick joint E-Z Valve E-Z Valve E-Z Valve

03a_safety_systems

Contents

Introduction

Features

Riser Sealing Mandrel

Features

SenTREE 3

Test Tree System

SenTREE 3 components

Valve assembly

Latch assembly

Retainer valve

Features

Spanner joint

Accessories

Subsea Control Systems

Disconnect times

Standard system features

Deep-sea hydraulic system

Deep-sea electrohydraulic system

Drift-off analysis

Subsea pressure and temperature carrier

Lubricator Valve

E-Z Valve Retrievable

Well Control Valve