Guidelines for Isolation and Intervention

5/21/2018 Guidelines for Isolation and Intervention

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Guidelines for

Isolation and Intervention:

Diver Access to Subsea Systems

IMCA D 044October 2009


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ABThe International Marine Contractors Association(IMCA) is the international trade association

representing offshore, marine and underwater

engineering companies.

IMCA promotes improvements in quality, health, safety,environmental and technical standards through the publicationof information notes, codes of practice and by otherappropriate means.

Members are self-regulating through the adoption of IMCAguidelines as appropriate. They commit to act as responsiblemembers by following relevant guidelines and being willing to beaudited against compliance with them by their clients.

There are two core activities that relate to all members: Competence & Training Safety, Environment & Legislation

The Association is organised through four distinct divisions,each covering a specific area of members interests: Diving,Marine, Offshore Survey, Remote Systems & ROV.

There are also five regional sections which facilitate work onissues affecting members in their local geographic area Asia-Pacific, Central & South America, Europe & Africa, MiddleEast & India and North America.

IMCA D 044

This guidance has been prepared for IMCA under the directionof IMCAs Diving Division Management Committee based onmaterial provided by Torquil M Crichton and other co-authorsof Technip UK Limited.

www.imca-int.com/diving

The information contained herein is given for guidance only and endeavours to

reflect best industry practice. For the avoidance of doubt no legal liability shall

attach to any guidance and/or recommendation and/or statement herein contained.

2009 IMCA International Marine Contractors Association


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Guidelines for Isolation and Intervention:

Diver Access to Subsea Systems

IMCA D 044 October 2009

1

Introduction ........................................................................................................... 1

2

Glossary .................................................................................................................. 2

3

Principles of Isolation ............................................................................................ 5

3.1

Principles of Isolation ........................................................................................................................................ 5

3.2

System Isolations ................................................................................................................................................ 5

3.2.1

Liquid and Gas Equipment ................................................................................................................... 5

3.2.2

Electrical Equipment ............................................................................................................................. 6

3.2.3

Optical Equipment ................................................................................................................................ 6

3.2.4

Hydraulic Equipment ............................................................................................................................ 6

3.3

Specific Risk Assessment .................................................................................................................................. 7

3.4

Isolation Precedence ......................................................................................................................................... 7

4

Flowline/Manifold/Tree and Wellhead Systems ................................................. 8

4.1

Isolation................................................................................................................................................................ 8

4.1.1

Types of Flowline/Manifold/Tree and Wellhead Isolations .......................................................... 8

4.1.2

Considerations for Flowline/Manifold/Tree and Wellhead Isolations ...................................... 14

4.1.3

Testing Flowline/Manifold/Tree and Wellhead Isolations ........................................................... 16

4.1.4

Integrity of Flowline/Manifold/Tree and Wellhead Isolations .................................................... 22

4.2

Intervention ....................................................................................................................................................... 24

4.2.1

Types of Intervention ......................................................................................................................... 24

4.3

Installation of Subsea Equipment .................................................................................................................. 27

4.3.1

General .................................................................................................................................................. 27

5

Subsea Control and Umbilical Systems ............................................................ 29

5.1

Isolation.............................................................................................................................................................. 29

5.1.1

Types of Subsea Control and Umbilical System Isolations ......................................................... 29

5.1.2

Electrical/Communication/Signal Isolations ................................................................................... 31

5.1.3

Optical Isolation .................................................................................................................................. 39

5.1.4

Hydraulic and Instrumentation Isolations ...................................................................................... 41

5.1.5

Mechanical Isolations .......................................................................................................................... 59

5.2

Intervention ....................................................................................................................................................... 60

5.2.1

Types of Subsea Control and Umbilical System Interventions .................................................. 60

5.2.2

Electrical and Communication/Signal System Interventions ....................................................... 61

5.2.3

Optical System Interventions ........................................................................................................... 70

5.2.4

Hydraulic and Instrumentation System Interventions ................................................................. 71

5.2.5

Mechanical System Interventions ..................................................................................................... 83

5.3

Installation and Retrieval of Subsea Components ..................................................................................... 84

5.3.1

General .................................................................................................................................................. 84

5.3.2

Subsea Control and Umbilical System Components Installation and Retrieval ................. 85


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6

Isolation Flowchart and Isolations Summary Table ........................................ 90

6.1

Isolation Flowchart for Subsea System ........................................................................................................ 90

6.2

Isolations Summary Table Subsea Control and Umbilical Systems .................................................... 91

7 Typical System Drawings .................................................................................... 92

8

References ............................................................................................................ 97

8.1

Reference Documentation ............................................................................................................................. 97

8.1.1

IMCA Guidance ................................................................................................................................... 97

8.1.2

Other Documents .............................................................................................................................. 97

8.2

Applicable Standard Graphical Symbols ...................................................................................................... 98

8.3

Laser Classifications Summary ...................................................................................................................... 99

Figures

Figure 1 Double block and bleed arrangements at intended break .............................................................................. 9

Figure 2 Small bore isolation valve configurations .......................................................................................................... 11

Figure 3 Typical test downline configuration DSV to subsea worksite .................................................................. 17Figure 4 Positive test method ............................................................................................................................................. 19

Figure 5 Negative or in-flow leak off test method .......................................................................................................... 20

Figure 6 Volume calculation test method ......................................................................................................................... 21

Figure 7 Integrity test graph acceptable......................................................................................................................... 24

Figure 8 Integrity test graph unacceptable .................................................................................................................... 24

Figure 9 Typical valve arrangement for post-installation flooding ............................................................................... 28

Figure 10 Minimum valves on typical pig launcher/receiver.......................................................................................... 28

Figure 11 Typical subsea control and umbilical system isolations ............................................................................... 30

Figure 12 Double block and bleed (DBB) valve manifold for instrument device ..................................................... 45

Figure 13 Block-block and bleed (BBB) valve manifold for instrument devices ....................................................... 46

Figure 14 Block and bleed valves with self-sealing diver coupling ............................................................................... 48

Figure 15 Isolation testing double block and bleed plus self-sealing coupling ........................................................... 53

Figure 16 Isolation testing single block and bleed plus self-sealing coupling ............................................................. 55Figure 17 Isolation flowchart for subsea system ............................................................................................................. 90

Figure 18 Fundamental considerations .............................................................................................................................. 92

Figure 19 Typical manifold and flowline P&ID ................................................................................................................. 93

Figure 20 Typical subsea tree P&ID ................................................................................................................................... 94

Figure 21 Typical subsea control and umbilical system schematic .............................................................................. 95

Figure 22 Typical DSV to subsea worksite test downline ............................................................................................. 96

Figure 23 Standard graphical symbols ................................................................................................................................ 98

Tables

Table 1 Potential energy sources in subsea workscopes ................................................................................................ 5

Table 2 Isolation and intervention considerations .......................................................................................................... 26

Table 3 Subsea electrical power categories ..................................................................................................................... 62

Table 4 Subsea components with optical elements ........................................................................................................ 70

Table 5 Hydraulic system connection categories for subsea components ................................................................ 72

Table 6 Subsea instrumentation types and categories ................................................................................................... 79

Table 7 Subsea control and umbilical system components installation and retrieval .......................................... 89

Table 8 Isolations summarised ............................................................................................................................................ 91

Table 9 Laser classifications ................................................................................................................................................. 99


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IMCA D 044 1

1 Introduction

This guidance document is primarily aimed at project managers, project engineers, offshore constructionmanagers, diving supervisors and safety personnel, all of whom have a responsibility for developing safeschemes of isolation and intervention for divers accessing subsea systems. Additionally, engineering personnelinvolved with the design of such systems should also use this document to ensure that all new (or beingmodified) subsea systems incorporate adequate isolation facilities.

This document sets out what is considered to be good practice for ensuring a safe degree of isolation isestablished prior to conducting diver intrusive works on any energy-conveying system in which pressuredifferentials, electrical power or laser power may exist at levels which on loss of containment would beharmful to personnel or cause damage to the environment or equipment.

The guidelines are applicable for use when preparing workscopes, procedures, reviews and risk assessments forany diver related work.

These energy sources (pressurised liquid, pressurised gas, electricity and laser light) may be found as aconveyed product or service utility within either or both of the following two major subsea equipmentcategories:

Flowline/manifold/tree and wellhead systems (containing any of oil, gas, condensate, water injection,chemical injection either separately or in various combinations);

Subsea control and umbilical systems (containing any of hydraulic fluid, high and low voltage poweredequipment, communication signals, instrumentation signals, optical data signals, power transmission anddistribution, chemicals, gas each within dedicated sub-systems).

The general principles of isolation philosophy and isolation practice, as applicable to such systems, are given insection 2, whilst detailed guidelines regarding isolation and intervention are given in sections 4 and 5respectively.

Adequate planning is essential for an effective isolation, not only to ensure awareness of the task requirementsand ready availability of all materials, tools, etc., before work begins, but also to identify and assess the isolationoptions and their associated hazards and effects.

Safe standards of isolation are primarily determined by the size and nature of the potential hazards associatedwith the equipment to be worked on. Other fundamental factors which should be addressed are:

i) an understanding of all the parameters associated with the energy source being isolated;

ii) status, condition and accessibility of available isolation hardware;

iii) identification of adjacent live systems which may influence or be affected by the isolations; and

iv) the anticipated duration of the actual intervention work.

Occasionally, the requirement may arise to utilise divers to conduct work on items of hardware which havebeen specifically designed for ROV installation, operation or recovery. In such instances, the isolation andintervention guidelines set out in this document should still be applicable.

Whilst it is not possible for these guidelines to account for the detailed and specific complexities of each andevery subsea system encountered, the principles set out in this guidance should be applicable.


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2 Glossary

AAV Annulus access valve

AC Alternating current

ACPI Annulus choke position indicator

ACV Annulus choke valveAMV Annulus master valve

APT Annulus pressure transducer

AWV Annulus wing valve

BBB Block-block and bleed (valve)

BBV Block-block-and-vent (valve)

Bleed valve A valve for draining liquids, or venting gas, from a pressurised system

Blind flange A component for closing an open end of pipework which is suitably rated tomaintain the pressure rating of the pipe

Block valve A valve which provides a tight shut-off isolation purpose

Charged The item has acquired a charge either because it is live or because it hasbecome charged by other means such as by static or induction charging, orhas retained or regained a charge due to capacitance effects even though itmay be disconnected from the rest of the system

CIV Chemical injection valve

DB Double block (valve)

DBB Double block and bleed (valve)

DC Direct current

DCS Distributed control system

DCV Directional control valveDead Not electrically live or charged

Design working pressure Maximum working pressure at which a hose or tube is rated for continuousoperation

DHPT Down-hole pressure and temperature (sensor)

DHSV Down-hole safety valve

Disconnected Describes equipment (or part of an electrical system) which is notconnected to any source of electrical energy

Double block and bleed An isolation method consisting of an arrangement of two block valves with ableed valve located in between

Double seated valve A valve which has two separate pressure seals within a single valve body. Itis designed to hold pressure from either direction as opposed to a singleseated valve

DSV Diving support vessel

DWP Design working pressure

EDB Electrical distribution box

ELCB Earth leakage circuit breaker

Electrical equipment Includes anything used, intended to be used or installed for use, to generate,provide, transmit, transform, rectify, convert, conduct, distribute, control,store, measure or use electrical energy

EPU Electrical power unitESD Emergency shutdown


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IMCA D 044 3

Final isolation Subsea isolation, local to the worksite. This isolation should consist of asecure physical separation. It is a readily understood way in whichprevention of the uncontrolled release of energy can be confirmed to divingpersonnel tasked with carrying out the work

FOP Fibre-optic processor

HAZOP Hazard and operability (study)

High voltage Within this document used to refer to any voltage over 1000V and up to30KV

HIRA Hazard identification and risk assessment

HPU Hydraulic power unit

IEC International Electrotechnical Commission

ISO International Organization for Standardization

Isolated Indicates equipment (or part of an electrical system) which is disconnectedand separated by a safe distance (the isolating gap) from all sources ofelectrical energy in such a way that the disconnection is secure, i.e. it cannotbe re-energised accidentally or inadvertently

Isolation The separation of plant and equipment from every source of energy(pressure, electrical, mechanical and optical), in such a manner that theseparation is secure

Laser Light amplification by stimulated emission of radiation

Let go current The upper limit of current at which the muscles of the forearm can be used

LIM Line insulation monitor

Live Equipment in question is at a voltage by being connected to a source ofelectricity. This implies that, unless otherwise stated, the live parts areexposed so that they can be touched either directly or indirectly by meansof some conducting object and that they are live at a possibly hazardouspotential

Low voltage Within this document used to refer to any voltage up to 50V

MAOP Maximum allowable operating pressure

Master control station (MCS) Generic name for the topside computer system dedicated to control andmonitoring of the entire subsea control and umbilical system

Maximum permissible exposure Level of laser radiation to which, under normal circumstances, persons maybe exposed without suffering adverse effects (see BS EN 60825-1: 1994)

MCS Master control station

MEG Monoethylene glycol

Medium voltage Within this document used to refer to any voltage between 51V and 1000V

MPE Maximum permissible exposure

Nominal (value) Minimal value in comparison with the normal expected value

Normally open A device which, when closed, will perform the function of a closed isolation

Obturator An internal part of a valve such as a ball, gate, disc, plug or clapper which ispositioned in the flow stream such that the flow may be either blocked orpermitted to pass

OEM Original equipment manufacturer

P&ID Process and instrumentation diagram

PCPI Production choke position indicator

PCV Production choke valve

Perception current The lower limit of current which can be felt


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Pig A device that can be driven through a pipeline by means of fluid pressure forpurposes such as cleaning, dewatering, inspecting, measuring, etc.

PIG Pipeline internal gauge

PLMV Production lower master valve

PPT Production pressure transducer

PPTT Production pressure and temperature transducer

Preliminary isolation Initial isolation. Set as precursor to facilitate the obtaining of a further finalisolation local to the worksite (where by design it is possible to do so).Generally it is a physical separation or (exceptionally) a software inhibit

PSL Product specification level

PUMV Production upper master valve

PWV Production wing valve

Rated working pressure The maximum internal pressure which the equipment is designed to containand/or control

RCD Residual current device

ROT Remotely operated tool

ROV Remotely operated vehicle

RWP Rated working pressure

Safe body current The maximum current which can be allowed to flow through the diversbody safely (explained in detail in IMCA D 045/R 015 see section 8.1). It isnotthe current flowing in the electrical equipment

SAM Subsea accumulator module

SBB Single-block and bleed (valve)

SCADA Supervisory control and data acquisition

SCM Subsea control module

SCMMB Subsea control module mounting base

SCSSSV Surface controlled sub-surface safety valve

SEM Subsea electronic module

SIL Safety integrity levels

Spade A solid plate for insertion in pipework to secure an isolation

SSIV Subsea safety isolation valve

SSSV Sub-surface safety valve

SST Spheri-seal test

SUDA Subsea umbilical distribution assembly

SUT Subsea umbilical termination

SUTA Subsea umbilical termination assembly

TCT Tree-cap test

Tested Integrity has been proven and/or can be monitored

TUTU Topside umbilical termination unit

Ultra-high voltage Within this document used to refer to any voltage greater than 30KV

UPS Uninterruptible power supply

Vent valve A valve for draining liquids, or venting gas, from a pressurised system

XOV Cross-over valve

XT Christmas tree


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IMCA D 044 5

3 Principles of Isolation

3.1 Principles of Isolation

The general principle of isolation is, where practicable, the removal of hazards or sources of energyfrom within the system to be worked upon, through the provision of an appropriate physical

separation which can be confirmed to provide adequate disconnection of that system from anypotential source of further energy.

The hyperbaric nature of subsea work means that divers are regularly exposed to the particularhazard of negative pressure systems during activities associated with system equalisation, as well as thenormal potential hazards associated with the positive release of pressure from a system. Even a verysmall aperture with an associated pressure profile can cause severe injury should a diver come intocontact with it. Thus when working on any subsea system containing liquid or gas under positive ornegative pressure, there should be no pressure differential, relevant to the seabed ambient, trappedwithin a space or void.

Similarly, divers may become exposed to live electrical or optical connections containing electrical orlaser energy at potentially hazardous levels which may also cause injury without warning. Thus, for

any subsea system conveying electrical energy, or laser energy, there should be no exposed liveelectrical connections, or optical contacts located subsea.

In many cases, diving operations cannot commence until the topside installation has firstly appliedprimary isolation(s) to the main energy source(s), following which, manual and tangible final isolationswill then need to be applied at the subsea worksite location. All isolations need to be proven, todemonstrate to diving personnel that protection from all potential energy sources has beenestablished.

Potential energy sources which may be associated with subsea isolations are:

Source Description

Reservoir Primary source of high pressure hydrocarbons

Process pipework Large capacity pipework containing hydrocarbons

Main oil line pumps High pressure and high volume hydrocarbons

Gas compressors High pressure and high volume gas compositions

Water injection pumps High pressure and high volume treated water

Chemical injection High pressure, low volume chemical solutions

Hydraulic control systems High pressure, low volume accumulated systems

Electrical power supply systems High voltage/current electrical energy

Electrical control systems High voltage/current electrical energy

Fibre-optic data systems High intensity (laser) light energy

Instrumentation pipework Small capacity pipework containing fluid/gas

Table 1 Potential energy sources in subsea workscopes

3.2 System Isolations

3.2.1 Liquid and Gas Equipment

For subsea liquid and gas conveying equipment, the general principle is that a minimum of twoindependent and tested isolations should be established between personnel engaged in anytask where the presence of potential hazard from a positive or negative pressure sourceexists.

Where practicable to do so, at least one of the isolation tests should take the form of apositive test, in the direction of flow, or alternatively, a negative test by reducing the pressure


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downstream of the isolation. Exceptionally, it may be appropriate to test both isolationsagainst the direction of flow.

3.2.2 Electrical Equipment

For subsea electrical equipment, the general principle (assuming that the voltage is higherthan is safe for the diver to work beside) is that the main power circuit of the electrical

equipment, together with any associated auxiliary circuits which constitute a hazard, shouldbe isolated and any stored energy in the electrical circuits should be discharged.

Isolation can be achieved by disconnecting and separating the electrical equipment from everysource of electrical energy in such a manner that this disconnection and separation isconfirmed and secure, i.e. it cannot be re-energised accidentally or inadvertently.

A minimum of two independent and certified isolations should be established betweenpersonnel engaged in any task where the presence of a potential hazard from electricalenergy at potentially hazardous levels exists. Normally at least one of these isolations shouldbe located on the topside host installation. However, it may be possible to set isolationslocal to the subsea worksite by physical disconnection of an inductive coupler (this does notapply to conductive connectors).

3.2.3 Optical Equipment

For subsea optical equipment, the general principle is that the main power circuit of the fibreoptic equipment, together with any associated auxiliary circuits which constitute a hazard,should be isolated.

Isolation can be achieved by disconnecting and separating the fibre-optic equipment fromevery source of electrical power (topside) and final optical interface (subsea) in such amanner that this disconnection and separation is confirmed and secure, i.e. it cannot be re-energised accidentally or inadvertently.

A minimum of two independent and certified isolations should be established between

personnel engaged in any task where the presence of a potential hazard from laser lightenergy at potentially hazardous levels exists. Normally at least one of these isolations shouldbe located on the topside installation. If, however, the laser sources are Class 1, Class 1M,Class 2 or Class 2M laser sources, then isolation is not a requirement.

3.2.4 Hydraulic Equipment

For subsea hydraulic equipment, the general principle is that the main power circuit of thehydraulic equipment, together with any associated auxiliary circuits which constitute a hazard,should be isolated and any stored energy in the hydraulic circuits vented.

Isolation can be achieved by disconnecting and separating the hydraulic equipment from everysource of hydraulic power in such a manner that the disconnection and separation is

confirmed and secure.

A minimum of two independent and tested isolations should be established betweenpersonnel engaged in any task where the presence of a potential hazard from hydraulicpressure at potentially hazardous levels exists. Normally at least one of these isolationsshould be located on the topside host installation. However, it may be possible to setisolations local to the subsea worksite by either physical disconnection of stab plate halves orby operating manual isolation and vent valves (the vent port needs to be fitted with a diver-safe pressure relief cap) in combination with the physical disconnection of self-sealinghydraulic couplers.

Note: Hydraulic systems operating sub-surface or down-hole safety valves may provide aconduit for well bore fluids to return to the surface and these may be present in these

systems. This possible hazard should be considered in any assessment of the isolationrequirements for such systems.


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IMCA D 044 7

3.3 Specific Risk Assessment

For the isolation of the subsea equipment described above (liquid and gas conveying equipment,electrical equipment and optical equipment), if, due to limitations in actual subsea architecture, twotested and independent isolations cannot be achieved, then it may be possible to identify an alternativemethod for undertaking the work, without compromising the safety of the operation. Any suchalternative method needs to be subjected to a task specific risk assessment by competent personnelwith appropriate company review and approval (see Figure 17).

3.4 Isolation Precedence

In certain projects it is possible that isolation techniques other than those set out in this documentmay be suggested. As an example, there may be a client or main-contractor isolation philosophydocument containing detailed procedures for isolation. Any such alternative methods should becompared with the techniques contained within this document and the more stringent requirementused.

In all cases the need for double isolation remains a fundamental principle.


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4 Flowline/Manifold/Tree and Wellhead Systems

4.1 Isolation

4.1.1 Types of Flowline/Manifold/Tree and Wellhead Isolations

A minimum of two independent and tested isolations should be established betweenpersonnel engaged in any task where the presence of a potential hazard from a pressuresource or vacuum exists. The physical isolation of pressurised systems is generally achievedby using various combinations of valves, spades or blank flanges.

Isolations for subsea flowline/manifold/tree and wellhead systems are primarily provided instandard form by valves located between the diver intervention workface and the potentialenergy source. There are also many instances whereby pre-installed and tested blind flangesmay provide isolation. The type, configuration, location and testing of such isolations areconsidered in further detail throughout this section.

Consideration is also given to certain alternative and specialised isolation techniques, whichmay not be appropriate for standard applications but, depending on system architecture, mayrequire to be utilised.

The following isolation terminology is applicable both to bulk subsea systems (i.e. flowlines,manifolds, trees and wellheads) and the associated smaller, but more complex, subsea controland umbilical systems (see section 5). The process of achieving an appropriate overallisolation scheme for subsea intervention work invariably has implications for both systems,therefore there needs to be a common understanding of the basic principles involved.

Preliminary Initial isolation. Set as a precursor to facilitate the obtaining of a further finalisolation local to the worksite. Generally this is a physical separation or (exceptionally)a software inhibit.

Final Subsea isolation, local to the worksite. This isolation consists of a secure physicalseparation. It is the tangible mechanism by which prevention of the uncontrolled release ofenergy is confirmed to those intending to carry out the work.

4.1.1.1 Standard Isolation Methods

4.1.1.1.1 Valves

Valves provide the simplest conventional form of preliminary and/or final in-lineisolation device across the dimension range, from large diameter trunk pipelinesthrough to small-bore injection tubing. When utilised in subsea systems theyare defined within two specific categories: either manually operated (i.e. by diveror ROV) or remotely actuated (i.e. by subsea control system).

Certain designs of remotely actuated valves may also be operated by purpose-designed diver/ROV override mechanisms.

The optimised isolation configuration for accessing a subsea bulk system forintervention purposes should consist of two sets of main double block valves,each with a bleed valve located between them. This bleed facility itself shouldconsist of an arrangement of small-bore valves in a double block and bleedconfiguration, as they connect directly into the bulk system. Such valving shouldbe in place on both sides of any intended break (see Figure 1).


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IMCA D 044 9

VALVE 1A VALVE 2A VALVE 2B VALVE 1B

CLOSED OPEN OPEN CLOSED

BLEED PORT

CONNECTION POINTTEST DOWNLINE

BULK SYSTEM

PRESSURISED

TEST DOWNLINECONNECTION POINT

BLEED PORT

LOCATION OF

INTENDED BREAK

BULK SYSTEM

PRESSURISED

Figure 1 Double block and bleed arrangements at intended break

Wherever practicable, it is prudent to utilise at least one manually operatedvalve for one of the isolations.

When two remotely actuated valves require to be utilised to establish the bulksystem isolation scheme, the supply lines to both should be locally isolated atthe worksite.

In the absence of any means to implement such isolations then the additionalpotential hazards arising need to be assessed with a view to either proposing analternative isolation scheme or identifying an increased isolation envelope.

Valves should be capable of providing a reliable and positive shut-off seal for theisolation of a hazardous substance and/or energy source. They should besuitable for the expected service and associated potentially hazardous conditionsto be encountered.

There are the two fundamental valve properties to consider:

i) type; and

ii) seat and seal material.

Standard valve types will conventionally be either gate, plug, globe or ball.Seat and seal material will be either metal-to-metal or metal-to-elastomeric/polymeric.

Full details of valve specifications and other applicable bulk system parametersshould be obtained at an early stage in the onshore phase of the project. Thisshould help avoid unnecessary delays during offshore integrity tests for a givenisolation scheme.

Small-bore valves which form the directly-connected vent/bleed outlet in anysubsea pipework system should always be arranged in a block-vent-block(double block and bleed) valve configuration. The block valves provide two in-line isolations, which should be kept closed during the initial diver interventionactivities (e.g. when connecting a dive support vessel (DSV) test downline to themain outlet port on the same valve assembly). The bleed valve provides a localsafety vent through the bleed port.


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The alternative, dual-in-line block only (double block) valve, i.e. without anyincorporated vent facility, should be considered the minimum form of small-bore valve isolation.

The protective cap fitted to the outlet port on small-bore double block ordouble block and bleed valves should be the diver-safe integral-vent type (i.e.pressure vents prior to full disengagement). Such devices are designed toensure any initial differential pressure equalisation occurring within, or through,the valve assembly (when preparing the cap for removal) can be vented in a safemanner, without the potential hazard of gross loss of containment or of the capcoming off in an uncontrolled manner. The use of any other type of cap (orplug) which does not incorporate a secondary pressure-relief mechanism is notconsidered suitable for diver intervention work.

The utilisation of a single-block valve only, in combination with either a non-venting cap/plug or an integral-vent type cap, fitted to the valve outlet port, isnot considered appropriate to meet the principles for safe diver interventiongiven in these guidelines.

The suitability, or otherwise, for the various configurations of small-boreisolation valves and their caps/plugs is summarised in Figure 2.

The outlet port on small-bore valve assemblies should also be of suitable designto guarantee a fixed pressure-retaining connection when the DSV test downlineis attached (and subsequently pressurised) to check for flow, either into or outof the cavity. This ensures a safe and secure facility is maintained for theequalisation of any entrapped pressure throughout the work.


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IMCA D 044 11

PRODUCT

FLOW

LEGEND

UNACCEPTABLE UNACCEPTABLE

ACCEPTABLE

(but not recommended)

ACCEPTABLE - BASIC

ACCEPTABLE

(but not recommended)

ACCEPTABLE - OPTIMISED

PRODUCT

FLOW

PRODUCT

FLOW

PRODUCT

FLOW

PRODUCT

FLOW

PRODUCT

FLOW

PR

E

S

S

URE

PR

E

S

S

URE

PR

E

S

S

UR

E

PR

E

S

S

UR

E

PR

E

S

S

UR

E

PR

E

S

S

UR

E

Figure 2 Small bore isolation valve configurations

4.1.1.1.2 Blind Flanges

The ends of pipelines, headers and spools are prepared with precision-machinedflange faces such that they can be inter-connected to form a pressure-containingliquid/gas transportation system. These flanges are specified to at least the samedesign and test standards as the item to which they are attached.

The flange faces require to be maintained in their factory-finished conditionthroughout the load-out and offshore installation activities and for the durationof the field life. Protection for the sealing surfaces is therefore provided in theform of a matching circular blanking cover/plate or blind flange. These providephysical protection and, where required, comply with the system installation andcommissioning specifications (i.e. free-flooding or pressure-tight), in combinationwith the intended field development programme (i.e. immediate hook-up, orfuture tie-in).


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Blind flanges are therefore specified and prepared with either a single, or a dual-purpose role, as follows:

Single Duty To provide physical protection only, for the sealing surfaces of theflange face. This is usually associated with a short-term requirement, the hook-up of adjacent items following soon after deployment.

The flange face may be protected with some simple covering arrangement or a

proprietary blind flange which should not be fully tightened into place (e.g. byinserting spacer washers). With this type of protection arrangement, the flangeinterface is designed to free-flood and should therefore present no differential-pressure equalisation hazards for diver intervention.

In certain circumstances it may be a requirement to tighten the blind flange inplace on surface, prior to deployment to the seabed (as it may be intended toallow the system to free flood in some other manner). Therefore the blindflange should be prepared with a welded outlet port to which is fitted, as aminimum, a small-bore double block valve, complete with either a T-piece or adiffuser. This is to ensure that there is no possibility of diver finger/handentrapment during differential-pressure equalisation at depth.

Dual Purpose To provide physical protection for the sealing surfaces of theflange face, plus the capability to maintain a pressure-containing isolation equalto the system design.

The flange face will normally be fitted with a proprietary blind flange and ring-gasket, and set in place with the full complement of tensioned studs. This levelof preparation enables full pressure-testing against the blind-flange duringpipeline commissioning. It also provides the capability, if required, of leaving theblind flange secured in place as a proven isolation, for some future tie-in.

With this type of flange protection, there exists the potential hazard of atrapped inventory of positive or negative pressure remaining in the cavitybetween the blind flange and the next (closed) valve in the bulk system.

Therefore the blind flange should be prepared with a welded outlet port towhich is preinstalled, as a minimum, a small-bore double block valve, completewith either a T-piece, or a diffuser. As an alternative, a small-bore doubleblock and bleed valve arrangement could be preinstalled.

In the absence of any means to safely depressurise the bulk system prior toremoval of the blind flange, then the additional potential hazards arising need tobe assessed with a view to identifying an increased isolation envelope.

4.1.1.2 Alternative Isolation Methods

Certain other types of special or novel isolation techniques are available. Dependingon specific design, these may or may not align with the recommended double block

and bleed isolation principle. Their utilisation should therefore be consideredthrough detail engineering review processes.

The various techniques available are outlined below:

4.1.1.2.1 Double-Seal within Valve Body

Double-wedge gate, parallel-expanding gate or double-seal (double-piston effect)ball valves, which provide a double-seal in a single valve body with a bleed inbetween, may be utilised if necessary.

There are, however, certain limitations and restrictions to this type of valvewhich should be considered:

i) In some applications both isolations cannot be easily tested;


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IMCA D 044 13

ii) The status of the double isolation depends upon the immobilisation of asingle valve operating stem therefore there should be no possibility of itbeing operated during the intervention work;

iii) The valve body outlet bleed port directly accesses the inventory of thevalve cavity. Also, this outlet is only protected from the potential energy inthe bulk inventories (i.e. on either side of the valve unit) by the singleisolations provided by each of the obturators within the valve assembly.

The outlet should be fitted with a permanently attached double blockaccess/vent valve arrangement as a minimum (a double block and bleed isrecommended).

The double seal valve design should only be used in preference to theconventional bulk system isolation arrangement (i.e. double block and bleed)after the increased hazards have been reviewed through the appropriate riskassessment process.

4.1.1.2.2 Pipeline Plugs

The utilisation of a bespoke in-pipe plug (or combination of plugs) to form aproven subsea isolation scheme is considered to be an appropriate form of

novel isolation technique, subject to the following considerations.

Redundancy and independence should exist within, or between, the plugs suchthat failure of a part of the sealing system does not cause total loss of sealingcapability. Similarly, power, control and monitoring systems for the isolationplug should be suitably robust and/or dual-redundant to account for any possiblein-situdamage or failure.

Certain designs of in-pipe plugs may only be capable of providing an appropriateform of single isolation, whilst others may claim to provide full double block andbleed isolation. Due to variations in manufacturers design and the techniquesby which these isolations are achieved, tested and maintained, the proposeddevice should be subject to thorough engineering evaluation and review at an

early stage in the project.

The potential hazards associated with the utilisation of in-pipe isolation plugdevices should be considered on a case by case basis under the appropriate riskassessment process.

4.1.1.2.3 Hot Tapping

Occasionally, for various reasons of operational or delivery constraints, it maybe necessary to perform a live intrusive intervention on a pipeline whilst itremains at a percentage of (or even full) service pressure throughout the work.Accessing a bulk system in this manner is termed hot tapping.

This method of intervention has been successfully utilised onshore andsubsequently adapted for subsea applications.

The section of pipe requiring intervention (e.g. to fit a valve assembly for somefuture tie-in) should be accessed by means of a hot tap clamp and drillingassembly, which should be suitably designed and tested for containing fullpipeline pressure. This stack-up should also incorporate a suite of valves tofacilitate the future tie-in. These should be arranged in a double block and bleedconfiguration which, on completion of the hot-tapping operation, should besubjected to full test pressure to confirm suitability as a permanent isolation.

4.1.1.2.4 Pigs

Pigs are not considered an appropriate form of subsea isolation. The utilisation

of a pig or a series of pigs (separated by slugs of nitrogen, diesel, glycol, water,etc.) does not provide a reliable form of static isolation which can be fully tested


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14 IMCA D 044

and accepted in the terms and recommendations of these guidelines. Theisolation properties previously offered by pigs have now been superseded bythose of pipeline isolation plugs (see ii), above).

4.1.1.3 Specialised Isolation Methods

Techniques for directly isolating the pipeline or hydrocarbon reservoir from thesubsea equipment, such as pipe freezing, hydrostatic column1, bridge plug, cement

plug or other such specialised methods, are considered to be outwith the scope ofthese guidelines and are therefore excluded.

Should it be necessary to utilise any of these as effective isolations (through theservices and supporting expertise of a specialised vendor) then their incorporationinto the isolation scheme would need to be subject to detailed review through theappropriate risk assessment processes of both the client and the diving contractor.

The following valve-type is not considered suitable for intervention isolations:

Choke valves the seats on flow-control elements of these valves are notdesigned to be pressure-retaining when fully closed. During interventions, thechoke should be previously set to at least 25% open to reduce possibility of a

potential pressure differential (e.g. due to restriction within choke).

The following valves are not normally considered suitable as intervention isolations:

i) Down-hole safety valves these valves have the potential to self-equalise/ openif pressure develops in well-bore column above valve obturator. However,exceptionally, it may be permissible to accept this type of valve as a suitableisolation, but only if it has been possible to prove the sealing properties of thevalve to at least the maximum anticipated pressure differential.

ii) Check valves the condition and status of a check valve cannot be guaranteed.However, exceptionally, it may be permissible to accept this type of valve as asuitable isolation, provided:

a) the valve can be positively locked closed throughout the workscope;

b) the valve is only utilised in conjunction with other proven valves in the bulksystem isolation scheme; and

c) it has been possible to prove the sealing properties of the valve to at leastthe maximum anticipated pressure differential. Caution is required forsmaller size check valves (e.g. in chemical injection lines) as a blockage maymask the test.

4.1.2 Considerations for Flowline/Manifold/Tree and Wellhead Isolations

4.1.2.1 Requirement to Flush

Before any intervention operations are conducted, consideration should be given at

the planning stage to the contents of the relevant subsea pipework/tree-cavity.Applicable details regarding the bulk systems pressure, volume quantity,temperature, flowrates and chemical composition should be obtained for the riskassessment.

To provide a safe worksite for the diver and to minimise damage to theenvironment, it may be necessary to flush the subsea pipework/tree-cavity toremove harmful contents prior to placing isolations. These operations are usuallyrequired when hydrocarbon inventories are involved; it is recognised industry

1The utilisation of a column of fluid in the well-bore of sufficient specific gravity such that its weight exceeds the up-thrust due to the

formation pressure below thus having the effect of forming an isolation. Key aspects to the reliability of this technique are:a) typically the overbalance pressure margin should be greater than 14 bar (200 psi);b) fluid level in the isolation column should be capable of being monitored continuously; andc) gas migration through the isolation column (from the reservoir) may occur, therefore any such inventory should be safely managed.


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IMCA D 044 15

practice to reduce the hydrocarbon content to less than 40 parts per million(


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16 IMCA D 044

(either from within the pipeline or by the surrounding seawater) can presentconsiderable potential hazard to diving personnel;

iii) Checks for the existence of a specific gravity differential between the pipelinecontents and that of the surrounding seawater should be undertaken. Theabsence of a local isolation combined with a significant differential in specificgravities can present a potential hazard to diving personnel located in the vicinityof a high volume pipeline discharge.

Each intervention of this nature therefore should be reviewed with particular regardto the key parameters given above. Consideration should also be given to otherimportant pipeline aspects such as inventory type, overall topography, size, historyand present condition.

Should the applicable risk assessment/review process determine that certain featuresof the intended isolation scheme are inadequate, or the pipeline inventory presents apotential hazard to diver or the environment, then the work should not be allowedto proceed until an appropriate alternative local isolation scheme is proposed, or anincreased isolation envelope/vent-down method is identified.

4.1.3 Testing Flowline/Manifold/Tree and Wellhead Isolations

Two independent subsea isolations should be established before intrusive works cancommence. Where possible, both should be tested in the direction of design-flow or in thedirection of potential hazard flow (i.e. in the direction of the expected pressure differential).

The procedures for installing, testing and implementing these isolations should clearly specifythe following four key items:

i) Valve alignment requirements, including subsequent operating system isolations, to bothprove and maintain the isolation. To achieve this, a thorough understanding of thesystem process flow diagrams (PFDs), all relevant piping and instrumentation diagrams(P&IDs) and subsea control system schematics is essential. An appreciation of theoperating principles of the overall subsea system and any associated topside operational

preferences or limitations is also required;ii) Technique(s) to regularly monitor the integrity of the isolation scheme throughout the

intervention work;

iii) The test method(s) to be implemented and the test pressure(s) to be applied;

iv) The acceptable leak rate for each valve forming the isolation see section 4.1.4.

It is important that detailed information regarding the valves to be subjected to test isobtained at an early stage during the onshore phase of the project, and certainly prior tocommencement of the offshore programme as this will determine their test parameters andhence their acceptance criteria.

Typically, such information will consist of valve design (globe, gate, etc.), size, specification,

sealing type and classification, actuator type, operating mechanism, operating pressure (forhydraulic-type actuator), original (or previous) valve test data, pipeline service (liquid or gas)and pipeline rated working pressure. It is also important to obtain knowledge of the valvehistory and frequency of operation.

The essential features of the test equipment and the principles of the various test methodswhich may be applied are outlined in the following sections.

4.1.3.1 Test Down-Line

In order to correctly test isolations, confirmation is required that there is actual flow or communication into the pipework/tree-cavity containing the isolation suchthat the test is in fact acting on the isolation.


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IMCA D 044 17

This is normally carried out as part of initial subsea intervention works by theattachment of a test down-line from the DSV to a suitable block and bleed assemblyon the subsea pipework and valve arrangements (see Figure 3).

REEL

GAUGE

M

POWER PACK

VENT

TBLV

TBLK2 TBLK1

DSV DECK

GAUGESUBSEA

CAPPED

C/W ISOLATION

& VENT VALVES

CHART- RECORDER &

TCV1TCV2

OR

TLIV

FROM DSVTEST DOWNLINE

SUITABLE FITTING

FOR EXISTING SYSTEM

CONNECTION POINT

Figure 3 Typical test downline configuration DSV to subsea worksite

Prior to attachment of the test downline into the bulk system, consideration shouldbe given to the contents of the subsea pipework/tree-cavity and the pressureanticipated. Divers should be made aware of the potential of a pressure differentialwhen removing any plug or cap from the bleed facility and should have confirmedpreviously that the pipework/tree-cavity block and bleed assembly is in the closedposition.

The test downline should be deployed complete with a double block and bleed

assembly and where the potential for returns to surface exists (or is unwanted) a double check-valve arrangement incorporated. The test downline configurationshould be pressure-tested on the DSV prior to deployment.

On attachment of the test downline onto the subsea pipework/tree-cavity block andbleed assembly, a leak test should be conducted against the closed bleed valve toconfirm the integrity of the test line connection.

Any block and bleed assembly on subsea pipework/tree-cavity needs to be proven tooperate correctly. It should not be assumed that communication has been achievedthrough the pipework block and bleed assembly into the void just because the blockand bleed is open. Debris, wax, hydrates2, asphaltenes etc. can readily restrict orblock small-bore bleed facilities.

To confirm communication through and into the pipework/tree-cavity, it isnecessary to have an open flow path that can be registered through the testdownline. Ideally this would involve flow into, and out of, the cavity.

This is normally achieved by locking in pressure in the test downline and opening upthe bleed-and-block valve into the cavity. This should register as a pressure-drop onthe topside gauge, thus confirming communication.

2A mixture of hydrocarbons and water forming an ice-like solid under certain conditions of pressure and temperature. These can maskisolation testing results as the hydrate itself may be forming the isolation (rather than the requisite valve), or may be blocking the route toa test port. Furthermore, the hydrate creating the blockage may melt, resulting in an unexpected release of trapped pressure.


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18 IMCA D 044

Generally, valves are designed such that the in-line pressure will actually assist inactivating their sealing mechanism(s). Thus, increasing the magnitude of thepressure difference across the valve (i.e. pressure differential) provides optimum testconditions. Tests should therefore be specified with as high a pressure differential asis reasonably possible.

Careful consideration, however, should be given in the various stages of the testingprogramme to determine whether the possibility will exist for the test acting on oneside of a valve to unseal (and thus negate) a previously successful test obtained onthe opposite face of the same valve. It is therefore important to obtain detailedinformation regarding the various valves intended to form the isolation, and tocorrectly select test pressures relevant to the status of immediately-surroundingsystem components.

The application of test pressure should be carried out in a controlled manner.Typically, the pressure should be increased in gradual increments until at least 50%of the test pressure is reached. Thereafter, the pressure may be increased in stepsof approximately one-tenth, or less, of the required test pressure, until the finalvalue is reached.

The actual testing of isolations may be carried out using several different methods depending upon the system type, architecture and the most suitable (or available)means of access. These are further detailed for flowline, manifold, tree and wellheadapplications in section 4.1.3.2 to 4.1.3.5, inclusive and for hydraulic andinstrumentation applications in section 5.1.4.2.

The integrity of a tested isolation should be determined with reference to theacceptance criteria given in section 4.1.4.

Note; Isolation and bleed components on subsea systems may remain inactive overextended periods of time. As a consequence they may become stiff and difficult tooperate. Care should be taken when functioning block and bleed valves or removingplugs and similar fittings.

There is a possibility that captive pressure may remain locked-in between blockvalves, plugs and other small bore fittings even if the pipework has beendepressurised (e.g. due to the presence of a hydrate).

At all times, divers should be aware of the potential for a pressure differential anegative pressure (vacuum) may exist.

4.1.3.2 Positive Test Method

When the valve forming a part of the isolation scheme between the energy sourceand the workface is accessible for test in the direction of design/potential hazardflow then this technique is described as the positive test. This is the preferred testarrangement as it enables a controllable test to be carried out (typically via the test

downline), resulting in a high degree of confidence in the properties of the isolation(see Figure 4).

Pressuredifferential should exist across the isolation, with the expected positive sideof the isolation being monitored for any decrease in pressure.


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IMCA D 044 19

REEL

CHART- RECORDER &GAUGE

TO REST OFSYSTEM

SUBSEA

TBLK2 TBLK1

CAPPED

TBLV

GAUGE

VENT

TCV2 TCV1

OR

TLIV

TEST DOWNLINEFROM DSV

DIRECTION OF DESIGN /

POTENTIAL HAZARD FLOW

CLOSED

VALVENo.2

CLOSED

VALVENo.1

PRIMARY

SIDE

( "UPSTREAM" )

SECONDARY

SIDE

( "DOWNSTREAM")

PRESSURISE

INTENDED

WORKFACE

ZONE

M

POWER PACK

DSV DECK

C/W ISOLATION

& VENT VALVES

Figure 4 Positive test method

Reference should be made to section 4.1.4 for determining the integrity of theisolation thus tested.

4.1.3.3 Negative Test Method

When it is not possible to gain test-access on to the upstream face of the isolationvalve then an alternative test is feasible, provided it is possible to gain access to the

inventory on the opposite side of the valve. This technique, being effectively in thedirection of flow also, is described as the negative test or in-flow leak-off test.The test downline requires to be attached into the downstream side of the isolationscheme, such that with upstream flow acting on the isolation valve, then anypossibility of leakage may be monitored as a pressure build-up in the test downlinesystem (see Figure 5).

Pressure differential should exist across the isolation, with the expected negativeside of the isolation being monitored for any increase in pressure.


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20 IMCA D 044

M

DSV DECK

REEL

PRESSURISEDBULK SYSTEM

GAUGECHART- RECORDER &

C/W ISOLATION

POWER PACK

& VENT VALVES

SUBSEA

TBLK2 TBLK1

CAPPED

TBLV

GAUGE

VENT

TLIV

FROM DSVTEST DOWNLINE

DIRECTION OF DESIGN /

POTENTIAL HAZARD FLOW

PRIMARY

SIDE

( "UPSTREAM" )

SECONDARY

SIDE

( "DOWNSTREAM" )

DEPRESSURISECLOSED

VALVE

INTENDED

WORKFACE

ZONE

CAPPED OUTLET, ORCONNECTED INTERFACE

TO REST OF SYSTEM

Figure 5 Negative or in-flow leak off test method


4.1.3.4 Volume Calculation Test Method

Where subsea inventory or architecture limitations dictate (e.g. unpredictablepressure/flow conditions, or no safe access port between both isolation valves), then

it may be the case that the only feasible form of pressure test which can be achievedis that both isolation valves have to be pressure tested against the direction ofdesign/potential hazard flow.

This method of isolation-proving requires that testing is supported by the volumetriccalculation technique, whereby the difference between the volumes of test fluidrequired to raise the two valve inventories to test pressure is computed thuschecking for the possibility of a leaking valve (see Figure 6).

Note that this form of test can only be realistically performed if there is a significantand therefore measurable volume between the valves, otherwise the two valvesneed to be treated as effectively forming a single isolation only.


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IMCA D 044 21

& VENT VALVES

POWER PACK

C/W ISOLATION

CHART- RECORDER &GAUGE

REEL

DSV DECK

SUBSEA

TBLK2 TBLK1

CAPPED

TBLV

GAUGE

VENT

BULK SYSTEM

PRESSURISED

TCV2 TCV1

OR

TLIV

FROM DSV

TEST DOWNLINE

DIRECTION OF

DESIGN / POTENTIAL

HAZARD FLOW

PRIMARY

SIDE

( "UPSTREAM")

SECONDARY

SIDE

( "DOWNSTREAM")

VALVE

No.1

VALVE

No.2

INTENDED

WORKFACE

ZONE

CAPPED OUTLET, ORCONNECTED INTERFACE

TO REST OF SYSTEM

M

Figure 6 Volume calculation test method


Note: This particular test method is dependent on the volumetric calculation. Any

procedural requirement to open/re-close a proven isolation subsequent to the testthus obtained will invalidate any isolation properties established for that valve.

4.1.3.5 Topsides Test Methods

Due regard should be given to the ability of the topside installation to assist in theprocess of proving the isolation properties of subsea valves, particularly in terms ofeither the positive or negative test methods.

For example, positive pressure testing into the cavity between two designatedsubsea isolation valves may be possible where there exists a chemical injection pointdirectly supplied from the topside chemical pumping skid, via a line in the umbilical.Subsea pressure-sensing instrumentation integral to the inventory under test should

also be available. This is in addition to any pressure-monitoring capability providedby the topside skid.

Similarly, negative pressure testing may be conducted by performing an in-flow leak-off test in respect of a designated subsea isolation valve, in conjunction withassociated subsea system pressure sensors, any other subsea or topside valves andtopside instrumentation.

Note: The validity of an isolation obtained by either of these topside methods ishighly dependent on the reliability, accuracy and in-situ track-record of subseasensors and the associated control system.

Consideration should therefore be given during the onshore engineering phase and

in applicable risk assessment processes, as to whether the permanently installedinstruments may be exclusively relied upon for the testing of isolations.


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22 IMCA D 044

In those instances where there exists a known possibility of inaccuracy or fault in thepermanent subsea instrumentation system then local supplementary pressure gaugesshould be incorporated by diver(s) at suitable locations in the isolation scheme. Thisis essential to establish confidence at the subsea intervention worksite for anyisolation which has been subjected to remote topside testing only.

See section 4.1.4 for determining the integrity of the isolation tested.

It should be noted that operations of any isolation valve after testing will invalidatethe test and a subsequent test will have to be re-applied prior to any intrusiveoperations.

Note; It should not be assumed that subsea valves are closed. All isolations shouldto be considered open or (partially open) until proven and confirmed otherwise byconclusive test. Such testing may consist of either:

Topsides to command in-line valve closed, perform in-flow test and monitor forpressure increase/decrease; or

Diver attachment of test downline into system from DSV and monitor forpressure increase/decrease.

Note: For intervention work, diver (or ROV) visual checking for movement of avalve to the known closed position by observation of its indicator/actuator stemdoes not constitute confirmation that the valve has actually closed. This is due tothe fact that the valve actuation mechanism may have become separated from thevalve closure element within the valve body.

(The visual checking method is only appropriate for valve position confirmationchecks during non-intrusive work, e.g. commissioning tests.)

4.1.4 Integrity of Flowline/Manifold/Tree and Wellhead Isolations

During the onshore phase of a project every effort should be made to determine agreedisolation integrity acceptance criteria for the various devices which it is intended toincorporate in an isolation scheme. This will considerably reduce the problem of unexpecteddelays to schedule during the offshore phase.

The pressure integrity of all aspects of an intended isolation scheme set within a flowline,manifold, tree or wellhead system should be proven to ensure that they are effective, prior tothe commencement of any intrusive intervention work by diver.

This may typically be achieved by implementing an appropriate test for each of the givenisolations, followed by a review of the results obtained. This review is extremely importantin determining whether the integrity of the device under test meets the key isolation requirements of being both effective and reliable for the duration of the requiredintervention.

Review and interpretation of test results are normally conducted with reference to industrystandards, or alternatively, require to be considered on a case-by-case basis.

There are no applicable international industry standards in place which provide guidance inthe interpretation of test results for an in-situ isolation device intended to be utilised in theprovision of a safe isolation scheme for diver intervention, prior to the breaking ofcontainment subsea. Whilst several standards do exist which address testing, leakage rates,repair/replacement criteria, etc. for subsea valves, these have been written with respect toeither tests which need to be conducted at various stages during the factory-assemblyprocess, or, the maintenance-testing of a valve to determine its capability (or otherwise) as anintegral safety component within a complete pipeline-to-topside production system.

In the absence of any relevant industry standards these guidelines set out isolation integrity

criteria, against which the results of an in-situ pressure test on a subsea isolation deviceshould be reviewed on an individual basis.


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These criteria are outlined below. The inherent potential hazards of the subsea hyperbaricenvironment, combined with the implicit trust which divers place in their work instructions,require that the isolation criteria are more stringent than the equivalent for onshore oroffshore (topside) plant and equipment. The principles, however, are identical.

Note: Test pressures should be at least equal to, or slightly above (but no greater than 1.1x),the highest system pressure which the valve may be expected to withstand throughout theduration of the intervention activity.

It is not necessary to perform an isolation integrity pressure test to 1.1xMAOP if the systemoperating pressure is a reduced figure (i.e. has been lowered from the original designpressure value, for operational reasons, during the life of the field). In such instances, the testcriteria maximum may be modified to 1.1x highest anticipated operating pressure.

The fundamental isolation integrity criteria of a subsea isolation is that, following theimplementation of a pressure test, and on completion of an appropriate stabilisation period,there should be no flow or loss of pressure across the device under test for the duration of afurther 15 minute (minimum) recorded test hold period (see Figure 7 below).

In the event of an initially unsatisfactory test result then the procedure may be continued byextending the recorded test hold period in 15 minute increments up to a maximum of

60 minutes. This will provide opportunity to, either:

i) extend the stabilisation period and so possibly obtain a test hold; or

ii) determine the isolation device leakage rate.

Note: The test should be extended to at least 60 minutes in the case of a leaking isolationdevice associated with a gas inventory.

Unless a specific set of isolation integrity acceptance criteria limits has been previouslycalculated and approved by project management during the onshore engineering phase, thenany leakage, evidenced as flow or pressure depletion, during the 15 minute test hold period,should be treated as a loss of isolation integrity, requiring some form of remedial action (seeFigure 8 below).

Note: When the integrity of an intended isolation fails to meet the required criteria, then aseries of extended tests should be carried out to enable the leakage rate to be measured,such that the possibility of utilising any suitable additional (or alternative) facilities to mitigateand manage the leak may be reviewed in specific detail through risk assessment (see Figure 7).

When required to conduct a task-specific risk assessment, as a consequence of unacceptablefield test results, key project data should be gathered and made available for review. This isessential in the process of determining, based on impartial engineering judgement, whether asafe means for proceeding with the work can be identified.

Typically, in the case of a leaking valve in an isolation scheme, the following list of detaileddata should be obtained and reviewed:

i) valve type (e.g. gate, expanding gate, ball, double seal ball, plug, etc.);

ii) manufacturers original specification;

iii) assembly and factory test documentation;

iv) valve sealing design elastomeric, or metal-to-metal;

v) current operating parameters versus original design values;

vi) associated line size, history and present condition;

vii) line pressure(s) and temperature(s);

viii) line inventory liquid (e.g. hydrocarbons, water), gas or multiphase;

ix) potential for system to form hydrate blockages;

x) accurate estimate of actual valve leakage rate;

xi) calculated pressure drop-off versus capacity of any available vent;


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24 IMCA D 044

xii) proposed method of routing and venting the leaking inventory;

xiii)all relevant engineering drawings.

When it is not possible to obtain a satisfactory isolation then the additional potential hazardsarising should be assessed with a view to either proposing an appropriate alternative isolationscheme, or, identifying an increased isolation envelope.

Consideration should be given on any change in temperature which could have an influenceon the slope of the leakage test.

Figure 7 Integrity test graph acceptable

Figure 8 Integrity test graph unacceptable

4.2 Intervention

4.2.1 Types of Intervention

In these guidelines, any system of hoses, tubes, flexibles or pipelines which is inter-linked bypiping and valves within a subsea installation, and which is designed to convey hydrocarbons,treated water, gases, gels, chemicals, etc., or any combination of these inventories, iscategorised as subsea equipment on which divers may be required to intervene.

The typical internal-diameter dimensions associated with such equipment generally rangefrom 3/8 (9.5mm) for chemical injection systems up to at least 36 (914.4mm) for inter-connecting trunk pipelines.


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IMCA D 044 25

Prior to all intervention works on hydrocarbon systems, careful consideration should begiven to the contents of the bulk system pipework/tree-cavity and whether flushingoperations are necessary. Even when flushing operations have been conducted, there maystill be the potential for hydrocarbon entrapment at the intrusive worksite, especially if thepipework includes sections of complex geometry.

Any potential for release of small volumes of hydrocarbons which may be unavoidablytrapped within cavities following the setting of requisite isolations should be identified inadvance, such that mitigating measures are applied. Typically this may occur during theremoval and replacement of a choke valve, from either a manifold or tree system.

The outline requirements and precautions for diver intervention on flowline/manifold/treeand wellhead, and chemical injection systems, are outlined in the sections below.

4.2.1.1 Flowline/Manifold/Tree and Wellhead

Interventions on subsea systems invariably produce unique areas of concernregarding isolations, even when the scope may appear very similar to some previouswork carried out on the same (or even identical) hardware.

To define workscope isolation limits for intervention on flowlines, manifolds, trees

and/or wellheads, it is essential to identify:

i) each type of energy source within the system;

ii) the various locations where this energy may appear throughout the system; and

iii) the intended means of securely isolating such energies from the diver at theworkface.

Basic information such as system schematics, flow schematics, process andinstrumentation diagrams, and specifications, drawings, and test documentation inrespect of selected isolation components needs to be obtained for review in detail,during the onshore phase of the project.

Some examples of key items for consideration when conducting isolation pre-engineering for diver intervention are listed in Table 2 below.

What energy forms will be encountered?

Is there stored energy to be released/discharged before breaking containment?

Can the energy source be reduced to seabed ambient pressure?

Is there a potential for sub-hydrostatic pressures (i.e. vacuum)?

Does the pipework require flushing?

Are there any other potential energy sources tied-in to the process pipework/tree-cavity (e.g. chemical injection)?

Can the topside installation provide a tested isolation by conducting an in-flow

leak-off test?How will each identified isolation be made secure, and subsequently monitoredand maintained?

Has confirmation been obtained that any associated pressure sensors are reliable,accurate, and functioning correctly?

Can any valve actuators be viewed for correct open/close operation?

If risers are involved, has consideration been given to the hydrostatic head, and isan open vent in place topside?

Have details of valve type, test data, history and usage been obtained andreviewed?

Can the divers actually access the considered test points on the pipework/tree-

cavity?

What type of vent-fitting arrangement has been pre-installed in any pressure-


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retaining blind-flange?

Are check-valves required on the deployed test down-line hose(s) to ensure noreturns are possible to the deck of the DSV?

Table 2 Isolation and intervention considerations

When all the required isolation conditions have been achieved, it is still essential that

the removal of a cap or plug, or the operating of a bleed valve, or the initial releasingof a flange or joint connection is performed in a controlled manner in accordancewith good diving working practices. Appropriate techniques for initial intrusiveoperations by diver are well established and include the following:

Diver to be positioned to one side of any small bore plugs or caps duringremoval;

Where possible, leave open any block and bleed valves which are locatedbetween the two tested isolations required for blind flange/spool-piece removal,or pipework disassembly;

During flange de-tensioning (to a pre-determined bolt order), ensure that theretaining nuts and bolts are never completely removed until the actual sealingjoint has been broken.

4.2.1.2 Chemical Injection

All isolation principles and intrusive operations on subsea chemical injectionpipework should to be treated under the same terms as for subsea pipeline/flowlinework.

Subsea chemical injection systems also require careful consideration as they may besubjected to energy sources at either end of their inventory, i.e. by design the lineswill be pressurised by injection pumps on the topside installation, however, theselines are invariably connected into the subsea production system at locations whichare also being pressurised from the reservoir.

The direction of potential hazard flow is therefore likely to be opposite to thedirection of design flow, control of which is entirely dependent on the effectivenessof a combination of flow control valves and check-valves3.

Whilst this presents additional complications in determining the isolation scheme,the selected subsea chemical injection valves should be integrity tested in accordancewith these guidelines.

When it is not possible to obtain a satisfactory isolation then the additional potentialhazards arising should be assessed with a view to either proposing an appropriatealternative isolation scheme or, identifying an increased isolation envelope.

Contamination of divers and/or the environment is also a significant hazard factor

which should be considered when conducting intrusive operations on chemicalinjection systems.

Prior to the commencement of any intrusive work on chemical injection systems it isessential that the data sheets for any and all chemicals currently (and previously)

3Note: Check-valves are associated with chemical injection systems which inject into hydrocarbon lines. These are aligned such as toprevent any reverse-migration from the reservoir or flowline into the chemical injection system (and hence, ultimately, to the topsideinstallation). These check-valves are not normally considered as an appropriate form of isolation device for the following three reasons:1) It is unlikely to be able to determine their condition or state (i.e. by any manual opening/closing operation);2) They may be permanently frozen in the open position due to the low viscosity or high density of injected fluids;3) It is unlikely to be able to positively lock them into a known safe (e.g. closed) position.

Exceptionally, however, it may be possible to utilise a check-valve as an isolation device, when:a) the sealing properties of the obturator can be proven;b) the closed status of the valve can be maintained; andc) the valve is only utilised in conjunction with other proven valves in the bulk system isolation scheme.


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conveyed within the system architecture are identified and the relevant safetyinformation made available to the DSV.

4.3 Installation of Subsea Equipment

4.3.1 General

The deployment to subsea depth of items capable of retaining pressure (and resistingcollapse) has the potential for either of two significant pressure-equalisation hazards. Theseare:

i) the possibility of locked-in atmospheric pressure resulting in a negative pressuredifferential at seabed location; or

ii) the possibility of high pressure inadvertently locked-in to pipework during the onshoretesting programme resulting in a positive pressure differential at depth.

These are of concern for diver intervention activities as the rapid equalisation of pressurethrough an aperture may not be readily observed and, depending on direction, can causeeither body-part entrapment or sudden component release at high velocity. Both have thepotential for very serious consequences.

Careful consideration should therefore be given to ensure any components/structures whichcontain free-flooding internal cavities are deployed subsea with suitable in-built facilities toenable safe and controlled pressure equalisation at depth.

The following lists some key examples:

Flange protection Pipework in a manifold structure should be deployed with simplefree-flooding flange protectors on either end, where possible;

Blind flanges Pipework ends requiring to be pre-sealed with blind flanges should befitted with at least double block isolation valves, preferably also incorporating a bleedvalve. In the absence of a bleed then a diffuser or T-piece should be pre-fitted to theoutlet port (especially if the possibility of a negative pressure differential exists);

Valves Pipework, manifolds, and spools should be deployed with any integral valves setin the open position, wherever possible;

Pressure differential A hydrostatic pressure differential is preferable to a gasdifferential, therefore consideration should be given to cavity flooding prior todeployment, where possible;

Flexible flowlines In certain circumstances, these may require to be sealed atatmospheric pressure, either empty, or pre-filled with a specific liquid. Considerationshould therefore be given to post-installation diver intervention requirements, especiallywith regards to negative pressure differentials;

Risers When working on installation caissons and risers consideration should be givento the combination of tidal and meteorological factors (e.g. wave height) which can cause

subsea (or topside) pressure differentials. Provision should therefore be made forensuring a pre-determined positive head-height can be established. Typically, caissons/risers should be filled until flooded, at topside hang-off level, which will provide a nominalpositive pressure release when flange stud-bolts are de-tensioned at the subsea worklocation;

Tubular sections Sealed tubular sections within a subsea structure which are requiredto remain un-flooded until deployment to the seabed should be fitted with a minimum oftwo manual vent-valves. The external venting port of these valves should be fitted with adiffuser to prevent hand entrapment due to negative pressure differential during theflooding operation. The valves should be set as far apart as possible along the long axisof the tubular section. See typical arrangement in Figure 9 below;


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FIRST BLOCK

V2 V1

BLEED VALVE (DOUBLE BLOCK & VENT)

TO ATTACH HOSE

DIVER INTERVENTION RE

Guidelines for Isolation and Intervention

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