Guidelines for
Isolation and Intervention:
Diver Access to Subsea Systems
IMCA D 044
International Marine
Contractors Association
A
B
The 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 publication of information notes, codes of practice and by other appropriate means.
Members are self-regulating through the adoption of IMCA guidelines as appropriate. They commit to act as responsible members by following relevant guidelines and being willing to be audited against compliance with them by their clients.
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IMCA D 044
This guidance has been prepared for IMCA under the direction of IMCA’s Diving Division Management Committee based on material provided by Torquil M Crichton and other co-authors of 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.
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 ... 53.2.1 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
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 ... 17
Figure 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 ... 55
Figure 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
1 Introduction
This guidance document is primarily aimed at project managers, project engineers, offshore construction managers, diving supervisors and safety personnel, all of whom have a responsibility for developing safe schemes of isolation and intervention for divers accessing subsea systems. Additionally, engineering personnel involved with the design of such systems should also use this document to ensure that all new (or being modified) subsea systems incorporate adequate isolation facilities.
This document sets out what is considered to be good practice for ensuring a safe degree of isolation is established prior to conducting diver intrusive works on any energy-conveying system in which pressure differentials, electrical power or laser power may exist at levels which – on loss of containment – would be harmful to personnel or cause damage to the environment or equipment.
The guidelines are applicable for use when preparing workscopes, procedures, reviews and risk assessments for any diver related work.
These energy sources (pressurised liquid, pressurised gas, electricity and laser light) may be found as a conveyed product or service utility within either or both of the following two major subsea equipment categories:
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 powered equipment, communication signals, instrumentation signals, optical data signals, power transmission and distribution, chemicals, gas – each within dedicated sub-systems).
The general principles of isolation philosophy and isolation practice, as applicable to such systems, are given in section 2, whilst detailed guidelines regarding isolation and intervention are given in sections 4 and 5 respectively.
Adequate planning is essential for an effective isolation, not only to ensure awareness of the task requirements and ready availability of all materials, tools, etc., before work begins, but also to identify and assess the isolation options and their associated hazards and effects.
Safe standards of isolation are primarily determined by the size and nature of the potential hazards associated with 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 have been specifically designed for ROV installation, operation or recovery. In such instances, the isolation and intervention 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 and every subsea system encountered, the principles set out in this guidance should be applicable.
2 Glossary
AAV Annulus access valve
AC Alternating current
ACPI Annulus choke position indicator
ACV Annulus choke valve
AMV 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 to
maintain 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 has become charged by other means such as by static or induction charging, or has retained or regained a charge due to capacitance effects even though it may 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 valve
Dead Not electrically ‘live’ or ‘charged’
Design working pressure Maximum working pressure at which a hose or tube is rated for continuous operation
DHPT Down-hole pressure and temperature (sensor)
DHSV Down-hole safety valve
Disconnected Describes equipment (or part of an electrical system) which is not connected to any source of electrical energy
Double block and bleed An isolation method consisting of an arrangement of two block valves with a bleed valve located in between
Double seated valve A valve which has two separate pressure seals within a single valve body. It is designed to hold pressure from either direction as opposed to a single seated 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 unit
Final isolation Subsea isolation, local to the worksite. This isolation should consist of a secure physical separation. It is a readily understood way in which
prevention of the uncontrolled release of energy can be confirmed to diving personnel 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 to 30KV
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 disconnected and separated by a safe distance (the isolating gap) from all sources of electrical energy in such a way that the disconnection is secure, i.e. it cannot be 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 the separation 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 of electricity. This implies that, unless otherwise stated, the live parts are exposed so that they can be touched either directly or indirectly by means of some conducting object and that they are live at a possibly hazardous potential
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 and monitoring of the entire subsea control and umbilical system
Maximum permissible exposure Level of laser radiation to which, under normal circumstances, persons may be 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 is
positioned in the flow stream such that the flow may be either blocked or permitted to pass
OEM Original equipment manufacturer
P&ID Process and instrumentation diagram
PCPI Production choke position indicator
PCV Production choke valve
Pig A device that can be driven through a pipeline by means of fluid pressure for purposes 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 final isolation 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 contain and/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 diver’s body safely (explained in detail in IMCA D 045/R 015 – see section 8.1). It is
not the 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
3 Principles of Isolation
3.1 Principles of Isolation
The general principle of isolation is, where practicable, the removal of hazards or sources of energy from 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 any potential source of further energy.
The hyperbaric nature of subsea work means that divers are regularly exposed to the particular hazard of negative pressure systems during activities associated with system equalisation, as well as the normal potential hazards associated with the positive release of pressure from a system. Even a very small aperture with an associated pressure profile can cause severe injury should a diver come into contact with it. Thus when working on any subsea system containing liquid or gas under positive or negative pressure, there should be no pressure differential, relevant to the seabed ambient, trapped within a space or void.
Similarly, divers may become exposed to live electrical or optical connections containing electrical or laser 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 live electrical connections, or optical contacts located subsea.
In many cases, diving operations cannot commence until the topside installation has firstly applied primary isolation(s) to the main energy source(s), following which, manual and tangible final isolations will then need to be applied at the subsea worksite location. All isolations need to be proven, to demonstrate to diving personnel that protection from all potential energy sources has been established.
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 two independent and tested isolations should be established between personnel engaged in any task where the presence of potential hazard from a positive or negative pressure source exists.
Where practicable to do so, at least one of the isolation tests should take the form of a positive test, in the direction of flow, or alternatively, a negative test by reducing the pressure
downstream of the isolation. Exceptionally, it may be appropriate to test both isolations against the direction of flow.
3.2.2 Electrical Equipment
For subsea electrical equipment, the general principle (assuming that the voltage is higher than 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, should be isolated and any stored energy in the electrical circuits should be discharged.
Isolation can be achieved by disconnecting and separating the electrical equipment from every source of electrical energy in such a manner 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 electrical energy at potentially hazardous levels exists. Normally at least one of these isolations should be located on the topside host installation. However, it may be possible to set isolations local to the subsea worksite by physical disconnection of an inductive coupler (this does not apply to conductive connectors).
3.2.3 Optical Equipment
For subsea optical equipment, the general principle is that the main power circuit of the fibre optic 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 from every source of electrical power (topside) and final optical interface (subsea) in such a manner 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 light energy at potentially hazardous levels exists. Normally at least one of these isolations should be 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 the hydraulic 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 every source 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 between personnel engaged in any task where the presence of a potential hazard from hydraulic pressure at potentially hazardous levels exists. Normally at least one of these isolations should be located on the topside host installation. However, it may be possible to set isolations local to the subsea worksite by either physical disconnection of stab plate halves or by 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-sealing hydraulic couplers.
Note: Hydraulic systems operating sub-surface or down-hole safety valves may provide a conduit 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 isolation requirements for such systems.
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, two tested and independent isolations cannot be achieved, then it may be possible to identify an alternative method for undertaking the work, without compromising the safety of the operation. Any such alternative method needs to be subjected to a task specific risk assessment by competent personnel with 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 document may be suggested. As an example, there may be a client or main-contractor isolation philosophy document containing detailed procedures for isolation. Any such alternative methods should be compared with the techniques contained within this document and the more stringent requirement used.
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 between personnel engaged in any task where the presence of a potential hazard from a pressure source or vacuum exists. The physical isolation of pressurised systems is generally achieved by using various combinations of valves, spades or blank flanges.
Isolations for subsea flowline/manifold/tree and wellhead systems are primarily provided in standard form by valves located between the diver intervention workface and the potential energy source. There are also many instances whereby pre-installed and tested blind flanges may provide isolation. The type, configuration, location and testing of such isolations are considered in further detail throughout this section.
Consideration is also given to certain alternative and specialised isolation techniques, which may not be appropriate for standard applications but, depending on system architecture, may require 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 control and umbilical systems (see section 5). The process of achieving an appropriate overall isolation 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 final isolation 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 physical separation. It is the tangible mechanism by which prevention of the uncontrolled release of energy 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-line isolation device across the dimension range, from large diameter trunk pipelines through to small-bore injection tubing. When utilised in subsea systems they are defined within two specific categories: either manually operated (i.e. by diver or 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 for intervention purposes should consist of two sets of main double block valves, each with a bleed valve located between them. This ‘bleed’ facility itself should consist of an arrangement of small-bore valves in a double block and bleed configuration, as they connect directly into the bulk system. Such valving should be in place on both sides of any intended break (see Figure 1).
VALVE 1A VALVE 2A VALVE 2B VALVE 1B
CLOSED OPEN OPEN CLOSED
BLEED PORT
CONNECTION POINTTEST DOWNLINE
BULK SYSTEM PRESSURISED TEST DOWNLINE CONNECTION 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 operated valve for one of the isolations.
When two remotely actuated valves require to be utilised to establish the bulk system isolation scheme, the supply lines to both should be locally isolated at the worksite.
In the absence of any means to implement such isolations then the additional potential hazards arising need to be assessed with a view to either proposing an alternative isolation scheme or identifying an increased isolation envelope. Valves should be capable of providing a reliable and positive shut-off seal for the isolation of a hazardous substance and/or energy source. They should be suitable for the expected service and associated potentially hazardous conditions to 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 parameters should be obtained at an early stage in the onshore phase of the project. This should help avoid unnecessary delays during offshore integrity tests for a given isolation scheme.
Small-bore valves which form the directly-connected vent/bleed outlet in any subsea 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 intervention activities (e.g. when connecting a dive support vessel (DSV) test downline to the main outlet port on the same valve assembly). The bleed valve provides a local safety vent through the bleed port.
The alternative, dual-in-line block only (‘double block’) valve, i.e. without any incorporated 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 or double block and bleed valves should be the ‘diver-safe’ integral-vent type (i.e. pressure vents prior to full disengagement). Such devices are designed to ensure any initial differential pressure equalisation occurring within, or through, the valve assembly (when preparing the cap for removal) can be vented in a safe manner, without the potential hazard of gross loss of containment or of the cap coming off in an uncontrolled manner. The use of any other type of cap (or plug) which does not incorporate a secondary pressure-relief mechanism is not considered 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, is not considered appropriate to meet the principles for safe diver intervention given in these guidelines.
The suitability, or otherwise, for the various configurations of small-bore isolation valves and their caps/plugs is summarised in Figure 2.
The outlet port on small-bore valve assemblies should also be of suitable design to guarantee a fixed pressure-retaining connection when the DSV test downline is attached (and subsequently pressurised) to check for flow, either into or out of the cavity. This ensures a safe and secure facility is maintained for the equalisation of any entrapped pressure throughout the work.
PRODUCT FLOW
LEGEND
UNACCEPTABLE UNACCEPTABLE
ACCEPTABLE (but not recommended)
ACCEPTABLE - BASIC
ACCEPTABLE (but not recommended)
ACCEPTABLE - OPTIMISED
PRODUCT FLOW
PRODUCT
FLOW PRODUCTFLOW
PRODUCT FLOW PRODUCT FLOW P R E S S U R E P R E S S U R E P R E S S U R E P R E S S U R E P R E S S U R E P R E S S U R 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-machined flange faces such that they can be inter-connected to form a pressure-containing liquid/gas transportation system. These flanges are specified to at least the same design and test standards as the item to which they are attached.
The flange faces require to be maintained in their factory-finished condition throughout the load-out and offshore installation activities and for the duration of the field life. Protection for the sealing surfaces is therefore provided in the form of a matching circular blanking cover/plate or blind flange. These provide physical protection and, where required, comply with the system installation and commissioning specifications (i.e. free-flooding or pressure-tight), in combination with the intended field development programme (i.e. immediate hook-up, or future tie-in).
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 the flange 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. by inserting spacer washers). With this type of protection arrangement, the flange interface 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 in place on surface, prior to deployment to the seabed (as it may be intended to allow the system to free flood in some other manner). Therefore the blind flange should be prepared with a welded outlet port to which is fitted, as a minimum, a small-bore double block valve, complete with either a ‘T’-piece or a diffuser. This is to ensure that there is no possibility of diver finger/hand entrapment during differential-pressure equalisation at depth.
Dual Purpose – To provide physical protection for the sealing surfaces of the flange face, plus the capability to maintain a pressure-containing isolation equal to 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 level of preparation enables full pressure-testing against the blind-flange during pipeline commissioning. It also provides the capability, if required, of leaving the blind 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 a trapped inventory of positive or negative pressure remaining in the cavity between the blind flange and the next (closed) valve in the bulk system. Therefore the blind flange should be prepared with a welded outlet port to which is preinstalled, as a minimum, a small-bore double block valve, complete with either a ‘T’-piece, or a diffuser. As an alternative, a small-bore double block and bleed valve arrangement could be preinstalled.
In the absence of any means to safely depressurise the bulk system prior to removal of the blind flange, then the additional potential hazards arising need to be 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. Depending on specific design, these may or may not align with the recommended ‘double block and bleed’ isolation principle. Their utilisation should therefore be considered through 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 in between, may be utilised if necessary.
There are, however, certain limitations and restrictions to this type of valve which should be considered:
ii) The status of the double isolation depends upon the immobilisation of a single valve operating stem therefore there should be no possibility of it being operated during the intervention work;
iii) The valve body outlet bleed port directly accesses the inventory of the valve cavity. Also, this outlet is only protected from the potential energy in the bulk inventories (i.e. on either side of the valve unit) by the single isolations provided by each of the obturators within the valve assembly. The outlet should be fitted with a permanently attached double block access/vent valve arrangement as a minimum (a double block and bleed is recommended).
The ‘double seal’ valve design should only be used in preference to the conventional bulk system isolation arrangement (i.e. double block and bleed) after the increased hazards have been reviewed through the appropriate risk assessment process.
4.1.1.2.2 Pipeline Plugs
The utilisation of a bespoke in-pipe plug (or combination of plugs) to form a proven 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 such that failure of a part of the sealing system does not cause total loss of sealing capability. Similarly, power, control and monitoring systems for the isolation plug should be suitably robust and/or dual-redundant to account for any possible
in-situ damage or failure.
Certain designs of in-pipe plugs may only be capable of providing an appropriate form of single isolation, whilst others may claim to provide full double block and bleed isolation. Due to variations in manufacturers’ design and the techniques by which these isolations are achieved, tested and maintained, the proposed device 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 plug devices should be considered on a case by case basis under the appropriate risk assessment process.
4.1.1.2.3 Hot Tapping
Occasionally, for various reasons of operational or delivery constraints, it may be necessary to perform a live intrusive intervention on a pipeline whilst it remains 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 and subsequently adapted for subsea applications.
The section of pipe requiring intervention (e.g. to fit a valve assembly for some future tie-in) should be accessed by means of a hot tap clamp and drilling assembly, which should be suitably designed and tested for containing full pipeline pressure. This stack-up should also incorporate a suite of valves to facilitate the future tie-in. These should be arranged in a double block and bleed configuration which, on completion of the hot-tapping operation, should be subjected 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
and accepted in the terms and recommendations of these guidelines. The ‘isolation’ properties previously offered by pigs have now been superseded by those of pipeline isolation plugs (see ii), above).
4.1.1.3 Specialised Isolation Methods
Techniques for directly isolating the pipeline or hydrocarbon reservoir from the subsea equipment, such as pipe freezing, hydrostatic column1, bridge plug, cement
plug or other such specialised methods, are considered to be outwith the scope of these guidelines and are therefore excluded.
Should it be necessary to utilise any of these as effective isolations (through the services and supporting expertise of a specialised vendor) then their incorporation into the isolation scheme would need to be subject to detailed review through the appropriate 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 not
designed to be pressure-retaining when fully closed. During interventions, the choke 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/ open
if pressure develops in well-bore column above valve obturator. However, exceptionally, it may be permissible to accept this type of valve as a suitable isolation, but only if it has been possible to prove the sealing properties of the valve 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 a suitable 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 bulk
system isolation scheme; and
c) it has been possible to prove the sealing properties of the valve to at least the maximum anticipated pressure differential. Caution is required for smaller size check valves (e.g. in chemical injection lines) as a blockage may mask 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 risk assessment.
To provide a safe worksite for the diver and to minimise damage to the environment, it may be necessary to flush the subsea pipework/tree-cavity to remove harmful contents prior to placing isolations. These operations are usually required when hydrocarbon inventories are involved; it is recognised industry
1 The 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; and
practice to reduce the hydrocarbon content to less than 40 parts per million (<40ppm) prior to any breaking of containment.
Flushing operations can either be conducted by the topside installation connected to the subsea system or remotely by the DSV when suitable tie-in points are available. Typical flushing agents include nitrogen, treated water, monoethylene glycol (MEG), methanol, diesel or gel slug with other mediums. The suitability of the flushing agent should be confirmed prior to work commencing.
4.1.2.2 Pre-determined Tree Valve Status
The initial setting of tree and/or flowbase valves to either the open or closed position (or some percentage thereof for a choke valve) are usually pre-established by the client and applied through the workover equipment of the tree/wellhead installation contractor.
Subsequent hook-up and pre-commissioning activities by the subsea system installation contractor may favour altering the settings of some of these valves, invariably to conduct pigging routine(s) or carry out the pipeline pressure-testing programme.
Such adjustments are not recommended by these guidelines, for the following three reasons:
i) Tree valves are likely to have been pressure-tested by the drilling/workover rig and left in a particular position to suit the tie-in intervention work and the operational start-up programme;
ii) It is normal practice for the drilling/workover rig to ‘pre-condition’ the various cavities within the flowbase/tree/wellhead combination to benefit initial start-up flowing conditions. Any subsequent intervention by way of altering the status of valves during pre-commissioning may result in the introduction of undesirable fluids/gases into these cavities. This may hinder start-up;
iii) The adjustment of tree valves further to a well having been perforated and prior to operation by the host installation may incur damage to tree valves. This would be likely to result in some form of tree intervention or may even require recovery to surface.
All efforts should be made to maintain the tree in the status and condition in which it was found and expected to be left. This is usually recorded in the handover certificate received from the tree/wellhead installation contractor.
4.1.2.3 Location of Isolation
In certain instances, the large scale of a subsea field layout, combined with interconnecting pipeline lengths (possibly measured in tens of kilometres) may necessitate the point of isolation (e.g. topside, or at an onshore landfall) to be some considerable distance from the actual subsea work location.
Such field layouts raise areas of specific concern with respect to diver intervention which need to be considered on a case-by-case basis. These are:
i) Care needs to be taken to ensure that inadvertent de-isolation cannot take place at one end of a pipeline system whilst work is still progressing at the other end. Such circumstances reinforce the requirement for tangible isolations, adequate security (e.g. at onshore location, if necessary), plus the maintenance of effective monitoring and communications throughout the entire work; ii) Confirmation that the remote isolation/vent-down has been implemented and is
effective by conducting a series of checks local to the subsea worksite, should be undertaken before any diver intervention activities commence. The possibility of only a small pressure differential supported by a large volume
(either from within the pipeline or by the surrounding seawater) can present considerable potential hazard to diving personnel;
iii) Checks for the existence of a specific gravity differential between the pipeline contents and that of the surrounding seawater should be undertaken. The absence of a local isolation combined with a significant differential in specific gravities can present a potential hazard to diving personnel located in the vicinity of a high volume pipeline discharge.
Each intervention of this nature therefore should be reviewed with particular regard to the key parameters given above. Consideration should also be given to other important pipeline aspects such as – inventory type, overall topography, size, history and present condition.
Should the applicable risk assessment/review process determine that certain features of the intended isolation scheme are inadequate, or the pipeline inventory presents a potential hazard to diver or the environment, then the work should not be allowed to proceed until an appropriate alternative local isolation scheme is proposed, or an increased 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 can commence. Where possible, both should be tested in the direction of design-flow or in the direction 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 specify the following four key items:
i) Valve alignment requirements, including subsequent operating system isolations, to both prove and maintain the isolation. To achieve this, a thorough understanding of the system process flow diagrams (PFDs), all relevant piping and instrumentation diagrams (P&IDs) and subsea control system schematics is essential. An appreciation of the operating 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 is obtained at an early stage during the onshore phase of the project, and certainly prior to commencement of the offshore programme as this will determine their test parameters and hence 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 (for hydraulic-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 valve history and frequency of operation.
The essential features of the test equipment and the principles of the various test methods which 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 such that the test is in fact acting on the isolation.
This is normally carried out as part of initial subsea intervention works by the attachment of a test down-line from the DSV to a suitable block and bleed assembly on the subsea pipework and valve arrangements (see Figure 3).
REEL GAUGE M POWER PACK VENT TB L V TBLK2 TBLK1 DSV DECK GAUGE SUBSEA CAPPED C/W ISOLATION & VENT VALVES
CHART- RECORDER &
TCV1 TCV2 OR TLIV FROM DSV TEST 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 should be given to the contents of the subsea pipework/tree-cavity and the pressure anticipated. Divers should be made aware of the potential of a pressure differential when removing any plug or cap from the bleed facility and should have confirmed previously that the pipework/tree-cavity block and bleed assembly is in the closed position.
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 configuration should be pressure-tested on the DSV prior to deployment.
On attachment of the test downline onto the subsea pipework/tree-cavity block and bleed assembly, a leak test should be conducted against the closed bleed valve to confirm the integrity of the test line connection.
Any block and bleed assembly on subsea pipework/tree-cavity needs to be proven to operate correctly. It should not be assumed that ‘communication’ has been achieved through the pipework block and bleed assembly into the void just because the block and bleed is open. Debris, wax, hydrates2, asphaltenes etc. can readily restrict or
block small-bore bleed facilities.
To confirm communication through and into the pipework/tree-cavity, it is necessary to have an open flow path that can be registered through the test downline. 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 up the bleed-and-block valve into the cavity. This should register as a pressure-drop on the topside gauge, thus confirming communication.
2 A mixture of hydrocarbons and water forming an ice-like solid under certain conditions of pressure and temperature. These can mask
isolation testing results as the hydrate itself may be forming the isolation (rather than the requisite valve), or may be blocking the route to a test port. Furthermore, the hydrate creating the blockage may melt, resulting in an unexpected release of trapped pressure.
Generally, valves are designed such that the in-line pressure will actually assist in ‘activating’ their sealing mechanism(s). Thus, increasing the magnitude of the pressure difference across the valve (i.e. pressure differential) provides optimum test conditions. Tests should therefore be specified with as high a pressure differential as is reasonably possible.
Careful consideration, however, should be given in the various stages of the testing programme to determine whether the possibility will exist for the test acting on one side of a valve to ‘unseal’ (and thus negate) a previously successful test obtained on the opposite face of the same valve. It is therefore important to obtain detailed information regarding the various valves intended to form the isolation, and to correctly select test pressures relevant to the status of immediately-surrounding system 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 steps of approximately one-tenth, or less, of the required test pressure, until the final value 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 wellhead applications in section 4.1.3.2 to 4.1.3.5, inclusive and for hydraulic and instrumentation applications in section 5.1.4.2.
The integrity of a tested isolation should be determined with reference to the acceptance criteria given in section 4.1.4.
Note; Isolation and bleed components on subsea systems may remain inactive over extended periods of time. As a consequence they may become stiff and difficult to operate. Care should be taken when functioning block and bleed valves or removing plugs and similar fittings.
There is a possibility that captive pressure may remain locked-in between block valves, plugs and other small bore fittings even if the pipework has been depressurised (e.g. due to the presence of a hydrate).
At all times, divers should be aware of the potential for a pressure differential – a negative pressure (vacuum) may exist.
4.1.3.2 Positive Test Method
When the valve forming a part of the isolation scheme between the energy source and the workface is accessible for test in the direction of design/potential hazard flow then this technique is described as the ‘positive test’. This is the preferred test arrangement 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).
Pressure differential should exist across the isolation, with the expected positive side of the isolation being monitored for any decrease in pressure.
REEL CHART- RECORDER & GAUGE TO REST OF SYSTEM SUBSEA TBLK2 TBLK1 CAPPED TB L V GAUGE VENT TCV2 TCV1 OR TLIV TEST DOWNLINE FROM DSV DIRECTION OF DESIGN / POTENTIAL HAZARD FLOW
CLOSED VALVE No.2 CLOSED VALVE No.1 PRIMARY SIDE ( "UPSTREAM" ) SECONDARY SIDE ( "DOWNSTREAM" ) PR E S S U RI SE 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 the isolation 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 isolation valve 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 the direction 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 isolation scheme, such that with upstream flow acting on the isolation valve, then any possibility of leakage may be monitored as a pressure build-up in the test downline system (see Figure 5).
Pressure differential should exist across the isolation, with the expected negative side of the isolation being monitored for any increase in pressure.
M DSV DECK REEL PRESSURISED BULK SYSTEM GAUGE
CHART- RECORDER & C/W ISOLATION
POWER PACK & VENT VALVES
SUBSEA TBLK2 TBLK1 CAPPED TB L V GAUGE VENT TLIV FROM DSV TEST DOWNLINE DIRECTION OF DESIGN /
POTENTIAL HAZARD FLOW
PRIMARY SIDE ( "UPSTREAM" ) SECONDARY SIDE ( "DOWNSTREAM" ) DEPRESSURISE CLOSED VALVE INTENDED WORKFACE ZONE CAPPED OUTLET, OR CONNECTED INTERFACE TO REST OF SYSTEM
Figure 5 – Negative or in-flow leak off test method
Reference should be made to section 4.1.4 for determining the integrity of the isolation thus tested.
4.1.3.4 Volume Calculation Test Method
Where subsea inventory or architecture limitations dictate (e.g. unpredictable pressure/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 achieved is that both isolation valves have to be pressure tested against the direction of design/potential hazard flow.
This method of isolation-proving requires that testing is supported by the volumetric calculation technique, whereby the difference between the volumes of test fluid required to raise the two valve inventories to test pressure is computed – thus checking 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 significant and therefore measurable volume between the valves, otherwise the two valves need to be treated as effectively forming a single isolation only.
& VENT VALVES POWER PACK C/W ISOLATION
CHART- RECORDER & GAUGE REEL DSV DECK SUBSEA TBLK2 TBLK1 CAPPED TB L V GAUGE VENT BULK SYSTEM PRESSURISED TCV2 TCV1 OR TLIV
FROM DSVTEST DOWNLINE
DIRECTION OF DESIGN / POTENTIAL HAZARD FLOW PRIMARY SIDE ( "UPSTREAM" ) SECONDARY SIDE ( "DOWNSTREAM" ) VALVE
No.1 VALVENo.2
INTENDED WORKFACE ZONE CAPPED OUTLET, OR CONNECTED INTERFACE TO REST OF SYSTEM M
Figure 6 – Volume calculation test method
Reference should be made to section 4.1.4 for determining the integrity of the isolation thus tested.
Note: This particular test method is dependent on the volumetric calculation. Any procedural requirement to open/re-close a proven isolation subsequent to the test thus 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 the process of proving the isolation properties of subsea valves, particularly in terms of either the positive or negative test methods.
For example, positive pressure testing into the cavity between two designated subsea isolation valves may be possible where there exists a chemical injection point directly 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 provided by 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 with associated subsea system pressure sensors, any other subsea or topside valves and topside instrumentation.
Note: The validity of an isolation obtained by either of these topside methods is highly dependent on the reliability, accuracy and in-situ track-record of subsea sensors 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 installed instruments may be exclusively relied upon for the testing of isolations.
In those instances where there exists a known possibility of inaccuracy or fault in the permanent subsea instrumentation system then local supplementary pressure gauges should be incorporated by diver(s) at suitable locations in the isolation scheme. This is essential to establish confidence at the subsea intervention worksite for any isolation 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 invalidate the test and a subsequent test will have to be re-applied prior to any intrusive operations.
Note; It should not be assumed that subsea valves are closed. All isolations should to be considered open or (partially open) until proven and confirmed otherwise by conclusive test. Such testing may consist of either:
Topsides to command in-line valve closed, perform in-flow test and monitor for pressure increase/decrease; or
Diver attachment of test downline into system from DSV and monitor for pressure increase/decrease.
Note: For intervention work, diver (or ROV) visual checking for movement of a valve to the known closed position by observation of its indicator/actuator stem does not constitute confirmation that the valve has actually closed. This is due to the fact that the valve actuation mechanism may have become separated from the valve closure element within the valve body.
(The visual checking method is only appropriate for valve position confirmation checks 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 agreed isolation integrity acceptance criteria for the various devices which it is intended to incorporate in an isolation scheme. This will considerably reduce the problem of unexpected delays 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 to the commencement of any intrusive intervention work by diver.
This may typically be achieved by implementing an appropriate test for each of the given isolations, followed by a review of the results obtained. This review is extremely important in 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 required intervention.
Review and interpretation of test results are normally conducted with reference to industry standards, or alternatively, require to be considered on a case-by-case basis.
There are no applicable international industry standards in place which provide guidance in the interpretation of test results for an in-situ isolation device intended to be utilised in the provision of a safe isolation scheme for diver intervention, prior to the breaking of containment subsea. Whilst several standards do exist which address testing, leakage rates, repair/replacement criteria, etc. for subsea valves, these have been written with respect to either – tests which need to be conducted at various stages during the factory-assembly process, or, the maintenance-testing of a valve to determine its capability (or otherwise) as an integral 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 device should be reviewed on an individual basis.
These criteria are outlined below. The inherent potential hazards of the subsea hyperbaric environment, 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 or offshore (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 the duration of the intervention activity.
It is not necessary to perform an isolation integrity pressure test to 1.1xMAOP if the system operating pressure is a reduced figure (i.e. has been lowered from the original design pressure value, for operational reasons, during the life of the field). In such instances, the test criteria maximum may be modified to 1.1x highest ‘anticipated’ operating pressure.
The fundamental isolation integrity criteria of a subsea isolation is that, following the implementation 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 a further 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 by extending 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 isolation device associated with a gas inventory.
Unless a specific set of isolation integrity acceptance criteria limits has been previously calculated and approved by project management during the onshore engineering phase, then any 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 (see Figure 8 below).
Note: When the integrity of an intended isolation fails to meet the required criteria, then a series 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 mitigate and 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 unacceptable field test results, key project data should be gathered and made available for review. This is essential in the process of determining, based on impartial engineering judgement, whether a safe 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 detailed data should be obtained and reviewed:
i) valve type (e.g. gate, expanding gate, ball, double seal ball, plug, etc.); ii) manufacturer’s 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;
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 hazards arising should be assessed with a view to either proposing an appropriate alternative isolation scheme, or, identifying an increased isolation envelope.
Consideration should be given on any change in temperature which could have an influence on 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 by piping 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, is categorised as ‘subsea equipment’ on which divers may be required to intervene.
The typical internal-diameter dimensions associated with such equipment generally range from 3/8” (9.5mm) for chemical injection systems up to at least 36” (914.4mm) for inter-connecting trunk pipelines.