Transcript
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LOSS OF CONTAINMENT - PROCESS
Source of Hazard Initiators Risk Evaluation Risk Management
Measures
Performance
Standards
HS1 - Pressure
Vessels (inc
Columns)
G1 - Corrosion:
Internal / External
Frequency F14 - Inherent
Safety
- fully rated
vessels,
Vessels,
pipework,
tubing, tanks,
risers
1. Scope
This section provides guidance for the assessment of safety case content with respect to the loss of
containment from process plant and process operations, from hazard identification through to
elements of consequence determination, including risk management measures. However it
excludes assessment of the consequences of ignition of any release. This is considered separately
in Section 2.3.3.
2. Assessment of Adequacy of Demonstration
The evaluation of risk that might stem from each major accident hazard is to be assessed by
identification of the factors that might result in an adverse combination of a source of hazard and
initiator, together with identification and evaluation of escalation paths that might result. Potential
sources of hazard, initiators etc, are shown in Section 4 below. Assessors should ensure that,
where relevant, safety cases contain appropriate consideration of each of these factors.
3. Depth of Assessment
This section gives guidance on the depth of assessment required to determine the adequacy of the
demonstration that measures have been or will be taken to ensure compliance with the relevant
statutory provisions.
Where safety case contents match with good practice identified in the assessment sheets for a
particular element associated with a major accident, there will usually be no need for an assessor to
probe into the details of how the good practice is applied. This may, however, be a suitable issue
for follow-up by inspection.
4. The assessor should examine the adequacy of the hazard identification, risk evaluation and
management in conjunction with the contents of the Categorisation Table below:
Loss of Containment - Process
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pipework,
pipelines, risers,
etc
-large segregation
distances
- separate
accommodation
jacket
- inventory
minimisation
- Temperature &
pressure rating
- Material
specification
- Corrosion
allowance
- Fatigue life
- Frequency of
inspection
- Relief
arrangements
and capacity
- Reliability of
protective
systems
- Adequacy of
supports
- Fire protection
HS2 - Heat
Exchangers
G2 - Erosion F1 - Generic
historical data
F15 - Relief
systems Heat
Exchangers
- Thermal rating
- Temperature
and pressurerating
- Shell and tube-
side flowrates
- Material
specification
- Fatigue life
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- Frequency of
inspection
- Relief
arrangements
and capacity
HS3 -
AtmosphericVessels [eg
Wemcos, tilted
plate separators,
deck tanks]
G3 -
Overpressure
F2 - Company &
installation data
F16 - HIPS
systems Atmosphericvessels
- Temperature &
pressure rating
- Material
specification
- Corrosionallowance
- Relief
arrangements
and capacity
HS4 -
Centrifuges /
Hydrocyclones
G4 - Internal
explosion
F3 - Installation
specific hazard
studies
- HAZOPs
- FMEAs
- Design reviews
F18 - Shutdown
systems
Centrifuges/
hydrocyclones
- Temperature &
pressure rating
- Material
specification
- Corrosion
allowance
- Separation
efficiency
- Vibration
(centrifuges)
HS5 Piping and
piping
components
G5 - Under
pressurisation
F4 - Layout F19 - Alarms /
Trips Piping
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- Temperature &
pressure rating
- Material
specification
- Corrosion
allowance
HS6 - Smallbore
tubing
G6 - Fatigue /
vibration cracking
F5 - Company
standards /
procedures
F20 - Good
procedures
- operational
- maintenance
Tubing
- Temperature &
pressure rating
- Material
specification
HS7 - Pipeline
Risers (see
section 2.3.2)
G7 - Fire F6 - Corrosion /
erosion policy
F21 - Competent
personnel
HS8 - Flexible
hoses
G8 - Seal failure F7 - Operational
reviews
[procedures]
F22 - Monitoring
& audit systems Flexible hoses
- Temperature &
pressure rating
- Material
specification
- Corrosion
allowance
- Fatigue life
- Frequency of
inspection
- Integrity of
connections
HS9 - Pumps G9 - Turret
failure
F8 - SIL
standards
F23 - Isolations
compressors,
turbines
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HS10 -
Compressors
G10 - Inadequate
installation
F9 - Equipment
selection [eg weld
or flange]
- Flowrate
- Head/pressure
- Shut-in pressure
- NPSH
- Turndown
Minimum flow
- Sealing system
HS11 - Turbines G11 - Operator
error: inadequate
Training
F10 - Concept
selection
F24 - Gas
detection (see
section 2.3.3)
HS12 - Valves G12 - Operator
error: inadequate
competency
Consequences: F25 - Fire
detection (see
section 2.3.3)
Valves
- Temperature &
pressure rating
- Material
specification
- Corrosion
allowance
- Closure mode
- Fire protection
- Integrty of seals
- Leakage rate
H13 Gas
treatment plant
G13 - Violation
F11 - Size of
release
- speed &
effectiveness of
detection
response
- blowdown
system
Gas treatment
plant
- Temperature &
pressure rating
- Material
specification
- Corrosion
allowance
- Performance
specification
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HS14 - Marine
storage tanks
G14 - Deficient
procedures:
operational
F12 Dispension
- open / closed
modules /
ventilation rates
Marine tanks
- Pressure rating
- Fatigue life
- Frequency of
inspection
- Relief
arrangements
and capacity
- Reliability of
protective
systems
HS15 -
Hazardous
drains / caissons
G15 - Deficient
procedures:
maintenance
F13 - Toxicity of
release
HS16 - Integral
storage cells
G16 - Ship
collision
HS17 Flare and
vent towers
G17 - Dropped
object
Flare and vent
systems
- Temperature &
pressure rating
- Material
specification
- Corrosion
allowance
- Separation
efficiency
- Gas dispersion
- Thermal
radiation
- Noise level
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HS1 Pressure Vessels (including Columns)
HS5 Piping and Piping Components
- Turndown
HS18 - Turrets G18 - Seismic
event
HS19 -
Temporary
Equipment
G19 - Missile [eg
turbine blade]
G20 - Ageing /mechanical
degradation
G21 - External
loads [eg stood
on, struck by
scaffold pole]
G22 - Helicopter
collision / rollover
G23 - Inadequate
design
G24 - Incorrect
material
specification
G25 - Incorrect
material usage
G26 - Thermal
radiation
G27 - Slugging /
water hammer
G28 - Sloshing /
slam liquid loads
G29 - Structural
failure
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HS12 Valves
[Relevant Sheets: G17, G18, G20, G21, G29, G3, G5, G6, G8, G10, G27, F15, F18]
1. This sheet is generally applicable to the mechanical integrity of static components that form the
boundary of a hydrocarbon containment system; ie pressure vessels and piping etc. It is also of
relevance to rotating equipment, in so far as these also have pressure boundaries. Aspects specific
to machinery and rotating equipment are dealt with elsewhere. Similarly, process control and plant
isolation requirements are not dealt with here.
This sheet is not intended to limit the scope of an assessor to pursue any aspect of safety that they
believe is important to a particular safety case, within the remit provided by the safety case
regulations. It is though intended to provide guidance as to the minimum acceptable demonstration
of safety that a duty holder should be able to provide. As with all safety assessment work, there is a
need for HSE assessors to concentrate on areas where there are grounds for believing the safety
demonstration may be weakest. Knowledge of such areas comes from HSEs collective experience,
as well as that of the wider engineering community. This document is intended to provide pointerstowards what are believed to be the most pressing concerns. Conversely, it is not considered
necessary or practical for a particular safety case to mention explicitly all of the aspects of design
and operational concerns identified below. However the duty holder should in principle be able to
address all such concerns and hence provide an adequate demonstration of integrity. Therefore, it
is reasonable for an assessor to question a duty holder on any aspect of the integrity justification.
Confirmation should be obtained that the pressure system elements have been designed,
constructed, installed, and operated in accordance with a recognised standard or code of practice.
As a general principle, HSE accepts that codes, standards published by BSI, ASME, API and
others, are for the most part well founded, in that they have been written to encompass the present
best knowledge and advice available. However adherence to a code is not in itself a demonstration
of safety. There are several reasons for this. Not only are some codes inherently goal oriented
themselves, but there are also some matters which are the subject of technical uncertainty, or
indeed where current code provisions appear to be inadequate or may not reflect the state of the
art. The safety case assessment process may therefore include questioning as to the detailed
application or adequacy of parts of codes. A typical, but non-exhaustive, list of standards and codes
of practice would include:
PD5500: 2009+A3:2011 Specification for unfired fusion welded pressure vessels
ASME VIII Boiler and pressure vessel code
BPVC Section VIII-Rules for Construction of Pressure Vessels Division 1 (BPVC-VIII-1 -
2010)
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BPVC Section VIII-Rules for Construction of Pressure Vessels Division 2-Alternative Rules
(BPVC-VIII-2 - 2010)
BPVC Section VIII-Rules for Construction of Pressure Vessels Division 3-Alternative Rules
for Construction of High Pressure Vessels (BPVC-VIII-3 - 2010)
BS EN 13445 Unfired pressure vessels
BS EN 13445-1:2009 Unfired pressure vessels. General
BS EN 13445-2:2009 Unfired pressure vessels. Materials
BS EN 13445-3:2009 Unfired pressure vessels. Design
BS EN 13445-4:2009 Unfired pressure vessels. Fabrication
BS EN 13445-5:2009+A3:2011 Unfired pressure vessels. Inspection and testing
BS EN 13445-6:2009 Unfired pressure vessels. Requirements for the design and fabrication
of pressure vessels and pressure parts constructed from spheroidal graphite cast iron
BS EN 13445-8:2009 Unfired pressure vessels. Additional requirements for pressure vesselsof aluminium and aluminium alloys
Part 7 isn't published as a "British Standard" but as a "Published Document"
PD CR 13445-7:2002 Unfired pressure vessels. Guidance on the use of the conformity
procedures
PD CEN TR 13445-9:2011 Unfired Pressure Vessels Conformance of the EN 13445 series
to ISO 16528
ASME B31.3 2010 Process piping
ISO13703 2000 [API 14E] Petroleum and natural gas industries. Design and installation of
piping systems on offshore production platforms. BS equivalent is BS EN ISO 13703:2000
ISO 15649 2001 Petroleum and natural gas industries. Piping. BS equivalent is BS ISO
15649:2001
PD CEN/TR 14549 2004 Guide to the use of ISO 15649 and ANSI/ASME B31.3 2010 for
piping in Europe in compliance with the Pressure Equipment Directive
ISO 14692 Parts 1 to 4 Petroleum and natural gas industries. Glass-reinforced plastics
(GRP) piping. Current versions are from 2002, BS equivalent;
BS EN ISO 14692-1:2002
BS EN ISO 14692-2:2002
BS EN ISO 14692-3:2002
BS EN ISO 14692-4:2002
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BS 4994 1987 Specification for design and construction of vessels and tanks in reinforced
plastics. Replaced by BS EN 13923:2005 and BS EN 13121-3:2008+A1:2010
Codes to assist in-service integrity:
A typical but non-exhaustive list of relevant standards would include:
ASME Boiler and Pressure Vessel Code Series Please see BPVC-VIII-1 2010, BPVC-VIII-
2 - 2010and BPVC-VIII-3 - 2010
Inspection:
API 510 Pressure vessel inspection code: Maintenance inspection: In-service inspection,
rating, repair, and alteration current version is 9th edition 2006
API 570 Piping Inspection Code: In-service Inspection rating, repair and alteration of piping
systems current version is 3rd edition 2009
API RP 574 Inspection practices for piping system components current version is 3rd edition
2009
EEMUA Standards
API RP 580 Risk based inspection. Current version is 2nd edition 2009
API 581 Risk based inspection technology. Current version is 2nd edition 2008
Flaw assessment:
BS 7910 2005 Guide to methods for assessing the acceptability of flaws in metallic
structures Fitness for purpose:
Fitness for service
API 579-1 Fitness for Service current version is 2nd edition, 2007
DNV RP F101 Corroded pipelines. Current version 2010
The emerging ASME Post Construction codes are likely to provide useful benchmarks for
inspection planning, flaw evaluation, repair, and testing.
2. Where a standard or code of practice other than those listed above has been employed,
udgement as to the adequacy of alternative measures can only be assessed on an individual basis,and the duty holder should be required to provide an engineering justification of how an equivalent
level of health and safety performance is delivered.
The avoidance of loss of containment relies primarily on the integrity of the containment in which
the hydrocarbons are held. The issue of mechanical integrity can itself be subdivided into issues of
initial integrity and continuing integrity.
2.1 Initial integrity
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Adequate initial integrity is delivered by adherence to suitable design principles, often embodied in
codes and standards. Full consideration should be taken of design details, operating and fault
conditions, material properties and potential failure modes. Related issues include the provision of
protective systems. Delivery of the design intent is provided by suitable quality controls on
manufacture followed by appropriate inspection and testing.
Adequate initial integrity is ensured by adherence to the following engineering principles.
Risks implicit in the design should be identified. [APOSC 91]
Engineering design should seek to minimise risk and adopt a hierarchical approach [APOSC
92 & 98]
Appropriate industry standards should be used.
Engineering structures important to safety should maintain their integrity through life,
requiring a demonstration that normal operating loads and foreseeable extreme loads have
been quantified.
The materials used should be suitable. [APOSC 95]
Active safety features should have demonstrably adequate reliability, availability and
survivability
2.2 In-service Integrity
Following a consideration of the initial integrity, attention must be turned to the continuing integrity
of the containment, throughout its service life. This is ensured by; operating the plant within the
limits for which it was designed; by carrying out appropriate maintenance and through periodicexamination by a competent person, to identify significant inservice degradation. Also, procedures
must be in place to ensure that modifications to the plant will not compromise the integrity of the
containment. Finally, the duty holder needs to be sure that the assumptions made at the design
stage are still valid. For example, a change of usage may lead to faster corrosion/erosion rates and
different applied loads may invalidate the design fatigue assessment. The effects of ageing need to
be considered to ensure that the inspection regime addresses all of the deterioration modes taking
place.
3. Relevant Legislation, ACOP and Guidance includes:
Offshore Installations (Safety Case) Regulations 2005, Regulations 12(1)(c) & 12(1)(d) &
Schedules
Offshore Installations (Prevention of Fire and Explosion, and Emergency Response)
Regulations 1995, Regulations 9 and 19
Provision and Use of Work Equipment Regulations 1998, Regulations 4, 5 and 6
Lifting Operations and Lifting Equipment Regulations 1998, Regulations 8 and 9
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Pressure Equipment Regulations 1999, Regulations 7 and 10
Assessment Principles for Offshore Safety Cases [APOSC] 14, 16, 35, 41, 91, 92, 95, & 98
4. Specific technical issues:
Relevant initiators and potential failure mechanisms are identified below:
4.1 Primary & Secondary Loads
Primary loads typically include design pressure and self-weight etc. Secondary loads typically
include thermal loads and equipment displacements etc. Adherence to the relevant design codes
and standards should ensure that the pressure systems are adequately designed for primary and
secondary loads.
4.1.1 Overpressure [Initiator G3]
Pressure system should be designed for maximum and, where relevant, the minimum anticipated
operating pressure under all modes of operation. It needs to be borne in mind that the maximumoperating pressure may not occur during the normal mode of operation. Designing equipment and
systems to the maximum pressure to which it can be subjected can have advantages in simplifying
plant by reducing or eliminating protection or relief systems. Based on established design
pressures, the facilities should be protected with recognised relief devices discharging to suitable
disposal or an instrumented high integrity protection system or a combination of both. The latter
subject is covered in F16. Possible sources of overpressure need to be identified and allowed for.
Issues for Safety Case Assessment
It should be established whether provision against over pressurisation is provided by active
measures, such as pressure relief and control systems, or is dependent upon the strength of the
component itself. Later in life, plant changes may necessitate reassessment.
When overpressurisation is a foreseeable event, the consequences should be considered. The
nature of the failure should be determinable, ie whether a leak or a catastrophic failure could result.
Further assessment of consequence could include assessment of the hazards posed by any
release.
4.1.2 Risers and Topsides Pressure Rating [Initiator F15]
It is normal practice in offshore industry to use different design codes for the design of topside
piping and risers. Risers are normally designed to pipeline design codes, such as BS 8010 and
topside piping is normally designed to piping code ASME B31.3 2010. Both the codes use different
factor of safety in the design of pressure systems for primary and secondary loads. Hence it is
important that at the specification break between riser and topside piping the pressure rating on
both sides, ie riser and topside, is compatible.
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Issues for Safety Case Assessment
It should be established that specification break made between topside piping and a riser is made
at appropriate location so that the design requirements of respective design codes are satisfied.
4.1.3 Under-Pressurisation [Initiator G5]
Underpressure events also have the potential to cause failures i.e. by implosion if the under-
pressure that results is below atmospheric pressure [vacuum conditions]. Normally, integrity isassured by adherence to a recognised design code.
4.1.4 External Loads and Structural Support Failure [Initiators G21 & G29]
Lack of consideration of pipe supports and movement of piping and connected equipment at the
design phase can result in failure of supports, leakage at flanged joints and overloading of sensitive
equipment such as pumps and compressors etc.
External loads could come from a disturbance of the structure itself, ie a partial failure or relativedisplacements. External movements may result from vessel movements [FPSO] or wind sway, eg
piping supported from a tall slender tower or temperature changes in connected equipment. Loads
due to such movements need to be considered and adequate flexibility should be provided within
the pipework.
For floating vessels, the motion may well contribute significantly to the fatigue load
Issues for Safety Case Assessment
Confirmation that external loads acting on the pressure system have been considered and allowed
for in the mechanical design.
4.1.5 Inadequate Installation [Initiator G10]
Inadequate installation of plant is a significant source of engineering failure. Deficiencies include
misalignment of mating parts, incorrect welding and jointing procedures, inadequate inspection, and
the omission of certain parts of the overall commissioning process, such as pressure testing.
Commissioning procedures should be in place to ensure that installed pressure equipment is
inspected before use to identify any design faults that may have been introduced at the construction
stage and to confirm suitability for use.
Issues for Safety Case Assessment
Does the duty holder have an effective safety management system for installation and modification
of plant.
4.1.6 Seismic Event [Initiator G18]
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If seismic events are deemed a possibility, then in principle the effects can be included as a design
load case. In such a situation, the response of the structure will have been calculated and the
resultant motion would have to be imposed on the hydrocarbon containment system.
Issues for Safety Case Assessment
Whether seismic assessment has been carried out at the design stage.
4.2 Occasional Loads
These include slugging, water hammer, wind, sloshing and liquid slam, etc [G27 & G28].
During design, the operation of each piping system needs to be clearly understood not only under
normal conditions but also those conditions arising during start up, shutdown and as a result of
process upsets.
The dynamic loads produced by the movement of fluids within a pressurised system can be
considerable. Excitation from valve slams or from flow instabilities has been known to be a sourceof severe vibration.
Issues for Safety Case Assessment
The safety case should make it clear that occasional loads have been considered during the design
phase.
4.3 Degradation in Service
4.3.1 Corrosion
Please refer to generic sheets G1 Parts 1 & 2 & F6.
Piping containing hydrocarbons should avoid 'dead legs' and be designed to facilitate drainage to
prevent trapping of fluid.
4.3.2 Erosion
Please refer to generic sheets G2 & F6.
4.3.3 Fatigue/Vibration Cracking G6]
Fatigue is a damage mechanism by which cracks can propagate in a structure under the influence
of repeated cycles of stress well below the level capable of causing general yielding. Fatigue is
often characterised as occurring in two phases, the first is that of initiation, i.e. from manufacture up
to the point where a detectable crack is present. The second is the phase of defect growth, where
propagation from the point of detectability to the point of failure occurs.
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Fatigue is addressed initially at the design stage. There are a number of methodologies by which
this can be done. However we note that for plant with a limited fatigue load, the codes normally
provide for the exclusion of a full analysis, providing that certain preconditions can be met, i.e. it is
established that there will only be a limited number of full pressure cycles etc.
In general though, the fatigue loads from all sources of repetitive stress have to be characterised
both in terms of the stress amplitude and their number. This can be used to determine a fatigue
lifetime for the component.
Issues for Safety Case Assessment
The importance of fatigue as a potential failure mechanism varies greatly according to the type of
duty a pressure vessel or piping system is subjected to. However, in an environment where
installations are increasingly being used beyond its original design lifetime, there are important
issues as to whether the plant is still within its original fatigue life. For older plant, the duty holder
could be questioned as to the current validity of the original fatigue calculations.
Experience has shown that fluid induced vibration is a significant cause of failure in offshore
pressure systems, affecting both vessels and piping. Such type of vibration is perhaps somewhat
difficult to treat within design codes. Further guidance on this topic is provided in:
Guidelines for the avoidance of vibration induced fatigue failure in process pipework published by
the Energy Institute
It is a reasonable question to ask how the duty holder assures the integrity of plant against this
source of fatigue.
4.3.4 Seal/Gasket/Compression Fitting Failure G8]
A suitable demonstration should be provided for the integrity of joints and seals where failure could
lead to a release of hydrocarbons. General information should be provided to indicate that flanges
and other joints have been adequately designed and properly made to avoid flammable and toxic
hazards. Further guidance is available in Guidelines for the management of the integrity of bolted
oints for pressurised systems published by the Energy Institute.
4.3.5 Fully Welded Topside Pipework in Critical Areas [F18 & F9]
The use of fully welded pipework topside is one of the approaches to adhere to the principle of
inherently safer design. However, for ease of access for operation, inspection, maintenance and
repairs, it is not possible to have fully welded pipework everywhere on topside plant. The duty
holder should avoid routing of pipework containing hazardous fluid through non hazardous area. If
this is unavoidable then pipework shall be all welded [no flanges] and not located in a vulnerable
position where it may be mechanically damaged.
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Issues for Safety Case Assessment
It should be established in the safety case that as far as possible hydrocarbon pipework in non-
hazardous areas is fully welded.
4.4 Materials
Materials chosen should be suitable for the application in terms of the process fluid, environment
and applied loading.
4.4.1 Incorrect Material Specification
Please refer to G24 regarding issues relating to incorrect material specification. Issues relating to
incorrect material usage [G25] are addressed by ensuring that pressurised equipment is designed
and manufactured in accordance with a recognised design standard as indicated in Section
1above.
4.4.2 Brittle Fracture
The prevention of brittle fracture is addressed within design codes. Prevention involves the correct
choice of materials, operation within strict temperature/pressure limits and monitoring ageing
phenomena such as embrittlement. Ferritic steels are subject to a ductile to brittle transition as
temperature decreases, rendering them highly vulnerable to brittle fracture when cold. Transition
temperatures vary, but are typically below ambient values for offshore applications. Ageing though
can lead to a shift in the transition temperature and render components more susceptible to brittle
fracture. Austenitic steels remain ductile at low temperatures and may be preferred for application
such as blowdown lines.
Brittle fracture is possible whenever low temperatures are involved, in particular low temperatures
associated with gas expansion. This is particularly the case when systems are still pressurised,
although in some circumstances, the differential stresses through the wall of a vessel by sudden
cooling could lead to crack propagation.
Issues for Safety Case Assessment
Choice of materials.
Identification of vulnerable components.
4.4.3 Ageing/Mechanical Degradation [G20]
The effect of ageing is undoubtedly one of the major integrity issues facing the older installations.
Ageing encompasses degradation mechanisms such as fatigue and corrosion. There are also some
other phenomena, for example creep and the deterioration in mechanical properties such as
fracture toughness. The latter phenomenon is associated with changes in transition temperatures.
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Provision against these mechanisms is explicitly required, as part of the design criteria and
operational monitoring exists for the express purpose of detecting these phenomena.
Nevertheless, ageing related failures are occurring. The implication of this is that either plant is
being operated beyond its original design life, that conditions have changed because modification
has rendered the initial assumptions invalid or that inspection regimes are inadequate.
In recent years, the popularity of risk-based inspection schemes has led to situations where
inspection intervals have been lengthened for some plant. Where such decisions have been made,
the requirements on the knowledge about plant state are high.
Issues for Safety Case Assessment
As for fatigue, corrosion and other degradation phenomena above; including:
Whether initial design assumptions are still valid.
Whether modifications have had their implications on lifetime assessed.
Whether the inspection regime is adequate.
The adequacy of the duty holders piping repair policy to take account of HSE Safety Notice 4/2005
Weldless repair of safety critical piping and ISO TS 24817 Composite repairs for pipework
Qualification and design, installation, testing and inspection for composite repairs.
4.5 Dropped Loads G17]
Major hazards assessed are the impact of dropped loads onto hydrocarbon containment plant and
or accommodation areas. Protection essentially relies upon having an effective safety management
system.
Typical benchmarks employed include:
HSG221 Technical guidance on the safe use of lifting equipment offshore
BS 7121-2 & 11 Code of practice for the safe use of cranes
Step Change lifting and mechanical handling guidelines
OGP 376 Lifting and hoisting safety recommended practice
OPITO Training and competency assessment standards for crane operators, riggers, and
banksmen / slingers
OMHEC Practical guidance on communications for safe lifting and hoisting operations
HSE Safety Notice 2/2005 Single line components in the hoisting and braking systems of
offshore cranes
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Issues for Safety Case Assessment
Plans showing crane over sail area and identification of areas where pipelines, HC piping and
vessels and accommodation units are vulnerable to dropped loads and or boom collapse.
References to dropped object/load impact studies and their conclusions. Provision of protective
barriers on vulnerable areas.
Description of cranes and lifting machinery including safe working load, de-rating for prevailing sea
state, and rated capacity indicator.
Details of the arrangements for maintenance and thorough examination of cranes including details
of structured engineering studies (e.g. FMECA) to give assurance that maintenance address ageing
issues
Details of how competence is assessed for crane operators, banskmen, slingers and for those
responsible for planning lifting operations.
Evidence that lifting operations are planned and assistance is available to identify and plan non-
routine lifts.
Personnel transfer using cranes and carriers
Some designs of carriers used for personnel transfer between an installation and vessel can
accommodate more than four persons. This introduces a new major accident hazard that must be
addressed in the safety case.
Typical benchmarks employed include:
HSE Offshore Information Sheet 1/2007 Guidance on procedures for the transfer of
personnel by carriers
Emerging guidance on lifting of persons from OMHEC
Issues for Safety Case Assessment
An assessment of how this major accident risk is addressed describing the control measures
in place to ensure the suitability of crane, suitability of the carrier, procedural controlsincluding recovery from the sea and competency.
5. Other Related Assessment Sheets in this Section are:
G1 Part 1 Corrosion: Internal
G1 Part 2 Corrosion: External
G2 Erosion
G18 Seismic Event
F16 High Integrity Protection Systems [HIPS]
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HS2 Heat Exchangers
6. Cross-Referenced Sections and Sheets are:
Section 2.3.2 Loss of Containment - Pipelines
1. Confirmation should be obtained that heat exchangers have been designed, constructed in
accordance with recognised standards or codes of practice. Recognised standards/codes of
practice would include:
BS EN ISO 16812:2007 and API Standard 660 for shell & tube exchangers
BS EN ISO 15547-1:2005 and API Standard 662 for plate type heat exchangers
BS EN ISO 13706:2011 and API Std 661 for air cooled heat exchangers
BS EN ISO 13705:2006 and API Std 560 for fired heaters
TEMA Standards of the Tubular Exchanger Manufacturers Association are applicable for
tubular heat exchangers.
Pressure Vessel Design Codes applicable to heat exchangers:
PD 5500:2009 + A3: 2011 Specification for unfired fusion welded pressure vessels
BS EN 13445 Unfired pressure vessels
ASME VIII Boiler and pressure vessel code
Printed circuit heat exchangers [PCHEs] are normally designed to ASME VIII Division 1 but
other design codes such as PD 5500 can be employed as required by the purchaser.
API SPEC 12K Specification for Indirect Type Oil Field Heaters
2. Where a standard/code of practice other than those listed above has been employed,
udgement as to the adequacy of the heat exchange equipment can only be assessed on an
individual basis and the duty holder should be required to justify that the applied standard/code will
be equally effective.
3. Relevant Legislation, ACOP and Guidance includes:
Offshore Installations (Safety Case) Regulations 2005, Regulation 12(1)(c)
Assessment Principles for Offshore Safety Cases [APOSC] paras 14 and 35
Provision and Use of Work Equipment Regulations 1998 Regulation 4
4. Technical Issues:
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4.1 Shell and Tube Heat Exchangers
Flow induced tube vibration which results in thinning of the tubes can occur where the tubes pass
through the tube sheets. The possibility of this occurring should have been examined as part of the
design.
The provision of overpressure relief for tube failure should be considered when the design pressure
for the low pressure side of the exchanger is low compared to the design pressure of the high
pressure side. A specific 2/3 rule is no longer contained in API 521. 5 thedition - section 5.19 (Heat
transfer equipment failure). The section now states Loss of containment of the low pressure side to
atmosphere is unlikely to result from a tube rupture where the pressure in the low pressure side
(including upstream and downstream systems) during the tube rupture does not exceed the
corrected hydrotest pressure.
[NB: Old 2/3 rule The provision of overpressure relief for tube failure should be considered when
the design pressure for the low pressure side of the heat exchanger is less than 2/3 of the design
pressure of the high pressure side. The 2/3 rule was written in the context of ASME pressure
vessel codes for which the test pressure was typically 150% of the design pressure . The 2/3 rule
was dependent on the hydrotest pressure being typically 150% of the design pressure, some
vessels are now hydrotested to 130% of the design pressure when the rule would become the
10/13 rule].
Related guidance:
API RP 521 Guide for Pressure Relieving and Depressuring Systems. 5 th
ed, 2007 (includes2008 addendum). ISO 23251.
Guidelines for the Design and Safe Operation of Shell and Tube Heat Exchangers to
Withstand the Impact of Tube Failure, September 2000, ISBN 9780852932865
4.2 Printed Circuit Heat Exchangers
For PHCEs there is an issue with thermal cycling which has been known to have caused failure of
the integrity of the heat exchange matrix. This phenomenon is most likely to occur when the unit is
subjected to frequent start-ups and shutdowns. Confirmation should be sought that this has been
taken into account as part of the design process.
4.3 Gasketed Plate Heat Exchangers
There is a likelihood of significant hydrocarbon release to the atmosphere on gasket failure. Shields
should normally be fitted to prevent fluids from contacting personnel in the event of gasket failure.
There is a working pressure limitation for gasketed plate heat exchanger of approx 25 barg.
4.4 Brittle failure due to the formation of titanium hydrides
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HS3 Atmospheric Vessels (eg Wemcos, Tilted Plate Separators, Deck Tanks)
A particular design of shell and tube cooler with the tubesheet manufactured from titanium sheet
explosively bonded to steel suffered catastrophic failure due to the formation of titanium hydrides
when the interface was exposed to wet gas. HSE Safety Alert SA 1/2005 Catastrophic failure of
shell and tube production cooler.
4.5 Design Requirements for Heat Exchangers
The following would be expected in heat exchanger design:
a. protection against high internal pressure, e.g. tube failure,
b. appropriate design, selection and location of PSVs and bursting discs,
c. detection system for hydrocarbon leaks into heating or cooling medium,
d. safe discharge/disposal of leaking material,
5. Other Related Assessment Sheets in this Section are:
2.3.1.HS1 Pressure Vessels (Including Columns)
6. Cross-Referenced Sections and Sheets are:
None
1. Confirmation should be obtained that atmospheric vessels and their accessories have been
designed and constructed in accordance with recognised standards or codes of practice.
Recognised standards/codes of practice would include:
API Standard 2000 Venting Atmospheric and Low Pressure Storage Tanks; Non
Refrigerated and Refrigerated, 6th Edition, November 2009 (ISO 28300:2008 identical)
API Publication 2210 Flame Arresters for Vents of Tanks Storing Petroleum Products
BS EN ISO 16852:2010 Flame arrestors Performance requirements, test methods and
limits for use
API Bulletin 2521 Use of Pressure-Vacuum Vent Valves for Atmospheric Pressure Tanks to
Reduce Evaporation Loss
API Standard 620 Design and Construction of Large, Welded, Low Pressure Storage Tanks
API Standard 650 Welded Steel Tanks for Oil Storage
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API SPEC 12D Specification for Field Welded Tanks for Storage Production Liquids
API SPEC 12F Specification for Shop Welded Tanks for Storage of Production Liquids
API SPEC 12B Specification for Bolted Tanks for Storage of Production Liquids
API SPEC 12P Specification for Fibreglass Reinforced Plastic Tanks
BS 1564:1975 Specification for pressed steel sectional rectangular tanks
BS EN 14015:2004 Specification for the design and manufacture of site built, vertical,
cylindrical, flat-bottomed, above ground, welded, steel tanks for the storage of liquids at
ambient temperature and above (replaces BS 2654:1989)
Withdrawn BS 2654:1989 Specification for the manufacture of vertical steel welded non-
refrigerated storage tanks with butt-welded shells for the petroleum industry
3. Where a standard/code of practice other than those listed above has been employed,
udgement as to the adequacy of the atmospheric vessel can only be assessed on an individual
basis and the duty holder should be required to justify that the applied standard/code will be equally
effective.
4. Relevant Legislation, ACOP and Guidance includes:
Offshore Installations (Safety Case) Regulations 2005, Regulation 12(1)(c)
Assessment Principles for Offshore Safety Cases [APOSC] paras 14, 16 and 35
Provision and Use of Work Equipment Regulations 1998, Regulation 4
Offshore Information Sheet No 2/2010 - Reducing the risks of hazardous accumulations of
flammable/toxic gases in tanks and voids adjacent to cargo tanks on FPSO and FSU
installations
Loss of Containment Manual Part 9.4 - Inert Gas Controls/Cargo Tank Blanketing
5. Specific Technical Issues:
4.1 Venting for Fire Exposure and In/Out Breathing
It is likely that tanks installed on offshore installations will not be fitted with a frangible roof-to-shell
attachment for fire venting purposes. Where this is the case, confirmation should be sought that
venting capacity is adequate for fire exposure conditions.
API 2000 6th edition now includes new, more accurate, equations for normal venting as opposed to
fire exposure where the equations stay the same. The new normal venting equations deal with
inbreathing and outbreathing caused by liquid movements and thermal effects. However the old
normal venting methods are still valid and appear as an Annex of API 2000.
4.2 Bunding
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HS4 Centrifuges / Hydrocyclones
It should be clear that any decision as to whether tanks should be bunded or not has been made in
the light of a corresponding fire analysis.
4.3 The emergency dumping/draining of the flammable content of large tanks should have been
considered.
4.4 Consideration should have been given to minimising storage tank sizes and inventories as
part of a wider consideration of an inherently safer design features.
4.5 Methanol Storage Tanks
Provision should be made to limit the discharge of methanol vapour to atmosphere. For large
storage tanks, the provision of an inert gas blanket should have been considered.
4.6 Design Requirements for Atmospheric Vessels
The following would be expected in atmospheric vessel design:
a. appropriate venting arrangements, e.g. two independent adequately sized vents,
b. appropriate and adequate bunding.
6. Other Related Assessment Sheets in this Section are:
2.3.1.F14 Inherent Safety
7. Cross-Referenced Sections and Sheets are:
None
1. Confirmation should be obtained that centrifuges and hydrocyclones have been designed, and
constructed, in accordance with recognised standards or codes of practice. Recognised
standards/codes of practice would include:
PD 5500:2003 Specification for unfired fusion welded pressure vessels
BS EN 13445 Unfired pressure vessels
ASME VIII Boiler and pressure vessel code
2. Where a standard/code of practice other than those listed above has been employed,
udgement as to the adequacy of the centrifuge or hydrocyclone can only be assessed on an
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HS6 Smallbore Tubing
individual basis and the duty holder should be required to justify that the applied standard/code will
be equally effective.
3. Relevant Legislation, ACOP and Guidance includes:
Offshore Installations (Safety Case) Regulations 2005, Regulation 12(1)(c)
Assessment Principles for Offshore Safety Cases [APOSC] paras 14 and 35
Provision and Use of Work Equipment Regulations 1998, Regulation 4
4. Technical Issues:
None
5. Other Related Assessment Sheets in this Section are:
2.3.1.HS1 Pressure Vessels (Including Columns)
6. Cross-Referenced Sections and Sheets are:
None
1. Confirmation should be obtained that the design, installation and maintenance of smallbore
tubing is in accordance with recognised standards or codes of practice. Recognised
standards/codes of practice would include:
Guidelines for the management, design, installation and maintenance of small bore tubing
assemblies: Energy Institute.
2. Where a standard/code of practice other than that listed above has been employed, judgement
as to the adequacy can only be made on an individual basis and the duty holder should be required
to justify why equivalent standards of safety should result.
3. Relevant Legislation, ACOP and Guidance includes:
Offshore Installations (Safety Case) Regulations 2005, Regulation 12(1)(c)
Assessment Principles for Offshore Safety Cases [APOSC] paras 14 and 35
Provision and Use of Work Equipment Regulations 1998, Regulation 4
Loss of Containment Manual Part 2 Small bore piping and tubing systems
4. Specific Technical Issues:
None over and above those described in the referenced standard.
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HS8 Flexible Hoses
HS9 Pumps
HS10 Compressors
5. Other Related Assessment Sheets in this Section are:
None
6. Cross-Referenced Sections and Sheets are:
None
1. Confirmation should be sought that the design, specification and usage of flexible hoses used on
the installation is in accordance with a recognised standard or code of practice. Recognised
standards/codes of practice include:
Guidelines for the management of flexible hose assemblies: Energy Institute, Oil and Gas UK, HSE,
2nd edition, February 2011
2. Where a standard/code of practice other than that listed above has been employed, judgement
as to the adequacy can only be made on an individual basis and the duty holder should be required
to justify why equivalent standards of safety should result.
3. Relevant Legislation, ACOP and Guidance includes:
Offshore Installations (Safety Case) Regulations 2005, Regulation 12(1)(c)
Assessment Principles for Offshore Safety Cases [APOSC] paras 14 and 35
Loss of Containment Manual Part 2 Small bore piping and tubing systems
4. Specific Technical Issues:
None over and above those described in the referenced standard.
5. Other Related Assessment Sheets in this Section are:
None
6. Cross-referenced Sections and Sheets are:
None
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HS11 Turbines
[Relevant Sheets:G7, G19]
1. Introduction
This sheet is to provide guidance for safety case assessment for areas dealt with by the Mechanical
Systems Team OSD3.4. What follows is therefore generally applicable to the mechanical integrity
of machinery and rotating equipment. Aspects specific to hydrocarbon containment are dealt with
elsewhere. Similarly, process control and plant isolation requirements are not dealt with here.
The document is not intended to limit the scope of an assessor to pursue any aspect of safety that
they believe is important to a particular safety case, within the remit provided by the Safety Case
Regulations. It is though intended to provide guidance as to the minimum acceptable demonstration
of safety that a duty holder should be able to provide. As with all safety case assessment work,
there is a need for HSE assessors to concentrate on areas where there are grounds for believing
the safety demonstration may be weakest. Knowledge of such areas comes from HSEs collective
experience, as well as that of the wider engineering community. There is some guidance below that
provides pointers towards what are believed to be the most pressing concerns. Conversely, it is not
considered necessary or practical for a particular safety case to mention explicitly all of the aspects
of design and operational concerns identified below. However, the duty holder should in principle be
able to address all such concerns and hence provide an adequate demonstration of integrity.
Therefore, in the last resort, it is reasonable for an assessor to question a duty holder on any
aspect of the integrity justification.
2. Machinery and Rotating Equipment Integrity
Machinery and rotating equipment is often packaged together to form a single system. The
packages employ a combination of rotating equipment such as pumps, compressors and
generators, driven by a gas turbine or electric motor. Typical applications include:
Process and export gas compression
Oil export pumping
Fire water pumping
Utilities [electricity generation/compressed air]
Our main source of reference is HSEs Inspection Guidance Notes [IGN]: HSE Research report
076 Machinery and Rotating Equipment Integrity Inspection Guidance Notes.
The IGN provides technical guidance that focuses on commonly used equipment such as gas
compression and oil export packages, typical machinery including turbines, motors and diesel
engines, and rotating equipment such as pumps and compressors etc. The IGN provides an
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HS13 Gas Treatment Plant
understanding of the technology used and considers those aspects of design, operation and
maintenance that could contribute to a major offshore incident. The report also includes a
structured review to assist Inspectors gauge compliance with statutory requirements and it gives
examples of poor practice to look out for.
A comprehensive list of relevant standards is provided in Section 5.15 of the IGN.
Our main references for gas turbine safety include:
ISO 21789 Gas turbine applications - Safety
Offshore gas turbines (and major driven equipment) integrity and inspection guidance notes
HSE Research Report 430
Fire and explosion hazards in offshore gas turbines HSE Offshore Information Sheet
10/2008
3. Relevant Legislation, ACOP and Guidance Includes:
Offshore Installations (Safety Case) Regulations 2005, Regulation 12(1)(c)
Assessment Principles for Offshore Safety Cases [APOSC] paras 14 and 35
4. Specific Technical Issues:
None over and above those described in the referenced standard.
5. Other Related Assessment Sheets in this Section are:
None
6. Cross-Referenced Sections and Sheets are:
None
1. Confirmation should be obtained that gas (and oil) treatment processes and plant have been
designed and constructed in accordance with recognised standards or codes of practice.
Recognised standards/codes of practice for design of vessels, piping, valves, etc are given in other
sections of this chapter. However specific standards for treatment processes includes:
API RP 55 Conducting oil and gas producing and gas processing plant operations involving
hydrogen sulphide.
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EFC Pub 16 Guidelines on materials for carbon and low alloy steels for H2S containing
environments in oil and gas production
EFC Pub 17 Corrosion resistant alloys for oil and gas production Guidance on general
requirements and test methods for H2S service
EFC Pub 23 CO2corrosion control in oil and gas production
NACE MR0175 Sulphide stress cracking resistant materials for Oilfield Equipment
2. Where a standard/code of practice other than that listed above has been employed, judgement
as to the adequacy of the system can only be assessed on an individual basis and the duty holder
should be required to justify that the applied standard/code will be equally effective.
3. Relevant Legislation, ACOP and Guidance includes:
Offshore Installations (Safety Case) Regulations 2005, Regulations 12(1)(c)
Assessment Principles for Offshore Safety Cases [APOSC] Principle 4
Provision and use of Work Equipment Regulations 1998, Regulation 4
4. Specific Technical Issues:
4.1 Materials of construction, appropriate to the service conditions and composition of the
fluids, should be specified and used.
4.2 The consequences of a release of toxic material should be addressed and appropriate
control and mitigation measures should be outlined.
4.2 Adsorbent and absorbent materials may be used to treat the gas stream. These
substances (e.g. amine) may themselves give rise to hazards. The consequences of
breakthrough of substances (e.g. elevated levels of H2S) on the downstream plant should be
addressed.
5. Other Related Assessment Sheets in this Section are:
2.3.1.HS1 Pressure vessels
2.3.1.HS2 Heat exchangers
2.3.1.HS5 Piping
2.3.1.HS6 Small bore tubing
HS8 Flexible hoses
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HS15 Hazardous Drains / Caisson
HS9 Pumps
HS10 Compressors
HS17 Flare and vent towers
G1 Corrosion
G20 Ageing / material degradation
G24/25 Incorrect material specification and usage
F11 Size of release, speed of detection and effectiveness
F12 Dispersion
6. Cross-Referenced Sections and Sheets are:
None.
1. Confirmation should be obtained that the hazardous drains system and disposal caisson have
been designed and constructed in accordance with recognised standards or codes of practice.
Recognised standards/codes of practice include:
Pipework:
ANSI B31.3 Petroleum refinery piping
Sump Tanks & Disposal Caisson:
API Standard 2000 Venting Atmospheric and Low Pressure Storage Tanks; Non Refrigerated
and Refrigerated, 6th Edition, November 2009 (ISO 28300:2008 identical)
API Publication 2210 Flame Arrestors for vents of tanks Storing Petroleum products
2. Where a standard/code of practice other than that listed above has been employed, judgement
as to the adequacy of the hazardous drains system and disposal caisson can only be assessed on
an individual basis and the duty holder should be required to justify that the applied standard/code
will be equally effective.
3. Relevant Legislation, ACOP and Guidance includes:
Offshore Installations (Safety Case) Regulations 2005, Regulation 12(1)(c)
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Assessment Principles for Offshore Safety Cases [APOSC] paras 14 and 35
Loss of Containment Manual Part 8.6 Segregation of hazardous drains
4. Specific Technical Issues:
4.1 Flame Arrester
The hazardous drains sump tanks and disposal caisson will generally be vented to the atmospheric
vent header although, in some cases, a dedicated vent may be provided. In either case, the vent
should be fitted with a flame arrester designed to API 2210, ISO 16852 or equivalent.
4.2 Wave Action
The drains sump vent should be of sufficient capacity to accommodate the inbreathing and
outbreathing due to the rise and fall in liquid level as a result of wave action.
Dip pipes, within the caisson, should terminate at sufficient depth to ensure that they are
submerged at all times.
4.3 Dip Pipe Perforation
Dip pipes can be subjected to accelerated rates of corrosion at, or just below, the liquid level in the
caisson. Perforation resulting from such corrosion may result in the migration of hydrocarbon
vapour from the caisson into the drains system, [this has resulted in a number of hydrocarbon
releases]. Confirmation should be obtained that there is an inspection scheme in place to address
this phenomenon.
4.4 Inappropriate inter-connections
A number of hydrocarbon releases have resulted from poor design involving inappropriate
interconnections between the closed/flare system and the open drains. Plant blowdown then
causes gas to discharge from the open drains. Confirmation should be sought that this possibility
has been examined during the plant HAZOP studies.
4.5 Design Requirements for Open and Closed Drains
The following would be expected in open and closed drains design:
a. segregation of open and closed drains,
b. open drain systems are typically classified as hazardous and non-hazardous. It is important
that segregation of the drain systems is maintained at times and under all foreseeable
conditions to prevent migration of hydrocarbons into safe areas where they may present an
ignition risk,
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HS17 Flare and Vent Towers
c. maintaining appropriate slopes to achieve drainage,
d. dedicated closed drain vessel or appropriate integrity and segregation if flare vessel is used
as a drain drum,
e. isolation of drain points to prevent over-pressurisation of drain system from HP process
plants, e.g. spades or locked valves.
5. Other Related Assessment Sheets in this Section are:
None
6. Cross-Referenced Sections and Sheets are:
None
1. Confirmation should be obtained that flare towers have been designed and constructed in
accordance with recognised standards or code of practice. Recognised standards/codes of practice
include:
API Standard 521 American Petroleum Institute [5th edition January 2007] Pressure
Relieving and Depressurising Systems (ISO 23251 identical)
BS EN ISO 25457:2008: Flare details for general refinery and petrochemical service
The Institute of Petroleum [2001] Guidelines for the Safe and Optimum Design of
Hydrocarbon Pressure Relief and Blowdown Systems ISBN 0 85293 287 1
The above codes, standards and guidance are applicable to flare towers on both fixed installations
and FPSOs. Well test equipment on drilling installations is likely to have dedicated well test flare
booms.
2. Where a standard/code of practice other than that listed above has been employed, judgement
as to the adequacy of the flare tower can only be assessed on an individual basis, and the duty
holder should be required to justify why its procedures/practices in the relevant areas will deliver an
equivalent level of health and safety performance.
3. Relevant Legislation, ACOP and Guidance includes:
Offshore Installations (Safety Case) Regulations 2005, Regulation 12(1)(c)
Assessment Principles for Offshore Safety Cases [APOSC] paras 14 and 35
Loss of Containment Manual Part 5.5 Relief/blowdown/flare system integrity
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HS18 Mechanical Integrity of FPSO Mooring Turrets
4. Specific Technical Issues:
A review of lessons learned from past incidents is given in Section 6 of Institute of Petroleum
Guidelines for the Safe and Optimum Design of Hydrocarbon Pressure Relief and Blowdown
Systems. This guide includes checklists for assessment of relief and blowdown systems [pp 100-
102] for both designers and operators. The guide should be included as part of the assessment
process.
An overview of radiation exposure levels is given in Section 5.8 of theInstituteofPetroleum
Guidelinesfor the Safe and Optimum Design of Hydrocarbon Pressure Relief and Blowdown
Systems. Confirmation should be obtained that the suggested limits are not exceeded.
The Design Requirements for Relief, Vent and Flare Systems are covered as a specific technical
issue in section 2.3.1 F15 Relief Systems.
5. Other Related Assessment Sheets in this Section are:
2.3.1.F15 Relief Systems
6. Cross-Referenced Sections and Sheets are:
None.
[Relevant Sheets: G.9]
Introduction
1. Many floating production storage and offtake facilities [FPSOs] employ the principal of free
weathervaning of the hull round a geostationary mooring spread. For this purpose, the hull structure
is designed or modified to accommodate an internal turret to which static mooring lines are fixed
permitting unrestricted rotation of the vessel about that axis of fixation. The turret incorporates a
bearing arrangement similar to a crane slew ring to reduce friction and, also usually a high pressure
swivel system to permit and control the transfer of fluids from the stationary risers to the rotating
vessel and its processing and storage facilities.
The design and operational safety/integrity of the bearing and swivel arrangements are matters for
technical assessment by OSD Mechanical Specialists at the design safety case and operational
safety case stages. Other aspects such as integration of the turret with the hull structure and the
design/integrity of flowlines and flexible risers need to be addressed by respective specialist
sections.
2. Assessment Principles:
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i. There are no national or international standards or formal codes for the design of turrets or
swivels, although they draw heavily upon existing large low speed bearing design and fluid/gas
sealing technology. Each example to date is a bespoke engineering solution and the most
appropriate method of assessment therefore involves the basic principals of hazard identification,
FMEA, Risk Assessment and whether risks are controlled to ensure compliance with the relevant
statutory provisions.
ii. OSD3.4, to obtain the information necessary to approach the assessment task in a competent
and consistent manner, commissioned a technical survey of published information covering all
FPSO and FSO installations in theUKsector. From this information a practical and comprehensive
database was created called:
The FPSO Turret and Swivel Interactive Knowledge Base
The IKB provides the following principal reference facilities:
i. General description of turret systems
Ship structures
General systems and arrangements
Mooring systems and turret loadings
Scaffolding and support systems
Personnel
Construction standards
ii. Turret system design
Major components and boundaries
Turret transfer systems
Interfacing systems
iii. Fluid transfer systems
iv. Failure modes
v. Inspection and maintenance
vi. Examples of good and bad practice
This extensive register encompasses detail of all existing turret mooring designs and arrangements
existing inUKwaters. In addition it discusses in appropriate technical language the merits and
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weaknesses of respective systems and guides the reader first toward an appreciation of the
broader aspects of the technology, hazard identification and risk recognition processes, to a
position where specific examples may be subject to comparative appraisal against a cross industry
selection of design types and their operational characteristics and histories.
3. Relevant Legislation, ACOP and Guidance includes:
Offshore Installations (Safety Case) Regulations 2005, Regulation 12
Offshore Installations (Prevention of Fire and Explosion, and Emergency Response) Regulations
1995, Regulations 4, 5, 9 & 19
Offshore Installations and Wells (Design and Construction, etc) Regulations 1996, Regulations 4, 5,
6, 7 & 8
Failure modes, reliability and integrity of floating storage unit (FPSO,FSU) turret and swivel
systems HSE research report OTO 2001/073
4. For marginal field development the turret moored FPSO offers commercial attractions. Mooring
turrets clearly embody major hazard potentials including both the control of the transient hazardous
inventories within them and station keeping of the parent vessel. Full and intelligent use of the
FPSO turret database and application of its reflective appraisal procedures are the best means
available for assessing and evaluating both the design and the lifetime operational integrity of this
advanced production technology.
5. Other Related Assessment Sheets in this Section are:
For the purpose of this manual mooring turrets have been assigned to Section 2.3.1 - Loss of
Containment - Process. However, the turret is a multi functional design feature, its construction and
housing form an integral part of the vessel primary structure and the mooring system. Whilst these
considerations are the responsibility of structural and marine specialists, structural strength and
especially stiffness are of paramount importance to the performance of the turret bearings, seals
and flanged joints. Consequently there are at least three safety critical elements to be assessed in
relation to the turret, namely integrity of primary and support structure, mooring integrity and the
integrity of fluid paths [flexible risers, swivels and rigid pipework]. It is therefore desirable that the
assessment of turret design and operational issues should be undertaken on a multi discipline basis
with input from OSD5 and other OSD3 Specialist Teams.
6. Cross-Referenced Sections and Sheets are:
None
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HS19 Temporary Equipment
1. Confirmation should be obtained that systems and procedures are in place to manage the risks
associated with the use of temporary equipment. These should be broadly in line with the guidance
given in SPC/TECH/OSD/25.
Confirmation should also be obtained that all temporary equipment has been designed and
constructed in accordance with recognised standards or codes of practice, or if not, justification
sought as to why the standard(s) employed should result in equivalent levels of safety.
2. Where systems and procedures differ markedly from those recommended in
SPC/TECH/OSD/25, judgement as to the adequacy of the management of risks associated with the
temporary equipment can only be assessed on an individual basis and the duty holder should be
required to justify that the applied systems and procedures will be equally effective.
3. Relevant Legislation, ACOP and Guidance includes:
Offshore Installations (Safety Case) Regulations 2005, Regulation 12(1)(c)
Assessment Principles for Offshore Safety Cases [APOSC], paras 14 and 35
Provision and Use of Work Equipment Regulations 1998, Regulation 4
4. Specific Technical Issues:
4.1 Deciding what is, and is not, temporary equipment
Essentially Temporary Equipment compromises equipment which is not a permanent part of the
installation, and which is intended to be removed after a finite period of time.
4.2 Impact of temporary equipment on existing plant/systems
A HAZID and HAZOP should have been conducted to ensure that the Temporary Equipment will
not compromise the integrity of the existing plant and systems [and vice versa].
4.3 Control of Change
There should be systems/procedures in place to control short term amendments to existing
procedures/documentation. The systems/procedures should cover the re-instatement of amended
material.
4.4 Competence and Training
Temporary training requirements need to be identified, recorded and implemented. Contractor
competence and training should be verified by the duty holder.
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G1 Part 1 Corrosion: Internal
4.5 Control of Contractors
The integration of systems/procedures will be required where the Contractors have their own
systems/procedures for the operation, control and maintenance of the temporary equipment.
5. Other Related Assessment Sheets in this Section are:
None
6. Cross-Referenced Sections and Sheets are:
None
Topsides Plant
1. Confirmation should be obtained that internal corrosion is being managed through
implementation of a corrosion management system. There are no recognised standards or codes of
practice that deal with the corrosion management system. Hence in co-operation with the offshore
industry CAPCIS have prepared the research report OTO 2001/044 Review of Corrosion
Management for Offshore Oil and Gas Processing for HSE, which provides guidance and examples
of best practice. This is considered to be the benchmark that duty holders corrosion management
system should satisfy. Recognised standards and codes of practice dealing with certain specificelements of corrosion management include:
DnV RP G-101 Risk Based Inspection of Topsides Static Mechanical Equipment
API Publication 581 Risk Based Inspection
HSE RR363/2001 Best Practice for risk based inspection as part of integrity management
RIMAP Generic Risk Based Inspection and Maintenance Planning
NORSOK standard M-506 CO2 Corrosion Rate Calculation Model
NORSOK Standard M-CR-505 Corrosion Monitoring Design
NACE Standard RP0775 Preparation and Installation of Corrosion Coupons and
Interpretation of Test Data in Oil Field Operations
NACE Standard RP0497 Field Corrosion Evaluation Using Metallic Test Specimens
NACE Standard RP0192 Monitoring Corrosion In Oil & Gas Production with Iron Counts
ASTM G4 Standard Guide for Conducting Corrosion Coupon Tests in Field Application
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ASTM G96 Standard Guide for On-line Monitoring of Corrosion in Plant Equipment
[Electrical and Electrochemical Methods]
InstituteofPetroleumModel Code of Safe Practice for Petroleum Industry Part 13: Pressure
Piping Systems Examination
InstituteofPetroleumModel Code of Safe Practice for Petroleum Industry Part 12: Pressure
Vessel Systems Examination
EEMUA 193 Recommendations for the Training, Development and CompetencyAssessment of Inspection Personnel
EEMUA 179 A Working Guide for Carbon Steel Equipment in Wet H2S Service [Developed
largely from Oil Refinery experience]
API RP574 Inspection Practices for Piping System Codes
API RP570 Piping Inspection Code: Inspection, repair, alteration and re-rating of in-service
piping systems
API RP510 Pressure vessel inspection code: Maintenance inspection, rating, repair, and
alteration
2. Where a standard/code of practice other than those listed above has been employed,
udgement as to the adequacy of corrosion management can only be assessed on an individual
basis, and the duty holder should be required to justify why its procedures/practices in the relevant
areas will deliver an equivalent level of health and safety performance.
3. Relevant Legislation, ACOP and Guidance includes:
Offshore Installations (Safety Case) Regulations 2005, Regulations12(1)(c) and 12(1)(d)
Assessment Principles for Offshore Safety Cases [APOSC], paras 95, 98 and 102
Offshore Installations (Prevention of Fire and Explosion, and Emergency Response)
Regulations 1995, Regulations 4(1)(a); 9(b) and 12
Pressure Equipment Regulations 1999
4. Specific Technical Issues:
The safety case assessment should seek to establish to what extent aspects of the corrosion
management system listed below have been addressed particularly because experience has shown
them to be contributory factors in corrosion incidents:
Clear, explicit policy governing corrosion and plant monitoring.
Sufficient inhouse expertise, clear allocation of responsibilities and involvement of offshore
staff to enable delivery of the policy.
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Better analysis and integration of inspection and monitoring data including use of statistical
techniques to allow for uncertainties resulting from limitations of inspection techniques and
coverage.
Better use of opportunistic inspection.
Better documentation of system.
Increased utilisation of platform staff knowledge and raised awareness.
Widen scope of inspection plans that includes certain amount of speculative inspection.
Improved identification of corrosion hot spots based on plant walkabout rather then
examination of drawings.
Increased system performance monitoring and improved failure investigations that identify
underlying system failures.
Regular system reviews that includes assessment of system performance against set
criteria, evaluation of system failures and identification of areas to be improved.
Regular independent audits of the corrosion management system.
Ensuring high availability of inhibitor injection system.
Consideration of enhanced degradation near injection points due to local flow/environmental
conditions.
Planning of non-invasive inspection [NII] scheme based on considerations outlined in JIP
reports HOIS NII Decision Guidance, Mitsui Babcock GSP 235, Recommended Practice
for NII.
Minimisation of deadlegs and where unavoidable implementation of targeted inspection
scheme.
Identification of areas prone to pitting and application of the most appropriate inspection
techniques and prevention schemes including designing them out.
Identification of components that could suffer preferential weld corrosion and application of
appropriate specialised inspection techniques and prevention strategies. Further guidance in
JIP report Risk of preferential weldment corrosion of ferritic steels in CO2 containing
environments and the Guidelines for the prevention, control and monitoring of preferential
weld corrosion of ferritic steels in wet hydrocarbon production systems containing CO2.
Level of attention given to the hydrocarbon drains systems integrity management.
Special consideration of the failure mechanisms of smallbore piping [3 and below] and
application of appropriate inspection techniques.
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NORSOK standard M-501 Surface preparation and protective coatings
ISO 12944 Paints and Varnishes Corrosion Protection of Steel Structures
85 5493: 1977 Protective coating of iron and steel structures against corrosion.
EN ISO 14713: Protection against corrosion of iron and steel in structures - Metal coatings -
Guide.
EN ISO 1461: Hot dip galvanized coatings on fabricated products.
EN 10240: (Draft) Coatings for steel tubes: Specification for hot dip galvanized coatings.
ISO 4628-3: 1982 Paints and varnishes - Evaluation of degradation of paint coatings -
Designation of intensity, quantity and size of common types of defect - Part 3: Designation of
degree of rusting.
BS 7079: Part Al Preparation of steel substrates before application of paints and related
products - Visual assessment of surface cleanliness - Part 1: Rust grades and preparation
grades of uncoated steel substrates and of steel substrates after overall removal of previous
coatings.
ISO 9223: 1992 Corrosion of metals and alloys - Corrosivity of atmospheres - Classification.
ISO 11303:2002 Corrosion of metals and alloys - Guidelines for selection of protection
methods against atmospheric corrosion
EN 22063: 1993 Metallic and Other Inorganic Coatings - Thermal Spraying - Zinc, Aluminium
and Their Alloys
EEMUA 200 Guide to the specification, installation, maintenance of spring supports of piping
ISO CD 19902 Petroleum and natural gas industries Fixed offshore structures
2. Where a standard/code of practice other than those listed above has been employed,
udgement as to the adequacy of corrosion management system can only be assessed on an
individual basis, and the duty holder should be required to justify why its procedures/practices in the
relevant areas will deliver an equivalent level of health and safety performance.
3. Relevant Legislation, ACOP and Guidance includes:
Offshore Installations (Safety Case) Regulations 2005, Regulations 12(1)(c) and 12(1)(d
Assessment Principles for Offshore Safety Cases [APOSC] paras 95, 98 and 102
Offshore Installations (Prevention of Fire and Explosion, and Emergency Response) Regulations
1995, Regulations 4(1)(a), 9(b) & 12
Pressure Equipment Regulations 1999
4. Specific Technical Issues:
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G2 Erosion
External corrosion of topsides on an ageing installation does not usually receive the same degree
of attention as the management of the internal corrosion with the result that on a number of
installations the primary threat of hydrocarbon release is from external corrosion. In addition a
significant number of personnel injuries on such installations are due to falls and trips resulting from
failure of corroded members used as temporary supports or steps. Corroded walkways have also
featured in a number of incidents. Particular issues that should be probed as part of the safety case
assessment include:
Management of process plant integrity around corrosion traps such as pipe supports,
penetrations, saddles, etc.
Management of the risks associated with surface preparation and painting on live plant.
Management of corrosion under insulation.
Management of bolt corrosion.
Management of pitting and stress corrosion cracking in corrosion resistant alloy piping and
tubing operating in areas exposed to sea spray/deluge. See RR129 Review of externalStress Corrosion Cracking of 22% Cr Duplex Stainless Steel for further guidance.
Painting and refurbishment planning systems and performance standards including short
term remedies.
Maintenance of spring supports.
Corrosion management of walkways, hand railings, escape equipment attachment points
and other similar secondary structural components.
5. Other Related Assessment Sheets in this Section are:
G15 Deficient Procedures: Maintenance
G20 Ageing/Mechanical Degradation
G24 Incorrect Material Specification
G25 Incorrect Material Usage
6. Cross-Referenced Sections and Sheets are:
None
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1. Confirmation should be obtained that erosion is being managed through implementation of an
erosion management system that includes amongst other things selection of appropriate materials
and coatings, control of fluid velocities, removal/prevention of solid particles, effective detection
systems, plant design that minimises changes in flow direction and erosion resistant valve design.
Recognised standards/codes of practice dealing with erosion include:
DNV Recommended Practice RP 0501 Erosive Wear in Piping Systems
ISO 13703 Offshore Piping Systems
API RP14E Design and Installation of Offshore Production Platform Piping Systems
2. Where a standard/code of practice other than those listed above has been employed,
udgement as to the adequacy of erosion management system can only be assessed on an
individual basis, and the duty holder should be required to demonstrate its procedures/practices in
the relevant areas will deliver an equivalent level of health and safety performance.
3. Relevant Legislation, ACOP and Guidance includes:
Offshore Installations (Safety Case) Regulations 2005, Regulations 12(1)(c) and 12(1)(d)
Assessment Principles for Offshore Safety Cases [APOSC], paras 95, 98 and 102
Offshore Installations (Prevention of Fire and Explosion, and Emergency Response) Regulations
1995, Regulations 4(1)(a), 9(b) and 12
Pressure Equipment Regulations 1999
4. Specific Technical Issues:
There have been a number of major hydrocarbon releases recently caused by solids particle
erosion where failure of a number of crucial control measures had occurred. Wall thinning is usually
very rapid and hence prevention rather then control should be the guiding principle. Operations staff
do not always appreciate the impact of the production rate on erosion risk. Prevention of erosion in
the production plant can be achieved by design whereas for well servicing and drilling operations
process management is usually the only available option. Erosion tends to be a localised effect
which means that a very good knowledge of the local rather then global flow velocities is required in
order to assess erosion risks. Sand detection systems have proved to have varying reliability and
hence their effectiveness should be explored as part of the assessment process.
Relevant guidance documents include:
RR115 Erosion in Elbows in Hydrocarbon Production systems: Review Document
SPC/TECH/OSD/19 Offshore Produced Sand Management
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G4 Internal explosion
5. Other Related Assessment Sheets in this Section are:
G1 Part 1 Corrosion: Internal
G1 Part 2 Corrosion: External
6. Cross-Referenced Sections and Sheets are:
None
1. Confirmation should be obtained that internal explosions have been assessed in accordance
with a recognised standard or code of practice. Recognised standards/codes of practice would
include:
HS025 Fire and Explosion Guidance, Oil and Gas UK/HSE 2007
Spouge, J, A Guide to Quantitative Risk Assessment for Offshore Installations, CMPT
(Centre for Marine and Petroleum Technology), 1999, Appendix IV Hydrocarbon event
consequence modelling (old)
BS EN ISO 13702:1999 Petroleum and Natural Gas Industries Control and Mitigation of
Fires and Explosions on Offshore Production Requirements and Guidelines.
The following document provides useful information but is based on a different regulatory regime,
so should be used with care to ensure consistency withUKlegislation:
VROM, Guidelines for quantitative risk assessment, Purple Book section 5, 2005
2. Where a standard/code of practice other than those listed above has been employed,
udgement as to the adequacy of the evaluation of the internal explosion hazard can only be
assessed on an individual basis, and the duty holder should be required to justify why its
procedures/ practices in the relevant areas will deliver an equivalent level of health and safety
performance.
3. Relevant Legislation, ACOP and Guidance include:
Offshore Installations (Safety Case) Regulations 2005
Offshore Installations (Prevention of Fire and Explosion, and Emergency Response)
Regulations 1995
Fire, Explosion and Risk Assessment Topic Guidance
http://www.hse.gov.uk/foi/internalops/hid/manuals/pmtech12.pdf
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Fire and Explosion Strategy Document http://www.hse.gov.uk/offshore/strategy/index.htm
OTN 95 196 1995 Gas explosion handbook HSE-OSD report
Loss Of Containment Manual Part 8.5 Air ingress and flammable mixtures
http://www.hse.gov.uk/offshore/loss-of-containment-manual%202012.pdf
4. Specific Technical Issues:
4.1 Internal explosions are regarded as a lower risk factor in comparison to topsides external
explosions. Specific attention should be paid to situations whereby air could ingress into a
hydrocarbon-saturated atmosphere and form a flammable air/vapour mixture. The risk from a gas
turbine sourced internal explosion should be assessed with particular emphasis on fuel/air control,
emergency shutdown control and internal conditions that could give rise to volumes of un-ignited
fuel air mixtures.
The adequacy of Internal Explosion venting available in each engine installation should also be
investigated.
4.2 Protection against air ingress and flammable mixtures in process
Flammable mixtures can form in piping, plant and equipment when air enters systems that normally
contain hydrocarbon, as a result of operational or maintenance activities. Correct purging and
operational procedures will ensure that the risks are minimised.
5. Other related assessment sheets in this Section are:
None
6. Cross-referenced Sections and sheets are:
Sheet HS9 Pumps
Sheet HS10 Compressors
Sheet HS11 Turbines
Sheet F3 Installation Specific Hazard Studies
Sheet F8 Safety Integrity Levels Standards
Sheet F23 Fire/Smoke/Gas/Flame Detectors/Alarms
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1. Confirmation should be obtained that requirements for the identification of fire hazards as
initiators to other hazardous events have been analysed in accordance with recognised standards
or codes of practice that would be used for a manned installation. Recognised standards/codes of
practice would include:
BS EN ISO 13702:1999 Petroleum and Natural Gas Industries Control and mitigation of
fires and explosions on offshore production installations requirements and guidelines.
Spouge, J, A Guide to Quantitative Risk Assessment for Offshore Installations, CMPT(Centre for Marine and Petroleum Technology), 1999, Appendix IV Hydrocarbon event
consequence modelling (old)
The following document provides useful information but is based on a different regulatory
regime, so should be used with care to en
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