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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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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


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.


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.


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.


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.


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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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.


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.


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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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


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



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.


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,


2.3.1.HS1 Pressure Vessels (Including Columns)


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


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.



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.


2.3.1.F14 Inherent Safety


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




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.





4. Technical Issues:

None


2.3.1.HS1 Pressure Vessels (Including Columns)


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.





Loss of Containment Manual Part 2 Small bore piping and tubing systems


None over and above those described in the referenced standard.


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HS8 Flexible Hoses

HS9 Pumps

HS10 Compressors


None


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


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.




Loss of Containment Manual Part 2 Small bore piping and tubing systems




None

6. Cross-referenced Sections and Sheets are:

None


26/76

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


27/76

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:






None


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


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.


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


4.1 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.


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


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


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.




30/76


Loss of Containment Manual Part 8.6 Segregation of hazardous drains


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.


None


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.


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.




Loss of Containment Manual Part 5.5 Relief/blowdown/flare system integrity


32/76

HS18 Mechanical Integrity of FPSO Mooring Turrets


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.


2.3.1.F15 Relief Systems


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


34/76

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.


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.


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.


None


35/76

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.



Assessment Principles for Offshore Safety Cases [APOSC], paras 14 and 35



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.


36/76


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.


None


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


37/76

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


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.


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


Regulations 1995, Regulations 4(1)(a); 9(b) and 12

Pressure Equipment Regulations 1999


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.


38/76

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.


39/76


40/76

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


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.


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


1995, Regulations 4(1)(a), 9(b) & 12




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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.


G15 Deficient Procedures: Maintenance

G20 Ageing/Mechanical Degradation

G24 Incorrect Material Specification

G25 Incorrect Material Usage


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


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.


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


1995, Regulations 4(1)(a), 9(b) and 12



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



G1 Part 2 Corrosion: External


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


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


Regulations 1995

Fire, Explosion and Risk Assessment Topic Guidance

http://www.hse.gov.uk/foi/internalops/hid/manuals/pmtech12.pdf


44/76G7 Fire

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


4.1 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

Documents

Loc Process