Onshore Pipeline Quantified Risk Assessment

8/21/2019 Onshore Pipeline Quantified Risk Assessment

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ALLSEAS ENGINEERING BV

SHELL E&P IRELAND LIMITED

CORRIB FIELD DEVELOPMENT PROJ ECT (PHASE II)

CONTRACT NO. 101.24.14

DOCUMENT TITLE: ONSHORE PIPELINE QUANTIFIEDRISK ASSESSMENT

ALLSEAS DOCUMENT NUMBER : 368821/D835-01

J PKENNY DOCUMENT NUMBER : 05-2102-02-F-3-835

Rev.

Date Revision Details Originator Interdisc.Check

AllseasApproved

ClientApproved

F 22/04/2005 Re-Approved for Design J PK RRij J avB


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Internal Revision Control

Revision Date Revision Details Revised by

0 22/06/01 Draft Issue for Comments J PK

1 20/08/01 Issued for Comment J PK

2 30/10/01 Issued for Approval J PK

3 11/02/02 Approved for Design J PK

4 02/07/02 Re-Approved for Design J PK

5 22/04/05 Major revision following peer review J PK

External Revision Control

Rev. Date Revision Details Revised by

A 04/07/01 For Client Review GD

B 23/08/01 For Client Review/Comments GD

C 06/11/01 For Client Approval GD

D 15/02/02 Approved for Design GD

E 04/07/02 Re-Approved for Design GD

F 22/04/05 Re- Approved for Design J avB

© Copyright Allseas

This document is the property of Allseas and may contain confidential and proprietary information. It may not be used for anypurpose other than that for which it is supplied. This document may not be wholly or partly disclosed, copied, duplicated or inany way made use of without prior written approval of Allseas.


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CORRIB FIELD DEVELOPMENT PROJECT

Onshore Pipeline Quantified Risk Assessment

g:\052377- enterprisecorrib additional work\ctr 140 - qra update\02-f-3-835- rev 05 - qra.doc Page 2 of 58

TABLE OF CONTENTS

1 INTRODUCTION...................................................................................................................4

1.1 General..................................................................................................................... 4 1.2 Scope........................................................................................................................4 1.3 Purpose ....................................................................................................................4 1.4 Abbreviations ........................................................................................................... 5

2 SUMMARY...........................................................................................................................6

3 ONSHORE PIPELINE DESCRIPTION ................................................................................... 9

3.1 General..................................................................................................................... 9 3.2 Routing .....................................................................................................................9 3.3 Operational Parameters............................................................................................ 9 3.4 Well Fluids Analysis............................................................................................... 10 3.5 Design Life .............................................................................................................. 10

3.6 Materials................................................................................................................. 10 3.7 Diameter and Wall Thickness ................................................................................. 10 3.8 Depth of Cover........................................................................................................ 10 3.9 Crossings ............................................................................................................... 10 3.10 Corrosion Allowance .............................................................................................. 11 3.11 Coatings ................................................................................................................. 11 3.12 Inhibitors................................................................................................................ 11 3.13 Cathodic Protection................................................................................................ 11 3.14 Pigging ................................................................................................................... 11

4 METHODOLOGY................................................................................................................ 12

4.1 General................................................................................................................... 12 4.2 Hazard Identification............................................................................................... 12

4.3 Risk Assessment .................................................................................................... 12 4.3.1 Qual i t at ive and Quan ti tat iv e A ss essm ent ... . .. . . . .. . . . .. . . . .. . . . .. . . . .. . . . .. . . .. . . . .. . . . .. . 12 4.3.2 Co ns equ enc e Anal ys is ............................................................................... 12

5 DATA AND ASSUMPTIONS ............................................................................................... 14

5.1 General................................................................................................................... 14 5.2 Population Density ................................................................................................. 14

5.2.1 Ar ea Classi fic atio n ...................................................................................... 14 5.2.2 Buil di ng s Lo cat io ns .................................................................................... 14

5.3 Release Frequencies.............................................................................................. 14 5.3.1 Hist ori cal Data ............................................................................................ 14 5.3.2 Pro bab il i st ic Mo del s................................................................................... 15

5.4 Consequence Assessment ..................................................................................... 15

5.4.1 Releas e Mod ell in g....................................................................................... 15 5.4.2 Ignit ion ........................................................................................................ 16 5.5 Tolerability of Risk .................................................................................................. 18

5.5.1 Rep res ent ations of Risk ............................................................................. 18 5.5.2 Inter nati on al Ris k Cr iter ia ........................................................................... 19 5.5.3 Tolerabil i ty of risk ....................................................................................... 23

6 RISK ASSESSMENT .......................................................................................................... 24

6.1 Failure Modes......................................................................................................... 24 6.1.1 General ....................................................................................................... 24 6.1.2 Pres su re Con sid erat ion s ............................................................................ 24 6.1.3 Pres su re Cy cli ng ........................................................................................ 24 6.1.4 Pip eline / Umbili cal Sep aratio n ................................................................... 25

6.1.5 Thir d Party Interfer enc e .............................................................................. 26 6.1.6 Est uar y / Riv er Cros sin gs ........................................................................... 28


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6.1.7 Int ern al Ero sio n .......................................................................................... 28 6.1.8 Gr ou nd Mo vem ent ...................................................................................... 28 6.1.9 Ext ernal Co rro sio n ...................................................................................... 29 6.1.10 Inter nal Cor ro sio n....................................................................................... 30

6.1.11 Inherent Defects and Cons tru ctio n Defects ... . .. . . .. . . . .. . . . .. . . . .. . . . .. . . . .. . . . .. . . . .. . . . 32 6.2 Failure Frequencies................................................................................................ 34 6.3 Failure Consequences............................................................................................ 34

6.3.1 Release Rates ............................................................................................. 34 6.3.2 Fir e Model l in g ............................................................................................. 35 6.3.3 Dis per sio n m od ell in g .................................................................................. 37 6.3.4 Event tr ees.................................................................................................. 39

6.4 Estimated Risk........................................................................................................ 40 6.4.1 Ris k Tr ans ect s ............................................................................................ 40 6.4.2 Individ ual Risk at the Nearest Bu i lding .... .. . . .. . . . .. . . . .. . . . .. . . . .. . . . .. . . . .. . . .. . . . .. . . . .. . 42

7 DISCUSSION, CONCLUSIONS AND RECOMMENDATIONS ......... ........ ......... ........ ......... .... 43

7.1 Conclusions............................................................................................................ 43

7.2 Risk Reduction Measures....................................................................................... 43 7.2.1 Fit tin gs........................................................................................................ 43 7.2.2 Ext ern al Int erfer enc e .................................................................................. 43 7.2.3 Gr ou nd Mo vem ent ...................................................................................... 44 7.2.4 Dem on st rati on of ALA RP............................................................................ 44

7.3 Design at road crossings........................................................................................ 45 7.4 Recommendations.................................................................................................. 46 7.5 Implied Assumptions.............................................................................................. 47

8 REFERENCES (MAIN TEXT) .............................................................................................. 48

APPENDICES

APPENDIX A PROBABILISTIC MODELS FOR RELEASE FREQUENCY DUE TO EXTERNALINTERFERENCE


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1 INTRODUCTION

1.1 General

JP Kenny Ltd. (JPK) have been contracted by Allseas Construction Contractors S.A. toprepare the detailed design of the pipeline system for the Corrib Field development Project.

The Corrib Field, being developed by Shell E & P Ireland Ltd (SEPIL), (formerly EnterpriseEnergy Ireland Ltd), is a Triassic gas field located in 350 m of water some 60 to 65 km off the

County Mayo coastline. Corrib will be developed as a long-range subsea tieback to anonshore facility. The gas will then be treated to meet the defined gas specification beforeonward transportation to the Bord Gais Eireann (BGE) grid via a new cross-country pipeline.

The subsea facilities will consist of a manifold with cluster wells, together with a number ofsatellite wells. The pipeline comprises flexible flowlines from the satellite wells to themanifold, and an export line to shore. This 83km 20-inch subsea pipeline from the manifold

makes a landfall at Broadhaven Bay in County Mayo, and then a further 9 km onshorepipeline leads to the terminal. An electro-hydraulic umbilical system will run parallel to the

pipeline and a water outfall pipeline will also run from the terminal to a diffuser some distanceoffshore.

1.2 Scope

This document presents the Quantified Risk Assessment (QRA) for the onshore section of thegas pipeline. Revision 05 (JPK) has had extensive textual changes from rev 04 to update it inaccordance with the peer review. For clarity, no revision markers are included.

The QRA has assessed the risks associated with the operation of the onshore section of thepipeline only, i.e. the section of the pipeline between the mean low water mark and the firstisolation valve upstream of the pig receiver in the Bellanaboy Bridge terminal. Risks

associated with the operation of the pig receiver have been assessed in the terminal QRA.

Hazards resulting from failure of the umbilical and the water outfall pipeline have beenexamined and are excluded from the analysis (although failure of the umbilical and water

outfall caused by pipeline loss of containment are addressed later in the QRA).

1.3 Purpose

The purpose of this assessment is to predict the individual risk and potential loss of life tomembers of the public who might be affected by the operation of the onshore section of theCorrib gas pipeline. The QRA makes recommendations for risk reduction where appropriate,

and demonstrates that the residual risks associated with the operation of the onshore pipelinehave been reduced to levels which can be considered tolerable when compared withinternational standards.

The methodology used in this assessment is generally in accordance with the Project Risk Assessment Procedure [Ref. 1] in order to be compatible with risk assessment work to becarried out by other Contractors (e.g. the terminal contractors) and will allow the results to be

incorporated into an overall Project Safety Assessment.

All references and assumptions are stated. All mathematical models and formulae used are

documented.


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1.4 Abbreviations

ALARP As Low As Reasonably Practicable

BGE Bord Gais Eireann

CP Cathodic Protection

DOE Department of Environment

E&P Exploration and Production

EGIG European Gas pipeline Incident data Group

EPA Environmental Protection Agency

ESDV Emergency Shut Down Valve

FAR Fatal Accident Rate

FBE Fusion Bonded Epoxy

HAZID Hazard Identification

HSE (UK) Health and Safety Executive

ID Internal Diameter

IR Individual Risk

LFL Lower Flammable Limit

MIACC Major Industrial Accidents Council of Canada

NDT Non Destructive Testing

PARLOC Pipeline and Riser Loss of Containment

QRA Quantified or Quantitative Risk Assessment

SEP Surface Emissive Power

SEPIL Shell Exploration & Production Ireland Ltd

SMYS Specified Minimum Yield Strength

SRB Sulphate Reducing Bacteria

TDU Thermal Dose Unit

UKOPA United Kingdom Onshore Pipeline (Operators) Association

WHSIP Well Head Shut In Pressure


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2 SUMMARY

The prediction of risks to the public resulting from the operation of the onshore section of theCorrib gas pipeline indicates that the risks would be tolerable when compared with

international criteria and legislation on risk, for both the initial normal operating pressure of120 barg as well as the maximum pressure of 345 barg.

For the purposes of this assessment, a fatality is conservatively assumed to result for anyperson receiving a "dangerous" thermal dose or worse (where "dangerous" is actually definedas a 1% risk of fatality). The risk levels have been predicted using data and assumptions

which are considered to be conservative (i.e. to over-estimate rather than under-estimate therisk level where judgement was required).

Figure 2-1 and Figure 2-2 show the predicted levels of Individual Risk (IR) with increasing

distance from the pipeline for the normal (Fig 2-1) and maximum (Fig 2-2) operating pressure.The risk is highest immediately above the pipeline. Here the risks are 2.6*10

-7/yr (1 in 4

million per year) for the normal operating pressure of 120 bar and 5.7*10-7

/yr (1 in 2 million

per year) for the maximum pressure of 345 bar. The difference in risk level is a result ofconsequences of failure spreading over a larger distance, not an increase in failureprobability. See section 6.4.1 for further explanation of the effect of different pressure.

Figure 2-1: Risk Transects for 120 bar operating pressure

1.E-09

1.E-08

1.E-07

1.E-06

0 50 100 150 200 250Lateral distance (m)

F r e q u e n c y p e r y e a r


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Figure 2-2: Risk transects for pipeline at 345 bar (design pressure)

A pipeline isolation valve (Beach Valve) located at the landfall is included in the design toallow shutting off the onshore section of the pipeline from the much longer offshore section.However as casualties are more likely to occur during the early stages of an ignited release

the effect of isolation by the Beach Valve on the overall risk levels is negligible. Closing thevalve in the event of a leak reduces considerably the total duration of the release event (andthe total quantity of gas released), but this does not affect the predicted risk levels.

The current design of the Beach Valve has incorporated all of the recommendations made inthe earlier revisions of this QRA. The valve has been designed as an all-welded assembly,with no flanged connections or small bore valves or fittings in order to minimise the potential

for leaks at the valve itself.

A fully-welded connection will be used on the pipeline side of the ESDV at the inlet to theterminal to minimise leak paths at this location.

Pipeline hazards have been included in the assessment of Terminal workers risks performedin the Terminal QRA.

The following recommendations have been made as a result of the risk assessment process.These have been added to the overall project hazard register to ensure that they areaddressed and implemented as required.

• Plastic warning tapes should be installed in the ground above the pipeline, and pipelinemarkers should be installed at field boundaries, to deter external interference (Section

6.1.5.3);

• The first intelligent pigging run should be performed within 3 years of pipeline start-up.The timing of subsequent inspections should be based on the results of this initial run

(Section 6.1.9 & 6.1.10.2);

• Periodic analysis of the well fluids should be undertaken to determine H2S concentrationthroughout the field life (Section 6.1.10.1);

1.E-09

1.E-08

1.E-07

1.E-06

0 100 200 300 400

Lateral distance (m)

F r e q u e n c y p e r y e a r


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• Corrosion Inhibitor should be continuously injected, and operational safeguards should beimplemented to guarantee high system availability, in order to prevent excessive internalcorrosion (Section 6.1.10.2);

• An appropriate corrosion monitoring system should be implemented in order to identifyexcessive internal corrosion (Section 6.1.10.2);

• Consideration should be given to the means employed for leak detection and the ability todetect small leaks (Section 6.3.1.1).

• A design factor of 0.72, complete with concrete protection slabs, will be used for the roadcrossings (section 7.3)


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3 ONSHORE PIPELINE DESCRIPTION

3.1 General

Generally, the onshore section of the pipeline will be designed, constructed, tested andcommissioned in accordance with BS 8010 [Ref. 2] and the Onshore Design Basis [Ref. 6].The basis for selection of the onshore design code is described in the Design CodeComparison [Ref. 3]. The following sections provide an outline of the design features of the

onshore section of the pipeline, in order to provide a background to the discussion of failuremodes contained in Section 6.1.

BS 8010 has now officially been withdrawn and effectively replaced by PD 8010 Pt 1. It is

normal practice in long running project that the original design code and revision continues tobe used in its entirety. PD 8010 maintains the same requirements for this project as BS 8010.

3.2 Routing

The pipeline comes ashore at the Dooncarton landfall in Broadhaven Bay. From the landfall ittravels 0.65km across a small headland until it reaches the Sruwaddacon Bay estuary.

From Ross Port the route heads in a predominantly south-easterly direction along the northside of Sruwaddacon Bay. The majority of the land in this area is improved or semi-improvedpasture with occasional areas of peat. After a further 5km the route crosses the Glenamoy

River and then heads in a more easterly direction through a densely forested area underlainwith blanket bog until the proposed terminal site, near Bellanaboy Bridge, is reached. Thetotal length of the onshore section of the pipeline is approximately 9 km.

The following considerations have been taken into account when finalising the route of theonshore pipeline section:

• Increasing separation distances from buildings, developed areas and planned futuredevelopments as far as reasonably practicable;

• Minimising road, rail and water crossings and crossings of existing utilities andservices as far as reasonably practicable.

Note that location class is determined, in accordance with BS 8010, in the Population Density

Analysis [Ref. 4].

Special consideration is given in the design to the stabilisation of the pipeline in areas of bogand marshland, where these cannot be avoided.

Design proposals and construction methods have been checked against geological /geotechnical data for suitability. A specific study has been performed to consider the effect ofa peat slip or land slide and the analysis shows that the pipeline as designed can withstand

such events without rupture or leakage. [Ref 5]

3.3 Operational Parameters

The following information has been taken from the Design Basis [Ref. 6].

Design Flow Rate: 350 mmscfd

Maximum Flow Rate: 350 mmscfd

Design Pressure: 345 barg

Operating Pressure Range (onshore section): 50 - 140 barg

Normal Operating Pressure (onshore section, at start of field life): 120 barg

Wellhead Shut In Pressure (WHSIP) (at start of field life): 345 bara


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Wellhead flowing pressure (at start of field life): 272 bara

Maximum Design Temperature: 50°C

Minimum Design Temperature: -10° C

3.4 Well Fluids Analysis

The Corrib field contains a water saturated sweet gas with an expected condensate yield ofless than 0.5bbls/mmscf [Ref. 6]. For the purposes of the consequence modelling the

following well fluids properties have been assumed, based on well 18/25-1 [Ref. 6].

Table 3-1 – Well Fluids Properties and Composition

18/ 25-1

Relative Density (Air=1) 0.587

Average MW (g/mole) 17.0

Composition (mol %)

Methane 94.0Ethane 3.0

Nitrogen 2.7Carbon Dioxide 0.3Hydrogen Sulphide nil

3.5 Design Life

The pipeline and all its attachments have a design life of 30 years.

3.6 Materials

The pipeline will be constructed from Carbon Steel to DNV OS-F101 SAWL 485 (equivalent to API 5L Grade X 70).

3.7 Diameter and Wall Thickness

The pipeline has a nominal external diameter of 20” (508 mm). Design of pipe wall thicknessis in accordance with BS 8010 [Ref. 2]. This has resulted in a nominal wall thickness of

27.1mm, including corrosion and manufacturing allowances.

3.8 Depth of Cover

Generally, the pipeline will be buried with a minimum depth of cover of 1.2m over the entire

route. This minimum cover is increased at crossings. Where this depth of cover is notachieved (e.g. at ditch crossings), additional protection is provided over the pipeline.

3.9 Crossings

The route taken by the onshore section of the pipeline includes the following crossings:

• 6 Track Crossings;• 3 Road Crossings (including the Terminal Boundary Road);• 3 River Crossings;• 33 Ditch Crossings.

Road crossings have been designed in accordance with BS 8010 [Ref. 2]. Specialconsideration will be made where pipe in soft ground crosses roads to ensure that stresses


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cannot be exerted on the pipe due to ground settlement over the life of the pipeline. Concrete

coated pipe is used at river and estuary crossings. Track, road and ditch crossingsincorporate a concrete barrier above the pipeline to protect from third party interference, e.g.during ditch clearing activities.

Buried utilities, drains, etc. are to be crossed in accordance with the individual owner'srequirements but will follow the convention of crossing beneath existing services withprotection between them unless indicated otherwise.

3.10 Corrosion Allowance

A corrosion allowance of 1.0mm has been included in the wall thickness calculation of the

onshore pipeline section. (section 3.7)

3.11 Coatings

The pipeline is provided with a 2.5 mm thick external polypropylene (3LPP) anti-corrosion

coating on all pipeline sections that are not concrete coated. Concrete coated sections (usedat river and estuary crossings) have asphalt enamel under the concrete coating.

3.12 Inhibitors

Throughout the life of the pipeline, a mixture of methanol, corrosion inhibitor and scale

inhibitor will be injected at the subsea wells in order to prevent internal corrosion, hydrateformation and scale deposition in the pipeline.

3.13 Cathodic Protection

In addition to the coating system described above, the onshore section of the pipeline will be

fitted with an impressed current cathodic protection system to prevent external corrosion.

The cathodic protection system has been designed in accordance with the requirements ofBS7361 and will comprise a transformer rectifier unit, anode groundbed and test facilities for

system monitoring.

The precise location and configuration of the anode groundbed has been determined

following completion of the soil resistivity survey [ref 19]. Test facilities to enable monitoringof the level of cathodic protection afforded to the pipeline will be installed at strategic locations(selected during the resistivity survey), taking due note of any particular corrosion hazards

identified during the survey work.

The interaction of the onshore and offshore CP systems was addressed in the design of theonshore system to ensure that no undesirable effects occur that could result in under-protection of either pipeline section. This is described in the Corrosion Protection DesignReport (Ref. 19). No electrical isolation joint is required between the onshore and offshore

pipeline sections.

The onshore pipeline is electrically isolated from the Terminal pipework.

3.14 Pigging

The onshore section of the pipeline has been designed to permit intelligent pigging, and

meets the requirements for the operation of all forms of pigs.


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4 METHODOLOGY

4.1 General

The risk assessment of the onshore section of the pipeline has generally been conducted inaccordance with the Project Risk Assessment Procedure [Ref.1] and the followingmethodology.

4.2 Hazard Identification

A Hazard Identification (HAZID) exercise has been carried out using a comprehensive genericHAZID checklist developed specifically for onshore pipelines. This activity was conducted to

provide the starting point for the onshore pipeline QRA by identifying those hazards to beincluded in the assessment.

The HAZID checklist included hazards applicable to pipelines carrying any product,

constructed from any material, having any diameter and wall thickness, crossing all types of

terrain and exposed to all possible environmental hazards. It therefore included somehazards that were not judged to be significant as potential causes of failure for the onshore

section of the Corrib pipeline, and others that will be adequately controlled by the design andconstruction practices. However, all hazards were discussed and assessed in the HazardReview report (Ref. 15) as part of the process.

Hazards that were judged to present a significant risk were carried forward for more detailedassessment (using qualitative and quantitative methods as appropriate) in the development ofthis document. Assessment of these hazards and ways in which the risks could be managed

led to recommendations which have subsequently been incorporated into the pipeline designin order to ensure that the risks were reduced to a tolerable, or As Low As ReasonablyPracticable (ALARP), level.

4.3 Risk Assessment

4.3.1 Qualitative and Quantitative Assessment

Qualitative and quantitative risk assessments have been conducted, as appropriate to theparticular risk. Qualitative discussions have been used to reduce the number of failure modes

requiring quantitative assessment. Quantitative risk assessment comprised hazardconsequences and hazard frequency assessments. The QRA has quantified the residualrisk, resulting from the operation of the onshore section of the pipeline, in terms of risk to

members of the public. The results of the assessment have been discussed andrecommendations have been made to reduce risks to levels that are as low as reasonablypracticable.

4.3.2 Consequence Analysis

This part of the analysis involves the following:

• Allocation of a release type (vapour, two phase etc) or hazard type (dispersion, fire,flash fire etc).

• Determination of release rate for each scenario. Standard release rate equations witha coefficient of discharge of 0.8 (typical for gas) were used. For releases through

large holes a pipeline model was used to determine the reducing release rate withtime.

• Association of each scenario with the type(s) of hazardous event that could occur

should there be ignition (i.e. jet fire, flash fire etc).


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• Determination of the consequences. Dispersion distances and distances to thermalradiation levels have been determined using Shell FRED (Fires, Release, Explosion,Dispersion) Version 4. This is a suite of consequence models based on Shell’sinvolvement over a more than 20 year period in Safety Research and Development.

The models are all validated by large-scale experiments, and published in reputablescientific literature.

In the determination of the hazardous envelope(s) associated with each scenario,

consequence end points need to be defined for each hazard type. Although at present thereare no published Irish standards for the determination of land use planning advice, it isunderstood that statutory criteria are being developed for such advice based on risk. In order

to establish a common basis for sites that present a combination of hazards, the authority willconsider the risks associated with a ‘dangerous dose’. A ‘dangerous dose’ is one which will:

• Cause severe distress to almost everyone;

• Require a substantial fraction to be given medical attention, with some sufferingirreversible effects;

• Cause fatalities in highly susceptible members of the population (the most vulnerable1%).

For the radiation hazards posed by the proposed pipeline a dangerous dose for radiation topeople (referred to as Thermal Dose Units or TDUs) of 1000(kW/m

2)1.3333

s is commonly used.For an exposure duration of 75 seconds a thermal flux of 7kW/m

2 is approximately 1000TDU

and a thermal flux of 4kW/m2 is approximately 500TDU. In this report 6kW/m

2 has been used

to represent 1000TDU.

The potential impact of the pipeline on the trees and buildings has been considered using the

thermal radiation frequency contours for 12kW/m2 for long duration fires and 20kW/m

2 for

short duration fires. The critical heat flux for piloted wood ignition is 13.1kW/m2, and 20kW/m

2

would be capable of igniting trees if the exposure duration was more than five minutes,

(Cohen and Butler [Ref 7]). For short duration fires, the distance to the spontaneous ignition

of wood has been used (Bilo and Kinsman[ Ref 8])

Other hazards more commonly associated with petrochemical activities like toxic effects and

explosions have not been considered. Toxic effects are not considered credible scenarios onthe basis of the composition of the Corrib gas. An explosion event is not considered torepresent a credible scenario (by comparison to the fire events that have been modelled) as

there are no areas along the route of the onshore pipeline section in which gas mayaccumulate, or where there would be sufficient confinement and congestion to allowsignificant explosion overpressures to be generated. Explosion modelling has not, therefore,

been conducted.


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5 DATA AND ASSUMPTIONS

5.1 General

The quality of the predictions of the QRA depends on the quality and relevance of the datasources and assumptions used. It is therefore important that appropriate sources of historicaldata are used, that the data is correctly applied and that realistic, yet conservative,assumptions are made based on best practice and experience available from other similar

risk assessments.

The data sources and assumptions used are described in the following sections.

5.2 Population Density

5.2.1 Area Classification

The area classification based on population density has been made in accordance with BS8010 [Ref. 2] and is reported in the Population Density Analysis [Ref. 9].

The estimated population density, calculated for a corridor 850m either side of the pipeline,

using aerial photographs (taken during 2000), is 0.65 people / hectare, which results in anarea class 1 location. The upper limit for an area to be classified as area Class 1 is 2.5people / hectare.

Ordnance survey maps (undated) are also available. A comparison of the maps with thephotographs show that in the intervening period some buildings have become redundant andnew buildings have been constructed. However it appears that the overall population density

has not changed significantly.

It is also unlikely that the population density of the area will increase significantly in the nearto medium future. In order to change from a Class 1 to a Class 2 location (i.e. more than 2.5

people / hectare), the population would have to increase by approx 200% in the immediatevicinity of the pipeline route.

For risk assessment purposes, the population density will be conservatively taken as 0.75

people / hectare to allow for modest growth in population density over the life of the pipeline.

5.2.2 Buildings Locations

The location of buildings along the pipeline route have been investigated using the alignmentsheets (which combine the aerial photographs, vector maps and the proposed pipeline route)in order to identify the closest building/s and the area with the greatest “density” of buildings.

The greatest density of buildings exists along the road to the north of the onshore section of

the pipeline, where it runs along the northern edge of Sruwaddacon Bay [Ref. 10].

The closest building to the pipeline route is located approximately 70m from the proposed

route centre-line.

5.3 Release Frequencies

5.3.1 Historical Data

Historical data for releases from valves and flanges has been taken from the E&P Forum

(now called International Association of Oil and Gas Producers) Risk Assessment DataDirectory [Ref. 11 ] and the UK Health and Safety Executive Offshore Hydrocarbon Releases

Statistics, 1999 [Ref. 12].


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Data from the UK Onshore Pipeline Operators' Association (UKOPA) [Ref.17 ] has been used

for specific onshore pipeline hazards such as external interference and external corrosion andhas also been used for materials defects data. The UKOPA database represents a source ofpipeline fault data which is specific to the UK and based on incidents occurring during over

half a million pipeline operating years (of which over 90% is natural gas pipelines) between1962 and 1998. The UKOPA data is considered to be more relevant to the onshore section ofthe Corrib Pipeline than US or European data.

However, as the gas pipelines in the UKOPA database were transporting sales specificationnatural gas (i.e. dry gas) the PARLOC 96 data for offshore pipelines [Ref. 13] has also beenconsulted for in relation to failures due to internal corrosion and material defects to determine

which are the most appropriate frequencies to use in this assessment

Although there are later versions of this data now available, the results in them are similar, ifnot a reduced incident frequency, therefore the original data has been retained in this revision

of the QRA and adds a slight further conservatism to the failure frequency data.

5.3.2 Probabilistic Models

The UKOPA data shows that external interference to buried onshore pipelines (frommechanical excavators, etc.) is a major contributor to the overall failure frequency. Twoprobabilistic limit state models are available to determine the risk of puncture or rupture due to

this type of external interference, i.e.:

• puncture due to penetration of the pipe by an excavator bucket tooth;

• a gouge and/or dent in the pipe wall resulting in a leak or rupture.

These models have been developed based on published reference works, and are describedin Appendix A.

For other failure modes, for which probabilistic models are not readily applicable, estimates offailure frequencies have relied on historical data.

5.4 Consequence Asse ssment

5.4.1 Release Modelling

5.4.1.1 Hole Sizes

The modelling of releases from large pipelines generally only uses two hole sizes to representleaks and ruptures. Intermediate hole sizes are not considered as large cracks or punctures

in the walls of pipelines (particularly high pressure gas pipelines) tend to propagate rapidlyinto full-bore ruptures.

Leaks have been modelled as having an equivalent hole diameter of 25 mm. This isequivalent to pipe punctures or cracks. Ruptures have been modelled as having anequivalent hole diameter equal to the pipe internal diameter. When modelling pipeline

ruptures, the release rate from both sides of the ruptured pipeline were addressed.

5.4.1.2 Release Conditions

• All releases were calculated at the normal operating pressure of 120 barg and the designpressure of 345 barg.

•For the 25 mm diameter leak event a rate independent of time was assumed


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• For the rupture event the average release rate over the first 60 seconds was used for thecalculation of dispersion and radiation distances.

All releases were assumed to occur at the ambient temperature of 10oC.

5.4.1.3 Release Orientation and Inventory

Leaks

Three different release orientations were used in the gas dispersion modelling of the leaks:

These are vertical, horizontal and buried. The vertical and horizontal releases were modelledas jets discharging into the air and were not obstructed (for the horizontal release this meansthat the sides of the crater were ignored). The buried release was modelled as directly

downwards into the ground underneath the pipeline such that the gas loses all momentumand then disperses out of the crater in the downwind direction (this ignores any upwardmomentum that the gas would obtain by being pushed upwards out of the crater by the gas

escaping from the release). To this extent, all release modelling is considered to be based onconservative assumptions.

For the leak failure modes, the release orientation is considered to be evenly distributed

around the pipeline circumference, but the releases need to be assigned as either vertical,horizontal or buried in order to match one of the gas dispersion and fire models. It has beendecided that 50% of the releases should be assigned as buried releases as these will impinge

significantly on the crater sides, causing the jet to lose (some or all of its) momentum. Theremaining releases are divided evenly between “vertical” and “horizontal”.

The event tree accounts for all three release directions used in the dispersion modelling. The

proportions assigned to each release direction in the first column of the event tree are theproportions of un-ignited releases in this direction (i.e. 25% vertical, 25% horizontal and 50%buried) for the other failure modes.

Ruptures

The directional component of a full bore rupture will be horizontal in the direction along thepipeline both for dispersing high momentum gas jets and ignited jet fires.

Inventory

The design of the gas production system includes automatic ESD valves at the subsea wellsand at the entrance to the terminal facilities. The length of pipeline between these two points

is approximately 93km, giving a maximum total pipeline inventory (at the initial wellhead shutin pressure) of approximately 3900 tonnes.

For small leaks in the onshore pipeline section, it has been assumed that these may not be

easily detected (due to the relatively low release rate) and may therefore persist for sometime before detection and closure of the ESD valves.

5.4.1.4 Meteorological Data

Wind statistics (strength and direction) used for the modelling have been provided by MetEireann (Belmullet). Information about the wind speed stability combinations is not available,

so it has been assumed that these could be represented by F2 (Pasquill stability F-stable,wind speed 2m/s) and D5 (Pasquill stability D-neutral, wind speed 5m/s). It has further beenassumed that D5 occurs for 85% of the time and F2 for the remainder. This in line with

common QRA practice.

5.4.2 Ignition

Ignition probabilities have been derived from a number of published data sources. Historical

data is available from hundreds of pipeline release incidents occurring during millions ofkm.yrs of pipeline operation and represents the best available estimates of ignition probability.


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The ignition frequencies used in this revision of the QRA (updated from previous revisions of

the document) are based on data published by EGIG in 2001) and are compared to otherdata sources in the table below:

Table 5.1 Historical Ignition probability

Data Source Release Size Ignition Probability

Pinhole-crack (< 2cm) 0.032

Hole (2cm < Dleak < Dpipe) 0.021

Rupture (> 16”) 0.25

EGIG 2001

All sizes 0.04

UKOPA 2000 [14] All sizes 0.047

The historical databases contain release frequencies for a large number of pipelines with arange of wall thickness. This includes thin-walled pipelines, which are more susceptible to

puncture by external interference than the thick-walled Corrib pipeline. As release events

caused by external interference have a higher probability of ignition (as a potential source ofignition is usually present) it is considered that the ignition probabilities derived from these

databases represent conservative estimates for the Corrib onshore pipeline.

The historical databases also include much data for pipelines in urban and suburban areas -where the ignition probability due to the number of ignition sources available in such locations

would be expected to be much higher than in a rural location such as the Corrib onshoreroute. Again, this means that the data presented in the databases is conservative for theCorrib onshore pipeline.

It has nevertheless been decided to use the historical ignition frequencies as a guide for theignition probabilities selected in this study. In general, the following ignition probabilities havebeen adopted, and the values used in the event trees have been based on these values.

Table 5.2 – Selected Ignition Probability values

Release Size Ignition

Probability

Rupture (> 16”) 0.25

Pinhole-crack (< 2cm) 0.032

In order to account for “early” and “late” ignition the available historical data for onshorepipeline releases was reviewed to ascertain whether any distinction was made with regard tothe timing of ignition in pipeline release events. The data search did not, however, yield any

information that could be used to determine the time delay between the onset of an accidental

release and the moment of ignition of the gas. This is probably to be expected because,while evidence of a gas cloud ignition is all too apparent, there are not usually any signs that

allow accident investigators to determine how long after the initial release the ignitionoccurred. While it is possible that this information may be available in a (very) few cases, it isnot normally recorded in historical accident databases.

The overall ignition figure in the EGIG data does not distinguish between “early” and “late”ignitions, but does include ALL ignitions (EGIG Report, 2001, Section 2.2 states that “Ignitionyes/no” was recorded for ALL pipeline release incidents, but nothing more specific than this).

Vertical leaks will have a very small flammable area at ground level and therefore a very smallprobability of early ignition. A probability of 0.002 is assumed (10% of the frequency attributedto horizontal and buried releases). Late ignition of vertical releases is considered as not

feasible and therefore give a probability of zero. Given that the effect of vertical jet fires from

leaks is much less than that for horizontal or buried leaks, this is a conservative assumptionas the overall ignition frequency remains the same but is spread over the other orientations.


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For ruptures from external impact, most likely caused by motorised diggers, an early ignition

probability of 0.9 has been assumed.

In the absence of historical data, it was decided that the proportion of “early” and “late”ignitions was to be evenly distributed in the development of the event tree. The area affected

by the late ignited clouds is, in most cases, smaller than the area enveloped by the 6kW/m2 contour /1000TDU. Therefore this assumption will not affect the result as in the study lateignited dispersing clouds will flash back to torch fires which is the same outcome from early

ignited dispersing clouds.

5.5 Tolerability of Risk

Tolerability of risk is normally determined by the authorities which authorise developments ofthis nature. A discussion on the various risk acceptance criteria found, applicable to pipelinesis presented in the following paragraphs. The most stringent criteria found, applicable to

pipelines, would tolerate a risk contour value below 10-6

per year (1 in a million chance peryear of a fatality).

5.5.1 Representations of Risk

Quantitative representations of risk are commonly used to describe the risk level to theworkforce and/or members of the public affected by industrial activities. These risk

representations are normally calculated as the potential risk of loss of life, and the resultingrisk levels can then be compared with known fatality statistics.

For pipelines, in general only Risk Contours are used. F/N curves (see 5.5.1.3) are not

usually used as the risk, when depicted in this way, would become dependent on the length ofthe pipeline section considered and the location of individuals, all of which change greatlyalong the length of the pipeline – which makes this figure meaningless. Risk Transects (see

also 6.4.1) show the effect of distance on risk frequency at 90 degrees to any point along the

pipeline and are developed from a section or intersection through Risk Contours.

5.5.1.1 Risk Contours

The Risk Contour is an iso-risk line on the map at which a hypothetical individual staying atone point on this line unprotected and for 24 hours per day would be subjected to a defined

probability of loss of life due to exposure to hazards induced by the industrial activity. This riskindicator is most frequently used to quantify the risk to the public around an industrial activity(in this case the gas pipeline) and is expressed as a risk of fatality on a per year basis.

Each point along the risk contour is specific to a certain point on the ground, and representsthe sum of any risk scenarios which can affect that point. It is sometimes called the LocationRisk. Another way to look at the definition above, is to say that a hypothetical individual is at

the location and exposed whenever any of the risk scenarios manifests itself.

Although the hypothetical individual is exposed when the scenario occurs, it is normal to takeaccount of human reaction. For example if the individual is in the heat radiation field of a big

flame, then an exposure time is assumed from the time of the event until after the individualcan reasonably be assumed to have taken cover or moved far enough away from the flamenot to be at further risk.

It is possible to take account of the protection offered by buildings, so that the risk contourlevel inside a building is lower than outside. However this is not normal practice whencalculating Risk Contours for land-use planning purposes and has not been undertaken for

this analysis.


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5.5.1.2 Individual Risk

The Individual Risk (IR) level is more specifically defined as the Individual Risk Per Annum(IRPA), which is the calculated annual risk loading to a specific individual or group of

individuals. Clearly this depends on the amount of time in a year that the individual spends indifferent risk areas. The individual risk calculation takes account of the fact that people movefrom one place to another.

When calculating individual risk from major accident scenarios, it is normal to take account ofprotection by buildings.

Sometimes the individual risk is calculated on the basis of 108 exposed hours. This is called

the Fatal Accident Rate (FAR).

5.5.1.3 Societal Risk Curves

Societal Risk is used in Quantified Risk Assessment (QRA) studies and is depicted on acumulative graph called an F/N curve. The horizontal axis is the number of potential fatalities,N. The vertical axis is the frequency per year that N or more potential fatalities could occur, F.

This risk indicator is used by authorities as a measure for the social disruption in case of largeaccidents.

It is normal to take account of protection by buildings, and people’s response. For large toxic

release models, alarm and evacuation can be included. The resulting curve is then theresidual risk should the emergency plans not be effective.

Because it is a cumulative curve, the curve always drops away with increasing N. Normally

the F/N curve has a lower frequency cut-off at one in a billion (1 x10-9

/yr).

Regulators often split the graph into different regions, so that different actions have to beundertaken depending on where the F/N curve falls. Sometimes a maximum limit is placed on

N (number of fatalities) possible for any event.This type of curve is normal for plant type hazardous installations where a large group ofpeople could be affected and their location is well established (housing estates, schools etc)

relative to the event location (the plant). For pipelines however, because there is no singlelocation for an event and the population affected varies along the pipeline route, this curve isnot normally generated unless a large group of people can be effected over a reasonable

distance. For the Corrib pipeline, the population is distributed over a long length, part has nopopulation close to it at all and therefore the calculation for this curve is not really possibleand does not provide a true picture of the societal risk presented by the pipeline.

5.5.2 International Risk Criteria

5.5.2.1 United Kingdom

In the UK the “Control of Major Accident Hazards” (COMAH) regulations are in line with thelatest EU “Seveso-2” Directive. The regulations do not formally require a quantitative risk

assessment, but the guidance notes make clear that in some circumstances quantification willhelp or could be asked for by the UK regulator - the Health and Safety Executive (HSE) - andthis is often done in practice.

To advise planning authorities on developments around industrial installations, the UK HSEhas been developing risk acceptance criteria over the years. A comprehensive treatment ofthe subject of tolerability of risk was given in a report titled “Reducing Risks Protecting

People” [Ref 14 ] . The report repeated the concept and criteria as argued by the RoyalSociety in 1983. It accepted the concept of tolerable Individual Risk as being the dividing linebetween what is just tolerable and intolerable and set the upper tolerable limit for workforce

fatalities at 10-3

/yr ( 1 in a thousand) for workers and 10-4

/yr ( 1 in 10 thousand) for members


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of the public. A level at which risks might be broadly acceptable but not altogether negligible

was set at 10-6

/yr (1 in a million). The region in between would be controlled by the ALARPconcept.

ALARP can be demonstrated in a variety of ways, depending on the severity of the worst

case scenario. These are expressed in HSE guidance to Inspectors Consultation DraftSeptember 2002. When a QRA is carried out, then the F/N regions are defined as in theFigure 5.1.

1E-09

1E-08

1E-07

1E-06

1E-05

1E-04

1E-03

1E-02

1 10 100 1000 10000

Number of fatalities

F r e q u e n c y

p e r y e a r

Unacceptable

Broadly

acceptable

ALARP

Figure 5-1 United Kingdom Societal Risk Guidelines (risk to workforce and public)

Unlike the Netherlands (see below), the potential workforce fatalities are included in the F/Ncurve.

5.5.2.2 Canada: Major Industrial Accidents Council of Canada (MIACC).

The MIACC recommend individual risk levels for use in respect to hazardous substances riskfrom all sources, i.e. there is no need to distinguish between risk from a fixed facility at whichhazardous substances may be found, or a pipeline or a transportation corridor. The

acceptability levels are equally applicable. With these considerations in mind, the guidelinesfor acceptable levels of risk are as follows

Table 5.3 Land use and Industrial Risk according to MIACC

Location (based on risk level) Possible land uses

From risk source to 1 in 10,000

(10-4

) risk contour:

no other land uses except the source facility, pipeline or

corridor1 in 10,000 to 1 in 100,000(10

-4 to 10

-5) risk contours:

uses involving continuous access and the presence oflimited numbers of people but easy evacuation, e.g. open

space (parks, golf courses, conservation areas, trails,excluding recreation facilities such as arenas),warehouses, manufacturing plants

1 in 100,000 to 1 in 1,000,000

(10-5

to 10-6

) risk contours

uses involving continuous access but easy evacuation,

e.g., commercial uses, low-density residential areas,offices

Beyond the 1 in 1,000,000(10

-6) risk contour

all other land uses without restriction including institutionaluses, high-density residential areas, etc

It is important to emphasize that these guidelines do not prohibit all activities or structureswithin the various risk contours, but rather restrict land use within each zone. As is the case


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for many other land use questions (e.g. flood plains), the contours are used to define special

restrictions on land uses. This aspect of the guidelines is particularly important since, asdiscussed in a subsequent section, land use controls around industrial sites have importantlegal and economic implications.

The guidelines are thought to be realistic in terms of existing practices of risk managementand levels of risk. They are also compatible with criteria that have been selected andimplemented in other industries and other countries. In a practical sense, these criteria can

only achieve authority if they represent a consensus view of Canadian society. They must notimpose unrealistic requirements on industry and should reflect the contemporary standards ofthe society to which they are applied.

5.5.2.3 Malaysia

The criteria used by the Department of Environment (DOE) for existing facilities are outlined

below for residential and industrial areas:

• Residential 1 x 10-6 fatalities / person / year

• Industrial 1 x 10-5 fatalities / person / year

In words, the acceptability criteria are as follows: the risk of death to persons in a residential

area must not exceed 1 chance in a million per person per year and the risk of death topersons in a nearby industrial area must not exceed 1 chance in 100,000 per person per year.

If the quantified individual risk compares favourably with the acceptability criteria, then it is

deemed acceptable. If not, the components of the overall risk are re-examined to determinewhere risk mitigation measures can be implemented cost effectively. Risk evaluation mustalso be conducted taking into account the fact that hazard analysis and consequence

assessment only gives an estimation of risks from a facility. In many cases the expertise andthe knowledge required to model various failure scenarios do not exist prior to the accidentoccurring. For instance, although dispersion models are used in the modelling of the release

of large masses of dense gases (in the 100s of tonnes), there has never been a large scaleexperimental release to justify the models used. Only the gross behaviour of the vapourcloud, i.e. density intrusion-gravity spreading and passive dispersion, can be modelled.

Obstacles and terrain effects cannot be incorporated in present day models, however theycan have substantial effects on the dispersion of the cloud. Therefore, as a safety factor, astandard quantitative risk assessment technique is always to err on the conservative side in

assumption making.

5.5.2.4 Australia

The Western Australia (WA) Department of Planning has adopted risk criteria for hazardousinstallations. They are based on risk contours and can be summarised as follows:

• A risk level in residential zones of one in a million per year (1 x 10-6/yr) or less, is sosmall as to be acceptable to the WA EPA (Environmental Protection Agency);

• A risk level in “sensitive developments”, such as hospitals, schools, child carefacilities and aged care housing developments, of between one half and one in a

million per year (5 x 10 –7

and 1 x 10-6

/yr) is so small as to be acceptable to the WAEPA;

• Risk levels from industrial facilities should not exceed a target of fifty in a million peryear (1 in 20,000) at the site boundary for each individual industry, and the

cumulative risk level imposed upon an industry should not exceed a target of onehundred in a million per year (1 in 10,000);

• A risk for any non-industrial activity, located in buffer zones between industrial and

residential zones, of ten in a million per year or lower is so small as to be acceptableto the WA EPA;


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• A risk level for commercial developments, including offices, retail centres andshowrooms located in buffer zones between industrial facilities and residential zones,of five in a million per year or less, is so small as to be acceptable to the WA EPA.

5.5.2.5 The Netherlands

The policy statement approved by the Dutch Parliament states the following criteria forexisting facilities. The risk is unacceptable if the 10

-6/yr risk contours affect residential areas or

the F/N curve is above 10 fatalities with a frequency of 10-5

/yr with a slope of -2. This isillustrated in Figure 5-2:

1E-09

1E-08

1E-07

1E-06

1E-05

1E-04

1E-03

1E-02

1 10 100 1000 10000


F r e q u e n c y p

e r y e a r advised

limit

ALARP

Figure 5-2 : Netherlands Societal Risk Guidelines (risk to public only)

Below the criteria, the ALARP, “As Low As Reasonably Practicable”, principle should be used.

All Dutch installations should meet the criteria for new facilities by the year 2005. For theSocietal Risk it should be emphasised that the exposure or “presence” factor of populationused for calculating the F/N curve during the day is 0.7 and 1 during night. Also the

assumption is made that being indoors gives protection where the fraction of people beingindoors is 0.93 during daytime and 0.99 during night time.

5.5.2.6 Hong Kong Government Criteria

The Hong Kong government has published “ Interim Risk Guidelines for Potential Hazardous

Installations”. The guideline covers new installations and expansion of existing installationsand also controls the development of land around installations. It should be pointed out thatalthough these are described as “guidelines” they are very strictly applied in practice. They

are seen as necessary because of the special circumstances of Hong Kong, where there is adense population in close proximity to industrial facilities, and are mainly used for land-useplanning decisions. The guidelines set forth two criteria;

• A risk contour of 10-5/yr for fatality as an upper limit of tolerability.

• The maximum F/N curve exceeds the line through the point of 10 fatalities at afrequency of 10

-4/yr with a slope of -1. No event at any frequency should take place

which causes more than 1000 deaths.

The societal risk zones are illustrated in Figure 5-3:


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1E-09

1E-08

1E-07

1E-06

1E-05

1E-04

1E-03

1 10 100 1000 10000


F r e q u e n c y

p e r y e

a r

Intolerable

Tolerable

ALARP

Figure 5-3: Hong Kong Societal Risk Guidelines (risk to public only)

The Hong Kong regulators scrutinise each risk assessment closely and insist on the use ofconsistent methodology from case to case.

5.5.3 Tolerability of risk

Although there are differences between the legislation adopted in the various countries it is

also clear that there is consensus on the tolerability of risk. The majority of the countrieswould accept risk levels for the public around 10

-5/yr whilst the more stringent countries would

set the tolerability level at 10-6

/yr.


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6 RISK ASSESSMENT

6.1 Failure Modes

6.1.1 General

The completed HAZID checklist is included in the HAZID Report [Ref. 15]. Many of thehazards were considered, based on the experience and judgement of the assembled team, to

present an insignificant risk of pipeline failure. These risks were therefore considered to betolerable and are not discussed beyond the HAZID Report. It should, however, be noted thatsome recommendations for future project phases (Construction, Operation) are made and

that these should be added to the Overall Project Hazard Register, as applicable.

Those hazards which were considered to present a significant risk are further assessed in thefollowing sections. As a result of further assessment the hazards are either assigned a

quantitative failure rate (i.e. a frequency of loss of pipeline containment), or are judged tomake a negligible contribution to the overall pipeline failure frequency. In this context anegligible contribution would be equivalent to a pipeline loss of containment frequency equal

to or less than 1 x 10-8

per km.yr.

6.1.2 Pressure Considerations

Increasing pressure above normal operating of the onshore pipeline section may occur as aresult of blockage, or during shut-in when the pipeline may reach the initial well-head shut-inpressure of 345 barg.

The only feasible scenario for blockage of the pipeline is due to hydrate formation. Methanolwill be injected into the well fluids at the subsea wells in order to suppress hydrate formation.In the event that methanol injection failed or was unavailable for any period of time, hydrates

could form in the pipeline. However, the typical hydrate dissociation temperatures are suchthat hydrate formation would be expected to occur in the offshore pipeline section andtherefore the section of pipeline which would be exposed to high pressures from the wells is

the offshore section.

Shut-in at the terminal due to process upset or terminal ESD will lead to higher pressures inthe onshore pipeline unless wellhead valves are closed. However, the entire pipeline is

designed to withstand the well-head shut-in pressure (WHSIP) existing at the start of field lifeand failure of the (defect free) pipeline due to pressure higher than normal pressure is not,therefore, considered to be a credible failure mode. The WHSIP decreases over the field life,

thus further reducing the risk of failure due to internal overpressure.

Prior to start-up the pipeline will be tested to pressures which exceed the design pressure of345 barg by over 20%. Thus the risks of defects existing in the pipeline that could cause

failure at the WHSIP is considered to be very low.

6.1.3 Pressure Cycling

A pressure cycle is defined by the range of the pressure variation, and the frequency of thecycle. The range of a variation is defined as the difference between the peak value and lowestvalue of the pressure variation and the frequency is defined as the period of time which

elapses between the identical point in two subsequent cycles (e.g. two subsequent peaks).

The pressure cycling constraints for a pipeline are governed by the material fatigue limits andare dependent on both the range and the frequency of the pressure variations. These factors

are related and vary inversely with one another, i.e. a high cycling frequency would have alower permissible range than a lower cycling frequency.

Generally the diurnal range of pressure cycling for the onshore section of the pipeline is smallas the pipeline is not feeding end-users directly but is "buffered" from the effects of the


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varying end-user demands by the Terminal process and the export pipeline downstream of

the terminal. It is assumed that the Terminal will initially operate at a steady state flow of 350mmscfd and a steady pressure regime. Any variation in flow would be managed by variationof the choke valve settings at the subsea production manifold in the field, with the aim to

achieve a set arrival pressure at the Terminal.The range of pressure cycling is therefore considered to be low. Pressure and stress fatiguelimits are considered to be negligible, and pressure cycling is not considered to represent a

credible cause of pipeline failure.

Pipeline fatigue is addressed in the Mechanical Design Report [Ref. 16]

6.1.4 Pipeline / Umbilical Separation

The scope of this assessment does not include hazards resulting from releases from theumbilical, except to the extent of assessing whether a fire resulting from the ignition of a

methanol leak from the umbilical may result in a release from the gas pipeline.

The distance between the pipeline and the umbilical of minimum 1m in the onshore sectionsis considered to be sufficient to allow access for potential future maintenance of one or the

other without undue risk of damage to the neighbouring line, and the risk of failure to onecaused by the other is considered to be low.

The most hazardous fluid transported in the umbilical is the methanol used for hydrate

inhibition. This is transported in separate lines at a maximum operating pressure in theonshore section of 345 bar. The onshore sections of the umbilical are housed in conduits.These provide some additional protection, but are not designed for pressure containment.

The separation distance of the umbilical and the pipeline will be a minimum of 1.0 m except atriver crossings.

The normal flow rate within any of the five methanol lines within the umbilical is only 1m3/hr.

Therefore a leak at any significant rate would be very likely to be detected. In the event of

ignition, the methanol would burn as a pool fire at ground level. In pool fire combustion thevapour burns above the pool (where it can mix with air) and the heat radiated back from the

combustion provides the energy to evaporate more liquid to fuel the fire. The temperature ofthe liquid in the pool remains around the boiling point of the liquid, which for methanol (atatmospheric pressure) is approximately 65

oC.

The heating effect on a pipeline buried beneath the pool would not, therefore, be sufficient topresent a risk of pipeline failure.

It is concluded, therefore, that the presence of the umbilical does not present a credible risk of

pipeline failure due to umbilical loss of containment.

For the converse, high pressure releases from the gas pipeline will generate significant forcesand create large craters in the ground around the release. Such releases could, therefore,

cause failure of the umbilical even if the pipeline release does not ignite. In the event of anignited pipeline release, any exposed umbilical sections would be expected to fail due to thehigh thermal radiation.

The additional hazardous consequences of umbilical failure in the proximity of a large pipelinegas release, are not considered to be significant, i.e. the consequences of the release ofsmall quantities of methanol are small in comparison to the hazards presented by the pipeline

release itself.

The case of whether the umbilical failure in the event of a gas pipeline failure will increase theprobability of a fire due to the presence of electrical cables in the umbilical has been

addressed. A gas release will only ignite if the correct conditions are present. In the event ofbreakage of the cables in the umbilical as a result of a large gas pipeline failure, the areaimmediately around the release is too rich in gas for ignition to occur. It is considered that the

ignition probability chosen for this assessment (see section 5.4.2) is appropriate andconservative for this location and arrangement.


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The presence of electrical cables in close proximity to the pipeline has been considered in the

design of the Cathodic Protection system and found not to cause any effects on the operationof the pipeline and its Cathodic Protection system.

All subsea christmas tree and manifold valves are of fail-closed design and will act

automatically to shut off the inventory of the gas reservoir in the event of loss of hydraulicpower or electrical control signals (both channels) through the umbilical.

6.1.5 Third Party Interference

6.1.5.1 Historical Failure Rate

The UKOPA pipeline fault database [Ref. 17] indicates a failure rate (leading to product loss)due to external interference for the period 1962–1998 of 5.98x10

-5 per km year (1.00x10

-5 per

km.year for the period 1994-1998). The UKOPA data encompasses failures in a wide variety

of steel pipelines (over 90% of which were gas pipelines) with a range of wall thicknessvalues.

The UKOPA data also shows that most incidences of external interference have occurred inrural areas, with semi-rural & suburban areas the next most frequent.

Table 6-1– Product Loss Incidents resulting from External Interference related to Area

Classification

Area Classification Exposureskm.yr

Incidents

Rural 443,447 24

Suburban & Semi-rural 46,060 7

Urban 516 0

Total 490,023 1 31Note 1. It is noted that the total exposure in this table is less than other UKOPA tables. The reason for this was notexplained in the UKOPA data. It is assumed that this is because the data for location of the pipelines wasincomplete.

The UKOPA data also shows that the maximum wall thickness for a loss of product incidentresulting from external interference was 12.7mm (whereas the Corrib pipeline wall thickness

is 27.1 mm). The distribution of failures resulting from external interference for each wallthickness category is shown in Table 6-2.

Table 6-2 – Product Loss Incidents resulting from External Interference related to Wall

Thickness Class

Wall Thicknessmm

Exposureskm.yr

Incidents

< 5 42,222 10

5 - 10 250,030 17

10 - 15 192,558 4

> 15 34,006 0

Total 518,816 31

The trend shown above is to be expected. However, the absence of a failure in the > 15mmcategory may be partly due to the low exposure time for this category and it is worth notingthat the exposure time of pipelines with wall thickness in excess of 15mm is relatively low by

comparison to the 10 - 15mm wall thickness category


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6.1.5.2 Failure Rate Estimated from Limit State Model

For the area in question, the risk of third party (or external) interference from constructionactivities, ditch digging, boring, etc. is considered to be low. British Gas Technology [Ref. 18]

indicated a frequency of external interference of 1.86 x 10-3

per km year as applying to typical36-inch diameter national transmission system pipelines. Note that this is the risk of someform of external interference actually making contact with the pipeline – but not the risk of

failure of the pipeline.

The onshore section of the Corrib pipeline passes through a fairly remote rural area whichhas a low possibility for major construction operations and few public utilities close to the

pipeline. However, there are peat cutting activities and associated drainage works and theremay be some tillage activity. The external interference frequency of 1.86 x 10

-3 per km-year is

therefore conservatively assumed for this location.

Protection from normal farming activities is provided by the pipeline minimum depth of cover[Ref 2]. However, the pipeline may be exposed to risk where the minimum cover is notachieved (construction defect) or where it has become eroded due to removal of overburden

(due to flooding, land erosion, or washout from the trench due to drainage patterns). The riskpresented by farming activities is assumed to be included in the above frequency for externalinterference.

The probability of failure (leaks and ruptures) resulting from third party interference isassessed using the limit state models defined in Appendix A. These models were developedto estimate the probability of failure in the event of external interference by excavation

equipment. It is assumed that the methodology used is also applicable to farming equipmentsuch as ploughs, and chain type excavators that might be used to create land drains.

The risk of product loss (from leaks and ruptures) is given by the product of the external

interference frequency and the failure probability, as shown in Table 6-3. A pipeline internalpressure of 345 bar is assumed in the limit state model as, even though this condition wouldonly exist infrequently, if at all, any unreported damage could lead to failure during shut-in

conditions caused by damage to the pipeline (dent, gouge etc) not reported or detected anddid not cause a leak at the normal operating pressure.

Table 6-3 – Risk of Product Loss due to External Interference (assuming WHSIP)

Release Type Frequency ofExternal Interference

/ km.yr

Probability ofFailure mode /interference event

(from model)

Risk of ProductLoss / km.yr

Leak (25mm) 1.86 x 10-3

2.55 x 10-4

4.74 x 10-7

Rupture (Full Bore) 1.86 x 10-3

6.09 x 10-5

1.13 x 10-7

Total 5.88 x 10-7

6.1.5.3 Selection of Representative Failure Rate

The Corrib pipeline has a high wall thickness (27.1 mm), normally referred to as “thick wall”,

and consequently the failure rate would be expected to be considerably lower than thatpresented in the UKOPA data, as this generally reports failures associated with much thinnerwalled pipe (the maximum wall thickness for any loss of product incident resulting from

external interference was 12.7mm).

The impact energy required to puncture thick-walled pipe is considerable, and this is reflectedin the results obtained from the limit state model

The failure rate due to external interference for the onshore pipeline section will, therefore, beassumed to be as presented in Table 6-3.


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A (small) additional risk reduction can also be achieved by the installation of brightly coloured

plastic warning tapes in the ground above the pipeline. These may warn the excavatoroperator of the presence of the pipeline, thereby averting damage. The level of risk reductionis small, but as the cost of installation is also low, the installation of warning tapes has been

included in the design in accordance with the ALARP principle.

6.1.6 Estuary / River Crossings

There is no significant river traffic in the water over the pipeline crossings. The river channelis not dredged.

River erosion, which may expose the pipe at river crossings cannot be discounted and thecrossings will therefore be inspected regularly following construction and during operation.

Concrete coated pipe will be used at the river crossings. Primarily this is for stability purposes,

but it will also provide a significant degree of protection from impact. Failure of the onshore

section of the pipeline due to impacts from small boats or their anchors at river crossings isnot, therefore, considered credible.

6.1.7 Internal Erosion

The well fluids are not expected to contain sand. However it is possible that in later field life,

the increasing water content of the fluids from some wells may carry small quantities of sandthrough the pipeline.

The flow velocity in the line is lower than the critical velocities required for erosion to occur.

Failure due to internal erosion is therefore not considered to be a credible failure mode for theonshore section of the pipeline.

6.1.8 Ground Movement

The pipeline is routed through an area of peat bog located on the north and south sides of theriver. Environmental events such as extreme flooding or drought may result in changes in the

ground level in this area, as may human activities resulting in drainage, a change of land useor increased peat cutting.

Where the ground level in the peat bog changes significantly the pipeline could be stressed at

the point where it crosses from the soft ground to the rocky areas, or where it crosses roads.In these areas the options for the construction of the onshore section of the pipeline will beinvestigated - refer to the Mechanical Design Report [Ref 16 ]. The design takes account of

the geo-technical information available and addresses options such as the use of stone piersto support the pipeline. If implemented, the separation of the supports will be designed to

account for spanning of the pipeline between supports in the event of ground settlement. Alternatively, the peat will be excavated down to base rock or alluvial gravels on which thepipeline will sit without the possibility of further movement.

The UKOPA pipeline fault da

Onshore Pipeline Quantified Risk Assessment

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