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PD 8010-3:2009
BSI British Standards PUBLISHED DOCUMENT Code of practice for pipelines – Part 3: Steel pipelines on land – Guide to the application of pipeline risk assessment to proposed developments in the vicinity of major accident hazard pipelines containing flammables – Supplement to PD 8010‑1:2004
This publication is not to be regarded as a British Standard. See Foreword for further information.
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PD 8010-3:2009
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The BSI copyright notice displayed in this document indicates when the document was last issued. © BSI 2008 ISBN 978 0 580 61732 4 ICS 23.040.10, 75.200 The following BSI references relate to the work on this standard: Committee reference PSE/17/2 Draft for comment 07/30138021 DC
Publication history First published December 2008
Amendments issued since publication Date
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Contents Foreword iii Introduction 1 1 Scope 3 2 Normative references 3 3 Abbreviations 3 4 Risk assessment of buried pipelines – Overview 4 5 Failure of hazardous gas or liquid pipelines 5 6 Individual risk assessment 13 7 Societal risk assessment 15 8 Factors affecting risk levels 19 Annexes Annex A (informative) Summary of HSE methodology for provision of advice on planning developments in the vicinity of major accident hazard pipelines in the UK 28 Annex B (informative) Failure frequencies for UK pipelines 33 Annex C (informative) Example of a site-specific risk assessment 47 Bibliography 53 List of figures Figure 1 – Overview of PD 8010-3 2 Figure 2 – Event tree for the failure of a hazardous pipeline 6 Figure 3 – Risk calculation flowchart for flammable substances 8 Figure 4 – Calculation of pipeline length affecting an individual in the vicinity of a pipeline 14 Figure 5 – Framework for the tolerability of individual risk 15 Figure 6 – Societal risk FN criterion line applicable to 1 km of pipeline 17 Figure 7 – Site-specific pipeline interaction distance 18 Figure 8 – Reduction in external interference total failure frequency due to design factor 22 Figure 9 – Reduction in external interference total failure frequency due to wall thickness 23 Figure 10 – Reduction in external interference total failure frequency due to depth of cover 24 Figure 11 – Indicative reduction in external interference total failure frequency due to surveillance frequency (dependent on frequency and duration of unauthorized excavations) 24 Figure A.1 – Planning application process and need for site-specific risk assessment 30 Figure B.1 – Generic predicted pipeline failure frequencies for third‑party interference 35 Figure B.2 – FFREQ predictions of total external interference failure frequency for UKOPA pipe cases 39 Figure B.3 – FFREQ predictions of external interference rupture frequency for UKOPA pipe cases 40 Figure B.4 – FFREQ predictions for external interference rupture and leak frequencies for specific diameter and wall thickness cases (per 1 000 km·y) 41 Figure C.1 – Proposed development 47 Figure C.2 – Risk for outside exposure 50 Figure C.3 Societal risk FN curves and PD 8010-3 FN criterion line – proposed development before and after slabbing 50
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List of tables Table 1 – Range of applicability of reduction factor for design factor, Rdf, and reduction factor due to wall thickness, Rwt 23 Table 2 – Failure frequency reduction factors, Rp, for pipeline protection 25 Table A.1 – Typical (1 × 10−6) and (0.3 × 10−6) risk distances for ethylene, spiked crude and natural gas liquids (NGLs) 31 Table B.1 – Failure rates for UK pipelines based on UKOPA data 33 Table B.2 – Failure frequency due to external interference vs. diameter 34 Table B.3 – Failure frequency due to external interference vs. wall thickness 34 Table B.4 – Comparison of external interference failure frequency estimates for example 1 with FFREQ predictions 36 Table B.5 – Comparison of external interference failure frequency estimates for example 2 with FFREQ predictions 37 Table B.6 – Comparison of external interference failure frequency estimates for example 3 with FFREQ predictions 37 Table B.7 – UKOPA pipe cases 38 Table B.8 – FFREQ predictions for total external interference failure frequency for pipe cases defined in Table B.7 (per 1 000 km·y) 39 Table B.9 – FFREQ predictions for external interference rupture frequency for pipe cases defined in Table B.7 (per 1 000 km·y) 40 Table B.10 – FFREQ predictions for external interference rupture and leak frequencies for pipe cases defined in Table B.7 (per 1 000 km·y) 41 Table B.11 – Comparison of external interference failure frequency estimates for example 5 with FFREQ predictions 43 Table B.12 – Critical defect lengths and equivalent hole diameters for UKOPA pipeline cases operating at a design factor of 0.72 44 Table B.13 – Failure frequency due to external corrosion 44 Table B.14 – Material and construction failure frequency vs. wall thickness 45 Table B.15 – Pipeline rupture failure frequency due to due to ground movement caused by natural landsliding 46
Summary of pages This document comprises a front cover, an inside front cover, pages i to iv, pages 1 to 56, an inside back cover and a back cover.
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Publishing information This part of PD 8010 was published by BSI and came into effect on 1 January 2009. It was prepared by Subcommittee PSE/17/2, Pipeline transportation systems, under the authority of Technical Committee PSE/17, Materials and equipment for petroleum. A list of organizations represented on this committee can be obtained on request to its secretary.
Relationship with other publications PD 8010‑3 is a new part of the PD 8010 series, and should be read in conjunction with PD 8010‑1. The series comprises:
•
Part 1: Steel pipelines on land;
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Part 2: Subsea pipelines;
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Part 3: Steel pipelines on land – Guide to the application of pipeline risk assessment to proposed developments in the vicinity of major accident hazard pipelines containing flammables – Supplement to PD 8010‑1:2004.
Information about this document This part of PD 8010 includes worked examples and benchmark solutions that can be used as a basis for specific studies.
Use of this document As a code of practice, this part of PD 8010 takes the form of guidance and recommendations. It should not be quoted as if it were a specification and particular care should be taken to ensure that claims of compliance are not misleading. Any user claiming compliance with this part of PD 8010 is expected to be able to justify any course of action that deviates from its recommendations. As with any risk assessment, judgement has to be employed by the risk assessor at all stages of the assessment. This part of PD 8010 is intended to support the application of expert judgement. The final responsibility for the risk assessment lies with the assessor, and it is essential that the assessor is able to justify every key assumption made in the assessment and that these assumptions are documented as part of the assessment.
Presentational conventions The provisions in this Published Document are presented in roman (i.e. upright) type. Its recommendations are expressed in sentences in which the principal auxiliary verb is “should”. Commentary, explanation and general informative material is presented in smaller italic type, and does not constitute a normative element.
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Compliance with a Published Document cannot confer immunity from legal obligations. Attention is particularly drawn to the Pipelines Safety Regulations 1996 [1] and to the requirements for risk assessments in UK health and safety legislation, in particular:
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the Health and Safety at Work etc Act 1974 [2];
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the Management of Health & Safety at Work Regulations 1992, amended 1999 [3].
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Introduction PD 8010‑1:2004, Clause 5 and Annex F provide guidance on the route selection and location of new pipelines in populated areas in terms of the acceptable proximity to significant inhabited areas. Clause 5 classifies locations adjacent to pipelines into location classes 1, 2 and 3 according to population density and/or nature of the immediate surrounding area. The general approach to the risk assessment process follows the stages outlined in PD 8010‑1:2004, Annex E. The present part of PD 8010 includes recommendations for: •
determining failure frequencies;
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consequence modelling;
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standard assumptions to be applied in the risk assessment methodology for land use planning zones;
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conducting site‑specific risk assessments;
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risk reduction factors to be applied for mitigation methods;
•
benchmark results for individual and societal risk levels.
This part of PD 8010 provides guidance for the risk assessment of developments in the vicinity of major hazard pipelines containing flammable substances notified under the Pipelines Safety Regulations 1996 [1]. It does not cover toxic substances which are also notified under these Regulations. The guidance is specific to the calculation of safety risks posed to developments in the vicinity of UK major accident hazard pipelines, but the principles of the risk calculation are generally applicable. The use of such risk assessments to determine the acceptability of developments in accordance with land use planning applied in Great Britain is discussed in Annex A. The guidance does not cover environmental risks. An overview of the document content is given in Figure 1. The guidance in this part of PD 8010 is provided for the benefit of pipeline operators, local planning authorities, developers and any person involved in the risk assessment of developments in the vicinity of existing major accident hazard pipelines. It is based on the established best practice methodology for pipeline risk assessment, and is intended to be applied by competent risk assessment practitioners. For significant developments or infringements the pipeline operator might wish to carry out risk assessment using societal risk analysis for comparison with suitable risk criteria to allow the operator to assess whether the risks remain within acceptable limits. Clause 7 describes the application of societal risk, and includes a recommended FN criterion line.
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Figure 1 Overview of PD 8010-3
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Scope Safety risks caused by flammable substances only
Clause 1
Clause 4
Risk assessment of buried pipelines
Consequences: Prediction Probability of ignition Thermal radiation and effects
Failure of a gas or liquid pipeline Event tree Prediction of failure frequency
5.3 5.4
5.5
Calculation of risk and risk criteria Individual Societal
Clause 6 Clause 7
Factors affecting risk levels Failure frequency Failure frequency reduction factors Implementation of risk mitigation measures
Clause 8 8.1 8.2, Annex B
8.3
Supporting annexes: Summary of HSE methodology for the provision of land use planning advice in the vicinity of UK MAHPs Failure frequencies for UK pipelines Example of a site-specific risk assessment
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Annex A
Annex B Annex C
5.1 5.2, 8.2 Annex B
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PD 8010-3:2009
1 Scope This part of PD 8010 provides a recommended framework for carrying out an assessment of the acute safety risks associated with a major accident hazard pipeline (MAHP) containing flammable substances. It provides guidance on the selection of pipeline failure frequencies and the modelling of failure consequences for the prediction of individual and societal risks. The principles of this part of PD 8010 are based on best practice for the quantified risk analysis of new pipelines and existing pipelines. It is not intended to replace or duplicate existing risk analysis methodology, but is intended to support the application of the methodology and provide recommendations for its use. This part of PD 8010 is applicable to buried pipelines on land that can be used to carry category D and category E substances that are hazardous by nature, being flammable and therefore liable to cause harm to persons. The guidance does not cover environmental risks.
2 Normative references The following referenced documents are indispensable for the application of this document. For dated references, only the edition cited applies. For undated references, the latest edition of the referenced document (including any amendments) applies. PD 8010-1:2004, Code of practice for pipelines – Part 1: Steel pipelines on land IGE/TD/1 Edition 4:2001, Steel pipelines for high pressure gas transmission1)
3 Abbreviations For the purposes of this part of PD 8010, the following abbreviations apply. ALARP as low as reasonably practicable FFREQ methodology recommended by UKOPA for prediction of pipeline failure frequencies due to external interference HSE Health and Safety Executive LFG liquefied flammable gases, including liquefied petroleum gases (LPG), liquefied natural gas (LNG), and natural gas liquids (NGL) MAHP
major accident hazard pipeline
MAOP maximum allowable operating pressure MDOB minimum distance to occupied building PoF
probability of failure
SMYS
specified minimum yield strength
1) Institution
of Gas Engineers and Managers (formerly Institution of Gas Engineers) (IGE) standards are available from the Institution of Gas Engineers and Managers, Charnwood Wing, Holywell Park, Ashby Road, Loughborough, Leicestershire LE11 3GH. © BSI 2008 •
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thermal dose units
TS
tensile strength
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UKOPA United Kingdom Onshore Pipeline Operators Association VCE
vapour cloud explosion
4 Risk assessment of buried pipelines – Overview The failure of a pipeline containing a flammable substance (which can be a gas, a liquid, a dense-phase supercritical fluid or a two- or three-phase fluid) has the potential to cause serious damage to the surrounding population, property and the environment. Failure can occur due to a range of potential causes, including accidental damage, corrosion, fatigue and ground movement. The acute safety consequences of such a failure are primarily due to the thermal radiation from an ignited release, whether directly (from the main release) or indirectly (from secondary fires). Quantified risk assessment applied to a pipeline involves the numerical estimation of risk by calculation resulting from the frequencies and consequences of a complete and representative set of credible accident scenarios. In general terms, a quantified risk assessment of a hazardous gas or liquid pipeline consists of the following stages: a) gathering data (pipeline and its location, meteorological conditions, physical properties of the substance, population) (5.1); b) prediction of the frequency of the failures to be considered in the assessment (5.2); c) prediction of the consequences for the various failure scenarios (5.3), including: •
calculation of release flow rate;
•
estimation of dispersion of flammable vapours;
•
determination of ignition probability;
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calculation of the thermal radiation emitted by fire in an ignited release;
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quantification of the effects of thermal radiation on the surrounding population;
d) calculation of risks and assessment against criteria: •
estimation of individual risk (Clause 6);
•
estimation of societal risk (Clause 7);
e) identification of site-specific risk reduction measures (Clause 8). Pipeline failure frequency is usually expressed in failures per kilometre year or per 1 000 kilometre years (km·y). Failure frequency should be predicted using verified failure models and predictive methodologies [4, 5, 6, 7], or otherwise derived from historical incidents that have occurred in large populations of existing pipelines that are representative of the population under consideration, as recorded in recognized, published pipeline data. Various factors may then be taken
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into account for the specific pipeline design and operating conditions to obtain the failure rate to be applied. NOTE Predictive models can be generated for all damage types and failure modes depending on the data available. In the UK, third-party interference is the dominant mode, and predictive models based on operational data are available [4, 5, 6, 7]. In general, failure frequency due to other damage types is derived using historical data [8, 9, 10].
The consequences of pipeline failures should be predicted using verified mathematical models, the results validated using experimental data at various scales up to full or comparison with recognized solutions, as well as comparison of model predictions with the recorded consequences of real incidents. The results of a consequence analysis should take into account all feasible events, in terms of the effect distance (radius) over which people are likely to become casualties. This should take into account people both outdoors and indoors. Pipelines present an extended source of hazard, and can pose a risk to developments at different locations along their route. Where a length of pipeline over which a location-specific accident scenario could affect the population is associated with a specific development, the full length over which a pipeline failure could affect the population or part of the population should be taken into account in the risk assessment. This length is known as the interaction distance (see Clause 6 and Clause 7).
5 Failure of hazardous gas or liquid pipelines 5.1
General Failure of a hazardous gas or liquid pipeline has the potential to cause damage to the surrounding population, property and the environment. Failure can occur due to a range of potential causes, including accidental damage, corrosion, fatigue and ground movement. The consequences of failure are primarily due to the thermal radiation that is produced if the release ignites. This can be caused directly, or indirectly by igniting secondary fires. Illustrative event trees for the failure of a hazardous pipeline are shown in Figure 2. NOTE 1 For detailed explanation of some of the consequence models which have been applied by HSE to derive existing Land Use Planning zones, see [11] to [14].
Failure of a high pressure pipeline can occur as a leak or rupture. Leaks are defined as fluid loss through a stable defect; ruptures are defined as fluid loss through an unstable defect which extends during failure, so the release area is normally equivalent to two open ends. The escaping fluid can ignite, resulting in a fireball, crater fire or jet fire which generates thermal radiation. Typical event trees for the failure of gas and liquid pipelines are shown in Figure 2. NOTE 2 Spray fire is equivalent to a jet fire from a liquid line. Fireballs are technically not possible but vapour cloud explosions (VCEs) can occur where the liquid in the pipeline produces heavier-than-air vapour.
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Figure 2 Event tree for the failure of a hazardous pipeline
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Immediate ignition
Delayed local ignition
Delayed remote ignition
Y
Fireball + spray + pool fire
Rupture
Pool fire A) B) VCE or flash fire
Y Y
N
Running fires C) VCE B) or flash fire Ground/water pollution C)
N
Pipe failure
N Y
Spray + pool fire
Puncture
Y
Pool fire A) Y
N
Running fire C)
N
Ground/water pollutionC)
N
a) Event tree for a liquid pipeline failure Release obstructed
Immediate ignition
Delayed local ignition
Delayed remote ignition
Y
Fireball + crater fire
Y
Y
Crater fire D) Y
N
N
Rupture
N Y
Flash fire B), E) + crater fire No ignition
Fireball + jet fires F) Y
N
Jet fires D), F) Y
N
N
Pipe failure
N Y
Flash fires B), E) + jet fires No ignition Impacted jet (crater) fire
Y
Y N
N
Impacted jet (crater) fire D) No ignition
Puncture Y
Jet fire Y
N N
N
Jet fire No ignition
b) Event tree for a gas pipeline failure A)
Ground/water pollution is also likely to occur.
D)
B)
If the vapour cloud could engulf any confined or congested region, the possibility of a VCE should be considered.
C)
Extent/distance will depend on ground permeability.
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There will be a limited flash fire which is not normally considered separately.
E)
Only credible for heavier than air gases.
F)
It is also possible for the release from one pipe end is obstructed and the other unobstructed.
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PD 8010-3:2009 For the assessment of a rupture release of a gaseous fluid, it is normally assumed that the ends of the failed pipe remain aligned in the crater and the jets of fluid interact. It is possible, e.g. at a location close to a bend or for a small diameter pipeline, for one or both pipe ends to become misaligned and produce one or two jets which are directed out of the crater and are unobstructed. Such releases can produce directional effects, making their assessment more complex. Where such a location or pipe is being assessed, the standard case would normally be assessed, then the sensitivity of the location to directional releases reviewed. A more detailed assessment might then be required which would go beyond the standard methodology described in this part of PD 8010. NOTE 3 For large diameter pipelines (i.e. >300 mm) this is a standard assumption.
If immediate ignition of a fluid release occurs, a fireball can be produced which lasts for up to 30 s and is followed by a crater fire. If ignition is delayed by 30 s or more, it is assumed that only a crater fire (jet obstructed) or a jet fire (jet unobstructed) will occur. For gases or vapours that are heavier than air, or form cold heavier‑than-air gas clouds when released, the possibility of a flash fire or VCE should be taken into account. The extent of such gas clouds depends on prevailing weather conditions at the time of release, the location of possible sources of ignition, and areas of congestion or confinement. The modelling of the consequences and effects of VCEs are not discussed in detail in this part of PD 8010. NOTE 4 In the case of natural gas, this scenario is not usually considered, as the release has a large momentum flux at the source and this normally has a significant vertical component. For the duration of the release relevant to the risk analysis, the transition to a low momentum (passive) release does not occur until the released natural gas has dispersed (is diluted) below the lower flammability limit.
The stages of pipeline risk assessment are represented in Figure 3. In general terms, a quantified risk assessment of a hazardous gas or liquid pipeline consists of four stages: a) input of data (pipeline and its location, meteorological conditions, physical properties of the substance, population); b) prediction of failure mode and frequency; c) prediction of consequences: •
calculation of release flow rate;
•
determination of ignition probability;
•
calculation of thermal radiation emitted by fire in an ignited release;
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quantification of the effects of thermal radiation on the surrounding population;
d) calculation of risks.
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Figure 3 Risk calculation flowchart for flammable substances Pipe geometry, material properties, operational parameters Location details (area category, depth of cover, protection etc) Population details Fluid properties Meteorological conditions
Input data
Determine failure rate data for leaks and ruptures due to: External interference
+
Material &
Corrosion
Failure frequency
+ construction + defects
Ground movement
+
Other
Calculate failure frequency Determine consequences based on: Release rate
+
Dispersion
+
Ignition
+
Type of fire
Consequences Thermal radiation
Individual risk
Effects of thermal radiation
Risk calculations
Societal risk
The first stage of the risk assessment process is to gather the required data to characterize the pipeline, its contents and the surrounding environment. These data are used at various stages of the analysis. The data should be obtained from engineering records, operating data, the pipeline operating limits in the pipeline notification and an examination of the pipeline surroundings. The principal input data required for a pipeline quantified risk analysis are:
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pipeline geometry – outside diameter, wall thickness;
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pipeline material properties – e.g. grade (SMYS, TS), toughness (or Charpy impact value), and any other data required to apply a fracture mechanics model or to calculate the design factor;
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pipeline operational parameters – maximum allowable operating pressure, temperature, pipeline shutdown period;
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location details, including: •
length and route of the pipeline to be assessed;
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topographical information in any region of interest (e.g. ground slope direction, location of drainage channels and ditches);
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location classification (class 1, class 2);
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•
•
depth of cover;
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additional protection measures for the pipeline (e.g. concrete slabbing);
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details of any above- and below-ground pipeline marking;
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development and building categories in the vicinity and their distance from the pipeline;
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population and occupancy levels within the consequence range of the pipeline;
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road/rail crossing details, including traffic density;
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river crossings;
physical properties of the material being transported, including: •
information to characterize the pressure, volume and temperature behaviour of the fluid throughout the range of conditions relevant to the analysis (e.g. from thermodynamic charts, tables or rigorous equations of state);
•
information to characterize any phase change within the fluid, e.g. from vapour to liquid (or vice versa), or to bound the dense phase region;
•
information about the density and viscosity of the fluid as a function of pressure, temperature;
atmospheric conditions, for example: •
details about ambient temperatures and pressures at the location of interest;
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atmospheric humidity;
•
information about wind speeds and directions.
Any site-specific variations in the data should be assessed, and justifications for any additional assumptions to be applied locally should be documented. In the case of depth of cover, site-specific depths should be taken into account. Where additional pipeline protection such as slabbing is to be taken into account, the design and installation should be assessed to ensure that additional loading is not imposed upon the pipeline, and direct contact should be maintained between the pipe coating and the surrounding soil.
5.2
Prediction of failure frequency Failure of a pipeline can occur due to a number of different causes such as: •
external interference;
•
corrosion [internal and external, including stress corrosion cracking (SCC) and alternating current (AC)/direct current (DC) induced corrosion];
•
material or construction defects;
•
ground movement;
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other causes, such as fatigue, operational errors etc.
The failure modes that should be assessed include leaks of various sizes (punctures) and line breaks (ruptures). A key parameter in setting the boundary between a leak of a stable size and a rupture is the critical defect length. © BSI 2008 •
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published document The critical defect length is the axial length of a through-wall defect which becomes unstable at the specific pipeline conditions, and above which a defect will continue to propagate along the pipeline until the defect size becomes equivalent to a rupture. This is primarily dependent on the pipeline diameter, wall thickness, material properties, fluid properties (in particular the compressibility) and operating pressure. The critical defect length is significant for external interference, where long, narrow crack-like defects can occur. In such cases, the crack opening area through which the fluid release occurs is transposed into an equivalent hole size which can be used for release calculations. Typical critical hole sizes for high pressure gas pipelines are given in Annex B. NOTE 1 Critical defect length and equivalent hole diameter applies to external interference where axial, crack-like defects can occur; the equivalent hole sizes which relate to such defects do not apply to rounded punctures, or stable holes due to corrosion or material and construction defects.
Leak sizes can range from pinholes up to a hole size equivalent to the critical defect size for the pipeline for external interference failures. A rupture release is typically represented by a full bore, double-ended break. The release is typically assumed to make a crater into which product is released from both ends of pipe. Typical failure frequencies for UK MAHPs are given in Annex B. Where other data sources are used, these should be documented. NOTE 2 In most cases the risk will be dominated by the rupture scenario. NOTE 3 The maximum possible hole size in high pressure gas pipelines is limited according to the critical defect size.
In a risk assessment, the likelihood of each failure scenario is evaluated and expressed in terms of failure frequency and pipeline unit length.
5.3
Prediction of consequences In the context of pipelines carrying flammable substances, for releases that ignite causing immediate hazards to people and property, consequence models are needed to predict the transient gas or liquid release rate, the ignition probabilities, the characteristics of the resulting fire (i.e. fireball, crater, jet, flash, spray or pool fire), the radiation field produced and the effects of the radiation on people and buildings nearby. The following aspects should be taken into account:
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outflow as a function of time (influenced by failure location, upstream and downstream boundary conditions, and by any response to the failure); pipeline rupture outflow requires complex calculations involving pressure reduction in the pipeline or two-phase flow for flashing liquids [15, 16]. Outflow from holes is calculated using conventional sharp-edged orifice equations for gas or liquid using a suitable discharge coefficient [13];
•
thermal radiation from the initial and reducing flow into the fireball if the release is ignited immediately;
•
thermal radiation from jet and crater fires. Jet fires that are unobstructed can have considerable jet momentum, resulting in a “lift-off” distance before the flame occurs, and therefore thermal radiation effects which can be greater in the middle and far field distance, depending on the release direction and degree
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of wind tilt. Crater fires can be modelled as large cylindrical flames starting at ground level having thermal radiation effects progressively reducing through near, middle and far distance; •
extent of the area covered by a flammable gas cloud causing a possible flash fire downwind of the release, and possible ignition points in downwind areas;
•
spillage rate and duration of release from a liquid pipeline affecting the local area and possibly causing a spray or pool fire.
Other consequences that are generally found to have a negligible effect on risk compared to fire effects include: •
release of pressure energy from the initial fractured section;
•
pressure generated from combustion during the initial phase if the release is ignited immediately;
•
missiles generated from overlying soil or from pipe fragments;
Additional aspects to be taken into account for pressurized liquid releases include: •
spray fires;
•
immediate and delayed ignition pool fires;
•
release of flammable liquids into water courses and the potential for running fires.
The consequence model should also take into account: •
wind speed, because this affects the crater fire and jet fire tilt and extent of the flash fire and hence the resulting radiation effects downwind; NOTE Weather category, as well as wind speed, also affects gas dispersion for flash fire prediction. In the UK, the conventional assumption is that night-time weather is modelled as Pasquill Category F and windspeed 2 m/s, and daytime as Category D and windspeed 5 m/s.
•
wind direction – required for a site-specific risk assessment where wind direction will affect the populated area non-symmetrically around the location of the fire;
•
humidity – this affects the proportion of thermal radiation absorbed by the atmosphere;
•
the type of ground environment, including topography where appropriate, into which a liquid is released.
There is considerable evidence from actual events and research work that immediate ignition events involving sudden large releases of flammable gases can cause a fireball to occur. Typical fireball burn times are 10 s to 30 s depending on pipeline diameter and pressure. Large releases of liquefied flammable gases, and flammable liquids containing LFGs such as spiked crude oil, can also cause a fireball to occur. When modelling either crater fires or unobstructed jet fires following a rupture, the transient nature of the release should be modelled. This calculation requires an estimate of the initial and steady state release rates and an estimate of the inventory of the pipeline network which is discharging to the release point. For generic calculations, the typical assumption made is that the break occurs half-way between compressor or pump stations (or pressure regulating station), with pressure being maintained from the upstream compressor, pump or © BSI 2008 •
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pressure reduction station and no reverse flow (with depressurization) occurring at the downstream check valve or regulator. When modelling jet fires from punctures, the release can be considered to be steady state. The consequence model usually assumes a vertical wind-blown jet flame. More elaborate models are possible with different angles of flame. The consequences predicted by such models are increased directionally, but the conditional probability is reduced. Flash fires occur when a plume of unignited heavier-than-air gas or vapour drifts downwind before finding a source of ignition. The ignition causes the fire to flash back to the source of release and then to cause a jet, crater or pool fire. A vapour cloud can drift further in night-time conditions (category F2) than daytime (category D5). The probability of flash fires is considered low, being dependent on the release source and the distribution of ignition sources in the vicinity of a pipeline. For non-flashing liquid releases from pipelines, the release rate is often dictated by the pumping rate at the point of release, depending on hole size. Small to medium holes can cause sprays and the hazard distance from spray fires can be significant. Large holes (>50 mm) in high pressure pipelines are likely to release the full pumping rate, so the consequences of large holes are similar to pipeline rupture. The amount released from a liquid pipeline is a function of the time taken to stop pumping, depressurization of the pipeline, and drain-down of adjacent sections of the pipeline. Spray releases occur when a flammable liquid is released at high velocity through a punctured pipeline.
5.4
Probability of ignition The risks from a pipeline containing a flammable fluid depend critically on whether a release is ignited, and whether ignition occurs immediately or is delayed. It is usually assumed that immediate ignition occurs within 30 s, and delayed ignition occurs after 30 s. Generic values for ignition probability can be obtained from data from historical incidents and these are product-specific. The various ignition possibilities such as immediate, delayed and obstructed or unobstructed, are drawn out logically on an event tree (see Figure 2) to obtain overall probabilities. Extensive references [12, 14,] are available for deriving probability of ignition for various situations (class 1, class 2, urban, roads, railways etc.). Probabilities used by HSE are discussed in Annex A.
5.5
Thermal radiation and effects Fatal injury effects are assumed for cases where people in the open air or in buildings are located within the flame envelope. Outside the flame envelope, the effects are dependent on direct thermal radiation from the flame to the exposed person or building. Thermal radiation is calculated from the energy of the burning material. There are two main methods of calculation in use: the view factor method, which assumes a surface emissive power from the flame, and the point source method, which assumes that all the energy is emitted from one (or several) point sources within the flame. The energy from the fireball pulse is usually calculated using the view factor method.
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PD 8010-3:2009 The thermal radiation effect at distances from the failure, calculated as the radiation dose, is summed through the complete fire event to determine the effect on people and property in terms of the piloted ignition distance for buildings, the escape distance for people out of doors, and the distance for which escape to safe shelter is possible. The thermal radiation effect from crater fires and jet fires is generally calculated by assuming that all persons outdoors, and indoors within the piloted ignition distance, try to escape. The cumulative thermal dose is then calculated, and the distance from the fire at which escape is possible without exceeding a threshold dose. The thermal dose unit (tdu), is defined as: tdu = W 4/3t where: t
is time, in seconds (s);
W is the intensity of thermal radiation, in kilowatts per square metre (kW/m2). NOTE 1 W is not independent of time for a transient release, and is normally summed over exposure until safe shelter, the dose limit or a cut-off thermal radiation level of, for example, 1 kW/m2 is reached.
Experimental and other data indicate that thermal radiation dose levels can have differing effects on a population depending on individual tolerance to such effects. The variation of effects has been estimated from burn data for human beings which suggests that the radiation level causing a significant likelihood of fatal injury in an average population is 1 800 tdu. This level of thermal dose is often used in risk assessments. NOTE 2 Due to the uncertainties in the effects of thermal radiation, a value of 1% lethality, equivalent to 1 000 tdu to 1 050 tdu as a threshold of dangerous dose or worse, is sometimes associated with such predictions (see Annex A).
In order to assess safe escape distance, a number of factors should be taken into account, including escape speed for people outside running away from the fire, location and types of buildings, populations indoors and outdoors, daytime or night-time, etc. The progression of a fire through the different stages of the event can be complex. The prediction of the thermal radiation effects is required to be summed through the event. This can prove difficult to achieve in a continuous way, hence the event might need to be subdivided into its stages and the effects summed later.
6 Individual risk assessment Individual risk is a measure of the frequency at which an individual at a specified distance from the pipeline is expected to sustain a specified level of harm from the realization of specific hazards. Individual risk contours for pipelines of given geometry, material properties and operating conditions form lines parallel to the pipeline axis. The distance from the pipeline at which a particular level of risk occurs depends upon the pipeline diameter, operating pressure, frequency of failure and failure mode. The risks from the various failure scenarios should be collated and the individual risk profile at various distances plotted on a graph. From
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this plot it is possible to identify the risk of a specified effect (e.g. fatality or dangerous dose) to an individual at a given distance from the pipeline. Shown in cross-section perpendicular to the pipeline, the risk levels are known as the risk transect. For a simple model where windspeed conditions are zero, the consequences are circular, the interaction distance (see Clause 4) is calculated as shown in Figure 4. The interaction distance shown can be multiplied by the pipeline failure frequency, the probability of ignition and the probability of effect to obtain the risk at any distance from the point of release. Figure 4 Calculation of pipeline length affecting an individual in the vicinity of a pipeline
1
1 2
2 3 4
4
a) Interaction distance = 2 × radius of circle = length of pipeline that could affect observer
R
D
R
4 b) Interaction distance = 2 ×
R2 − D2
Key 1
Location of observer, at distance D from the pipeline
2
Circular effect distance/consequence distance, radius R
3
Pipeline
4
Interaction distance for observer at location 1
Criteria for individual risk levels have been determined by the HSE in the UK. The framework for the tolerability of risk which gives individual risk values for the defined regions, published by HSE [17], is shown in Figure 5. HSE sets land use planning zones for major hazard sites, including high-pressure pipelines transporting defined hazardous substances based on individual risk levels. Land use planning zones applied to major accident hazard pipelines in the UK defined by HSE are discussed in Annex A.
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Figure 5 Framework for the tolerability of individual risk
Increasing individual risks and societal concerns
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Unacceptable region -3
1 x 10 (Worker) -4
1 x 10 (Public)
Tolerable if ALARP region
-6
1 x 10 (All)
Broadly acceptable region
7 Societal risk assessment Societal risk is the relationship between the frequency of the realization of a hazard and the resultant number of casualties. Societal risk can be generic, in which a constant distributed population in the vicinity of a pipeline is assumed, or site-specific, in which the details of particular developments, building layouts and population distributions are taken into account. Site-specific assessments are needed for housing developments, industrial premises, workplaces such as call centres, commercial and leisure developments, and any developments involving sensitive populations. Developments such as schools, hospitals and old people’s homes are classed as sensitive developments because of the increased vulnerability of the population groups involved to harm from thermal radiation hazards and the increased difficulty in achieving an effective response (e.g. rapid evacuation) to mitigate the consequences of an event such as a pipeline fire. The hazards associated with pipelines tend to be high consequence low frequency events, and therefore it is more appropriate that societal risk is used to assess the acceptability of pipeline risk. The calculation is carried out by assessing the frequency and consequences of all of the various accident scenarios which could occur along a specified length of pipeline. Societal risk is of particular significance to pipeline operators because the location of pipelines might be close to populated areas, so the impact of multiple fatality accidents on people and society in general should be taken into account. The original routing of the pipeline is expected to have taken into account the population along the
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route, but infill and incremental developments might increase the population in some sections of the route. Societal risk assessment allows these developments to be assessed against the original routing criteria where a location class 1 area has a population density of up to 2.5 persons per hectare. When the societal risk has increased significantly, the pipeline operator might then need to consider justifiable mitigation measures to reduce the risk. The criterion for societal risk is expressed graphically as an FN criterion line, showing the cumulative frequency F (usually per year) of accidents causing N or more casualties. For application to pipelines, it is necessary to specify a length over which the frequency and consequences of all accident scenarios are collated. Developing criteria for tolerability for hazards giving risk to societal concerns is not straightforward. Reference [17] describes the derivation of a societal risk limit from a study of Canvey Island and subsequently endorsed by the HSC’s Advisory Committee on Dangerous Substances in the context of major hazards transport. From this, HSE proposed that the risk of an accident causing the death of 50 people or more in a single event should be regarded as intolerable if the frequency is estimated to be more than one in five thousand per annum [17]. Subsequently HSE’s Hazardous Installations Directorate have proposed [18] criteria for major hazard sites in the context of the Control of Major Accident Hazards Regulations 1999 [19] (COMAH), based on the following which enables criteria for case societal risk to be defined for the FN diagram. The unacceptable region is taken as the region above the line of slope −1 through the defined point on the logF v. logN plot; and the broadly acceptable region is taken as the region below a line two orders of magnitude below, and parallel to, the −1 slope line (see Figure 6). The “tolerable if ALARP” region lies between these two lines. A typical medium-sized COMAH site might typically have a perimeter exposing risk to the public outside the site of 2 km, so the equivalent length of pipeline exposing the same risk to the public is 1 km. Therefore the same FN risk curves could be applied to 1 km of pipeline. In the absence of product-specific risk curves, it is therefore suggested that the FN criterion line given in Figure 6 should be used to assess societal risk due to MAHPs. This allows the assessment of the residual risk from a specific pipeline to be compared with the risk from the average class 1 pipeline population density (i.e. up to 2.5 persons per hectare) adjacent to each 1 km length of pipeline, where the population is assumed to be located in a strip centred on the pipeline from the MDOB, extending out to the hazard distance of the worst case event from the pipeline. In effect the FN criterion line represents the upper limit of the cumulative frequency of multiple fatality accidents in any 1 km section of a pipeline route assumed to be acceptable as implied by conformity to PD 8010-1. In the assessment of societal risk, the methodology applied should be consistent with the risk limit in terms of the length of pipeline considered. The FN criterion line shown here is applicable to assessments carried out using 1 800 tdu, equivalent to a significant likelihood of causing fatality.
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NOTE 2 In some cases, a product-specific criterion line might be available for assessing societal risk tolerability. An example of this is the FN envelope presented in IGE/TD/1:2001, Figure 20 for natural gas, which is based on the application of previous editions of IGE/TD/1. This envelope curve represents the boundary for a series of curves applying to numerous different pipeline cases which are acceptable in accordance with IGE/TD/1.
Figure 6 Societal risk FN criterion line applicable to 1 km of pipeline 1.E-02 Frequency (per year) of N or more casualties
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NOTE 1 The areas below the FN criterion line in Figure 6 represent broadly acceptable risk levels and therefore relevant good practice in both location classes 1 and 2.2)
1.E-03 1.E-04
B
1.E-05 1.E-06
A
1.E-07 1.E-08 1.E-09 1.E-10 1
10
100
1 000
Number of casualties Key A Broadly acceptable B
Tolerable if ALARP
Population density tends to vary along a pipeline route, with clusters of population at some locations. Assessment of the societal risk in accordance with the FN criterion line might still allow such variations to be classified as an acceptable situation not requiring any upgrading of the pipeline to reduce the risk. The methodology for assessing risk scenarios, failure cases, failure frequencies and consequences is similar to that used to obtain individual risk levels. To carry out a site-specific societal risk assessment, the maximum distance over which the worst case event could affect the population in the vicinity should be determined, e.g. the site length combined with the maximum hazard range within which the population is to be assessed (see Figure 7). This is defined as the site interaction distance.
2) Operators
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published document The accident scenarios which are relevant for the pipeline section within the site interaction distance should be listed, and the actual population density within the area defined by the pipeline section and the interaction distance (see Figure 7) determined. The frequency, f, and effect area for each accident scenario should then be assessed along the site interaction distance, and the number of people, N, who would be affected, is determined for each scenario at each specific location. This provides a number of fN pairs, which are then ordered with respect to increasing number of casualties, N, and the cumulative frequency, F, of N or more people being affected is determined, giving a site-specific FN curve.
Figure 7 Site-specific pipeline interaction distance
1
2
3
Key 1
Maximum hazard range within which population is to be assessed
2
Pipeline
3
Site interaction distance Existing buildings New buildings
NOTE 3 The shape and dimensions of the site-specific hazard range is dependent upon the characteristics of the released fluid, the presence of directional effects and, for heavier-than-air gases and liquids, the topography.
The site-specific FN curve should be compared with the FN criterion line in Figure 6. As the FN criterion line relates to a 1 km length of pipeline, the site-specific FN curve is obtained by factoring risk values by a factor equal to 1 km divided by the site interaction distance. The FN criterion line given in Figure 6 represents broadly acceptable risk levels for pipeline operation. If the calculated site-specific FN curve falls below the FN criterion line, the risk levels to the adjacent population are considered broadly acceptable. If the site-specific FN curve is close to or above the FN criterion line, then further mitigation might be required to reduce risks to acceptable/negligible levels if this is economically justifiable in terms of the requirement to demonstrate that the risks are ALARP. Alternatively, the proposed development might be deemed unacceptable in that the societal risk levels are too high.
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If the specified area of interest includes another pipeline, the risk from this pipeline should be included in the assessment if it is considered that: •
the pipelines could interact such that a failure on one pipeline would lead to the failure of the other pipeline;
•
the development site under consideration is within the interaction distances of more than one major accident pipeline in the specified area.
If pipeline interaction is considered likely then expert opinion should be obtained on how to model the combined failure frequencies and product outflow. The pipelines should be individually assessed and the risk from each summed to obtain overall individual risk transects and societal risk FN curves. When assessing multiple pipelines, FN data should be obtained for each pipeline assessed. When calculating the overall risk it is necessary to combine the individual FN pairs from each assessment. This data should then be factored by a value equal to 1 km divided by the sum of the interaction lengths for each pipeline considered, and compared to the FN criterion line.
8 Factors affecting risk levels 8.1
Individual factors influencing pipeline failure frequency All the key damage mechanisms should be taken into account when carrying out a risk assessment. Typical causes classified in databases include: a) external interference; b) corrosion, either internal or external; c) mechanical failure, including material or weld defects created when the pipe was manufactured or constructed; d) ground movement, either natural (e.g. landslide) or artificial (excavation, mining); e) operational, due to overpressure, fatigue or operation outside design limits. Assessment of pipeline failure databases shows that external interference and ground movement dominate pipeline rupture rates, and these have the greatest effect on risk from pipelines. The failure rates due to other damage mechanisms can be managed and controlled by competent pipeline operators through testing, inspection, maintenance and operational controls in accordance with PD 8010-1:2004, Clause 13. The failure rate for external interference is influenced by a number of parameters, including the pipeline wall thickness, design factor and material properties, as well as the location class, the pipeline depth of cover and the local installation of pipeline protection such as slabbing. The failure rate for natural ground movement and for artificial ground movement depends upon the susceptibility to landsliding or
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subsidence at the specific location. In some cases other causes might need to be considered in specific locations, such as the quality of girth welds, the potential for stress corrosion cracking (SCC) or alternating current (AC)/direct current (DC) induced corrosion. The failure frequency associated with each damage mechanism should be determined using published operational data sources [8, 9, 10], or predictive models validated using such data. Typical failure frequencies for UK MAHPs based on UKOPA data are given in Annex B. The risk analysis requires the principal input data described in 5.1. Any site-specific variations should be assessed, and justifications for any additional assumptions to be applied locally should be documented. In the case of depth of cover, site-specific depths should be taken into account. Where additional pipeline protection such as slabbing is to be taken into account, the design and installation should be assessed to ensure that additional loading is not imposed upon the pipeline, and that cathodic protection is maintained. The determination of failure rate data requires several parameters to be taken into account, including: •
pipeline diameter;
•
pipe wall thickness;
•
design factor;
•
depth of cover;
•
steel type and properties;
•
location class (1 or 2).
In determining the external interference failure frequency, it is recommended that the damage incidence rate for location class 2 areas should be assumed to be higher than for class 1 areas. Typically, the factor applied is approximately four times that for location class 1 areas, i.e. the failure frequency in a class 2 area is four times that in a class 1 area. Data relating to class 1 and 2 incident rates for UK MAHPs is provided by UKOPA [9]. The failure rates obtained from database records or predictive models should be justified for application to a site-specific case. Generic failure data might not be applicable to specific cases. Information is given in Annex B.
8.2
Factors for reduction of the external interference failure frequency for use in site-specific risk assessments NOTE 1 An example of a site-specific risk assessment is given in Annex C. Examples of typical benchmark solutions are given in Annex B.
The primary residual risk for existing pipelines is that due to external interference. Risk mitigation measures are identified and agreed as necessary by the statutory authority or relevant stakeholder. These should be installed prior to the completion and use of any new development within the pipeline consultation zone. Risk mitigation measures fall into two categories: physical and procedural. Procedural measures rely upon management systems and can be subject to change over time, and therefore might only be applicable for short‑term risk control.
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Physical measures include: •
wall thickness and design factor;
•
slabbing;
•
depth of cover.
Procedural measures include: •
additional surveillance;
•
additional liaison visits;
•
additional high visibility pipeline marker posts.
A site-specific risk assessment should take into account relevant details of the pipeline, and should document justification of any assumptions applied following assessment of these details. The pipeline failure frequency due to external interference is obtained as follows: F = (PoF × I) / OE where: F
is the pipeline failure frequency;
I is the number of external interference events causing damage in a given pipeline population; OE is the operational exposure of the pipeline population, in kilometre years (km·y); I/OE is the damage incidence rate. NOTE 2 The number of external interference events causing damage , and the operational exposure, relate to the population that the pipeline is part of, not just the pipeline itself. Pipeline failure frequencies derived from published operational data sources are given in Annex B.
When predicting site-specific pipeline failure frequencies for external interference, the parameters listed above should be taken into account. A number of factors which describe the specific effects of wall thickness, design factor, depth of cover, surveillance frequency and damage prevention measures (slabbing and marker tapes) are described in the present subclause. These factors can be used to assess the effect of individual measures on a known or existing unadjusted pipeline failure frequency for a particular pipeline, or to obtain a failure frequency prediction for a given pipeline. Appropriate factors can be applied cumulatively to the base failure frequency for the particular pipe diameter as shown in Annex B. The influence of specific parameters on the predicted pipeline failure frequencies is given as reduction factors as follows: •
Rdf – reduction factor for design factor, given in Figure 8 and Table 1;
•
Rwt – reduction factor for wall thickness, given in Figure 9 and Table 1;
•
Rdc – reduction factor for depth of cover, given in Figure 10;
•
Rs – reduction factor for surveillance frequency, given in Figure 11;
•
Rp – reduction factor for protection measures, given in Table 2.
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Figure 8 Reduction in external interference total failure frequency due to design factor
0.8
Reduction factor
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1.0
0.6
0.4
0.2
0.0 0.1
= e 0.97 (f -0.72)
0.2
0.3
0.4
0.5
0.6
0.7
0.8
Design factor
NOTE Figure 8 relates to a pipe wall thickness of 5 mm, and can be used to assess the influence of design factor on failure frequencies due to external interference for pipelines with wall thickness equal to or greater than 5 mm.
Figures 8 and 9 show simple reduction factors for design factor and wall thickness which can be used in estimating the failure frequency due to external interference. These two reduction factors have been derived from the results of comprehensive parametric studies [20, 21, 22] carried out using models which describe the failure of a pipeline due to gouge and dent-gouge damage [23, 24, 25], and damage statistics for such damage derived from the UKOPA pipeline database [9]. The reduction factors take the form of a factor for the design factor and a factor for wall thickness, which are applied either to a predicted pipeline PoF or to a failure frequency predicted for a specific pipeline using a specific damage incidence rate. The range of pipeline parameters over which the reduction factors are applicable is given in Table 1. The reduction factors given in Figures 8 and 9 are based on a conservative interpretation of the parametric study results. They may be applied separately to modify existing risk assessment results (i.e. to modify existing risk assessment results taking into account local changes in wall thickness), or may be used more comprehensively to estimate the failure frequency in screening risk assessments, using both reduction factors in conjunction with the generic failure frequency curve in Annex B as an alternative to using more complex structural reliability based methods. Further details are given in Annex B.
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Figure 9 Reduction in external interference total failure frequency due to wall thickness
0.8
Reduction factor
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1.0
e -0.24 (t-5) f = 0.72
0.6
=
e -0.31 (t-5) f = 0.5 e -0.39 (t-5) f = 0.3
0.4
0.2
0.0
4
6
8
10
12
14
16
18
20
Wall thickness (mm)
NOTE Figure 9 relates to design factors of 0.72, 0.5 and 0.3 and can be used to assess the influence of wall thickness on failure frequency due to external interference for pipelines with design factor less than or equal to these values.
Table 1
Range of applicability of reduction factor for design factor, Rdf, and reduction factor due to wall thickness, Rwt Parameter
Range of applicability of Rdf and Rwt
Design factor
G0.72
Wall thickness
H5.0 mm
Material grade
GX65
Diameter
219.1 mm to 914.4 mm
Charpy energy
H24 J (average)
Figure 10 shows a simple reduction factor for depth of cover which can be used to assess the reduction in damage incidence rate in the estimation of the failure frequency due to external interference. This reduction factor has been derived from the results of published studies [26]. Use of this reduction factor places a requirement on the pipeline operator to carry out and document periodic checks to confirm that the depth of cover is being maintained (see 8.3.4).
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Figure 10 Reduction in external interference total failure frequency due to depth of cover
1.4
Reduction factor
1.2 1.0 0.8 0.6 0.4 0.2 0
0.5
0
2.0
1.5
1.0
3.5
3.0
2.5
Depth of cover (m)
Figure 11 shows a simple reduction factor for a surveillance interval which can be used to assess the reduction in damage incidence rate in the estimation of the failure frequency due to external interference. This reduction factor has been derived from the results of studies carried out by UKOPA relating infringement incidence data to damage incidence data [27]. Figure 11 Indicative reduction in external interference total failure frequency due to surveillance frequency (dependent on frequency and duration of unauthorized excavations) 1.4 1.2 Risk reduction factor
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1.6
1.0 0.8 0.6 0.4 0.2 0
0
5
10
15
20
25
30
Surveillance interval (days)
Table 2 gives reduction factors that apply to pipeline protection measures, which can be used to assess the reduction in damage incidence rate in the estimation of the failure frequency due to external interference. These factors are based on expert studies [28].
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Table 2 Failure frequency reduction factors, Rp, for pipeline protection Measure
Reduction factor Rp
Installation of concrete slab protection
0.16
Installation of concrete slab protection plus visible warning
0.05
NOTE 1 Concrete slabbing with high visibility marker tapes has been shown to achieve significant risk reduction factors below 0.1 [28]. NOTE 2 In order to use the reduction factor, the physical barrier mitigation measures should apply to the whole pipeline interaction length for every failure that has to be considered.
The reduction factors given in Figure 8 and Figure 9 affect the pipeline tolerance to defects and therefore the PoF, whereas the reduction factors given in Figure 10, Figure 11 and Table 2 affect the damage incident rate, I/OE. For site-specific risk assessments, the main factors affecting failure frequency should be given careful consideration and the appropriate reduction factor applied as follows: a) probability of failure, RPoF, determined using the recommended reduction factors given in this subclause for: •
Rdf (reduction factor for design factor);
•
Rwt (reduction factor for wall thickness);
NOTE 3 Rdf and Rwt have been derived from a parametric study in which Rdf is derived for a constant wall thickness of 5 mm, and Rwt is derived for a constant design factor of 0.72. These reduction factors can be applied together within the limits of applicability given in Table 1, e.g. when used in conjunction with the base pipeline failure frequencies given in Annex B.
b) the factor reduction on number of incidents (or incident rate), RIR, determined using the recommended reduction factors given in this subclause for: •
Rdc (reduction factor for depth of cover);
•
Rp [reduction factor for protection (slabbing and marking)].
Factors for risk control measures along the pipeline route to reduce the number of incidents may be applied as follows for other mitigation measures, using reduction factors assessed by the risk analyst for specific situations: •
Rs (reduction factor for surveillance frequency);
•
Rlv (reduction factor for additional liaison visits);
•
Rmp (reduction factor for additional high visibility marker posts).
NOTE 4 With respect to control of risk to developments in the vicinity of pipelines, the application of Rs , Rlv might only be applicable for short term/temporary developments only (e.g. fairs, festivals, temporary construction sites etc.). No recommendations are made here for values of Rlv and Rmp. Assessment should be carried out for specific cases.
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8.3
8.3.1
Implementation of risk mitigation measures General The implementation of risk mitigation measures should be carried out in accordance with PD 8010-1 and the recommendations given in 8.3.2 to 8.3.5.
8.3.2
Relaying the pipeline in increased wall thickness The pipeline should be designed in accordance with PD 8010-1:2004, Clauses 5, 6 and 8, constructed in accordance with PD 8010-1:2004, Clause 10, and tested in accordance with PD 8010-1:2004, Clause 11. Particular care is required where the consolidation of the pipeline trench bed is disturbed allowing settlement. Settlement at the tie-in points with the existing pipeline should be avoided. The function and integrity of pipeline corrosion protection across the new section and at the points of connection with the existing pipeline should be confirmed to be adequate and fit for purpose in accordance with PD 8010-1:2004, Clause 9. The rationale for the design of the new pipeline section should be specified and justified in relation to the need for risk reduction, e.g.:
8.3.3
•
design factor specified as 0.3 to reduce pipeline PoF at operating conditions;
•
selection of the wall thickness to achieve an acceptable pipeline PoF;
•
selection of wall thickness in relation to risks to new planned development;
•
selection of design factor and wall thickness based on ALARP calculations.
Laying slabbing over the pipeline Installation of slabbing to provide impact protection to the pipeline should be carried out in accordance with PD 8010-1:2004, 6.9.7 and in accordance with details specified in IGE/TD/1. The structural loads imposed on the pipeline by the slabbing should be taken into account. The installation of concrete slabbing over the pipeline can restrict access to the pipeline in the event of coating deterioration or corrosion damage. It is therefore recommended that a coating survey is carried out prior to the installation of slabbing, that the results of previous in-line inspection are assessed to determine whether there are any indications of corrosion in the length of pipeline to be slabbed that might need assessment and/or repair prior to slabbing, and that the functionality and integrity of the cathodic protection system is confirmed before and after installation of the slabbing.
8.3.4
Taking account of increased depth of cover Increased depth of cover at the location under consideration may be taken into account where this exceeds the recommendations given in PD 8010-1:2004, 6.8.3. A full survey of the actual depth of cover over the full interaction distance at the location under consideration should be carried out in order to record the depth of cover. A justification of the permanence of the depth of cover should
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PD 8010-3:2009 be prepared, including the reason for the increased depth of cover, the type of soil, the susceptibility to land sliding and the current and future land use. The depth of cover should be rechecked at specified locations during pipeline route inspections carried out in accordance with PD 8010-1:2004, 13.3.2 to detect factors that could affect the safety and operation of the pipeline. Such checks should be carried out at intervals not exceeding 4 years.
8.3.5
Installing additional pipeline markers PD 8010-1:2004, 10.14 recommends that pipeline markers be installed at field boundaries, at all crossings and, where practicable, at changes in pipeline direction. In addition, high visibility pipeline markers, providing further information on contacts and emergency telephone numbers, can be installed as an additional risk mitigation measure. (See PD 8010-1:2004, 13.3.2 and E.9.)
8.3.6
Increasing surveillance frequency PD 8010-1:2004, 13.3.2 recommends that pipeline route inspections should be carried out. Where route inspections are carried out at two‑weekly intervals, increasing the surveillance frequency will increase the likelihood of detection of activities that could damage the pipeline. The surveillance frequency may be increased using walking or vantage point surveys at specific locations as a risk mitigation measure. Full details of any additional mitigation measures installed or implemented should be recorded in the pipeline records systems or included in the major accident prevention document (MAPD) for the pipeline.
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Annex A (informative)
A.1
Summary of HSE methodology for provision of advice on planning developments in the vicinity of major accident hazard pipelines in the UK Land use planning zones The Health and Safety Executive (HSE) sets land use planning zones for major hazard sites, including high-pressure pipelines transporting defined hazardous substances, so that it can provide advice to the local planning authorities on the risks posed by major hazards to people in the surrounding area. Land use planning zones are used by HSE for MAHPs as defined by Regulation 18 and Schedule 2 of the Pipeline Safety Regulations 1996 [1], and to pipelines that were notified under the Notification of Installations Handling Hazardous Substances Regulations 1982 [29] before the enactment of the Pipeline Safety Regulations 1996. Land use planning zones define three areas: •
inner zone, which is immediately adjacent to the pipeline;
•
middle zone, which applies to significant development;
•
outer zone, which applies to vulnerable or very large populations.
The zone boundaries are determined by HSE using a process for calculating individual risk levels, based on information provided to HSE by the pipeline operator. HSE then notifies the inner, middle and outer zone distances to local planning authorities. The outer zone distance is also called the consultation zone, within which the risk implications of proposed developments that significantly increase the population density have to be considered by the local authority. Local planning authorities in Great Britain are responsible for land use planning decisions under the Town and Country Planning Act 1990 [30], and HSE is a statutory consultee with responsibility to provide advice with respect to public safety for any developments planned within or which straddle the consultation zone. Detailed guidance defining the HSE advice (“advise against” or “do not advise against”) for various types of development is contained in a comprehensive document available from the HSE website entitled Planning advice for developments near hazardous installations (PADHI+) [31]. A developer or local planning authority might wish to seek further information to see whether the risk at the specific development location is different from the generalized land use planning zone notified by HSE, or whether additional risk reduction measures (risk mitigation) can be applied at that location, to allow the planned development to proceed. Land use planning zones notified to local planning authorities by HSE are based on pipeline details provided in the operator’s pipeline notification, and do not cover local variations. Where local pipeline details differ from the notified conditions, including whether the pipeline has additional protection [e.g. thicker walled pipe or slabbing3)]
3)
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The risk reduction factors given in 8.2 are not currently used in the HSE methodology. Risk reduction factors associated with slabbing are currently under review by HSE.
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near the proposed development), a detailed risk assessment is carried out by HSE to assess any change to zone boundaries. At the time when the pipeline operator becomes aware of the possibility of a development near a pipeline, especially if it involves an increase in population within 1 MDOB, they need to assess the population increase against the original routing parameters. In some cases they might decide to initiate a full societal risk assessment to define acceptability or otherwise of the development against the FN risk curve presented in Figure 6, before deciding whether to object to the proposed development. In these cases, there is a need to reassess the impact of site-specific details on the risk levels within the interaction zone using an established risk assessment methodology. The guidance in this part of PD 8010 is provided for use by pipeline operators, local planning authorities, developers and any person involved in the risk assessment of developments in the vicinity of existing MAHPs. It is based on the established best practice methodology for pipeline risk assessment. It is recommended that the methodology be used for the prediction of site-specific risk levels for consideration in the reassessment of land use planning developments, so that specific local conditions can be taken into account. The process is shown in Figure A.1. HSE has adopted a risk-based approach for calculating the distances to the zone boundaries from the pipeline, defining the levels of risk at each boundary as follows: a) boundary between inner and middle zone – based on the greater of: 1) an individual risk of (1 × 10−5) per year of dangerous dose or worse to the average householder; or 2) the pipeline MDOB; NOTE 1 Because of the low levels of risk, some MAHPs will not have an inner zone based on an individual risk level of (1 × 10−5) per year. However, an inner zone equivalent to the MDOB has been applied by HSE to MAHPs. This distance is calculated using the equation and substance factors given in PD 8010-1:2004, 5.5.3. NOTE 2 In the past, HSE has used a consequence-based approach for calculating this distance.
b) boundary between middle zone and outer zone – an individual risk of (1 × 10−6) per year of dangerous dose or worse to the average householder; c) boundary between outer zone and no restrictions – the lesser of: 1) an individual risk of (0.3 × 10−6) per year of dangerous dose or worse to the average householder; 2) notified outer zone distance. NOTE 3 In cases where the calculation of risks indicates risk levels are lower than (1 × 10−6) per year and therefore there is no middle zone, the inner and middle zones are made equal to the MDOB. Similarly, where risk calculations show levels lower than (0.3 × 10−6) per year, all three zones, inner, middle and outer, are made equal to the MDOB (PD 8010-1:2004, 5.5.3). NOTE 4 The location of very large sensitive developments (e.g. very large hospitals, schools, old people’s homes) is restricted to the outer zone (see also Clause 7). © BSI 2008 •
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Figure A.1 Planning application process and need for site-specific risk assessment
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Application for Planning Permission submitted to Local Planning Authority
PADHI + assessment applied by Local Planning Authority
No safety or risk issues for LPA to consider with this Planning Application
Do not Advise Against NOTE 1
Planning decision result?
Advise Against
Pipeline design different from notified details
HSE Advise Against letter may prompt developer to request further information from the pipeline operator on the pipeline design in the vicinity of the development
Pipeline details as notified
HSE reassess risks which may revise LUP zone distances
Do not Advise Against NOTE 1
Planning decision result?
Advise Against
Developer may request Pipeline Operator to consider further risk reduction / mitigation measures in vicinity of proposed development NOTE 2
HSE reassess risks which may change advice
Improvements agreed and implementation planned
Do not Advise Against NOTE 1
Planning decision result?
Advise Against
Risk reduction / mitigation measures proposed and evaluated Cost effective risk reduction may not be possible. Results of risk assessment can be given to LPA for consideration
NOTE 1 In all cases where the PADHI+ decision is “do not advise against”, the pipeline operator needs to consider the impact of increased population within the consultation zone and the effect on the original routing decisions made for the pipeline, especially if the development is within 1 MDOB. If significant population increase is likely to occur if the planning development goes ahead, the pipeline operator might need to carry out a societal risk assessment to allow comparison with the societal risk criteria in Figure 6. If unfavourable results are obtained from the societal risk assessment, the pipeline operator might consider objecting to the proposed development. NOTE 2 In cases where risk mitigation measures are being considered, the land use planning individual risk assessment and the pipeline operator’s societal risk assessment need to be carried out in parallel, so that a common understanding using the same data and risk assessment assumptions allows the effectiveness of the mitigation to be agreed.
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MDOBs are given in PD 8010-1:2004, 5.5.3. In the case of mixtures, it might be appropriate to take into account proportions when calculating this distance. Dangerous dose is defined by HSE as a dose of thermal radiation that would cause: 1) severe distress to almost everyone in the area; 2) a substantial fraction of the exposed population requiring medical attention; 3) some people being seriously injured, requiring prolonged treatment; 4) any highly susceptible/sensitive people being killed. NOTE 5 Due to the uncertainties associated with such predictions, the “dangerous dose” concept is used by HSE to define land use planning zones. Normally, a dangerous dose for thermal radiation is defined as 1 050 tdu. These criteria are based on the assumption that the exposed people are typical householders and indoors most of the time. There are a number of aspects of the HSE land use planning and major hazards work that PADHI+ [31] does not deal with, including developments near pipelines, where the pipelines have sections with additional protection measures. PADHI+ uses the three zones set by HSE that are based on the details given in the pipeline notification. In cases where local pipeline details differ from notified details, then HSE risk assessors might be willing to reconsider the case using the details relevant to the pipeline near the development.
A.2
Distances to risk zones Current HSE land use planning distances to (1 × 10−6) and (0.3 × 10−6) risk contours for ethylene, spiked crude and natural gas liquids (NGLs) are given in Table A.1. Zone distances based on these risk levels notified to the local planning authorities are as calculated by HSE, and therefore might differ from equivalent risk levels calculated using other methodologies. Where possible, specific assumptions made by HSE are given in this document, so that the effect can be quantified.
Table A.1 Typical (1 × 10−6) and (0.3 × 10−6) risk distances for ethylene, spiked crude and natural gas liquids (NGLs) Content of pipeline
Distances to risk zones MAOP
Diameter
Wall thickness
bar
mm
mm
Ethylene
95
219
7.03
Ethylene
95
273
Ethylene
99
Spiked crude NGL
MaterialA)
Distance to (1 × 10−6) risk contour
Distance to (0.3 × 10−6) risk contour
m
m
X42
150
200
7.09
X52
190
230
273
5.56
X52
240
320
64
914
9.52
X65
380
435
69
508
9.52
X52
432
485
−6
−6
NOTE The land use planning zones defined in Table A.1 as (1 × 10 ) and (0.3 × 10 ) risk distances were calculated by HSE using historical rupture frequency data. A)
As specified in ISO 3183‑2:1996.
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Specific HSE methods and assumptions
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NOTE Specific methods applied and assumptions made by HSE are given in this Annex so that the impact on calculated risk values can be considered.
A.3.1
Prediction of consequences In predicting consequences, HSE calculates the reducing release rate with time and so obtains the cumulative amount released. The time required to release the cumulative amount is then compared with the burn time of a fireball containing the cumulative amount released; when the two times are equal, the largest fireball is obtained. NOTE Uncertainties relating to the near field consequence analysis are accommodated through the application of an inner zone based on the MDOB, which is calculated using the formula and substance factors given in PD 8010-1:2004, 5.5.3.
A.3.2
Probability of ignition Typical overall probabilities for flammable gases, other than natural gas, used by HSE are: •
immediate ignition resulting in a fireball followed by jet fire: 0.2;
•
delayed ignition resulting in a jet fire: 0.512;
•
delayed ignition resulting in a flash fire followed by a jet fire: 0.128;
•
no ignition: 0.16.
NOTE Other probabilities are observed in historical data.
A.3.3
Thermal radiation and effects HSE assumes that the typical person will move away from the fire at a speed of 2.5 m/s and will find shelter at a distance of 75 m in a class 1 environment or at a distance of 50 m in a class 2 environment, provided that the thermal radiation dose they receive does not exceed 1 050 tdu. If the cumulative thermal dose exceeds 1 050 tdu, then the typical person is deemed to have received a dangerous dose. The methodology used by HSE calculates the distance to the spontaneous ignition of wood, and people inside buildings within this distance are assumed to become fatalities. People inside buildings outside the distance to the spontaneous ignition but within the distance to the piloted ignition of wood are assumed to survive the fireball, but are then assumed to try to escape from the building and to be subject to the thermal radiation effects from the crater fire. For people inside buildings that are beyond the distance to piloted ignition, the building is assumed to provide full protection. People inside buildings engulfed by pool fires or spray fires are assumed not to escape. HSE assumes that the average householder is present 100% of the time. The proportion of time the average householder spends indoors during the day is 90%, and the proportion at night is 99%. For further details of HSE’s consequence models, see [11, 14, 15, 32, 33].
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Annex B (informative)
B.1
Failure frequencies for UK pipelines General In deriving the failure frequency for a specific pipeline, all credible damage mechanisms and location specific factors that can influence the frequency of failure due to each individual mechanism need to be assessed.
B.2
All damage mechanisms Pipeline failure frequencies for the population of UK major accident hazard pipelines derived from UK data collated since 1962 and published by UKOPA are given in Table B.1.
Table B.1 Failure rates for UK pipelines based on UKOPA data Units in failures per 1 000 km·y Damage mechanism
PinA)
HoleB)
RuptureC)
Total
% pin
% hole
External interference
0.006
0.04
0.011
0.057
10.5
70.2
19.3
External corrosion
0.035
0.011
0
0.046
76.1
23.9
0
Internal corrosion
0.003
0
0
0.003
100.0
0
0
Material and construction
0.063
0.013
0
0.076
82.9
17.1
0
Ground movement
0.003
0.004
0.002
0.009
33.3
44.4
22.2
Other
0.052
0.019
0.002
0.073
71.2
26.0
2.7
Total
—
—
—
0.264
—
—
% rupture
—
A)
Equivalent diameter up to 6 mm.
B)
Equivalent diameter greater than 6 mm but less than pipe diameter.
C)
Equivalent diameter equal to or greater than pipe diameter.
NOTE Application of pipeline failure rates in a site-specific risk assessment requires careful consideration of local details.
The data given in Table B.1 represents the overall averaged set of failure frequencies applied to the whole pipeline population included in the database. It is presented to enable general comparison of the datasets only, and is not intended to be applied to specific pipelines. Further information is available in the UKOPA pipeline fault database report [9]. In order to apply the above data in a pipeline risk assessment, account needs to be taken of pipeline-specific factors such as wall thickness, pressure, diameter, material properties, location, environment and pipeline operator management practices. Based on an analysis of the data given in Table B.1, the data and examples given in B.3 to B.8 for failure frequency for the different damage mechanisms apply to UK MAHPs.
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Prediction of pipeline failure frequency due to external interference Pipeline damage due to external (third-party) interference is random in nature, and as operational failure data is sparse, recognized engineering practice requires that a predictive model is used to calculate failure frequencies for specific pipelines. These models allow the prediction of failure frequencies taking into account pipeline diameter, wall thickness, material properties and pressure. Operational data relating to failure frequency due to external interference is presented in Tables B.2 and B.3.
Table B.2
Failure frequency due to external interference vs. diameter Units in failure frequency per 1 000 km·y Diameter (mm)
PinA)
HoleA)
RuptureA)
Total
100
0
0.119
0.03
0.149
250
0.022
0.072
0.022
0.116
400
0
0.079
0
0.079
560
0.01
0.01
0.01
0.03
700
0
0.028
0
0.028
860
0
0
0.031
0.031
1 200
0
0
0
0
A)
See Table B.1 for definitions.
Table B.3
Failure frequency due to external interference vs. wall thickness Units in failure frequency per 1 000 km·y Wall thickness (mm)
PinA)
HoleA)
RuptureA)
Total
10 to 15
0
0.012
0.004
0.016
>15
0
0
0
0
A)
See Table B.1 for definitions.
NOTE Failure frequency predictions based on assessment of current operational fault and failure data are published by UKOPA [9].
B.4
B.4.1
Generic pipeline failure frequency curve for external interference General A generic pipeline failure frequency curve for external interference which can be used with the failure frequency reduction factors for design factor and wall thickness given in Figure 8 and Figure 9 respectively is derived by predicting the failure frequency for pipelines
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PD 8010-3:2009 of varying diameter with a constant design factor of 0.72, a constant wall thickness of 5 mm and a material grade of X65. This curve is shown in Figure B.1. The generic failure frequency curve has been generated using probabilities of failure produced using the original dent-gouge model [23, 24, 25]. The failure model is two-dimensional, and predicts the total probability of through wall failure, i.e. for leaks and ruptures. A conservative assumption for the proportion of ruptures which can be applied to the generic failure frequency curve is 0.7. However, the leak/rupture failure mode is dependent upon the critical length of an axial defect, which is dependent upon both the diameter and the wall thickness, so the proportion of ruptures of 0.7 needs to be treated as an upper bound. The data presented in B.5 can be used to select a more representative value. NOTE 1 Predicted failure frequencies due to external or third-party interference increase with material grade due to the consequent reduction in wall thickness, so the generic curve given in Figure B.1 can be conservatively applied to pipelines with material grades of X65 and lower. NOTE 2 The generic curve given in Figure B.1 provides failure frequencies for pipelines in R areas. Failure frequencies for pipelines in S areas can be derived by multiplying the R area failure frequency by a factor of 4, as recommended in 8.2.
Figure B.1
Generic predicted pipeline failure frequencies for third-party interference 0.225 Total failure frequency per 1 000 km .y
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0.22 0.215 0.21 0.205 0.2 0.195
0.0
200.0
400.0
600.0
800.0
1 000.0
Diameter (mm)
Use of the generic failure frequency curve with a fixed proportion of ruptures of 0.7 is conservative. In cases where risk levels are critical, a pipeline specific analysis needs to be carried out using a recognised failure frequency prediction tool. The failure frequency prediction tool recommended by UKOPA is FFREQ (see B.5.1). Example calculations of failure frequency using the generic failure frequency curve and the design factor and wall thickness failure frequency reduction factors are given in B.4.2, and the estimated values are compared with FFREQ predictions for the equivalent pipeline case.
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B.4.2
B.4.2.1
Estimation of pipeline external interference failure frequency using the generic failure frequency curve Example 1: Estimation of external interference failure frequency for 219 mm diameter, 5.6 mm wall thickness pipeline operating at a design factor of 0.3 The reduction factor, Rdf, for a design factor of 0.3 at wall thickness 5 mm, taken from Figure 8, is: Rdf = 0.67 The reduction factor, Rwt, for a wall thickness of 5.6 mm at a design factor of 0.72, taken from Figure 9, is: Rwt = 0.87 The total failure frequency (TFF) for a 219 mm diameter pipeline, estimated from the generic total failure frequency curve in Figure B.1, is 0.223 per 1 000 km·y, so the failure frequency for this pipeline is: TFF = 0.223 × 0.67 × 0.87 = 0.130 per 1 000 km·y The proportion of ruptures, RF, is assumed to be 0.7, so the rupture frequency is: 0.013 × 0.7 = 0.091 per 1 000 km·y The above estimates are compared with FFREQ predictions (per 1 000 km·y) in Table B.4.
Table B.4 Comparison of external interference failure frequency estimates for example 1 with FFREQ predictions Pipe case
219 mm diameter × 5.6 mm wall thickness × 0.3 design factor
B.4.2.2
Estimated total failure frequency
FFREQ prediction
Estimated rupture frequency
FFREQ prediction
0.13
0.076
0.091
0.024
Example 2: Estimation of external interference failure frequency for 609 mm diameter, 7.9 mm wall thickness pipeline operating at a design factor of 0.5 The reduction factor, Rdf, for a design factor of 0.5 at wall thickness 5 mm, taken from Figure 8, is: Rdf = 0.81 The reduction factor, Rwt, for a wall thickness of 7.9 mm at a design factor of 0.72, taken from Figure 9, is: Rwt = 0.5 The total failure frequency (TFF) for a 609 mm diameter pipeline, estimated from the generic total failure frequency curve in Figure B.1, is 0.208 per 1 000 km·y, so the failure frequency for this pipeline is: TFF = 0.208 × 0.81 × 0.5 = 0.084 per 1 000 km·y
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PD 8010-3:2009 The proportion of ruptures, RF1, is assumed to be 0.7, so the rupture frequency is:
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0.084 × 0.7 = 0.059 per 1 000 km·y The above estimates are compared with FFREQ predictions (per 1 000 km·y) in Table B.5. Table B.5 Comparison of external interference failure frequency estimates for example 2 with FFREQ predictions Pipe case
609 mm diameter × 7.9 mm wall thickness × 0.5 design factor
B.4.2.3
Estimated total failure frequency
FFREQ prediction
Estimated rupture frequency
FFREQ prediction
0.084
0.061
0.059
0.020
Example 3: Estimation of external interference failure frequency for 914 mm diameter, 9.5 mm wall thickness pipeline operating at a design factor of 0.5 The reduction factor, Rdf, for a design factor of 0.5 at wall thickness 5 mm, taken from Figure 8, is: Rdf = 0.81 The reduction factor, Rwt, for a wall thickness of 9.5 mm at a design factor of 0.72, taken from Figure 9, is: Rwt = 0.34 The total failure frequency (TFF) for a 914 mm diameter pipeline, estimated from the generic total failure frequency curve in Figure B.1, is 0.199 per 1 000 km·y, so the failure frequency for this pipeline is: TFF = 0.199 × 0.81 × 0.34 = 0.055 per 1 000 km·y The proportion of ruptures, RF, is assumed to be 0.7, so the rupture frequency is: 0.055 × 0.7 = 0.039 per 1 000 km·y The above estimates are compared with FFREQ predictions (per 1 000 km·y) in Table B.6.
Table B.6 Comparison of external interference failure frequency estimates for example 3 with FFREQ predictions Pipe case
914 mm diameter × 9.5 mm wall thickness × 0.5 design factor
Estimated total failure frequency
FFREQ prediction
Estimated rupture frequency
FFREQ prediction
0.055
0.043
0.039
0.008
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B.5
B.5.1
Pipeline external interference failure frequency predictions for specific pipe cases FFREQ external interference failure frequency predictions for specific pipe cases The use of a generic failure frequency curve for external interference as described in B.4 allows conservative failure frequency estimates for specific pipeline cases to be readily estimated. However, the approach is approximate, and where possible, predictions for the specific pipe case under consideration need to be carried out using a recognized failure frequency prediction model. The current tool for the prediction of pipeline failure frequency due to external interference recommended by UKOPA is FFREQ. Failure frequency predictions generated using FFREQ for pipe cases selected to represent the range of pipe parameters in the UKOPA database given in Table B.7 are given in this subclause for reference and application.
Table B.7
UKOPA pipe cases Outside diameter
Wall thickness
Material grade
mm
mm
168.3
5.6
X42
219.1
5.6
X46
273
5.6
X52
323.9
5.6
X52
406.4
7.9
X52
508
7.9
X52
609
7.9
X60
762
7.9
X60
914
9.5
X65
NOTE The wall thickness values in Table B.7 represent a lower bound of pipeline wall thickness data in the UKOPA database. These values are generally below the minimum recommended wall thicknesses given in IGE/TD/1.
The FFREQ failure frequency predictions given in Tables B.8, B.9 and B.10, and Figures B.2, B.3 and B.4, are for pipelines located in R areas. Detailed predictions, including results for pipelines located in S areas, are published on the UKOPA website.
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Design factor
Total failure frequency 168.3A)
219.1A)
273A)
323.9A)
406.4A)
508A)
609A)
762A)
914A)
0.72
0.185
0.186
0.188
0.189
0.103
0.103
0.090
0.097
0.068
0.6
0.137
0.138
0.142
0.143
0.061
0.065
0.068
0.073
0.051
0.5
0.109
0.107
0.112
0.115
0.050
0.056
0.061
0.063
0.044
0.4
0.082
0.088
0.095
0.100
0.042
0.046
0.054
0.059
0.039
0.3
0.071
0.076
0.082
0.086
0.030
0.037
0.040
0.044
0.026
0.2
0.056
0.059
0.064
0.067
0.022
0.027
0.029
0.031
0.020
A)
Diameter, in millimetres (mm).
Figure B.2 FFREQ predictions of total external interference failure frequency for UKOPA pipe cases
Total failure frequency per 1 000 km . y
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Table B.8 FFREQ predictions for total external interference failure frequency for pipe cases defined in Table B.7 (per 1 000 km·y)
0.200
168
0.180
219
0.160
273
0.140
323
0.120 0.100
406
0.08
508
0.06
609
0.04
762
0.02
914
0.0 0.0
0.20
0.40
0.60
0.80
Design factor
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Design factor
Rupture frequency 168.3A)
219.1A)
273A)
323.9A)
406.4A)
508A)
609A)
762A)
914A)
0.72
0.139
0.138
0.135
0.130
0.064
0.060
0.049
0.047
0.027
0.6
0.093
0.091
0.089
0.087
0.031
0.030
0.029
0.028
0.014
0.5
0.065
0.064
0.062
0.060
0.022
0.021
0.020
0.017
0.008
0.4
0.043
0.042
0.041
0.039
0.012
0.011
0.011
0.010
0.004
0.3
0.026
0.024
0.023
0.022
0.006
0.005
0.004
0.004
0.001
0.2
0.013
0.011
0.010
0.009
0.002
0.001
0.001
0.001
0.000
A)
Diameter, in millimetres (mm).
Figure B.3 FFREQ predictions of external interference rupture frequency for UKOPA pipe cases Rupture failure frequency per 1 000 km .y
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Table B.9 FFREQ predictions for external interference rupture frequency for pipe cases defined in Table B.7 (per 1 000 km·y)
0.16
168
0.14
219
0.12
273
0.1
323
0.08
406
0.06
508
0.04
609
0.02
762
0 0
0.2
0.4 Design factor
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0.6
0.8
914
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FFREQ predictions for external interference rupture and leak frequencies for pipe cases defined in Table B.7 (per 1 000 km·y) Design factor
Rupture frequency 219.1
406.4
914
219.1A)
406.4A)
914A)
0.72
0.138
0.064
0.027
0.048
0.039
0.041
0.6
0.091
0.031
0.014
0.047
0.030
0.037
0.5
0.064
0.022
0.008
0.043
0.028
0.036
0.4
0.042
0.012
0.004
0.046
0.030
0.035
0.3
0.024
0.006
0.001
0.052
0.024
0.025
0.2
0.011
0.002
0.000
0.048
0.021
0.019
A)
A)
Leak frequency A)
A)
Diameter, in millimetres (mm).
Figure B.4 FFREQ predictions for external interference rupture and leak frequencies for specific diameter and wall thickness cases (per 1 000 km·y) 0.16 Failure frequency per 1 000 km .y
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PD 8010-3:2009
219 dia x 5.6 wt ruptures
0.14
219 dia x 5.6 wt leaks
0.12 406 dia x 7.9 wt ruptures
0.1 0.08
406 dia x 7.9 wt leaks
0.06
914 dia 9.5 wt ruptures
0.04
914 dia 9.5 wt leaks
0.02 0 0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
Design factor
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B.5.2
B.5.2.1
Estimation of external interference failure frequencies using FFREQ predictions and reduction factors for design factor and wall thickness General The FFREQ predictions in B.5.1 provide more realistic failure frequency predictions than the conservative estimates given in B.4 for specific pipe cases. The FFREQ failure frequencies can be modified to produce estimates for further pipe cases using the reduction factors for design factor and wall thickness given in Figures 8 and 9 respectively. Example calculations are given in B.5.2.2 and B.5.2.3.
B.5.2.2
Example 4: Modification of an existing external interference failure frequency for a 219.1 mm diameter pipeline of 5.6 mm wall thickness, operating at a design factor of 0.6, to that for a pipeline of wall thickness of 7.9 mm and design factor of 0.4 From Table B.8, the existing failure frequency for a 219 mm diameter pipeline of 5.6 mm wall thickness operating at a design factor of 0.6 is 0.138 per 1 000 km·y. From Figure 8, the design factor reduction factor for a design factor of 0.6 is 0.89. From Figure 8, the design factor reduction factor for a design factor of 0.4 is 0.79. The reduction factor, Rdf, for design factor to be applied in this case is therefore: Rdf = 0.79/0.89 = 0.918 From Figure 9, the wall thickness reduction factor for a 5.6 mm wall thickness is 0.88. From Figure 9, the wall thickness reduction factor for a 7.9 mm wall thickness is 0.5. The reduction factor, Rwt, for wall thickness to be applied in this case is therefore: Rwt = 0.5/0.86 = 0.575 The revised total failure frequency (TFF) is therefore: TFF = 0.138 × 0.918 × 0.575 = 0.073 per 1 000 km·y From Table B.10 and Figure B.4, the proportion of ruptures for a 219.1 mm diameter pipe operating at a design factor of 0.4 is 0.48. The revised rupture frequency is therefore: 0.073 × 0.48 = 0.035 per 1 000 km·y
B.5.2.3
Example 5: Modification of an existing external interference failure frequency for a 762 mm diameter pipeline of 5.6 mm wall thickness, operating at a design factor of 0.72, to that for a pipeline of wall thickness 7.9 mm and design factor of 0.4 The existing failure frequency for a 762 mm diameter pipeline of 5.6 mm wall thickness operating at a design factor of 0.72 is given as 0.187 per 1 000 km·y.
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PD 8010-3:2009 From Figure 8, the design factor reduction factor for a design factor of 0.4 is 0.75.
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From Figure 9, the wall thickness reduction factor for a wall thickness of 5.6 mm is 0.81. From Figure 9, the wall thickness reduction factor for a wall thickness of 7.9 mm is 0.5. The reduction factor, Rwt, for wall thickness to be applied in this case is therefore: Rwt = 0.5/0.81 = 0.617 The revised total failure frequency (TFF) is therefore: TFF = 0.187 × 0.75 × 0.617 = 0.087 per 1 000 km·y The proportion of ruptures reduces as the diameter and wall thickness increase, so it is conservative to assume that the proportion of ruptures for a 762 mm diameter × 7.9 mm wall thickness pipe is equivalent to that for a 406 mm diameter × 7.9 mm wall thickness pipe. From Table B.10 and Figure B.4, the proportion of ruptures for a 406 mm diameter pipe operating at a design factor of 0.4 is 0.286. The revised rupture frequency is therefore: 0.087 × 0.286 = 0.025 per 1 000 km·y The above estimates are compared with FFREQ predictions for a 762 mm diameter × 7.9 mm wall thickness pipe operating at a design factor of 0.4 in Table B.11. Table B.11 Comparison of external interference failure frequency estimates for example 5 with FFREQ predictions Pipe case
762 mm diameter × 7.9 mm wall thickness × 0.4 design factor
B.5.3
Estimated total failure frequency
FFREQ prediction
Estimated rupture frequency
FFREQ prediction
0.087
0.059
0.025
0.01
Critical defect size Damage caused by external interference typically includes gouges, which are of a narrow slot shape, and are modelled as crack-like defects. For high-pressure gas releases (in which the energy of the depressurizing gas does not decay immediately), the critical size of a crack-like defect at which the failure mode changes from leak to rupture, i.e. when the critical length is exceeded, needs to be taken into account. The maximum area through which the high pressure gas escapes at the critical length is usually determined as an equivalent hole size in order to calculate the maximum leak release rate [34]. Typical values of the equivalent hole diameter for critical defect lengths for pipelines operating at a design factor of 0.72 are given in Table B.12.
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Table B.12 Critical defect lengths and equivalent hole diameters for UKOPA pipeline cases operating at a design factor of 0.72
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Dimensions in millimetres (mm) Diameter
Wall thickness
Material grade
Critical defect length
168.3
5.6
X42
28.97
2.41
219.1
5.6
X46
31.72
2.98
273
5.6
X52
33.09
3.42
323.9
5.6
X52
36.03
4.05
406.4
7.9
X52
47.92
5.09
508
7.9
X52
53.53
6.35
609
7.9
X60
57.99
7.52
762
7.9
X60
64.72
9.38
914
9.5
X65
85.91
12.73
B.6
B.6.1
Critical hole diameter limit rupture/leak
Pipeline failure frequency due to corrosion External corrosion UKOPA data for external corrosion is given in Table B.13. The failure frequency due to external corrosion in the UK is dependent upon the year of construction and hence the age and applicable coating, corrosion protection design standards and corrosion control procedures. Corrosion control procedures for external corrosion include: •
monitored and controlled CP;
•
regular in-line inspection; and
•
defect assessment and remedial action.
The data shows that to date there is no operational experience of rupture failure due to corrosion in the UK.
Table B.13
Failure frequency due to external corrosion Units in failure frequency per 1 000 km·y Wall thickness (mm)
PinA)
HoleA)
RuptureA)
Total
10 to 15
0
0
0
0
>15
0
0
0
0
A)
See Table B.1 for definitions.
For pipelines commissioned pre-1980, it is expected that the corrosion rates in Table B.13 will be applicable unless corrosion control procedures have been used. Based on analysis of UKOPA pipeline fault and failure data [35], for pipelines of wall thickness up to 15 mm commissioned after 1980 and with corrosion control procedures applied, the corrosion failure frequency rate can be assumed to reduce by a factor of 10. For pipelines of any age with wall thicknesses
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greater than 15 mm and with corrosion control procedures in place, the corrosion failure frequency can be assumed to be negligible. The UKOPA data indicates that corrosion failures occur as leaks, and that no ruptures have been recorded to date in the UK.
B.6.2
Internal corrosion Review of UKOPA data confirms that the incidence of internal corrosion in MAHPs in the UK to date is low. The likelihood of occurrence of internal corrosion depends upon the fluid transported, and needs to be assessed on a pipeline specific basis, and the failure frequency needs to be assessed taking into account corrosion control procedures and use and frequency of in-line inspection.
B.7
Pipeline failure frequency due to material and construction defects UKOPA data for the failure frequency due to material and construction defects is given in Table B.14; this shows that the failure frequency reduces as the wall thickness increases. The UKOPA data indicates that material and construction failures occur as leaks, and that no ruptures have been recorded to date.
Table B.14
Material and construction failure frequency vs. wall thickness Wall thickness range
Wall thickness value assigned to range
Failure frequency
mm
mm
per 1 000 km·y
8 to 10
10
0.046
>10 to 12
12
0.031
>12 to 15
15
0.007
>15
17
0.004
Analysis of the UKOPA pipeline fault and failure data [35] shows that failure frequency due to material and construction defects in the UK is dependent upon the year of construction and hence the age, design and construction standards, in particular the material selection controls and welding inspection standards applied. For pipelines commissioned after 1980, the material and construction failure frequency rate can be assumed to reduce by a factor of 5.
B.8
B.8.1
Pipeline failure frequency due to ground movement General There is insufficient historical data to establish a relationship between ground movement failure data and individual pipeline parameters. The failure frequency of a specific pipeline due to ground movement is dependent upon the susceptibility to natural landsliding along the route, and this needs to be assessed on a location specific basis.
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Natural landsliding Based on a detailed assessment of pipeline failure frequency due to natural landsliding in the UK, UKOPA has concluded that the predicted background rupture failure rate of (2.1 × 10−4) per 1 000 km·y due to natural landsliding is applicable to all UK MAHPs. However, where the local susceptibility to landsliding and the associated likelihood of slope instability has been assessed, the rupture rate due to ground movement caused by natural landsliding can be obtained from Table B.15.
Table B.15
B.8.3
Pipeline rupture failure frequency due to due to ground movement caused by natural landsliding Description
Pipeline rupture rate per 1 000 km·y
Slope instability is negligible or unlikely to occur, but might be affected by slope movement on adjacent areas
0 to (9 × 10−5)
Slope instability might have occurred in the past or might occur in future, or is present and might occur in future
(1 × 10−4) to (2.14 × 10−4)
Slope instability is likely and site specific assessment is required
>(3.0 × 10−4)
Artificial ground movement Artificial ground movement can be induced through activities such as mining, quarrying, adjacent construction work etc. Such activities are location-specific and time-limited, and the associated risks need to be assessed and managed by the pipeline operator through notification and surveillance activities, and procedures for safe working in the vicinity of pipelines. Where and when activities that might result in artificial ground movement occur in the vicinity of a pipeline, the likelihood of failure of the pipeline needs to be assessed on a case‑specific basis.
B.9
Pipeline failure frequency due to other causes Pipeline failure rates due to causes other than those outlined in B.1 to B.8 need to be assessed on a pipeline-specific basis. Relevant causes can include overpressure, fatigue etc., and will vary according to the operating regime and/or location of the pipeline or pipeline section. NOTE The UKOPA product loss data in Table B.1 indicates that other causes account for approximately 28% of the total failure rate. The UKOPA pipeline fault data report [9] confirms that 62.5% of the incidents recorded in this category relate to pre-1970 pipelines, and are not relevant to pipelines designed, constructed and operated in accordance with current pipeline standards. Derivation of a failure rate based on this data is therefore not recommended.
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Annex C (informative)
C.1
Example of a site-specific risk assessment Scenario A planning application for a housing estate consisting of 38 houses in a green field rural area near a village has been lodged with the local planning authority. On checking their records, the planning authority finds that there is an ethylene pipeline located near the proposed site which has land use planning zones. The closest house is 75 m from the pipeline. Details are shown in Figure C.1.
Figure C.1 Proposed development
Proposed housing development
Outer zone 200 m Middle zone 150 m Inner zone 70 m Pipeline
The planning authority checks pipeline risk zones against advice from HSE, and discovers that for a larger development of more than 30 dwelling units, if more than 10% of the development is in the middle zone, HSE advises against allowing this development to proceed. The planning authority therefore informs the developer that they will refuse planning permission on safety grounds. The developer then contacts the pipeline operator to see whether there are any special conditions associated with the pipeline that could affect the planning application. After discussion with the operator, the developer is able to confirm that the pipeline design conditions are as notified to HSE and therefore the only possibility would be to apply mitigating factors to reduce the risk zones.
C.2
Risk assessment The developer commissions a risk assessor to review the land use planning zones and possible mitigation that could be applied. The following details are confirmed: •
product: ethylene (dense phase);
•
pipeline diameter: 219 mm;
•
wall thickness: 7.03 mm;
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steel: X42;
•
maximum allowable operating pressure: 95 bar;
•
depth of cover: 1 100 mm;
•
area classification: class 1 (rural).
From this the design factor is calculated as 0.51. Obtaining failure rates from Annex B: a) Failure rate due to third-party interference: From Figure B.1, the total failure rate for a 219 mm diameter pipeline with 5 mm wall thickness at a design factor of 0.72 is 0.223 1 per 1 000 km·y. The rupture rate assuming 70% ruptures is 0.156 2 per 1 000 km·y. Applying reduction factors given in Figures 8 and 9: •
reduction factor for design factor of 0.51 = 0.81;
•
reduction factor for wall thickness 7.03 mm = 0.5.
The total failure rate due to third-party interference is therefore: •
total failure rate = 0.223 × 0.81 × 0.5 = 0.090 8.
The rupture failure rate due to third-party interference is: •
rupture failure rate = 0.7 × total failure rate = 0.063 6 per 1 000 km·y;
•
therefore, the leak rate is 0.027 per 1 000 km·y.
b) The critical hole diameter for this pipeline to be used to determine the release rate for leaks [i.e. the maximum leak hole size (see Table B.12)] is calculated as 6.32 mm. c) External corrosion: failure frequency due to leaks (Table B.13) = 0.046 per 1 000 km·y. d) Material and construction: failure frequency due to leaks (Table B.14) = 0.064 per 1 000 km·y. e) Ground movement: failure frequency due to ruptures = 2.1 × 10−4 per 1 000 km·y. From a) to d) above, the total failure frequency rate for this pipeline is therefore determined as follows: •
failure frequency due to leaks = 0.137 2 per 1 000 km·y.
•
failure frequency due to ruptures = 0.063 8 per 1 000 km·y.
•
total failure frequency rate = 0.201 per 1 000 km·y.
For this pipeline, the above assessment indicates that third-party interference accounts for 45% of failures. The risk assessor is therefore able to simulate risks from the following main calculation steps:
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•
minimum distance to occupied buildings (MDOB): 45 m.
•
fireball radius: 50 m;
•
fireball duration: 7.5 s;
•
fireball spontaneous ignition distance: 67 m;
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PD 8010-3:2009 •
fireball 1 000 tdu in open air distance: 95 m;
•
rupture 30 s jet flame escape distance: 86 m.
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From this, the distance to risk levels are calculated as follows: •
10−6 per year individual risk: 125 m;
•
(3 × 10−7) per year individual risk: 275 m.
These risk levels correspond well to HSE land use planning zones, which are:
C.3
C.3.1
•
inner zone: 70 m (as originally notified by HSE);
•
middle zone: 150 m;
•
outer zone: 200 m (as originally notified by HSE).
Mitigation measures Possible measures The following possible mitigation measures are proposed for risk reduction: a) install concrete slabbing and marker tape over the pipeline; b) re-lay pipeline in heavy-wall pipe. These measures are discussed in C.3.2 and C.3.3 respectively.
C.3.2
Installing concrete slabbing and marker tape over the pipeline This is conservatively assumed to reduce the third-party failure frequency by a factor of 0.1 in this case. The new failure rates are therefore: •
rupture failure rate: (0.064 × 0.1 + 2.1 × 10−4) = 0.006 6 per 1 000 km·y;
•
total failure rate: (0.090 8 × 0.1 + 0.046 + 0.064 + 2.1 × 10−4) = 0.119 per 1 000 km·y.
The re-calculated risk distances are: •
10−6 per year individual risk: 80 m;
•
(3 × 10−7) per year individual risk: 120 m.
This can reduce the middle zone so that most of the new development is outside the middle zone, subject to formal acceptance that concrete slabbing reduces the risk. However, if this was accepted, the concrete slabbing would be defined by the effect on the planning decision and an ALARP assessment. The distance adjacent to the proposed housing over which slabbing and marker tape is required is the interaction distance as shown in Figure C.2.
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Fireball outdoor hazard distance 95 m
Fireball outdoor hazard distance 95 m
Closest house 75 m Pipeline Interaction distance 117 m
The operator also requests a societal risk assessment for the situation before slabbing and after slabbing to be able to assess the risk reduction achieved. The resulting graph is shown in Figure C.3. Figure C.3 Societal risk FN curves and PD 8010-3 FN criterion line – proposed development before and after slabbing 1.00E - 03
1.00E - 04
D
1.00E - 05
B
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Figure C.2 Risk for outside exposure
C 1.00E - 06
1.00E - 07
1
100
10
1 000
A Key A Number of casualties
PD 8010-3 risk criterion line
B
Frequency (per year) of N or more casualties
Proposed development before slabbing
C
Broadly acceptable
Proposed development after slabbing
D Tolerable if ALARP
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PD 8010-3:2009 Measured against the 1 km societal risk criterion for an interaction distance of 450 m (the site interaction length, which in this case is equal to the length of the proposed development plus twice the maximum hazard range), and applying the thermal radiation level of 1 800 tdu for comparison with this criterion, this indicates that the proposed development was above the “negligible/tolerable” risk criterion line, whereas after slabbing the risk has reduced so that all risks are within the “broadly acceptable” region, and are therefore considered to be ALARP.
C.3.3
Re-laying the pipeline section in thick-wall pipe The effect on risk of re-laying the pipeline adjacent to the proposed new development in 11.91 mm thick pipe is assessed. a) Failure rate due to third-party interference: From Figure B.1, the total failure rate for a 219 mm diameter pipeline with 5 mm wall thickness at a design factor of 0.72 is 0.223 per 1 000 km·y. The rupture rate assuming 70% ruptures is 0.156 per 1 000 km·y. However, thick wall pipe will have a lower proportion of ruptures; more detailed assessment methods need to be applied to obtain the proportion of ruptures. Applying reduction factors given in Figures 8 and 9 for a wall thickness of 11.91 mm and design factor 0.3: •
reduction factor for design factor of 0.3 = 0.67;
•
reduction factor for wall thickness 11.91 mm = 0.068.
The total failure rate due to third-party interference is therefore: •
total failure rate = 0.223 × 0.64 × 0.067 = 0.001 0 per 1 000 km·y.
The rupture failure rate due to third-party interference is: •
rupture failure rate = 0.7 × total failure rate = 0.007 per 1 000 km·y;
•
therefore, the leak rate is 0.003 per 1 000 km·y.
b) External corrosion: failure frequency due to leaks (Table B.13) = 0.0 per 1 000 km·y. c) Material and construction: failure frequency due to leaks (Table B.14) = 0.031 per 1 000 km·y. d) Ground movement: failure frequency due to ruptures = (2.1 × 10−4) per 1 000 km·y. From a) to d) above, the total failure frequency rate for this pipeline is therefore determined as follows: •
failure frequency due to leaks = 0.034 0 per 1 000 km·y.
•
failure frequency due to ruptures = 0.007 2 per 1 000 km·y.
•
total failure frequency rate = 0.041 per 1 000 km·y.
For this pipeline, the above assessment indicates that third-party interference accounts for 24% of failures.
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published document The re-calculated risk distances are: •
10−6 per year individual risk: 55 m;
•
(3 × 10−7) per year individual risk: 100 m.
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This can reduce the middle zone so that all the new development is outside the middle zone, and would again need to be justified by ALARP considerations. ALARP considerations would include cost benefit considerations based on the reduction in total loss, or expectation value achieved by the mitigation measures [18]. The judgement based on the results needs to take account of:
52 • © BSI 2008
•
the uncertainty in the data and models used in the assessment;
•
societal concerns including aversion;
•
criteria specific to the individual pipeline operating company.
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Bibliography For dated references, only the edition cited applies. For undated references, the latest edition of the referenced document (including any amendments) applies.
Standards publications PD 8010-2, Code of practice for pipelines – Part 2: Subsea pipelines ISO 3183-2:1996, Petroleum and natural gas industries – Steel pipe for pipelines – Technical delivery conditions – Part 2: Pipes of requirements class B
Other publications [1] GREAT BRITAIN. Pipelines Safety Regulations 1996. London: HMSO. [2] GREAT BRITAIN. Health and Safety at Work etc. Act 1974. London: HMSO. [3] GREAT BRITAIN. Management of Health & Safety at Work Regulations 1992, amended 1999. London: HMSO. [4] CORDER, I. The application of risk techniques to the design and operation of pipelines. Proceedings of International Conference on Pressure Systems: Operation and Risk Management, October 1995, Paper No. C502/016/95, PP. 113-125. London: Institution of Mechanical Engineers. [5] CORDER, I., FEARNEHOUGH, G.D. and KNOTT, R.N. Pipeline design using risk based criteria. Communication 1492. Institute of Gas Engineers 129th Annual General Meeting and Spring Conference, Eastbourne, UK, May 1992. [6] LYONS, C., HASWELL, J.V., HOPKINS, P., ELLIS, R. and JACKSON, N. A methodology for the prediction of pipeline failure frequency due to external interference. International Pipeline Conference, Calgary, Canada, 30 September – 3 October 2008.4) [7] ACTON, M., BALDWIN, T., and JAGER, E.R. Recent developments in the design and application of the PIPESAFE risk assessment package for gas transmission pipelines. International Pipeline Conference, Calgary, Canada, 29 September – 3 October 2002. [8] LYONS, D. Western European cross country oil pipelines 30 year performance statistics. Report 1/02. Brussels: CONCAWE, February 2002.5) [9] ARUNAKUMAR, G. UKOPA PIPELINE FAULT DATABASE. Pipeline product loss incidents 1962-2006 – 5th report of the UKOPA Fault Data Management Group. Advantica Report 6957. Loughborough: Advantica, August 2007.6)
4)
Available from UKOPA.
5)
Available for downloading at http://www.concawe.org.
6)
Available for downloading at http://www.ukopa.co.uk/publications. © BSI 2008 •
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PD 8010-3:2009
published document [10] EUROPEAN GAS PIPELINE INCIDENT DATA GROUP. Gas pipeline incidents – 6th report of the European Gas Pipeline Incident Data Group 1970-2004. EGIG 05 R.0002. European Member States: EGIG, December 2005.7)
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[11] SPENCER, H. and REW, P.J. Ignition probability of flammable gases. Contract Research Report CRR146/1997. London: W.S. Atkins for the HSE, 1997.7) [12] SPENCER, H., DAYCOCK, J. and REW, P.J. A model for ignition probability of flammable gases. Contract Research Report CRR203/1997. London: W.S. Atkins for the HSE, 1997. [13] LEES, F.P. Loss prevention in the process industries. Second edition. London: Butterworths-Heinemann, 1996. ISBN 0 7506 1547 8. [14] BILO, M. and KINSMAN, P. MISHAP – HSE’s pipeline risk assessment methodology. Pipes and Pipelines International, July‑August 1997. [15] BILO, M. and KINSMAN, P. Risk calculation for pipelines applied within the MISHAP HSE computer program. Pipes and Pipelines International, March-April 1998. [16] MAHGEREFTEH, H. PipeTech – Pipeline rupture computational fluid dynamics simulator. London: University College.8) [17] HEALTH AND SAFETY EXECUTIVE. Reducing risks, protecting people – HSE’s decision-making process. London: HSE Books, 2001. ISBN 0 7176 2151 0. [18] HEALTH AND SAFETY EXECUTIVE, HAZARDOUS INSTALLATIONS DIRECTORATE. HID’s approach to ‘As Low As Reasonably Practicable’ (ALARP) decisions. London: Health and Safety Executive, 2007.9) [19] GREAT BRITAIN. Control of Major Accident Hazards Regulations 1999. London: The Stationery Office. [20] LYONS, C. and HASWELL, J.V. The influence of pipe design factor and geometry on the failure of pipelines subject to 3rd party damage. PIE/2005/R104, Issue 1.0, October 2005.10) [21] HASWELL, J.V. Failure frequency reduction factors for design factor and wall thickness. PIE/07/TN051 V0, 14 September 2007.10) [22] COSHAM, A., HASWELL, J. and JACKSON, N. Reduction factors for estimating the probability of failure of mechanical damage due to external interference. International Pipeline Conference, Calgary, Canada, 30 September – 3 October 2008.10) [23] ROOVERS, P., BOOD, R., GALLI, M., MAREWSKI, U., STEINER, M. and ZARÉA, M. EPRG methods for assessing the tolerance and resistance of pipelines to external damage. Pipeline technology, Volume II, Proceedings of the Third International Pipeline Technology Conference (Ed. R. Denys), Brugge, Belgium, 2000, PP. 405-425.
7)
Available for downloading at http://www.hse.gov.uk/research/rrhtm/.
8)
Details at http://www.homepages.ucl.ac.uk/~ucecm01/pipe-tech.html.
9)
Available for downloading at http://www.hse.gov.uk/comah/circular/perm09.htm.
10) Available
54 • © BSI 2008
from UKOPA.
published document
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[24] HOPKINS, P. The application of fitness for purpose methods to defects detected in offshore transmission pipelines. Conference on Welding and Weld Performance in the Process Industry, London, 1992. [25] CORDER, I. and CHATAIN, P. EPRG recommendations for the assessment of the resistance of pipelines to external damage. Proceeding of the EPRG/PRC 10th Biennial Joint Technical Meeting On Line Pipe Research, Cambridge, UK, April 1995. [26] MATHER, J., BLACKMORE, C., PETRIE, A., and TREVES, C. An assessment of measures in use for gas pipelines to mitigate against damage caused by third party activity. Contract Research Report 372/2001. London: W.S. Atkins for the HSE, 2001. [27] McCONNELL, R. Effect of surveillance frequency on 3rd party excavation rate. Briefing paper to UKOPA RAWG. October 2005.11) [28] TOES, G. The effectiveness of slabbing in preventing pipeline damage due to third party interference. Advantica Report 8904. March 2006.11) [29] GREAT BRITAIN. Notification of Installations Handling Hazardous Substances Regulations 1982 and subsequent amendments. London: HMSO. [30] GREAT BRITAIN. Town and Country Planning Act 1990. London: HMSO. [31] HEALTH AND SAFETY EXECUTIVE. Planning advice for developments near hazardous installations (PADHI+). London: Health and Safety Executive.12) [32] BILO, M. and KINSMAN, P. Thermal radiation criteria used in pipeline risk assessment. Pipes and Pipelines International, November-December 1997. [33] CARTER, D.A. Aspects of risk assessment for hazardous pipelines containing flammable substances. Journal of Loss Prevention in the Process Industries, January 1991, Volume 4. [34] BAUM, M. and BUTTERFIELD, J.M. Studies of the depressurisation of gas pressurised pipes during rupture. Journal of Mechanical Engineering Science, Volume 21, No. 4, 1979. London: Institution of Mechanical Engineers. [35] LYONS, C. and HASWELL, J.V. UK pipeline failure frequencies. PIE/06/R0131, Issue 1.0, February 2007.11)
11) Available
from UKOPA.
12) This
document does not carry a publication date. It is available for downloading at http://www.hse.gov.uk/landuseplanning/index.htm. © BSI 2008 •
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