adv antic a presentation on draft report
TRANSCRIPT
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Safety Review of the Proposed Onshore
Section of the Corrib Gas Pipeline- Draft Report
Dr. Mike Acton and Dr. Bob Andrews (Consultants)
Mr. Arwel Griffiths (Executive Director)
Copyright 2005 Advantica, Inc. (USA Only) and Advantica Ltd. (Outside USA). All rights reserved by the respective owner.
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Overview
Introduction to Advantica Company Overview Key Personnel
Safety Review of the Corrib Gas Pipeline Background Scope of Safety Review
Safety Review Process Draft Report
Summary of Recommendations and Closing Remarks
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What Does Advantica Do?
Provide engineering, consultancy andsoftware services to customers acrossthe hydrocarbon chain
throughout the project lifecycle, frominfrastructure development through toasset management.
Approximately 500 highly qualifiedscientific and engineering staff, including
internationally renowned experts. Complete gas chain coverage.
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We are a Global Business
Advantica Clients found in these locations
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Award Winning Technology
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Key Personnel
Dr. Mike Acton (Hazard & Risk Management) 17 years oil & gas experience at Advantica (formerly British Gas R&T) Involved in many large and full scale pipeline tests
Chairman of PIPESAFE Group of companies Extensive experience in the application of pipeline risk assessment Experienced incident investigator, including transmission pipeline failures
Active member of IGEM Committees, and contributed to several IGEMCodes of Practice and Safety Recommendations
Dr. Bob Andrews (Integrity Management) 20 years experience at The Welding Institute and then Advantica
Extensive experience of structural integrity issues in components andstructures, particularly pipelines
Specialist in pipeline integrity and fracture control
Active member of IGEM and BSI Committees, and contributed to IGEM and
BSI Codes of Practice and Standards
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Safety Review of the Corrib Gas Pipeline
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Background
The pipeline industry has a good safetyrecord, but incidents have occasionally
occurred
The Corrib onshore pipeline is plannedto operate at high pressure, carrying
untreated gas
Serious concerns expressed by local
residents over the safety of the pipeline,especially the consequences of failure
Safety review commissioned inresponse to those concerns
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Scope of Safety Review
Included: Review of the health and safety aspects of the proposed pipeline in terms of
engineering design and risk to public safety
Review of the available documentation for completeness and suitability NOT included
Assessment of environmental impact
Assessment of the risk to workers during construction
Review of the onshore terminal, offshore pipeline or subsea equipment
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Safety Review Process
Evaluate initial set of documents supplied by TAG
Identify and request additional information from Shell
Meeting with Shell for points of clarification and discussion of projectdesign selection process
Documents classified as: Technical documents requiring detailed technical review by specialists
Documents providing background information including project history Documents outside the scope of the review
Site visit to confirm understanding of pipeline route and local conditions
2 day oral hearing and opportunity for written submissions to raiseissues of concern and points to be taken into account in the review
Draft report issued for comment
Final report
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Draft Report
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Report Structure
Executive Summary Main Report
1. Introduction
2. The Safety Review Process3. Overall Project Development Plan
4. Review of Pipeline Design
5. Quantified Risk Assessment
6. Discussion7. Final Remarks and Recommendations
AppendicesA. Advantica Personnel
B. Summary of Oral and Written SubmissionsC. Geotechnical Analysis
D. Societal Risk Analysis
E. Geotechnical Investigations on Corrib Pipeline Route
F. Comments on Rossport Pipeline Hazard Calculations by DJ Aldridge PhD
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Overall Project Development Plan
High level review of constraints relevant to the onshore pipeline
Assessment of consideration given to safety issues in the design optionselection process for:
Sub-sea tie-back option Landfall and terminal locations
Proposed onshore pipeline route
This section considers the process followed Not a detailed technical review
Consideration of alternative design options, terminal locations orpipeline routes was outside the scope of our work
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Overall Project Development Plan
Terminal location, 9km inland, drives requirement for an onshorepipeline
High pressure onshore pipeline required whether gas processed
onshore or offshore Onshore processing introduces additional threats that must be
managed
Public safety was one of many factors in selection process, which alsoincluded: Visual impact
Economic
Environmental Technical
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Overall Project Development Plan
QRA informed design and route selection
Risk levels within recognised international criteria
Ireland has no formal risk-based framework in place
Consideration should be given by the Irish Government to establishinga risk-based framework for decisions on proposed and existing major
hazard pipelines and related infrastructure
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Overall Project Development Plan
Four route options considered: Pollatomish via Dooncarton landfall Brandy Point via Brandy Point landfall
Via Struwaddacon Bay Rossport via Dooncarton landfall (preferred)
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Overall Project Development Plan
Initial design based on pressure of 150 bar
Subsequently adopted more cautious approach Wall thickness increased
Withstand 345 bar theoretical worst case
Most cautious approach to routing based on consequence distances,but in practice, rarely practical to avoid all population
Design codes have more onerous requirements for Higher population density Proximity to housing (in some cases)
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Overall Project Development Plan
Route through Rossport determined by Ground stability
Avoidance of possible future land development
Maximising distance from housing Nearest building 70m from pipeline
Justified by QRA
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Review of Pipeline Design
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Integrity - fatigue
Failure due to variations in pressure
Several predictions from flowsimulations
Stresses around cut-off in codes Recommend:
Monitoring of pressure variations
Check small attachments
1000 10000 100000 10000002 3 4 5 6 7 2 3 4 5 6 2 3 4 5 6
Cycles
100
30
40
50
60
70
80
90
200
Stressrang
e(Nmm-2)
165Nmm-2
35Nmm-2
Edition 4
Edition 3
I i i i
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Integrity impact protection
Protection at road crossings using concrete slabs is accepted practice
Concerns with the data supplied: Design left to contractor and not location specific
Slabbing should extend the full width of the route already addressed Distance between slab and pipe may be too shallow Support slab from subsoil in peat areas
Formal safety analysis for 72% SMYS operation at crossings notdocumented
These issues should be addressed to provide best practice impactprotection
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I t it d t
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Integrity ground movement
We also checked other failure modes such as buckling
We considerother analyses are required to demonstrate integrity: Movement parallel to the pipe
Effect of bends Increased depth of cover
We recommend monitoring of stresses in critical areas
Gro nd Mo ement
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Ground Movement
Effects of pipeline on ground stability have been considered
Dooncarton type slide on steep slopes will not affect the route as theslopes are too shallow
Shallow slope slide has been addressed by Shells consultants All recommendations by these consultants should be implemented in
full
Materials
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Materials
Pipe material to DNV OS-F101 Grade 485
This grade (or equivalent) has been widely used for onshore andoffshore projects
Plate produced by German and Japanese mills and pipe produced inUK
Mill certificates examined requirements satisfied
Formal fracture control plan not produced, but we have checked therequirements for the gas composition and consider material issatisfactory
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External Corrosion
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External Corrosion
Mainline coating specificationgenerally satisfactory
We recommend testing to assess
possible long term UV degradationduring storage
We are concerned with the quality offield joint coating and recommend a
robust inspection regime during
construction
Cathodic protection system requiresan insulation jointat the beach to
achieve separation from offshore
system
Construction
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Construction
Welding to British Standards
Toughness requirements exceed BS
Actual levels above requirements
Welds meet best practice
Pressure Testing
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Pressure Testing
We recommend: A high level pressure test to 105% SMYS should be carried out The test pressure should be calculated on nominal wall thickness not
design We support the recommendation for a fingerprinting ILI run during
commissioning
Operations & Maintenance
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Operations & Maintenance
Procedures were requested from Shell but we were advised that thesehad not yet been written and would be prepared prior to operation in
accordance with BS 8010
An Integrity Management System (IMS) is required and should include Inspections
Management systems and management of change
Audit and corrective actions
IMS should be in place from the start of the project
Frequency of inspections should be updated based on results
We consider a leak detection system is not sufficient as an integrity
management system A formal integrity management system should be established for the
pipeline before construction is allowed to commence
Operations & Maintenance
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Operations & Maintenance
We recommend: Defect assessment and procedures should be defined in advance so that
anomalies can be sentenced quickly
Repair procedures should be developed for non-leaking damage Procedures are required for safe working in proximity to the pipeline
Future Operation
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Future Operation
We have not considered tie-ins of other fields to this pipeline
We note the system is designed for sweet gas, ie no H2S
Monitoring is required to check that H2S is not introduced into the
system In the event that additional fields were proposed to be tied in to the
pipeline at any future date, a full review would be required to consider
issues such as extension of the life beyond the initial design life,
changes in the fluids in the pipeline or changes in the operating
pressures
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Risk Assessment
HAZard IDentification (HAZID)
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HAZard IDentification (HAZID)
Original HAZID covered main onshore pipeline hazards
Some additional hazards identified
Project Hazard Register prepared to track HAZID actions
Some actions to be addressed in operations and maintenanceprocedures (not yet prepared)
Action to address H2S threat needs to be more robust
The Project Hazard Register should be maintained and updated and allHAZID actions addressed
Population Density Analysis
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Population Density Analysis
Area classification in accordance with BS8010, based on 345 bar Minimum proximity distance of 170m by extrapolation
Population density found to be low (Class 1 or Rural)
Ribbon development parallel to pipeline Anomaly of increasing population density with reducing pressure Not enough for Class 2 (Suburban) classification
Consideration should be given to the nature of ribbon developmentsparallel to the pipeline in calculating population density in any future
reassessment of the pipeline classification
Quantified Risk Assessment (QRA)
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Quantified Risk Assessment (QRA)
Pipeline risk assessment: Failure cause Failure mode
Gas outflow Ignition Thermal radiation Thermal effects
Risk calculations
Risk reduction measures
Input
Parameters
Failure cause?
Failure mode?
Calculation of
Failure Frequency
Outflow Dispersion IgnitionThermal
radiation
Radiation
effects
Consequence calculations
Rupture or Puncture?
Fatigue
External
interferenceGround
movementCorrosion
Causes
Risk Calculations
Risk Transect
FN curve (PLL, EV)
Societal
Individual
Review of JP Kenny QRA
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Review of JP Kenny QRA
Failure frequencies included for: Third party interference Ground movement
Inherent and construction defects Assumes measures against other threats effective and no H2S
Inclusion of ground movement inconsistent
Concluded that Individual Risk levels acceptable at all distances The measures to protect the pipeline integrity assumed in the QRAmust be established for the Corrib pipeline, and maintained throughout
its life
A procedure should be established for monitoring of the gas for H2S,specifying the actions to be taken and the threshold concentrations
above which action would be required
Review of JP Kenny QRA
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Review of JP Kenny QRA
Consequence modelling simplistic
No recognition of uncertainty at very high pressures
Low value for ignition probability assumed for rupture case
Consideration of Individual Risk only Risk unexpectedly insensitive to pipeline pressure
Advantica Risk Assessment
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Advantica Risk Assessment
Independent check on QRA results PIPESAFE package Validated at pressures up to 120 bar
Assumes proposed measures AND those recommended in this report Range of hazard distances given
Increasing uncertainty with higher pressures recognised
Individual Risk levels lower than JP Kenny results Included Societal Risk analysis
Individual Risk Analysis
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Individual Risk Analysis
1.00E-11
1.00E-10
1.00E-09
1.00E-08
1.00E-07
1.00E-06
0 50 100 150 200 250 300
Distance from Pipeline (m)
Individua
lRisk(peryear)
144barg 240barg 345barg
Societal Risk Analysis
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Societal Risk Analysis
1 . 0 0 E - 1 3
1 . 0 0 E - 1 2
1 . 0 0 E - 1 1
1 . 0 0 E - 1 0
1 . 0 0 E - 0 9
1 . 0 0 E - 0 8
1 . 0 0 E - 0 7
1 . 0 0 E - 0 6
1 . 0 0 E - 0 5
1 . 0 0 E - 0 4
1 1 0 1 0 0 1 0 0 0
N u m b e r o f C a s u a l t ie s (N )
FrequencyofNo
rMoreCasualtiesperYear(F)
I G E / T D / 1 S o c ie t a l R is k C r ite r io n E n v e l o p e
1 4 4 b a r g
2 4 0 b a r g
3 4 5 b a r g
Risk Reduction Measures
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Risk Reduction Measures
Risk levels within recognised limits
Other possible risk reduction options considered
Third party damage dominates residual risk
Pipeline wall thickness main defence against failure The proposed arrangements for surveillance and landowner liaison
should be specified in the operations and maintenance procedures
Risk Reduction Measures
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Risk Reduction Measures
Uncertainty increases with increasing pressure
Highest pressure should be assumed Dormant defects may fail when pressure rises
Limiting pressure reduces failure frequency and consequences Limiting design factor to 0.3 or less (~144 bar for Corrib pipeline)
recognised as effective measure to allow pipelines to be routed in
higher population density (Suburban) locations
UKOOA Decision Framework
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Significance of Bases to
Decision Making Process
Means of Calibration Decision Context
Codes and Standards
Verification
Peer Review
Benchmarking
Internal Stakeholder
Consultation
External StakeholderConsultation
Codes &
Standards
Goo
dPrac
tice
Engineerin
gJudg
emen
t
QRA
CBA
Company
Values
Societal Values
Nothing new or unusual
Well understood risks
Established practice
No major stakeholder
implications
No significant economic
implications
A
B
C
Business risk or lifecycle
implications
Some risk trade-offs/transfer
Some uncertainty
Some deviation from standard
or best practice
Some significant economic
implication
Very novel or challenging
Strong stakeholder views
and perceptions
Significant risk trade-offs
or risk transfer
Large uncertainties
Perceived lowering of safetystandards
Major economic implications
Significance of Bases to
Decision Making Process
Means of Calibration Decision Context
Codes and Standards
Verification
Peer Review
Benchmarking
Internal Stakeholder
Consultation
External StakeholderConsultation
Codes &
Standards
Goo
dPrac
tice
Engineerin
gJudg
emen
t
QRA
CBA
Company
Values
Societal Values
Nothing new or unusual
Well understood risks
Established practice
No major stakeholder
implications
No significant economic
implications
A
B
C
Business risk or lifecycle
implications
Some risk trade-offs/transfer
Some uncertainty
Some deviation from standard
or best practice
Some significant economic
implication
Very novel or challenging
Strong stakeholder views
and perceptions
Significant risk trade-offs
or risk transfer
Large uncertainties
Perceived lowering of safetystandards
Major economic implications
Risk Reduction Measures
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Risk assessment powerful tool to inform decisions, but not only factor
Corrib pipeline conventional in that the pipeline wall thickness isincreased to accommodate high design pressure and upstream pipeline
technology is well-established BUT:
It lies outside normal range of application on onshore design codes
There is uncertainty in the risk analysis at such high pressures
It gives rise to significant societal concerns
We therefore recommend that the pressure in the onshore pipelineshould be limited to enable the pipeline to be reclassified as a Class 2
(Suburban) pipeline, with a design factor not exceeding 0.3
Pressure Safety Measures
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y
Reliability assessment of subsea pressure control systems flawed
Does not form a basis for selection of options
A full and technically thorough reliability analysis should be carried out
of the subsea pressure control and isolation systems specified in thefield design
Additional pressure control measures should be implemented and theeffective limitation of the pressure in the onshore pipeline demonstrated
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Discussion
Selection of Design Code
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We consider BS 8010 was an appropriate choice of design code Synthesis of accumulated UK experience IS 328 closely related
Better safety levels than US or ISO codes see later Generally accepted practice to keep the original code on long running
projects unless there are reasons for change
IGE codes allow continued operation to an earlier edition
Should have considered adopting PD 8010 O&M section
Selection of Design Code
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Withdrawal of BS 8010 Some observations have been made that BS 8010 was obsolete This is incorrect, the withdrawal was a consequence of the introduction of
European standards BSi paid for the conversion of the BS into a PD so that the guidance was
still available
UK National Foreword to EN 14161 states:
that a more comprehensive approach to the design of pipelines is possible
through using BS EN 14161 in association with the following Codes of
Practice: PD 8010-1:2004
Selection of Design Code
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Code Comparison BS 8010 calculates design thickness on minimum, not nominal wall BS 8010 allows a higher level hydrotest, giving a more searching test of
integrity BS 8010 has minimum proximity distances based on pressure US andCanadian codes have no restrictions on proximity except for access
If the onshore pipeline is reclassified as a Class 2 (Suburban) pipeline,
the pipeline design should be revised in accordance with PD 8010, toensure that the pipeline is consistent with current best practice, while
minimising the change required to the existing design
Design Pressure
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High design pressure of 345 bar Higher than normal for onshore gas transmission Above range of onshore pipeline codes and standards
Pressures over 100 bar increasingly used for new pipeline designs Cautious approach by Shell resulted in a very thick and strong pipe
Maximum pressure falls steadily as gas extracted
Advantica recognises the concerns and recommends limiting thepressure to ~144 bar, consistent with pipeline design factor used forpipelines in more densely populated suburban areas
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Untreated Gas Composition
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Corrib gas has unusually high natural methane content (~94%) Typical of methane content of treated gas Similar to composition used in validating Advantica models
Other fluids contained in the gas stream present additional threats: Gas is wet - combined with CO2 can cause internal corrosion Hydrates - can cause blockage
H2S - not detected, but can be formed during lifetime of a gas field
Appropriate precautions have been identified to combat these additionalthreats
Must be maintained and effectiveness monitored
A plan should be in place in case H2S is detected
Ground Stability
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Effects of ground movement on the pipeline JP Kenny analysis conservative for straight pipe Expected to withstand ground movement loading
Analysis should be extended to other configurations (e.g. bends) If not acceptable, need to consider additional measures Techniques to stabilize pipelines in muskeg (similar to peat) used in
Canada
Effects of pipeline construction on future ground stability Raised as an issue in oral hearings
Obtained advice on Irish peat issues from GSI
Practical advice from contacts with experience of construction in peat
Additional information supplied by Shell includes reports by AGEC
The recommendations made by AGEC should be followed in full and theproposed construction methods revised accordingly, in order that the
ground stability issues are managed appropriately
Risk Mitigation Options
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Main additional measure identified is pressure limitation for onshoresection
Scope for further risk reduction limited
Very important that measures already identified and recommended inour report are in place not only when pipeline is new but also
throughout the life of the pipeline
Arrangements should be made for an independent audit of construction
work and an inspection regime established to confirm safe operation ofthe pipeline in future
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Summary of Recommendations and
Closing Remarks
Summary of Recommendations (1)
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1. Consideration should be given by the Irish Government to establishing
a risk-based framework for decisions on proposed and existing major
hazard pipelines and related infrastructure, to ensure transparency and
consistency of the decision-making process
2. A formal integrity management plan should be established prior to
construction, including the operational and maintenance philosophy,
and that an independent audit and inspection regime for both the
construction and operation of the pipeline is established3. The pressure in the onshore pipeline should be limited to enable the
pipeline to be reclassified as a Class 2 (Suburban) pipeline, with a
design factor not exceeding 0.3, and the pipeline design revised in
accordance with PD 8010
Summary of Recommendations (2)
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4. A full and technically thorough reliability analysis should be carried out
of the subsea pressure control and isolation systems specified in the
field design to enable appropriate additional pressure control measures
to be implemented and the effective limitation of the pressure in the
onshore pipeline demonstrated
5. The recommendations made by AGEC should be followed in full and
the proposed construction methods revised accordingly, in order that
the ground stability issues are managed appropriately6. In the event that additional fields were proposed to be tied in to the
pipeline at any future date, a full review would be required to consider
issues such as extension of the life beyond the initial design life,
changes in the fluids in the pipeline or changes in the operatingpressures
Closing Remarks (1)
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We recognise the real concerns over the safety of the Corrib pipeline
The review has been undertaken by independent, professional staff withwide-ranging experience of pipeline safety issues including pipeline
incidents We have applied world class risk assessment tools and methodologies
for the assessment of risk from gas pipelines, validated by full scale
experiments and incident data
In making our recommendations, we have taken into account thesocietal concerns and the uncertainty in risk analysis
Our recommendations are in line with the principles embodied in soundengineering design standards for pipelines
Closing Remarks (2)
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The fact that a new design is not fully covered by an existing standarddoes not make it unsafe, but it does make the requirement to
demonstrate that the design is safe more onerous
Based on a rigorous assessment of the detailed engineeringdocumentation, we have identified a number of areas where importanttechnical issues must be addressed
Provided that these detailed recommendations are followed, the
pressure is limited effectively as recommended, and a robust integritymanagement plan is in place to ensure that safety levels are maintained
throughout the life of the pipeline, we believe that there will be a
substantial safety margin in the pipeline design
Closing Remarks (3)
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We recognise that it is the nature of any review of this type that areaswhere problems are identified are given a high profile, whereas much of
the engineering design work is satisfactory and receives little credit
We would like to recognise the co-operation received from Shell andtheir contractors, including responses to requests for information
We would also like to thank those that made submissions as part of theprocess, both written and oral, and in particular the courtesy shown to
us at the oral hearings