Risk Assessment of Subsea Pipelines

8/13/2019 Risk Assessment of Subsea Pipelines

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Deep and Ultra-deepwater Pipelines Co nference

27 - 28 September 2011, Novotel Paris Les Halles

Ian Nash

Inspection Maintenance and Repair ofDeepwater Pipelines 1

Inspection Maintenance and Repair of Deepwater Pipelines

DNV RP-F113
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Inspection Maintenance and Repair ofDeepwater Pipelines

Introduction

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Requirements for pipeline inspection: what, when and how Pipeline maintenance and routine inspection Pipeline damage during installation and operation in

deepwater, causes and effects Understanding the risks and potential need for repair Repair systems & tools


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Requirements for pipelineinspection: what, when and how


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All inspection, maintenance and

repair is performed remotely

4

Water depths are beyond diver limits and all activity (IMR) is remote Wall thickness are typically high } Materials, Welding, buckling Operating pressures are typically very high or very low Ambient external pressures are high, commonly similar to internal operational

pressures } Coating and Insulation Degradation High levels of Insulation are commonly required } Insulation Degradation Waters are typically cold approx 4 C- 6 C } CP, Flow Assurance, Materials Pipelines tend not to be protected by a concrete coating } Damage Geohazards can be significant } Spanning, Buckling, Damage, Bend Stability,

Turbitity and Debris flows Slugging within produced fluids is common } Spanning, Fatigue Greater tolerances Survey inaccuracy, installation accuracy

Metocean and environmental conditions tend to be benign } Stability Seabed mobility is less dominant } Scour, Spanning Corrosion coatings tend to be of very high quality } Corrosion, Damage

Typical Characteristics of Deepwater Pipelines


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The ongoing assessment of inspection findings will involve comparison of datawith that recorded during previous inspection campaigns.

This will allow trends to be extrapolated and judgments made regarding theurgency of remedial action.

This process necessarily commences with the acquisition of the measurement ofinternally and externally taken values at the commencement of pipeline service,known as a Baseline Survey .

BASELINE SURVEY


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Planned inspection campaigns are an integral part of the IMR strategy , thepurpose of the inspections being: to monitor pipeline system integrity over time monitor the impact of the subsea and production environments on the

pipeline. Understanding and confirming design assumptions

Routine inspections may indicate a requirement for more specific investigationsinvolving detailed or specialist techniques.

The normal physical inspection tasks undertaken on the Deepwater Pipelinescan be split into locations internal and external to the pipeline.

Internal and External locations are typically periodically inspected by Pigging and Remote Vehicle methods respectively.

Permanent monitoring methods also exist and are becoming morecommonplace.

INSPECTION STRATEGY (Monitoring)


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It is essential that in developing an inspection regime that the deign is

understood and must include interaction with the designers: deepwater lateral buckling and walking issues will have been solved with

reference to the anticipatedpipeline operation response. Is that what reallyhappened?

If your system is anticipated to have multiple start up and shut downscenarios you will need to understand what the designers anticipatedhappening and how to monitor it.

there may be need to reconfirm what has actually happened once thepipeline is in operation.

INSPECTION STRATEGY (Understanding the Design)


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Location Method Technique Defects

8

Inspection

Internal

Pigging

Magnetic Flux

Ultrasonic

Visual

Calliper

Geometry (XYZ)

PermanentMonitoring

CorrosionProbe/SpoolSand Probe

External

ROV

Visual

Geometry XYZ

Burial

Acoustic

CP Probe

Weld Scanner Tomography

ScanningSide Scan

AUV

Visual

Geometry (XYZ)Sidescan

PermanentMonitoring

Vibration

Strain

Spanning/Burial

Corrosion

Dents

Gouges

leak

CP Failure

Coating Damage

Hydrate

Movement

Buckle

Vibration

Cracking

Fatigue

Protection Integrity (mattresses/Rock/Covers)

INSPECTION METHODS


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Location Method Technique

Defect

S p a n n i n g /

B u r i a

l / S c o u r

C o

r r o s i o n

D e n t s

G

o u g e s

l e a k

E r o s i o n

C P

F a i l u r e

C o a t i n g

D a m a g e

H y d r a t e

M o v e m e n t

B u c k

l e

V i b r a t i o n

P r o t e c t i o n

I n t e g r i t y

C r a c k i n g

Internal

Pigging

Magnetic FluxUltrasonic

VisualCalliper

Geometry(XYZ)

Permanent

Monitoring

CorrosionProbe

Sand Probe

External

ROV

VisualAcousticCP Probe

Weld Scanner

Tomography

Side Scan

AUV

Visual

AcousticSidescan

PermanentMonitoring

VibrationStrain

INSPECTION DEFECT MATRIX


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Risk Based Inspection Concept

IdentifyThreats/Hazards

to Pipeline

AssessInspection

History

Susceptibilityto Threat

MitigationMeasure to

reducesusceptibility

Likelihood ofFailure

Failure Mode

Consequenceof Failure

Risk Factor

RemainingLife or

InspectionGrade

InspectionScheme

DNV RP-F116 (Sec H1)

The risk assessment comprises the following maintasks;

a) Establish equipment scope

b) Identify threats

c) Data gathering

d) Data quality review

e) Estimate probability of failure (PoF) f) Estimate consequences of failure (CoF)

g) Determine risk

h) Identify risk mitigating measures

i) All equipment threats have considered

j) Determine aggregated risk

k) Planning of inspection, monitoring and testingactivities

RiskOK?


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Defectselected

RecordResults

Determinemost likely

location

Reviewdesign

Reviewprevious

inspections

Prepare &PerformTargeted Inspection

Defectobserved?

I n s p e c

t i o n

R e c o r

d s

DesignDossier

No

Stop

Yes

Defect Type 2

Defect Type 3

Defect Type 4

Defect Type 5

Defect Type 6

Defect Type1

Assess Defect &Determine Correction

CodeRequirements

Targeted Inspections


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Pig Inspection of offshore pipelines tends to look for internal problems .

Generally running pigs in offshore pipelines is very similar to running in onshorelines, after the wall thickness and higher pressures are taken in to consideration.

The most favoured inspection methods are either ultrasonic or magnetic flux inspection.

Magnetic flux is limited by magnet strength , ie get enough magnetism in the wall

of the pipe to enable good results to be obtained.Ultrasonic can inspect very thick wall pipe but Ultrasonic's have to be run in aliquid medium .

The main difference between offshore and onshore is the length of run betweenpig traps, as Offshore pipelines tend not to have intermediate compressionstations with conveniently located pig traps. The pig must not get stuck in thepipeline as retrieving it will be much more expensive than from an onshorepipeline. The pig must stay alive and recording data (battery duration may be anissue)

Deepwater Pig Inspection


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Traditionally, external inspection, of deepwater pipelines is performed usingwork ROVs deployed from DP ROV support vessels .These vessels are expensive , and they may not be available when they areneeded most.

In deep waters, ROVs become heavy to handle from these vessels, becauseof long umbilicals ; and they become prone to breakdowns .

ROV inspections of long transmission lines can be very slow and may takemany months to complete end to end

Weather downtime is also an issue for ROV support vessels when workingin harsh and hostile environments

Deepwater ROV Inspection


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AUV based Inspection

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AUV-based Inspection in deepwater fields may provide dramatic improvements incost, performance, safety and reliability. Large DPII vessels with high-end ROV spreads would no longer be required for

simple inspection. AUVs have demonstrated solid performance requiring simple autonomy for

missions such as bathymetric survey and high resolution sonar imaging AUVs can be deployed from small utility vessels , be capable of operations in

higher seas , without the operational limitations and equipment hazards imposedby umbilical and tether management systems. In the future AUVs would become field resident , residing in the subsea field for

periods of months.


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Pipeline routine inspection and maintenance

O i i i f R i /S h d l d I i


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Optimisation of Routine/Scheduled Inspection

An optimum IMR plan aims to strike an appropriate balance between the

following objectives: maximising the availability of the pipeline system during its operating life by

maintaining and preserving its integrity, thus maximising revenue; minimising inspection, intervention and rectification measures through the

life of the pipeline system, thus minimising through-life IMR related costs . reducing to as low as is reasonably practicable all risks to people, the

environment and assets , in accordance with legislative, societal and businessrequirements, thus minimising the costs of failures.

When and What do we inspect?

O i i i f R i I i M


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Optimisation of Routine Inspection Measures

Phase 1

Phase 2

Phase 3

Time

F a

i l u r e

r a t e

The typical variation of failure rate in anoperating system with time, takes the shapeof the classic ' bath-tub ' curve, and can bedivided into three phases: Phase 1, early failures or damage, due to

defects in materials, incorrect installation,incorrect operation, unexpectedenvironmental effects (Scouring etc)

Phase 2, random failures or damage, dueto earthquakes, impacts (dropped objects,fishing, anchors), etc

Phase 3, wear out failures or damage, dueto corrosion, fatigue, internal erosion,anode depletion, coating breakdown etc

C d R i t DNV OS F101
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Code Requirements DNV OS-F101

1. Define equipment scope ( i.e. All equipment that can lead to a failure) (DNV- OS-F101, Sec. 11, D304)

2. For each equipment, identify all threats which can lead to a failure (DNV-OS- F101, Sec. 11, D201)

3. For each threat; estimate risk (DNV-OS-F101, Sec. 11, D202) Consequence of failure (CoF) Probability of failure (PoF)

Propose plans for: Inspection, monitoring and testing (IMT) (DNV-OS-F101, Sec. 11, D103) Mitigation, intervention and repair (MIR) (DNV-OS-F101, Sec. 11, D700) Integrity assessment (IA) (DNV-OS-F101, Sec. 11, D600)

I ti Pl i g


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Inspection Planning

Inspection Planning


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Inspection Planning

APPENDIX G

EXAMPLE - RISK ASSESSMENT AND IM PLANNING

E mple Process from RP F116


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Example Process from RP-F116Inspection Interval


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Example Process from RP-F116Schedule Planning


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1) Reduction in annual inspection applies to remote subsea pipelines only 2) Acoustic side scan sonar is not always cost effective especially indeepwater or where there are strong currents. An ROV survey with reduced scope could be considered 3) the third phase may not occur withinnormal project lifetimes, i.e. the Phase 2 (plateau phase) extends for several decades with well designed, operated and maintained facilities.

Type of Inspection

Years

s t s -

i l t

r

s l i

r

P h a s e 1

" E a r

l y F a i l u r e

"

Phase 2 1)

"Random Failure"Phase 3 3)

"Wear-Out Failure"

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Intelligent Pig

Visual including CPand Side Scan

Towed Acoustic SideScan Sonar 2)

Targeted Special

Events ? ? ?

Pipeline Maintenance


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Preventive maintenanceBecause of the high cost and potential delays associated with intervention,preventive maintenance should be eliminated at the design stage , wherever

possible.Routine maintenanceRoutine maintenance tasks are required where the elimination of specificintervention is uneconomic or technically problematic . Normally suchmaintenance would be undertaken during repair activity, or combined withplanned inspection campaigns.

Corrective MaintenanceIntervention to rectify breakdown or degradation (Corrective Maintenance) isreferred to as Repair.

Normally Subsea Facilities shall possess sufficient reliability to ensureavailability throughout the field life.

Subsea equipment that is susceptible to failure should be designed tominimize the effort /cost required for replacement of the failed assembly.

Pipeline Maintenance


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Pipeline damage during installation andoperation in deepwater, causes and effects

Installation Damage Scenarios


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Installation Damage Scenarios

The potential causes and effects of damage during installation Phase of the pipeline(s) are summarized as follows:

rd PartyObjects Dropped from Ships Material and Construction Defects

InstallationTension failure Station Keeping

Geohazards Slope Stability

Route Features

Rock Outcrops, Cement Soil, Shell and Coral Banks.Pockmarks

Coating Damage (Corrosion and Weight coating):

Lost & Damaged weight coating Damaged corrosion coating Lost & Damaged insulation coating

Anode Damage:Lost anode Disconnected anode

Damage to pipeline geometry and/or pipe wall:

Gouges, Grooves and Notches.Dents Wet and Dry Buckles.Overstressing or Excessive Bending.Fatigue Damage.Bend Pull Out

Operational Damage Scenarios


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Operational Damage Scenarios

The potential causes of damage during operational Phase of the pipeline(s) are summarized as follows:

GeohazardsEarthquakes Seismic Fault movement Submarine Landslides Mass Gravity Flows Turbidity Currents Sub-marine Volcanoes Liquefaction Tsunamis

Route FeaturesRock Outcrops, Cement Soil, Shell and Coral Banks.Shallow Gas and Seepage of Gas and Fluids Pockmarks Mud Diapirs and Mud Volcanoes Slope Instability Mass Movements

rd PartyTrawling Anchoring Objects Dropped from Ships Ship sinking

Ship Grounding Shipwrecks and Debris Material and Construction Defects Sabotage Military Action

Environmantal

Wind, Waves and Currents Scour Seabed Morphodynamics

Operational Damage Scenarios (effects)


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Operational Damage Scenarios (effects)

The effect of damage that could occur during the operational phase of the pipeline(s) are summarized as follows:

Coating Damage (Corrosion and Weight coating):

Lost & Damaged weight coating Damaged corrosion coating Lost & Damaged insulation coating

Anode Damage: Lost anode Disconnected anode Over consumption Anode pasivity

Hydrate Formation: Pinhole Leak.Lost & Damaged insulation coating Incorrect operation

Damage to pipeline geometry and/or pipe wall:

Rupture.Internal Corrosion.External Corrosion.Pinhole Leak.

Gouges, Grooves and Notches.Cracks and Fracture Propagation.Dents and Buckles.Overstressing or Excessive Bending.Fatigue Damage.


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Based on the damage scenarios and risk assessment it is clear that: The pipeline installation contractor should have fully developed procedures

and all necessary equipment mobilised and ready for implementation in the event of dry or wet buckles, prior to the start of deepwater pipelay operations.

The operator should have fully developed procedures and all necessary

equipment ready for implementation prior to the start of operations, to cater for the following scenarios:

Hydrate formation.Localised damage (i.e. dent or pinhole leak).Local Rupture.Rupture over extensive pipeline length.


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Understanding the risks and potential need forrepair

MEIDP Example

MEIDP Example (3500m WD)


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MEIDP Example (3500m WD)

Intervention Zones


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Based on this preliminary information, the route has been divided into five differentintervention requirement zones.

1) Shallow Water Zone (0 to 150m WD)

2) Continental Slope Zone (150m to 2500m WD)3) Deep Water Section (2500m to 3500m WD)

4) Remote Seamount Section (300m to 3000m WD)

5) Indus Fan Section (2500m to 3000m WD)

Upper Indus FanMiddle Indus Fan AbyssalPlain

S o u t

h M u r r a y

R i d g e

N o r t h

M u r r a y

R i d g e

D a

l r y m p

l e

T r o u g

h

A b y s s a

l

P l a i nAbyssal

PlainQualhat Seamou

nt R i s eRise

S l o p e

S l o p e Shelf

1 1

45

3

33

2 2

Intervention Zones

Typical QRA for Deepwater Pipelines


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yp p p

MEIDP QRA Risk Contributors and % contribution Ship sinking (40.24%) Objects dropped from ships (19.91%) Ship grounding (14.07%) Material and construction defects (11.17%) External corrosion (10.62%) Anchoring (3.23%) Internal corrosion (0.63%) Trawling (0.12%)

Typical QRA for Deepwater Pipelines


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Trawling Anchoring

Dropped objectsInternal corrosion

External corrosionMaterial and construction defects

0.00E+00

5.00E-04

1.00E-03

1.50E-03

2.00E-03

2.50E-03

3.00E-03

Trawling Anchoring

Dropped objectsShip sinking

Ship groundingInternal corrosionExternal corrosionMaterial and construction defects

0.00E+00

1.00E-03

2.00E-03

3.00E-03

4.00E-03

5.00E-03

6.00E-03

Most likelylocation forIntervention is thedeepest water

Upper Indus FanMiddle Indus Fan AbyssalPlain

S o u t

h

M u r r a y

R i d g e

N o r t h

M u r r a y

R i d g e

D a l r y m p

l e

T r o u g

h

A b y s s a

l

P l a

i nAbyssalPlain

Qualhat Seamou

nt

R i s eRise S l o p e S l o p e Shelf


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Repair systems & tools

Help is at Hand


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This Recommended Practice (RP) is intended to provide criteria and guidelines for the qualification offittings and systems used for pipeline subsea repair and/or modifications and tie-ins.

Help is at Hand


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Why Tooling is Needed


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Why Tooling is Needed

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Equipment PurposePipeline CoatingRemoval Tool

Removal of external pipeline coatings in the vicinity of any section that hasbeen cut (by the Pipeline Cutting Tool). Required in the event that the PipelineRecovery Tool grips the pipeline on its external steel surface.

External Weld BeadRemoval Tool

Removal of external longitudinal weld seam (SAW linepipe) to preventinterference on connector seal.

End Preparation Tool Machining of the end face of the pipeline to prevent interference on connectorseal.

Pipeline RecoveryTool

Tool connected to the end of the cut pipeline to allow recovery to surface.Designed to allow the pipeline be dewatered and isolated prior to recovery.

Pipeline RepairClamp

Permanent clamp installed around the pipeline in the vicinity of minor damage(i.e. dent) for the purpose of ensuring the structural integrity of the pipelinewithout the need for cutting out and replacing an entire section of pipe.

Subsea PipelineConnectors

Connector assembly and modular system used for the installation andconnection of a new section of pipeline.

Replacement Spoolpiece

New section of pipeline used to replace area of damage.

Hydrate BlockageRemoval Spread

Accidental ingress of moisture into the pipeline can cause formation of ahydrate plug. Hydrate removal is possible by various passive methods but may

ultimately require a deepwater hot-tap operation at actual location of thehydrate where the spread taps a hole into the pipeline and injects hydrateremoval chemicals.

Summary of Inspection for Deepwater Pipelines
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Su a y o spect o o eepwate pe es

Intelligent pigging is the primary form of internal inspection

ROV are the primary tool for performing external inspection

The development of AUVs for flypast inspections may give benefits deepwater byisolating the vehicle from surface influences

Risk Based methods have been established for determining Inspection regimes (DnV

RP116)

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Summary of Repair for Deepwater PipelinesI ll i Ph


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Installation Phase

Damage scenarios during installations and operation pose differing levels of risk.

The most significant potential damage scenarios during the installation phase aredry and wet buckles.

The technology and methodologies required for rectification of installation phasedamage (i.e. buckles) are a direct extension of techniques used for similar events inshallow water, and currently exists with installation contractors and specialistequipment suppliers.

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Summary of Repair for Deepwater PipelinesO ti l Ph


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Operational Phase

Several potential damage scenarios exist during the operational phase. The most

significant are where a damaged section of pipeline needs to be reinforced, replacedor cleared of a hydrate blockage.Where a replacement pipeline section is required, the length could vary significantlydepending on the nature of the event causing the damage (a few meters to severalkilometres in the event of a geohazard (i.e. slope instability).There is a wide range of qualified or nearly qualified equipment for the subsearepair, both currently available and under continual development. The equipmentexists both as individual components (equipment, tools and fittings) and fullsystems.Some repair systems are owned and operated on a club basis, by a group orconsortia of pipeline operators. The clubs at present operate in specificgeographical locations.The need to access the pipeline at both ends for the purpose of re-commissioning

(i.e. flooding, cleaning, dewatering, etc.), is inherent in many of the repair scenarios.Access facilities and the provision of adequate space for equipment (particularlydewatering) are significant.

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References


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I Nash & P Roberts OPT 2011, MEIDP The Deepwater Gas Route to India, February23-24,I Nash & P Roberts DUDPC 2011, Case Study: MEIDP Installation, intervention andRepair, Sept 27-28 Peritus International, 18001.01-REP-IIDP-Y-0014 MEIDP, Emergency Pipeline RepairSystems, Aug 2011Peritus International, 18001.01-REP-IIDP-Y-0007 MEIDP Quantified Risk

Assessment Update, Dec 2010 Dan McLeod, Emerging Capabilities for Autonomous Inspection Repair andMaintenance, OCEANS 2010 (ART) DNV RP-F116 Integrity Management of Submarine Pipeline Systems DNV RP-F113 Subsea Pipeline Repair

Documents

Risk Assessment of Subsea Pipelines