Inspection Maintenace and Repair of Deepwater Pipelines - PERITUS

Inspection Maintenance and Repair of Deepwater Pipelines

DNV RP-F113

Deep and Ultra-deepwater Pipelines Conference

27 - 28 September 2011, Novotel Paris Les Halles

Ian Nash

Inspection Maintenance and Repair of Deepwater Pipelines 11

Introduction

R i t f i li i ti h t h d h• Requirements for pipeline inspection: what, when and how

• Pipeline maintenance and routine inspection

• Pipeline damage during installation and operation in Pipeline damage during installation and operation in deepwater, causes and effects

• Understanding the real risks and potential need for repair

• Repair systems, tools and techniques



Ian Nash


Requirements for pipeline Requirements for pipeline inspection: what, when and how



Ian Nash


Typical Characteristics of Deepwater Pipelines

• 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

• All inspection, maintenance and repair is performed remotely

• High levels of Insulation are commonly required } Insulation Degradation

• Waters are typically cold approx 4C- 6C } CP, Flow Assurance, Materials

Pi li d b d b i } Drepair is performed remotely• 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• 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, DamageDeep and Ultra-deepwater Pipelines Conference


Ian Nash


BASELINE SURVEY

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

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

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

l f h ll f h d l b lOn completion of the installation of the deepwater Pipelines, an as-built survey will be undertaken by the Installation Contractor to ensure that the construction is fit for service. Similarly the Subsea Commissioning Team will

d t k t t bli h t f ti lit d i iti l i t it f th undertake surveys to establish correct functionality and initial integrity of the system.

Together the As-Built and Commissioning surveys will form the Baseline Survey g g y f yagainst which future inspection will be measured.



Ian Nash


INSPECTION STRATEGY (1)

Planned inspection campaigns are an integral part of the IMR strategy, the purpose of the inspections being to monitor pipeline system integrity over time and to monitor the impact of the subsea and production environments on the and to 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 investigations involving detailed or specialist techniques. The normal physical inspection tasks undertaken on the Deepwater Pipelines can be split into locations internal and undertaken on the Deepwater Pipelines can be split into locations internal and external to the pipeline.

Internal and External locations are typically periodically inspected by Piggingd ROV/AUV th d ti l and ROV/AUV methods respectively.

Permanent monitoring methods also exist and are becoming more commonplace.p



Ian Nash


INSPECTION STRATEGY (2)

With deepwater lateral buckling and walking issues, Inspection strategy needs to include interaction with the designersto include interaction with the designers.

If your system is anticipated to have multiple start up and shut down scenarios you will need to understand what the designers anticipated happening and how

i ito monitor it.

In addition there may be need to reconfirm whats happened once the pipeline is in operation. I.e. the designers have probably planned for the worst case, but if p g p y p f , fthings are not that bad and/or the operational approach changes this can result in very different results to those planned and design for.

The requirement for and frequency of inspection will most commonly be The requirement for and frequency of inspection will most commonly be determined using risk based techniques



Ian Nash


INSPECTION METHODSLocationLocation MethodMethod TechniqueTechnique DefectsDefects

Magnetic FluxMagnetic Flux

UltrasonicUltrasonicSpanning/Burial

InternalInternal

PiggingPigging VisualVisual

CalliperCalliper

Geometry (XYZ)Geometry (XYZ)

PPCorrosion Corrosion

Corrosion

Dents

GougesPermanent MonitoringPermanent Monitoring

Probe/SpoolProbe/SpoolSand ProbeSand Probe

VisualVisual

Geometry XYZGeometry XYZ

leak

CP Failure

C i DInspectionInspection

ROVROV

BurialBurial

AcousticAcoustic

CP ProbeCP Probe

Weld ScannerWeld Scanner

Coating Damage

Hydrate

Movement

ExternalExternal

SSTomography

Scanning Tomography

Scanning Side ScanSide Scan

AUVAUV

VisualVisual

G t (XYZ)G t (XYZ)

Buckle

Vibration

CrackingAUVAUV Geometry (XYZ)Geometry (XYZ)

SidescanSidescan

Permanent MonitoringPermanent Monitoring

VibrationVibration

StrainStrain

Cracking

Fatigue

Protection Integrity (mattresses/ Rock/Covers)



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INSPECTION – DEFECT MATRIX

Location Method Technique

Defect

anning

/ ial/ Scour

orrosion

Den

ts

Gou

ges

leak

rosion

P Failu

re

Coating

amage

Hydrate

ovem

ent

Buckle

bration

otectio

n ntegrity

racking

Spa

Buri Co

D G E CP C D H

Mo B Vi Pro In Cr

Pigging

Magnetic FluxUltrasonicVisual

Internal

PiggingCalliper

Geometry (XYZ)

Permanent Corrosion Probe

MonitoringProbe

Sand ProbeVisualAcousticCP Probe

External

ROV Weld Scanner

TomographySide ScanVisual

AUV AcousticSidescan

Permanent Monitoring

VibrationStrain



Ian Nash


Risk Based Inspection Concept

Identify Threats/Hazards

to Pipeline

Assess Inspection

History DNV RP-F116 (Sec H1)

The risk assessment comprises the following main

Susceptibility to Threat

Failure Mode

R i i

The risk assessment comprises the following main tasks;

a) Establish equipment scope

b) Identify threatsLikelihood of

FailureConsequence

of Failure

Remaining Life or

Inspection Grade

b) Identify threats

c) Data gathering

d) Data quality review

f fRisk Factor

e) Estimate probability of failure (PoF)

f) Estimate consequences of failure (CoF)

g) Determine risk

Mitigation Measure to

h) Identify risk mitigating measures

i) All equipment threats have considered

j) Determine aggregated risk

Risk Risk OK?OK?

Measure to reduce

susceptibilityInspection

Scheme

j) Determine aggregated risk

k) Planning of inspection, monitoring and testing activities



Ian Nash


Design Design Code Code

Targeted Inspections

DossierDossier

Defect Type1Defect Type1

RequirementsRequirements

Defect Defect selectedselected

Rec

ords

Rec

ords

Defect Type 2Defect Type 2


Review Review designdesign

Review Review previous previous

inspectionsinspections Insp

ecti

on R

Insp

ecti

on R




Determine Determine most likely most likely

locationlocation

Prepare & Prepare & Perform Perform TargetedTargetedI iI i


Record Record ResultsResults

InspectionInspection

Defect Defect Defect Defect observed?observed?No

StopStop

Yes

Assess Defect & Assess Defect & Determine CorrectionDetermine Correction



Ian Nash


Deepwater Pig Inspection

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

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

The most favoured inspection methods are either ultrasonic or magnetic fluxThe most favoured inspection methods are either ultrasonic or magnetic fluxinspection.

Magnetic flux is limited by magnet strength, ie get enough magnetism in the wall of the pipe to enable good results to be obtained 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 a liquid medium.

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



Ian Nash


issue)

Deepwater ROV Inspection

Traditionally, external inspection, of deepwater pipelines is performed using work ROVs deployed from DP ROV support vessels.

These vessels are expensive, and they may not be available when they are needed most. needed most.

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

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

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



Ian Nash


AUV based Inspection

AUV-based Inspection in deepwater fields may provide dramatic improvements in cost, 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 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 imposed higher seas, without the operational limitations and equipment hazards imposed by umbilical and tether management systems.

• Reduction in equipment complexity, vessel size and crew size would also result in i d f t li bilit d l i t l i t improved safety, reliability, and lower environmental impact.

• In the future AUVs would become “field resident”, residing in the subsea field for periods of months. The end state of “Vessel Independent Operations” will achieve f h d h l f d ffurther reductions in cost while improving performance and safety.



Ian Nash


Pipeline routine inspection and maintenance



Ian Nash


Optimisation of Routine/Scheduled Inspection

An optimum IMR plan aims to strike an appropriate balance between the f ll i bj ifollowing 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 thereducing to as low as is reasonably practicable all risks to people, the

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



Ian Nash


Optimisation of Routine Inspection Measures

The typical variation of failure rate in an operating system with time, takes the shape of the classic 'bath-tub' curve, and can be divided into three phases:• Phase 1, early failures or damage, due to

Phase 1Phase 3

rate

, y g ,defects in materials, incorrect installation, incorrect operation, unexpected environmental effects (Scouring etc)

Phase 2

Failu

re r

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

Time

g, ),• Phase 3, wear out failures or damage, due

to corrosion, fatigue, internal erosion, anode depletion coating breakdown etcanode depletion, coating breakdown etc



Ian Nash


Minimising through-life IMR-related costs

The implication of the bath-tub curve is that relatively frequent and intensive inspectionis required in the early years, i.e.• Phase 1. As inspection data demonstrating good pipeline system* performance

accumulates, it is rational to adopt a reduced frequency and scope of inspection. Thus a progressive reduction of inspection effort may be expected towards the end of Phase 1 and into Phase 2of Phase 1 and into Phase 2.

• Phase 2 for a typical subsea pipeline extends to several decades, • Phase 3 may not actually be reached during the operational lifetimes of many

j t H if i ti d t t t t h th t f tprojects. However, if inspection data starts to show the onset of wear-out mechanisms then an increased level of maintenance could be reintroduced.

As far as possible, inspection, maintenance and repair activities should be pre-plannedp , p , p p pto take advantage of tendered contracts, optimum weather conditions and wherenecessary co-incidence with planned pipeline shutdowns.

*Th b l f h i i h h d i h i h i d b i*The best way to control some of these is with the designers having the experience and beingallowed the time to investigate/ design a more robust solution CAPEX vrs OPEX



Ian Nash


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 OS2. 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)



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Inspection Planning



Ian Nash


Example Process from RP-F116Inspection Interval



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Example Process from RP-F116Schedule PlanningSchedule Planning



Ian Nash


Years

urvey

vey

e"

Type of Inspectionst As‐Bu

ilt S

Baselin

e Surv

Phase 1

"Early Failure

Phase 21)

"Random Failure"Phase 33)

"Wear‐Out Failure"Co

ns B "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 CP and Side Scan

Towed Acoustic Side Scan Sonar 2)

Targeted Special ? ?

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.

Targeted Special Events ? ? ?



Ian Nash


j g

Pipeline Maintenance

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

ibl possible.

Routine maintenance Routine maintenance tasks are required where the elimination of specific q f p fintervention is uneconomic or technically problematic. Normally such maintenance would be undertaken during repair activity, or combined with planned inspection campaigns. p p p g

Corrective MaintenanceIntervention to rectify breakdown or degradation (Corrective Maintenance) is referred to as ‘Repair’referred to as Repair .

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

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



Ian Nash


Pipeline damage during installation and operation in deepwater, causes and effectsp p , ff



Ian Nash


Installation Damage Scenarios

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

• 3rd Party Objects Dropped from Ships

• Damage to pipeline geometry and/or pipewall:

Objects Dropped from Ships Material and Construction

Defects

• Installation

Gouges, Grooves and Notches. Dents Wet and Dry Buckles. Overstressing or Excessive Bending.

• Installation Tension failure Station Keeping

• Geohazards

• Coating Damage (Corrosion and Weightcoating):

Fatigue Damage. Bend Pull Out

• Geohazards Slope Stability

• Route Features Rock Outcrops Cement Soil

g) Lost & Damaged weight coating Damaged corrosion coating Lost & Damaged insulation coating

• Anode Damage: Rock Outcrops, Cement Soil,Shell and Coral Banks.

Pockmarks

g Lost anode Disconnected anode



Ian Nash


Operational Damage Scenarios

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

• Geohazards Earthquakes Seismic Fault movement

• 3rd Party Trawling Anchoring

Submarine Landslides Mass Gravity Flows Turbidity Currents Sub-marine Volcanoes

g Objects Dropped from Ships Ship sinking Ship Grounding Shipwrecks and Debris

Liquefaction Tsunamis

• Route Features Rock Outcrops, Cement Soil, Shell and Coral

p Material and Construction

Defects Sabotage Military Action p , ,

Banks. Shallow Gas and Seepage of Gas and Fluids Pockmarks Mud Diapirs and Mud Volcanoes

y• Environmantal

Wind, Waves and Currents Scour Seabed Morphodynamics p

Slope Instability Mass Movements

p y



Ian Nash


Operational Damage Scenarios (effects)

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

• Coating Damage (Corrosion and Weightcoating): Lost & Damaged weight coating Damaged corrosion coating

• Damage to pipeline geometry and/or pipe wall: Rupture. Internal Corrosion. External Corrosion Damaged corrosion coating

Lost & Damaged insulation coating• Anode Damage:

Lost anode Disconnected anode

External Corrosion. Pinhole Leak. Gouges, Grooves and Notches. Cracks and Fracture Propagation. Dents and Buckles Disconnected anode

Over consumption Anode pasivity

• Hydrate Formation: Pinhole Leak

Dents and Buckles. Overstressing or Excessive Bending. Fatigue Damage.

Pinhole Leak. Lost & Damaged insulation coating Incorrect operation



Ian Nash


Damage Category and ScenarioPhase Damage Category Specific Damage Scenario

Installation Dry Buckle Dry Local BuckleDry Propagating Buckle

Wet Buckle Wet BuckleWet Buckle Wet BuckleLoss of Coating Buckle/Stinger impactHydrate Hydrate

Internal/External CorrosionGouge/Dent/Buckle

Localized Damage,No Leak

Gouge/Dent/BuckleOverstressingFatigue DamageTrawling/AnchoringObjects Dropped from Ships

Operation

Ship Sinking/Ship GroundingShipwrecks and DebrisEarthquakes/TsunamiMass Gravity Flows and Turbidity Currents

Localized Damage,Minor Leak

Pinhole LeakSeismic Fault/Submarine LandslipsLiquefaction/Scour

R t L l RuptureRupture, Local pEarthquakes/Slope Stability

Rupture, Extensive LengthExtensive Damage, NoLeak

RuptureInternal/External Corrosion



Ian Nash


Based on the damage scenarios and risk assessment it is clear that: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 theevent of dry or wet buckles, prior to the start of deepwater pipelayevent of dry or wet buckles, prior to the start of deepwater pipelayoperations.

• The operator should have fully developed procedures and all necessaryp y p p yequipment ready for implementation prior to the start of operations, to caterfor the following scenarios: Hydrate formation. Localised damage (i.e. dent or pinhole leak). Local Rupture. Rupture over extensive pipeline length.



Ian Nash


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



Ian Nash


Understanding the real risks and potential need Understanding the real risks and potential need for repair

MEIDP E lMEIDP Example



Ian Nash


MEIDP Example (3500m WD)



Ian Nash


Intervention ZonesBased on this preliminary information, the route has been divided into five different intervention 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)) e ote Sea ou t Sect o (300 to 3000 )

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

e

Sh lfUpper Indus FanMiddle Indus Fan Abyssal

Plain

South

Murr

ay

Rid

ge

Nort

h M

urr

ay

Rid

ge

Dalr

ym

ple

Tro

ugh

Abyss

al

Pla

inAbyssal Plain

QualhatSeamou

nt Ris

eRise

Slo

peSlo

p Shelf

11 1122 22

4455

33

3333



Ian Nash


Typical QRA for Deepwater Pipelines

MEIDP QRA Risk Contributors and % contribution

• Ship sinking (40 24%)Ship sinking (40.24%)

• Objects dropped from ships (19.91%)

• Ship grounding (14.07%)Ship grounding (14.07%)

• Material and construction defects (11.17%)

• External corrosion (10.62%)( )

• Anchoring (3.23%)

• Internal corrosion (0.63%)

• Trawling (0.12%)



Ian Nash


Typical QRA for Deepwater Pipelines

3.00E-036.00E-03

Most likely

1 50E 03

2.00E-03

2.50E-03

4.00E-03

5.00E-03Most likely location for Intervention is the deepest water

5.00E-04

1.00E-03

1.50E-03

Material and construction defects1.00E-03

2.00E-03

3.00E-03p

TrawlingAnchoring

Dropped objectsInternal corrosionExternal corrosionMaterial and construction defects

0.00E+00

TrawlingAnchoring

Dropped objectsShip sinkingShip groundingInternal corrosionExternal corrosionMaterial and construction defects

0.00E+00

Trawling

Upper Indus FanMiddle Indus Fan Abyssal Plain

South

M

urr

ay

Rid

ge

Nort

h

Murr

ay

Rid

ge

Dalr

ym ple

Tro

ugh

Abys

sal

Pla

inAbyssal Plain

QualhatSeamou

nt

R is eRise Sl o p e

Sl o p e Shelf



Ian Nash


Repair Scenarios and Types

Repair Scenario Repair Type

Dry Buckle

Excessive Plastic Strain

Profiled clamp or Spool and /or External protection

(Rock Dump)

Wet Buckle Spool (External protection)[1]Wet Buckle Spool, (External protection)[ ]

Rupture Spool, (External protection)

Internal Corrosion Clamp or Spool

External Corrosion Clamp or SpoolExternal Corrosion Clamp or Spool

Coating Damage Clamp or Spool, (External protection)

Pinhole leak Clamp

Dents, Gouges, Grooves, Notches Clamp and /or External protectiong p p

Cracks, Fracture Propagation Clamp

Hydrate Blockage Hydrate removal

Excess Unsupported Span External protection i.e. strakes, mechanical support (frame,

rock ,jetting additional analysis

Anode damage / depletion Anode replacement

Note: [1]. External protection inside ( ) denotes a secondary measure



Ian Nash


Repair systems, tools and techniques



Ian Nash


Emergency Pipeline Repair System

The minimum functional requirements identified for an emergency repair system arelisted as follows:

• Operable at water depths up to deepest water of the pipeline (3500m)p p p p p p ( )• Operable on pipe size(internal diameter) of pipelines (24”)• Operable with steel wall thickness up to maximum and relevant coatings

(40.5mm)O bl ft b d il ( ft l l d ilt)• Operable on soft seabed soils (soft calcareous clay and silt)

• Operable on seabed slopes (of up to 28 degrees)• Capable of providing a repair capability extending from minor dents to

replacement of multiple pipe jointsp p p p j

While not mandatory, it is advantageous if the system(s) and equipment also exhibitthe following characteristics:

Modular and/or lightweight• Modular and/or lightweight• Minimum number of components• Incur minimal shut down and/or reduction of operation• Minimum CAPEX investment



Ian Nash


Repair System Components

An overall pipeline repair system to install a clamp or spool requires anextensive array of equipment to conduct a repair operation The repairextensive array of equipment to conduct a repair operation. The repairsystems generally perform tasks from the following list:• Metrology of the pipeline damage and repair site• Isolation of the damaged section of pipe with internal plugs if required• Isolation of the damaged section of pipe with internal plugs if required• Soil excavation• Pipeline lifting, locally at the repair site or completely to the surface• Pipe coating removalPipe coating removal• Pipe cutting• Removal of damaged section• Pipe end surface preparationp p p• Metrology of the pipeline for clamp and spool piece preparation• Transport and positioning of clamps, spool pieces and connectors• Closing and sealing clamps and connectors• Testing the repair• Lower the pipeline to the seabed• Removal of repair system equipmentDeep and Ultra-deepwater Pipelines Conference


Ian Nash


Why Tooling is NeededEquipment Purpose

DP Support Vessel Platform from which to operate ROV’s and conduct repair operations. Pipelay Vessel Working platform in the event that an extensive section of damagedPipelay Vessel Working platform in the event that an extensive section of damaged

pipeline has to be relaid/replaced. Flooding/Dewatering/Drying Spread

Various purposes including: Pressure equalisation prior to cutting (flooding). Coupling for intelligent pigging (flooding). Removal of water (dewatering). Drying prior to returning to service to minimise water content and

risk of hydrates.Seabed Dredging/Levelling Equipment

Exposure of the pipeline, if locally trenched or buried, to allow for survey and/or repair operations.

f f ff f fPipeline Lifting Frames Elevation of pipeline off the seabed in the vicinity of any repair, for the purpose of improving access for repair equipment and operations.

Subsea Measurement Tool Performance of measurements between pipeline ends for accurate spool piece and connector assemblypiece and connector assembly.

Pipeline Cutting Tool Cutting of pipeline (and coatings) to allow removal of any damaged sections.



Ian Nash


Why Tooling is NeededEquipment Purpose

Pipeline Coating Removal Tool

Removal of external pipeline coatings in the vicinity of any section that has been cut (by the Pipeline Cutting Tool). Required in the event that the Pipeline R T l i h i li i l l fRecovery Tool grips the pipeline on its external steel surface.

External Weld Bead Removal Tool

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

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

Pipeline Recovery Tool

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 Repair Permanent clamp installed around the pipeline in the vicinity of minor damage Clamp (i.e. dent) for the purpose of ensuring the structural integrity of the pipeline

without the need for cutting out and replacing an entire section of pipe.Subsea Pipeline Connectors

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

Replacement Spool piece

New section of pipeline used to replace area of damage.

Hydrate Blockage Removal Spread

Accidental ingress of moisture into the pipeline can cause formation of a hydrate plug. Hydrate removal is possible by various passive methods but may p y p g y p y p yultimately require a deepwater hot-tap operation at actual location of the hydrate where the spread taps a hole into the pipeline and injects hydrate removal chemicals.



Ian Nash


Example Lifting Frame



Ian Nash


Damage Equipment Matrix

/ D

ryin

g Deep Water Repair System Components

Leve

lling

prea

d

quip

men

t

.e.

Split

(i.e.

ol

Tool

Tool

and

Vess

el

uppo

rt V

esse

l

g/D

ewat

erin

g (O

nsho

re)

d D

redg

ing

/ m

ent

e R

emov

al S

p

ent P

iggi

ng E

q

Cla

mp

(i.) fti

ng D

evic

e es

)

uttin

g To

ol

g R

emov

al T

oo

e R

ecov

ery

Tw

cap

abili

ty)

gy U

nit

ead

Rem

oval

ctio

n S

yste

m a

ce

Pip

elay

RO

V S

u

Floo

din

Spr

ead

Sea

bed

Equ

ipm

Hyd

rate

Inte

llige

Rep

air

Sle

eve )

Pip

e Li

H-fr

ame

Pip

e C

u

Coa

ting

Pip

elin

e(w

ith d

/w

Met

rolo

g

Wel

d B

e

Con

nec

Spo

olpi

ec

Dry Local Buckle (recoverable) (recoverable) Dry Local Buckle (non-recoverable)

Dry Propagating Buckle (non-recoverable)

Local Wet Buckle (nonLocal Wet Buckle (non-recoverable)

Hydrate plug Localised damage, no leak

Localised damage withLocalised damage with leak

Rupture, local Rupture, extensive length



Ian Nash


Repair Systems and Clubs

Equipment Name Main Contractor / Operator

Bespoke Systemsp y

Chevron Petronius Repair System Oil States / Chevron

BP Mardi Gras Pipeline Repair System Oil States / BP

SIRCOS ENI / Saipem (Sonsub)SIRCOS ENI / Saipem (Sonsub)

Pipeline Connection and Repair Systems (PCRS) Oceaneering

Total Girassol Pipeline Repair System Subsea 7

Repair Clubs

Shell Deepwater Pipeline Repair System Shell HOLD (there are two version of the Shell club?)

DW RUPE DW RUPE

Pipeline Repair System Pool Technip (Norway), Deep Ocean, Statoil

Newly Founded Repair Clubs

Emergency Pipeline Repair Equipment SharingEmergency Pipeline Repair Equipment Sharing

(EPRES)South East Asia Pipeline Operators Group (SEAPOG)

?? Pipeline Repair Operators Forum Australasia (PROFA)



Ian Nash


Candidate Systems Capability

Pipeline Repair Systems Up to 3500m Sonsub’s SIRCOS currently can work up to 2200m

Deepwater Pipeline Repair System from Oceaneering and Oil States

currently rated to about 3000m.

Saipem indicates it can be upgraded for higher water depths

Oceaneering indicates depth requirement of 3500m can be

designed and manufactured

Oil States indicates further tests are required to re-qualify their

system for 3500m rating

EPRS Capability in Terms of MEIDP RequirementsOil States Saipem Oceaneering

160%

170%

180%

190%

200%

210%

Oil States Saipem Oceaneering

90%

100%

110%

120%

130%

140%

150%

tage o

f Req

uirem

ents

20%

30%

40%

50%

60%

70%

80%

Perce

nt

0%

10%

Water Depth (m)

Connector Size (in)

Wall Thickness (mm)

Seabed Slope (deg)

Seabed Soil Strength (kPa)

Pipeline Coating (mm)

Concrete Coating (mm)

<600m



Ian Nash


Summary of Inspection for Deepwater Pipelines

Intelligent pigging is the primary form of internal inspection

ROV are the primary tool for performing external inspection

The development of AUV’s for flypast inspections may give benefits deepwater by isolating the vehicle from surface influences

Risk Based methods have been established for determining Inspection regimes (DnV Risk Based methods have been established for determining Inspection regimes (DnVRP116)



Ian Nash


Summary of Repair for Deepwater PipelinesInstallation Phase

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

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

The technology and methodologies required for rectification of installation phase damage (i e buckles) are a direct extension of techniques used for similar events indamage (i.e. buckles) are a direct extension of techniques used for similar events in shallow water, and currently exists with installation contractors and specialist equipment suppliers.



Ian Nash


Summary of Repair for Deepwater PipelinesOperational Phase

Several potential damage scenarios exist during the operational phase. The most significant are where a damaged section of pipeline needs to be reinforced, replaced or cleared of a hydrate blockage.

Where a replacement pipeline section is required, the length could vary significantly d di th t f th t i th d ( f t t ldepending on the nature of the event causing the damage (a few meters to several kilometres in the event of a geohazard (i.e. slope instability).

There is a wide range of qualified or nearly qualified equipment for the subsea repair both currently available and under continual development The equipmentrepair, both currently available and under continual development. The equipment exists both as individual components (equipment, tools and fittings) and full systems.

Some repair systems are owned and operated on a “club” basis by a group or Some repair systems are owned and operated on a club basis, by a group or consortia of pipeline operators. The clubs at present operate in specific geographical locations.

The need to access the pipeline at both ends for the purpose of re-commissioning p p p p g(i.e. flooding, cleaning, dewatering, etc.), is inherent in many of the repair scenarios. Access facilities and the provision of adequate space for equipment (particularly dewatering) are significant.



Ian Nash


Acknowledgements

The author would like to thank South Asia Gas Enterprise PVT Ltd. for giving permission to

publish aspects of this work, and the team in Peritus, for their continued hard work.



Ian Nash


References

I Nash & P Roberts OPT 2011 MEIDP The Deepwater Gas Route to India February I Nash & P Roberts OPT 2011, MEIDP The Deepwater Gas Route to India, February 23-24,

I Nash & P Roberts DUDPC 2011, Case Study: MEIDP Installation, intervention and Repair, Sept 27-28p , p

Peritus International, 18001.01-REP-IIDP-Y-0014 MEIDP, Emergency Pipeline Repair Systems, Aug 2011

Peritus International, 18001.01-REP-IIDP-Y-0007 MEIDP Quantified Risk Assessment Update, Dec 2010

Dan McLeod, Emerging Capabilities for Autonomous Inspection Repair and Maintenance, OCEANS 2010 (ART)

DNV RP-F116 Integrity Management of Submarine Pipeline Systems DNV RP-F113 Subsea Pipeline Repair



Ian Nash


Documents

Inspection Maintenace and Repair of Deepwater Pipelines - PERITUS