MARINTEK 1

Infield pipelines

-Internal condition monitoring and inspection

technology

Anders Valland, MARINTEK

Ole Øystein Knudsen, SINTEF

Roy Johnsen, NTNU

Øystein Sævik, MainTech AS

Operation and inspection of infield pipelines

9 December, 2009

Petroleumstilsynet, Stavanger

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MARINTEK 2

Agenda

Introduction A brief discussion on requirements

Use of inspection data

Inspection and monitoring technologies and methods Corrosion monitoring

In-line inspection

Future development of ILI tools and methods

First inspection Use of terms

Requirements

Risk based methodology

Conclusion

MARINTEK 3

A brief discussion on requirementsActivity regulations §47

The regulations uses the term ”first inspection”

The terms ”baseline inspection” or ”initial inspection” are

not used

”First inspection” in this regard means an inspection to

determine the actual condition with regard to fabrication,

installation and commissioning anomalies

The scope includes inspection of small, local anomalies

The results can/should be used to establish basis for comparative

future inspections

MARINTEK 4

A brief discussion on requirementsActivity regulations §47

“With regard to pipeline systems where fault modes may constitute an environment or safety risk, cf. Section 43 on classification, inspections shall be carried out to map possible corrosion of the pipe wall. Parts of the pipeline system where the lay condition or other factors may cause high loads, shall also be checked.”

Risk assessment determines whether first inspection shall be carried out

The purpose of the first inspection is to show actual condition of pipe with regard to corrosion

to show actual condition with regard to installation and commissioning defects

“The first inspection shall be carried out in accordance with the maintenance programme as mentioned in Section 44 on maintenance programme, however at the latest two years after the system has been put into operation.”

If risk assessment shows that first inspection is required, this shall take place within 2 years

The risk assessment is not used to determine time to first inspection

MARINTEK 5

Use of inspection data

Most corrosion measurements are

local

Used for evaluation of inhibitor

efficiency and change in process

parameters

Models used to describe expected

corrosion and erosion challenges

Pipeline integrity assessment

should be based on:

Risk assessment

Regularly updated measurements

and inspection findings

Corrosion modelling

MARINTEK 6

Agenda

Introduction

About the report

A brief discussion on requirements

Use of inspection data

Inspection and monitoring technologies and methods

Corrosion monitoring

In-line inspection

Future development of ILI tools and methods

First inspection

Use of terms

Requirements

Risk based methodology

Conclusion

MARINTEK 7

Corrosion monitoring technologies and

methods

Weight loss coupons

Not in use subsea

Electrical resistance probes

Inhibitor efficiency

May be used subsea

Ultrasonic technologies

Non-intrusive

Wall thickness

New, little experience

Promising results

Electric field mapping

Non-intrusive

Metal loss

Local measurements

High accuracies

Rapid response

Subsea deployment

Main issues with power, communication

MARINTEK 8

Corrosion monitoring technologies and

methods

Technology Installation Retro

Fitting

What is

measured?

Sensitivity Subsea

maturity

Type of

defect*

Limitations

UT Non-intrusive Yes Wall

thickness

<0.1 mm Prototypes

installed

Uniform Pipe coating may prevent signal

transmission

Need for physical contact with pipe

Local measurement directly under sensor

Guided wave Non-intrusive Yes Cross-

Sectional

area (CSA)

1% CSA Prototypes

installed

Uniform, local,

crack

50-100 meters in both directions from

sensor

ER Intrusive Yes (topside)

No (subsea)

Corrosivity

of fluid

<0.1

mm/year

Mature NA Finite lifetime

Electric field

mapping

Non-intrusive No Wall

thickness

0.1 mm Mature Uniform

Weight loss Intrusive Yes Corrosivity

of fluid

0.1

mm/year

No NA Provides average corrosivity only after

removal of coupon

MARINTEK 9

In-line inspection technologies and

methods

Magnetic flux leakage

Low accuracy

Fast, high coverage

Ultrasonic transducers

Liquid carrying pipelines only

Electromagnetic acoustic transducer

UT for gas pipelines

Eddy current

Suited for combination with MFL

Optical

Caliper

Requires reduced production or shut-down

Accuracy dependant on velocity

Covers entire pipeline

Technological challenges

Compare older results with new

Results <5 years old give good results

Results > 5 years old may not be comparable to new inspections

MARINTEK 10

In-line inspection technologies and

methodsTechnology Type of

fluid

Material Maturity What is measured? Sensitivity Type of defect Limitations

MFL Gas,

liquid

CS,

Magnetic

materials

Mature Volume loss Low Uniform, local Maximum wall thickness (~40 mm)

depending on force of magnetic

field

UT piezo Liquid All Mature Wall thickness Medium to high

depending on

velocity

Uniform, local Needs physical contact with pipe

wall (liquid as contact medium)

Special requirements for cleaning

prior to inspection

EMAT Gas,

Liquid

All New Uniformity of pipe wall

material

Uncertain, highest

for near-surface

Defects

Local, crack

Eddy current Gas,

liquid

All New Surface cracks and pitting Uncertain, claimed

as high

Local, crack Not for uniform metal loss

UT TOFD Gas,

liquid

All New Cracks Uncertain, claimed

as high

Crack Only for inspection of specific areas

(e.g. welds)

Requires production shut-down

Optical Optically

clear

All Mature Surface appearance

(geometry,precipitation)

Low Geometry, large

Surface

anomalies

Oil carrying pipelines must be

flushed and cleaned prior to

inspection.

Caliper Gas, liquid All Mature Surface appearance

(geometry, precipitation)

Low to medium Geometry

ART Gas, liquid All R&D Wall thickness Uncertain, claimed

as high

Uniform, local

Guided wave Gas, liquid All R&D Cross-sectional area (CSA) Uncertain, claimed

1% CSA

Uniform, local,

circumfere

ntial

cracks

ILI device needs to be stopped at

location for measurement

Production shut-down required

RFEC Gas, liquid All R&D Wall thickness (claimed),

surface cracks,

pitting

Uncertain Local, crack

MARINTEK 11

01 2 ff02 3 ff 0f

Emitting and receiving transducer

’Footprint’

Beam angle

d Sound velocity c

New developments

Research focus ”Unpiggable” pipelines

Increased accuracy, resolution, detecting small defects

Avoid production loss during inspection

Acoustic Resonance Technology No need for liquid or physical contact

Flexibility towards variations in pipe diameter

The high accuracy of the measurement enables wall thickness measurement at higher pig velocities than current state-of-art pigging.

Pigging be performed during regular production in the pipeline.

Remote field eddy current Ability to operate with some liftoff from

pipe wall

Reasonably high accuracy in the measurement

Relatively small sensor unit

Able to detect both corrosion and cracks

Primarily developed for small, snake-robots

MARINTEK 12

New developments

UT – TOFD Time-of-Flight Diffraction

US wave between two probes

Normal: reflection from surface and back-wall

Abnormal: any reflection in-between

Combined MFL and EC Eddy current probe utilises field

from MFL

Enhances capability on detection of small anomalies, e.g. cracks

May need reduced speed for accuracy

EMAT UT technology without need for

couplant/physical contact with pipe wall

Timing of reflected US pulse determines size/depth of anomaly

MARINTEK 13

New developments

Smartpipe

Sensor belt mounted under pipe

coating, thus protected

Ultrasound transducers for wall

thickness measurement

Strain gauges (both hoop and

axial direction)

Thermo elements and

accelerometers

The sensor belts are mounted in

every field joint, together with a

local micro controller, a

communication antenna and a

power supply (node).

MARINTEK 14

Agenda

Introduction

About the report

A brief discussion on requirements

Use of inspection data

Inspection and monitoring technologies and methods

Corrosion monitoring

In-line inspection

Future development of ILI tools and methods

First inspection

Use of terms

Requirements

Risk based methodology

Conclusion

MARINTEK 15

First inspection - terms

What term to use?

Baseline inspection

Forms the base condition with

which future inspections will be

compared

First inspection

Term used by the PSA

Similar to ”Initial inspection”

Anomalies from fabrication,

installation and commissioning

When to perform?

Risk based approach (e.g.DNV

RP-F116)

Design, Fabrication and

Installation (DFI) resumè

During hydrotest

Only fabrication and installation

anomalies (UT can be used)

After hydrotest

Includes effects of hydrotest

water, i.e. commissioning

anomalies

MARINTEK 16

First inspection – risk based approach

Risk = PoF x CoF

Detailed risk assessment

should be performed

DFI as valuable input

Link risk with time to first

inspection

Differentiate time to first

inspection

Time span 1-5 years

CRA pipelines

Selected to keep PoF low

Probability of detection is low

> 5 years to first inspection?

”Baseline” inspection

Defined scope

Results comparable also for

future use

Risk based assessment

Use relevant parts of first

inspection as baseline for

future inspections

MARINTEK 17

Agenda

Introduction

About the report

A brief discussion on requirements

Use of inspection data

Inspection and monitoring technologies and methods

Corrosion monitoring

In-line inspection

Future development of ILI tools and methods

First inspection

Use of terms

Requirements

Risk based methodology

Conclusion

MARINTEK 18

Summing up

Corrosion monitoring New developments within

UT technology

Electric field mapping technology

Subsea issues with power and communication

In-line inspection Increased capabilities with MFL

EMAT - UT developed for gas pipelines

Enhanced results through combination of technologies

Technology no longer obstacle for future comparative inspections

New developments Unpiggable pipes become piggable

Avoid production loss

First inspection Risk-based approach

DFI-resumè important input

Risk is linked to Time to first inspection

Time to next inspection

Differentiate time to first inspection High risk < 1 year

Low risk < 5 year

CRA pipelines Material selected for low PoF

Water from hydrotest present after production startup

May be possible with > 5 years before first inspection

MARINTEK

Report – State-of-the-art corrosion monitoring and in-line

inspection of pipelines

Available from PSA after this seminar

19

MARINTEK 20

Infield pipelines

-Internal condition monitoring and inspection technology

Thank you!