Ormen Lange

8/18/2019 Ormen Lange

1/19

Ormen Lange – CorrosionManagement of Import Pipelines

Grethe Selboe, MainTech AS


2/19

Introduction

• MainTech was awarded a contract

with A/S Norske Shell within

“Inspection &Corrosion Monitoring for

Draugen and Ormen Lange”

•Member of Shell’s start-up team for

Ormen Lange from 2005

• Localised together with the project in

Oslo to prepare for start-up in 2007

This lecture will present the work done from 2005 and how the

corrosion management systems for the import pipelines are managed

today


3/19

Ormen Lange - Facts

• Reservoir is located 120 km north

west of Kristiansund

• Discovered: 1997

• Production start: September 2007

• When Ormen Lange produces atits top, this will cover about 20 %

of Great Britain’s gas needs.

• Norsk Hydro was operator during

design and construction.

• Operator today: Norske Shell


4/19

Ormen Lange - Challenges

• Deepwater project

• Reservoir in landslide area,

steep rise towards land

• Rough seabed

• 120 km to the controlcentre

• Multiphase

• Minus 1.7 degree C,

hydrates can form


5/19


6/19

Corrosion Protection Philosophy

Import pipelines contains:

– 0.3mol% CO2

– 0.5ppmv H2S

– Acetate is present in the produced gas

– Formate is present in drilling fluids

Protection Philosophy by Injection of Chemicals:

– MEG is injected @ wellhead to prevent hydrates – pH-stabilizer (added to MEG)

– scale and corrosion inhibitor (added to MEG)

Based on

extensive testingby Hydro before

start-up


7/19

Import Pipelines – Design Details

• Made of X65 carbon steel

• Design life is 50 years

• Robust Corrosion Allowance

• Nominal wall thickness is 26.8-

35.5mm

• Thick film coating externally

• Sacrificial anodes subsea

• Impressed Current in buried

landfall area


8/19

Main Internal Threats

1. Bottom of line

– pH stabiliser + corrosion inhibitor

– Control CO2 concentration

2. Top of line – Inspection of external coating (avoid

condensation)

– Control CO2 concentration

– Control formate and acetateconcentration

– Alkalinity in MEG


9/19

Sampling & Monitoring

•Concentration of:pH stabiliser

Corrosion Inhib

•pH + Fe

•Acetate + Formate

•Water/MEG content

•Fe

•Concentration of:

pH stabiliser

Corrosion Inhib

•pH + Fe

•Acetate + Formate

•Water/MEG content

•Oxygen

Kp 0

ER probes + WLC

•Erosion probes

•Sand detectors

•Temp

•Pressure

CO2 + H2S

sampling in gas

from SC (+ in

export gas)

Wells


10/19

Inspection

Kp 0

Inspected internallyby NDT externally

Inspected externallyfor coating damage

+ Internal pigging if found necessary

Wells


11/19

Intergrity Operating Window (IOW)

What is IOW?

A selection of sample data, process data, corrosion data to control that we

are operating within defined limits. For example:

0

50

100

150

200

250

300

1 0 - m a r

1 7 - m a r

2 4 - m a r

3 1 - m a r

7 - a p

r

1 4 - a p r

2 1 - a p r

2 8 - a p r

5 - m a i

1 2 - m a i

1 9 - m a i

2 6 - m a i

2 - j u

n 9 - j u

n

C o

n c e n t r a t i o n

0

2

4

6

8

10

12

p H

Lean - pHStab (mg/l)

Rich - pHStab (mg/l)

Lean - Alk (mg/l)

Rich - Alk (mg/l)

Lean - pH

Rich - pH

pH in MEGFormate concentration


12/19

Example of IOW Parameters C

o r r o s i o n l o o p

M

o n i t o r i n g p o i n t

S y s t e m

P r i o r i t y

(

X = R e m o v e d )

F r e q u e n c y

( R

= O n R e q u e s t )

Tag # Type Parameter

T h r e a t

U n i t Limit

P h y s i c a l L o c a t i o n

C o m m e n t s

D a t aL o c a t i o n

Time

interval:01.06.09-

31.08.09

Sign: GS

Reviewed

Time

interval:01.09.09-

30.11.09

Sign: GS

Reviewed

Time

interval:01.12.09-

28.02.10

Sign: GS

Reviewed

Time

interval:01.03.10-

31.05.10

Sign: GS

Reviewed

Time

interval:01.06.10-

31.08.10

Sign:

GS/KB

Time

interval:31.08.10-

30.11.10

Sign: KB

Reviewed

01

CE-16-1025

ER probe /

Corrosion rate

LOCATION:

Import pipeline

16 1 3m CE-16-1025 ER probeCorrosion

rate

CO2corrosion

mm/yr

max 0,33

mm/yr (CA

10 mm)

Import

pipeline A

before pig

receiver/slu

g catcher

PCAD/

Livelink

0,000 mm/y

(Q3 2009)

(not

reviewed in

corrosion

0,001 mm/y

(Q4 2009)

(not

reviewed in

corrosion

0,000 mm/y

(Q1 2010)

(not

reviewed in

corrosion

0,000 mm/y

(Q2 2010)

(not

reviewed in

corrosion

0,000 mm/y

(Q3 2010)

(not

reviewed in

corrosion

0,0012

mm/y (Q4

2010) (not

reviewed in

corrosion

01

CE-16-1024

WLC / Corrosion

rateLOCATION:

Import pipeline

16 1 1yr CE-16-1024 WLC

Corrosion

rate

CO2

corrosion mm/yr

max 0,33

mm/yr (CA10 mm)

Import

pipeline A

before pigreceiver/slu

g catcher

Not online,

manual

measureme

nts yearly

Livelink

0,001 mm/y

(Q4 2009)

(notreviewed in

corrosion

0,001

/mm/y (Q4

2010) (notreviewed in

corrosion

01

EC-89-0050

ICCP / Potential

on pipelines PL-

A/B, Kp 0 to HAT

LOCATION:

89 1 1w EC-89-0050 ICCP

Potential on

pipelines PL-

A/B, Kp 0 to

HAT

External

corrosion

-0.85 to -

1.20 V vs.

Cu/CuSO4-

Landfall,

L56

Send report

to Gassco

monthly

Livelink

ICCP area

Potentials

outside

acceptable

levels from

10th of

Problem

fixed,

system is

working

satisfactory

OK OK

OK - still

current

leakage for

Pl-B

OK - still

current

leakage for

Pl-B

01

QN-16-1084

Sampling / Iron

content (total

iron)

LOCATION: After

16 1 3m QN-16-1084 SamplingIron content

(total iron)

CO2corrosion

mg/lNo limit

defined

After slug

catcher

Sample

Manager

Incrasing

trend, (6, 6

and 32

mg/l)

~ max 10

mg/l

Max 14.8

mg/l (3

samples)

Max 6.3

mg/l (3

samples)

Max 17 mg/l

(2 samples)

Max 26 mg/l

(2 samples)

01

QN-16-1084Sampling / Iron

content

(dissolved iron)

LOCATION: After

16 2 3m QN-16-1084 Sampling

Iron content

(dissolved

iron)

CO2corrosion

mg/lNo limit

defined

After slug

catcher

Sample

Manager

Incrasing

trend, (12, 7

and 36

mg/l)

~ 5 mg/l

(only 1

sampling)

No

sampling

performed

No

sampling

performed

No

sampling

performed

No

sampling

performed

01

QT-18-0638

Erosion probe /

Erosion

LOCATION:

Template A, well

18 2 3m QT-18-0638Erosion

probeEros ion Erosi on mi cron

No limit

defined.

Template A,

well 6PI Max. 47 Max. 46 Max. 46 Max. 39 Max. 38 Max. 37


13/19

Expert Group Meeting

Typical members of the group:

• Material & Corrosion Engineer (head of the group)

• Area Inspection Engineer

• Operations Representative

• Process Engineer• Production Chemist

• Pipeline Engineer

• Maintenance Engineer

• Technical Safety Engineer

Meeting frequency: Every 2nd month


14/19

Modifications to CorrMngt System

• Tests performed before start-

up showed that the CI was

effective after regeneration.

• Concentration of CI was

included as an IOW paramter

to follow

• Corrosion tests of field MEG

show that the CI partly looses

its effect after regeneration

• IOW was then revised toinclude corrosion tests, in

addition to CI concentration

sampling

Rich MEG

Lean MEG


15/19

Modifications to CorrMngt System

Original CI limits:

Lean MEG: 200 ppm Rich MEG: 100 ppm


16/19

Monthly/Bi-monthly Evaluation

QN-38-0686

LabA -

rotating1

LabA -

rotating2

LabA -

stationary1

LabA -

stationary2LabB rich lean rich lean rich lean rich lean rich lean

End March 2008 MG exp group 0 300 390 60 70 100 110 80 92

August 2008 MG exp group 5 0.11 0.14 0.06 0.1 230 290 80 100 90 100 80 92

January 2009 MG exp group 9 0.12 0.16 0.06 130 170 110 130 200 240 77 92

April 2009 MG exp group 12 0.08 110 150 80 95 180 210 6 6 6.9 75 92

June 2009 MG exp group 1 0.04 0.02 0.03 200 250 95 110 190 210 6.1 6.4 6.9 76 92

July 2009 MG exp group 2 0.03 230 330 95 120 210 210 6.2 6.4 6.4 76 91

August 2009 MG exp group 3 0.04 230 330 120 140 200 230 6.3 6.7 6.3 70 90

November 2009 MG exp group 2 0.06 270 330 no analysi o analysi o analysisno analysi 6 6.2 6.2 76 92

December 2009 MG exp group 3 0.06 220 330 220 250 350 400 6.3 6.4 6.3 77 92

March 2010 MG exp group 1 0.05 280 370 220 240 320 350 6.1 6.4 6.0 77 92

April 2010 MG exp group 2 0.07 270 370 200 250 280 330 6 6.5 6.0 77 92

July 2010 MG exp group 1 0.03 400 500 200 250 280 330 6.3 6.4 6.0 80 92

September 2010 MG exp group 3 0.06 330 430 200 290 330 400 6.1 6.5 6.1 77 92

October 2010 MG exp group 1 0.06 350 530 200 310 320 450 6.1 6.4 6.0 75 92

November 2010 MG exp group 1 0.05 350 460 200 270 320 440 6 6.4 6.1 73 92December 2010 MG exp group 2 0.06 310 430 200 300 320 460 6.1 6.3 6.1 75 92

April 2011 MG exp group 3 0.07 410 560 250 340 350 450 6.2 6.4 6.0 75 92

April 2011 MG exp group 0 0.02 410 760 250 340 350 450 6.2 6.4 6.0 75 92

Date Sign Review by

No of

months

w ithout

CI

Rate (mm/year)

QN-20-0121/QN-38-0686 QN-20-0121/QN-38-0686 QN-20-0121/QN-38-0686 QN-20-0121/QN-38-0686

CI concentration (mg/l) Acetate

concentration(mg/l)

Formate concentration

(mg/l)

pH @1bar CO2 rich

(lean) MEG

pH @1bar

CO2 rich

MEG

MEG concentration (%)

QN-20-0121/QN-38-0686


17/19

Yearly Review• Review of all parametres collected last year

• Review of all inspection results

• HydroCor calculations

– Result is compared to corrosion tests of sampled MEG and rates found during

qualification of chemicals

• PipeRBA assessment gives pipeline remaining life and inspection due date


18/19

Follow-up of IOW

1. Monthly to 3-Monthly review of most important parameters

in IOW

2. Yearly review of entire IOW + inspection results + experience

from operation + HydroCor calculations + PipeRBA

MIGHT LEAD TO A CHANGE IN PROTECTION PHILOSOPHY, PIGGING

INTERVAL, CHANGES IN SAMPLING/MONITORING PROGRAM


19/19

Summary

• By establishing a Corrosion Management system from day 1,

this will be the tool to document any life extension in the

future, if necessary

• Early involvement in project phase (approx. 2 years before

start-up) allowed us to have:

– Good understanding of challenges

– Good transfer from project (NH) to operation (Shell/MainTech)

– Good communication between disciplines, when in operation

• Systemising useful information allows you to optimise yourrisk based decision, away from conservatism

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Ormen Lange