ormen lange – corrosion management of import pipelines 2011... · corrosion management systems...

Ormen Lange – Corrosion Management of Import Pipelines Grethe Selboe, MainTech AS

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

Ormen Lange - Facts • Reservoir is located 120 km north

west of Kristiansund • Discovered: 1997 • Production start: September 2007 • When Ormen Lange produces at

its top, this will cover about 20 % of Great Britain’s gas needs.

• Norsk Hydro was operator during design and construction.

• Operator today: Norske Shell

Ormen Lange - Challenges

• Deepwater project • Reservoir in landslide area,

steep rise towards land • Rough seabed • 120 km to the control

centre • Multiphase • Minus 1.7 degree C,

hydrates can form

Ormen Lange – Subsea CORROSION CHALLENGES: • No corrosion monitoring

subsea • Rely on sampling and

online monitoring onshore • Pigging is difficult and non-

conclusive in early stage of operation

Template A

Template B

Template D

Template C (future)

2x30” multiphase pipelines

2x6” MEG pipelines and umbilicals

42” Langeled

ESTABLISHMENT OF A RELIABLE CORROSION MANAGEMENT SYSTEM TO CONTROL THE PIPELINES BECAME VERY IMPORTANT

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 testing by Hydro before start-up

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

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 acetate

concentration – Alkalinity in MEG

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

Inspection

Kp 0

Inspected internally by NDT externally

Inspected externally for coating damage

+ Internal pigging if found necessary

Wells

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

10-m

ar

17-m

ar

24-m

ar

31-m

ar7-a

pr

14-ap

r

21-ap

r

28-ap

r5-m

ai

12-m

ai

19-m

ai

26-m

ai2-j

un9-j

un

Con

cent

ratio

n

0

2

4

6

8

10

12

pH

Lean - pHStab (mg/l)Rich - pHStab (mg/l)Lean - Alk (mg/l)Rich - Alk (mg/l)Lean - pHRich - pH

pH in MEG Formate concentration

Example of IOW Parameters

Corrosion loop

Monitoring point

System

Priority (X = Rem

oved)

Frequency (R= O

n Request)

Tag # Type Parameter

Threat

Unit Limit

Physical Location

Comm

ents

Data Location

Time interval: 01.06.09-31.08.09Sign: GSReviewed




Time interval: 01.06.10-31.08.10Sign: GS/KB

Time interval: 31.08.10-30.11.10Sign: KBReviewed

01

CE-16-1025ER probe / Corrosion rateLOCATION: Import pipeline

16 1 3m CE-16-1025 ER probeCorrosion

rateCO2

corrosionmm/yr

max 0,33 mm/yr (CA 10 mm)

Import pipeline A before pig receiver/slug catcher

PCAD/Livelink

0,000 mm/y (Q3 2009) (not reviewed in corrosion






01

CE-16-1024WLC / Corrosion rateLOCATION: Import pipeline

16 1 1yr CE-16-1024 WLCCorrosion

rateCO2

corrosionmm/yr

max 0,33 mm/yr (CA 10 mm)

Import pipeline A before pig receiver/slug catcher

Not online, manual measurements yearly

Livelink


0,001 /mm/y (Q4 2010) (not reviewed in corrosion

01

EC-89-0050ICCP / Potential on pipelines PL-A/B, Kp 0 to HATLOCATION:

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-16-1084Sampling / Iron content (total iron)LOCATION: After

16 1 3m QN-16-1084 SamplingIron content (total iron)

CO2

corrosionmg/l

No 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 SamplingIron content (dissolved

iron)

CO2

corrosionmg/l

No limit defined

After slug catcher

Sample Manager

Incrasing trend, (12, 7 and 36 mg/l)

~ 5 mg/l (only 1 sampling)

No sampling performed




01

QT-18-0638Erosion probe / ErosionLOCATION: Template A, well

18 2 3m QT-18-0638Erosion probe

Erosion Erosion micronNo limit defined.

Template A, well 6

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

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

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 to include corrosion tests, in addition to CI concentration sampling

Rich MEG

Lean MEG

Modifications to CorrMngt System Original CI limits: Lean MEG: 200 ppm Rich MEG: 100 ppm

Monthly/Bi-monthly Evaluation

QN-38-0686

LabA - rotating1

LabA - rotating2

LabA - stationary1

LabA - stationary2

LabB rich lean rich lean rich lean rich lean rich lean

End March 2008 MG exp group 0 300 390 60 70 100 110 80 92August 2008 MG exp group 5 0.11 0.14 0.06 0.1 230 290 80 100 90 100 80 92January 2009 MG exp group 9 0.12 0.16 0.06 130 170 110 130 200 240 77 92April 2009 MG exp group 12 0.08 110 150 80 95 180 210 6 6 6.9 75 92June 2009 MG exp group 1 0.04 0.02 0.03 200 250 95 110 190 210 6.1 6.4 6.9 76 92July 2009 MG exp group 2 0.03 230 330 95 120 210 210 6.2 6.4 6.4 76 91August 2009 MG exp group 3 0.04 230 330 120 140 200 230 6.3 6.7 6.3 70 90November 2009 MG exp group 2 0.06 270 330 no analysisno analysisno analysisno analysis 6 6.2 6.2 76 92December 2009 MG exp group 3 0.06 220 330 220 250 350 400 6.3 6.4 6.3 77 92March 2010 MG exp group 1 0.05 280 370 220 240 320 350 6.1 6.4 6.0 77 92April 2010 MG exp group 2 0.07 270 370 200 250 280 330 6 6.5 6.0 77 92July 2010 MG exp group 1 0.03 400 500 200 250 280 330 6.3 6.4 6.0 80 92September 2010 MG exp group 3 0.06 330 430 200 290 330 400 6.1 6.5 6.1 77 92October 2010 MG exp group 1 0.06 350 530 200 310 320 450 6.1 6.4 6.0 75 92November 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 92April 2011 MG exp group 3 0.07 410 560 250 340 350 450 6.2 6.4 6.0 75 92April 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

MEGMEG concentration (%)

QN-20-0121/QN-38-0686

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

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

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 your risk based decision, away from conservatism

ormen lange – corrosion management of import pipelines 2011... · corrosion management systems...

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