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7th PIM forum, Berlin, February, 2014

Integrity Assurance of Unpiggable Pipelines

Dr Ali N Moosavi

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1.conducted since Nov. 2003.

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Corrosion is the Biggest Integrity Threat to Pipelines

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Corrosion Protection Options for Pipelines

INTERNAL • Chemical Inhibition

• Internal Coating

• Dewatering Pigging

• Liners (HDPE)

• Cladding

EXTERNAL • Coating

• Cathodic Protection

• Raising the Pipelines

EXTERNAL & INTERNAL • GRE/RTP/HDPE Lines

• CRA

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Inspection / Monitoring Options for Pipelines

• Intelligent Pigging Surveys

• UT

• Visual Inspection

• CIPS / DCVG

• Tomography

• Corrosion Monitoring

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Monitoring Test Post

Gatch Track 25 m

Coated Flowline Section

Surface Laid Flow line 25 m

Anode

Track Crossing

Protection at Road Crossings

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SOLAR POWERED/MOBILE CHEMICAL INJECTION SKID & STACKABLE/MOBILE

CHEMICAL STORAGE TANKS

• Skid mounted system with flow meter. • Intrinsically safe or Safe Area Rated. • Option to rent or own

Liquid level in the base tank to be remotely monitored

REMOTE TANK LEVEL

MONITOR →

• Enables remote monitoring of liquid level in storage tank. • Enables timely ordering of chemical. • Enables uninterrupted injection of

corrosion inhibitor.

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Life Cycle Costing for Options

Option Cost ($ ) Comments

1 Surface laid flowline 770,000 replace entire flow line once

2 Pad concept neutral

3 Surface laid + Chemical Injection 840,000

4 Buried+ external coating + CP + Chemical injection

1,140,000

5 Incoloy 825 cladding+ buried + external coating + CP

2,140,000 hydro forming process

Life cycle costs between the technically feasible options 25 years design life A “typical” flow line was used as the basis for the analysis:

4 Km, Carbon Steel API 5L Grade B, 4 inch, wall thickness 8.5 mm

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The Pad Concept

Flowline

Transfer Line

SSV

Manifold

RDS

Well Site

Manifold

SSV

Transfer Line

CDS

design press = WHCIP

design press = WHCIP

SDV

(HIPPs)

SDV

(HIPPs)

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Pad Concept

• The most effective way to mitigate a risk is to eliminate the hazard

• In a pad or clusters; essentially there are no flow lines

• ADCO adopted this concept successfully in the recent projects. • New developments are based on the Pad concept • Work is underway in developing the pad concept in other fields

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Risk Ranking of Oil Flowlines

− Age

− Leaks / Km (within last 5 years).

− Production rate

− Water Cut

− Corrosive gases (CO2, H2S)

− Pipe Size

− Soil Resistively

− Repair History (within last 5 years).

− Pipeline Nominal Size

− Line Protection (Coating, Over-ground).

− Production interruption without Mothballing.

Low,599 nos,

62%

Medium,214 nos,

22%

High,

160 nos,16%

Risk Ranking (PoF x CoF)ADCO (Bab, Bu Hasa & SE)Oil Flow Lines Nov-12

LOW MEDIUM HIGH

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Companies specializing in in-line inspection of pipelines not fitted with pigging facilities have been used to assess the integrity status of high risk flowlines External Metal Loss Located Downstream of

Girth Weld #3500 with a Depth of 13.8% of

Nominal Wall Thickness

2D and 3D Views of External Metal Loss Downstream of Girth Weld #3500

In Line Inspection

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Intelligent Pigs for Unpiggable Pipelines

Image of a Pig Within a Bend Section

Image of a Pig within a Pipeline Section

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Pipeline Inspection Layout

• The pipeline numbering system progresses in a positive direction, beginning at the Well Head location and ending at the RMS location. In the report each feature is referenced to a relative position to the Upstream Girth Weld along with the absolute position from the initial Girth Weld

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Depth Based Internal Defects

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ERF Based Internal Defects

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Summary Table

Pipeline Segment

% of Sensor Data Captured

% of Valid Data (Inner Profile)

% of Valid Data (Thickness)

Min. Meas. Wall Thickness {mm}

8” Gas Flow Line

100% 100% 99.3% 4.70

RSF

[min]

Min. MAOPr [psig]

MAOP

[psig]

0.486 2,928 1,540

•One (1) external metal loss anomaly was identified in the inspection data. The min measured thickness due to external metal loss was 10.95mm. Based on a nominal wall thickness of 12.70mm, this metal loss corresponds to a 13.8% wall loss. •78 internal metal loss anomalies were individually identified in the inspection data. The min calculated thickness due to internal metal loss was 4.70mm. Based on a nominal wall thickness of 12.70mm, this metal loss corresponds to a 63.0% wall loss. •4 dents in excess of 0.5% of the nominal OD were identified in the inspection data. The max dent size was 0.7% of nominal OD and is located at 5906.41m. The min Safe Operating Pressure calculated according to ASME B31G-1991 is 2,208 psig. Based on this inspection data, the pipeline satisfies API 579 Part 5 Level 2 Fitness-For-Service criteria for any maximum operating pressures equal to or below the listed MAOP of 1,540 psig. •No metal loss anomalies with a depth greater than 80% of the nominal wall thickness were identified in the inspection data, therefore the pipeline satisfies the ASME B31G depth criteria. •Note: that assessment calculations were performed without any future corrosion allowance

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Summary

• An ultrasonic inline inspection, API 579-1 / ASME FFS-1 2007 Fitness-For-Service assessment, and ASME B31G assessment were performed on an 8-inch gas pipeline.

• The pipeline inspection data was analyzed for wall thinning and anomalies such as corrosion, denting, and ovality. The qualified data from the analysis were assessed using specialized Pipeline software to determine the Remaining Strength Factor (RSF) and Reduced Maximum Allowable Operating Pressure (MAOPr) for the pipeline.

• This assessment was based on the longitudinal extent of thinning found in the pipeline and in accordance with a Level 2 Assessment described in Part 5 of the API 579 standard.

• The data was also assessed in accordance with ASME B31G to determine the failure pressure &the Estimated Repair Factor (ERF) of individual wall

loss anomalies identified in the inspection data.

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