RCFA Report

Inspection Report Integrity Inspection of Shell Gamba Terminal Gabon

Failure Analysis Report of Wellhead Choke Assembly

Mari Petroleum Company Limited, Sujawal Field

January 2014

Integrity Inspection of

[V-1616 2nd Stage Discharge Bottle

Failure Analysis Report of Wellhead Choke Assembly Mari Petroleum Company Limited, Sujawal Field

1616 2nd Stage Discharge Bottle]

Failure Analysis Report of Wellhead

Failure Analysis Report of Wellhead Choke Assembly at Sujawal Field, MPCL

Date: 30-Jan-2014 SGS JKHI-140027 MPCL Ref no. 7100015783 Page: 2 of 12

This document is issued by the Company under its General Conditions of Service accessible at http://www.sgs.com/terms_and_conditions.htm. Attention is drawn to the limitation of liability, indemnification and jurisdiction

issues defined therein.

Any other holder of this document is advised that information contained hereon reflects the Companys findings at the time of its intervention only and within the limits of Clients instructions, if any. The Companys sole

responsibility is to its Client and this document does not exonerate parties to a transaction from exercising all their rights and obligations under the transaction documents.

Any unauthorized alteration, forgery or falsification of the content or appearance of this document is unlawful and offenders may be prosecuted to the fullest extent of the law.

SGS Pakistan Private Limited -H 3/3, Sector 5, Korangi Industrial Area, Karachi-74900, Pakistan. UAN: 92 (21) 111 222 747 Tel : 92-21-35121388-97 Fax: 92 (21) 3 5121386-87 Web : ww.sgs.com

Table of Contents

1. INTRODUCTION: ............................................................................................................................................ 3

2. WELLHEAD DATA: ......................................................................................................................................... 3 2.1 DESIGN PARAMETERS ........................................................................................................................... 3 2.2 OPERATING PARAMETERS .................................................................................................................... 3

3. FAILURE HISTORY: ....................................................................................................................................... 4

4. ROOT CAUSE FAILURE ANALYSIS METHODOLOGY: ................................................................................. 5

5. INSPECTION FINDINGS:.................................................................................................................................. 6 5.1 EXTERNAL VISUAL INSPECTION: .......................................................................................................... 6 5.2 INTERNAL VISUAL INSPECTION: ........................................................................................................... 6 5.3 POSITIVE MATERIAL IDENTIFICATION (PMI): ....................................................................................... 6 5.4 REMOTE VISUAL INSPECTION (RVI) / VIDEOSCOPY: .......................................................................... 6 5.5 ULTRASONIC THICKNESS GAUGING (UTG): ........................................................................................ 6 5.6 METALLOGRAPHY .................................................................................................................................. 6

6. FINDINGS AND OBSERVATIONS: .................................................................................................................. 7

7. FAILURE ANALYSIS: ....................................................................................................................................... 8 7.1 CODE CRITERIA FOR CO2 CORROSION AGAINST ACTUAL EVIDENCE: .......................................... 9 7.2 CODE CRITERIA FOR CAVITATION CORROSION AGAINST ACTUAL EVIDENCE: ......................... 10

8. DESCRIPTION OF DAMAGE MECHANISM: ................................................................................................. 11 8.1 CO2 CORROSION: ................................................................................................................................. 11 8.2 CAVITATION CORROSION: ................................................................................................................... 11

9. CONCLUSION: ............................................................................................................................................... 12

10. ANNEXURES ................................................................................................................................................ 12









1. INTRODUCTION:

Determine the root cause and contributing causes for Local metal loss at wellheads fixed choke and choke assembly of Sujawal Field. This root cause study will help to take decision for mitigation and prevention for the future occurrence of this kind of failure.

2. WELLHEAD DATA:

2.1 DESIGN PARAMETERS

Material Of construction : EE-NL (As per API 6A - PSL-3, PR-2, TC-PU) choke size : 28/64 Year of Installation (choke) : March, 2013 Manufactured by : Cortec (Model PH2 Alloy Steel)

2.2 OPERATING PARAMETERS

Wellhead Fluid Pressure (psi) : 2302 Operating Temperature(F) : 120 CO2 (mol%) : 4.544 (on dry basis) H2S (ppm) : 2 4 (on dry basis) Flow of Gas ( MMSCFD) : 09 Flow of Condensate (bbl/day) : 60 - 70 Flow of Water (bbl/day) : 20 Upstream Pressure (psi) : 2121 Downstream Pressure (psi) : 933









3. FAILURE HISTORY:

In March 2013, the Choke of size 28/64 was installed in Choke assembly. In August 2013, the fixed choke assembly was dismantled and inspected visually, no damage threats were found in Choke and Choke Assembly. Due to operational constraint entire inspection was not carried out at that time, and only previous installed choke beam was replaced by the choke of same size i.e. 28/64. In December 2013, Increase in flow of well head fluid with the gradually decrease in flowing pressure was observed. In December 14, 2013 the complete Christmas tree was dismantled and all the components were inspected by the Mari Petroleum Engineers. During inspection of wellhead components Corrosion due to local metal loss was observed at Fixed choke assembly and choke cap, wing valve at upstream of fixed choke, upstream of instrument flange and slight pitting corrosion observed at bottom of swab valve and at tree cap. Below is the pictorial Presentation of findings;

Internal thread of choke body damaged

Localize Corrosion at Choke Cap Severe Corrosion inside choke body

Slight pitting / corrosion observed at bottom end of Swab Valve









Pitting/ Corrosion found in internal thread of Tree cap

Severe corrosion observed at Wing Valve, Upstream of Fixed Choke

After the finding of severe inside erosion in choke and metal loss at choke assembly, the wellhead took into operation through the Variable choke and it is also decided to carryout Root Cause Failure analysis (RCFA) of Choke assembly to determine the causes of failure.

4. ROOT CAUSE FAILURE ANALYSIS METHODOLOGY:

For detailed RCFA Methodology, inspection of choke assembly was carried out and laboratory reports provided by MPCL were reviewed in detail. During field visit, the wellhead was in operation through variable choke; therefore, internal condition of all the components of wellheads could not be inspected. The fixed choke has been isolated and available for internal visual inspection, after that the fixed choke assembly was moved to SGS Head office for further analysis. This report is limited to analysis of fixed choke assembly and it has been assumed that the same mechanism is active in other parts of the wellhead. The root cause failure analysis methodology of choke assembly was structured on the following components;

Equipment design, operation and fluid composition data review Visual inspection include internal and external inspection Non destructive testing include Metallography, PMI, UTG and RVI

After obtaining these data, analysis conducted with the help of the following references for the determination of probable damage mechanism. References:

1. API RP 571: Damage Mechanisms Affecting Fixed Equipment in the Refining Industry. 2. API RP 581: Risk Based Inspection Technology. 3. ASM Metals Handbook Volume 11: Failure Analysis and Prevention. 4. API-6A, 19th Edition : Specification for wellhead and Christmas tree equipment









5. INSPECTION FINDINGS:

5.1 EXTERNAL VISUAL INSPECTION:

External condition of choke and choke assembly has no sign of corrosion or any other deterioration.

5.2 INTERNAL VISUAL INSPECTION: Metal loss due to localize corrosion found inside the body of choke assembly. (See the below attached reference fig:1 and 2) Metal loss due to localize corrosion found on the choke cap. (See the below attached reference fig: 3) Local metal loss observed inside the choke via Videoscopy. (See the below attached reference fig: 4) Metal loss due to localize corrosion found at the up-stream Nozzle (N1) of the choke assembly. (See the below attached reference fig: 5) Abrasive surface found at the downstream Nozzle (N2) of choke assembly. (See the below attached reference fig: 6) 5.3 POSITIVE MATERIAL IDENTIFICATION (PMI): Positive material identification (PMI) was performed to confirm the material of construction of fixed choke beam and choke assembly. Readings were collected from three locations of choke assembly by using PMI and the material is identified as Medium Alloy Steel. While for the choke, the material of construction is identified as Stainless Steel (SS-446). PMI Report attached as Annexure-A. 5.4 REMOTE VISUAL INSPECTION (RVI) / VIDEOSCOPY: Remote visual inspection was performed to analyse the internal condition of choke. After videoscopy severe localize metal loss found inside the choke. CD of Video is attached. Pictures of videoscopy attached as Annexure-B.

5.5 ULTRASONIC THICKNESS GAUGING (UTG): Ultrasonic thickness measurement was performed to determine the metal loss in choke beam. After performing UTG, metal loss of 2.6 mm is found at localize corroded section of the choke beam. The depth of metal loss found at the choke cap is 1.5 mm.

5.6 METALLOGRAPHY Metallographic testing was performed at the Choke assembly cap. Test was performed to investigate the material degradation. No Metallurgical anomalies were observed. Metallographic report is attached as Annexure -C

Defect Sketches of choke assembly attached as Annexure-D.









6. FINDINGS AND OBSERVATIONS:

Fig: 1 - Metal loss found inside the body of choke assembly

Fig: 4 - Metal loss found via Videoscopy inside the choke beam

Fig: 6 Rough surface found at the downstream Nozzle (N2) of choke assembly

Fig: 2 - Metal loss and severe corrosion found inside the body of choke assembly

Fig: 5 - Pitting corrosion found at the upstream Nozzle (N1) of choke assembly

Fig: 3 - Metal loss and corrosion found on the choke cap









7. FAILURE ANALYSIS: Since the wellhead is in service of well fluids containing Gas, Condensate and water. The chemical analysis revealed the presence CO2 (4.5 mol %) and H2S (2-4 ppm) in the stream. Therefore, primarily the susceptibility of CO2 Corrosion is analysed. Due to the presence of turbulence flow and fluid impingement conditions in the choke assembly, secondly the susceptibility of Cavitations is analysed.









7.1 CODE CRITERIA FOR CO2 CORROSION AGAINST ACTUAL EVIDENCE:

S. No. Susceptibility of as per Code / Industries Guidelines Actual Scenario Meet

Criteria

01 API-571, Clause 4.3.6.2; Affected Material-Carbon steel & Low alloy Steel Material of construction of choke assembly-Alloy steel Yes

02 API-581, Table 2.B.13.1; Partial pressure of CO2 above 30 psi cause severe corrosion Partial pressure of CO2 = 104.51psi Yes

03 API-571 and 581, pH in the range of 4.5 6 enhance corrosion rate pH of wellhead fluid =5.44 Yes

04 API-581, temperature below 140C (284F) increase corrosion rate Temperature of wellhead fluid = 120F Yes

05 API-581, Total pressure above 250 psi increase corrosion

Operating pressure of wellhead fluid = 2302 psi Yes

06 API-571, Clause-4.3.6.3; corrosion occur in liquid phase increase the rate of corrosion Wellhead fluid contains gas, condensate and water as well Yes

07 API-571, Clause 4.3.6.5; Corrosion generally occurs in areas of turbulence and impingement and sometimes at the root of Piping welds

Turbulent flow inside the choke due to flow through the orifice Yes

08

API-571, Clause 4.3.6.7; Corrosion may occur along the bottom surface of the pipe if there is a separate water phase, at the top surface of the pipe if condensation in wet gas systems is anticipated, and in the turbulent flow areas at elbow and tees

Pitting /Corrosion found at the bottom surface of the Upstream nozzle (N1) of fixed choke assembly also localize corrosion found at the cap of assembly

Yes

11 API-581, Presence of water Well fluid contain Water Yes

12 API-571, Clause 4.3.6.5; Localized thinning, pitting corrosion and grooving in areas of turbulence

Localize metal loss Pitting and grove like structure found inside the choke and choke assembly

Yes









7.2 CODE CRITERIA FOR CAVITATION CORROSION AGAINST ACTUAL EVIDENCE:

S. No.

Susceptibility of cavitations as per Code / Industries Guidelines

Actual Scenario at Choke assembly Meet Criteria

01 API-571, Clause 4.2.15.1 (a) formation and instantaneous collapse of innumerable tiny vapour bubbles

According to process conditions and parameters, formation and collapsing of vapour bubbles is expected

Yes

02 API-571, Clause 4.2.15.1 (b) collapsing bubbles exert severe localized impact forces that can result in metal loss

According to process conditions and parameters, formation and collapsing of vapour bubbles is expected

Yes

03 API-571, Clause 4.2.15.1 (c) bubbles may contain the vapour phase of the liquid, air or other gas entrained in the liquid medium.

On the basis of data provided by MPCL, wellhead fluid contains gas, condensate and water; hence the bubbles may contain the gas.

Yes

04 API-571, Clause 4.2.15.2 Affected material copper and brass, cast iron, carbon steel, low alloy steels, 300 Series SS, 400 Series SS and nickel base alloys

Material of construction of choke assembly-Alloy steel, fixed choke Stainless steel SS-446

Yes

05 API-571, Clause 4.2.15.4 Damage can also be found in restricted-flow passages or other areas where turbulent flow is subjected to rapid pressure changes within a localized region

Turbulent flow inside the choke due to flow through the orifice and damage also observed in the restricted flow passage (choke beam)

Yes

06 API-571, Clause 4.2.15.5 damage generally looks like sharp-edged pitting but may also have a gouged appearance in rotational components

During internal visual inspection of choke and choke assembly Pitting and grove like structure found.

Yes









8. DESCRIPTION OF DAM AGE MECHANISM:

8.1 CO2 CORROSION: Aqueous CO2 corrosion of carbon and low alloy steels is an electrochemical process involving the anodic dissolution of iron and the cathodic evolution of hydrogen. Carbon dioxide (CO2) corrosion results when CO2 dissolves in water to form carbonic acid (H2CO3). The acid may lower the pH and sufficient quantities may promote general corrosion and/or pitting corrosion. Corrosion usually occurs in Boiler feed water, condensate systems and effluent gas streams of the shift converters. This corrosion results localized thinning and/or pitting corrosion of carbon steel. It also corrodes the metal by making grooves in areas of turbulence. CO2 Corrosion generally occurs in areas of turbulence and impingement and sometimes at the root of piping welds. In the scenario of wellhead assembly and choke corrosion, the susceptible factors of CO2 corrosion are turbulent flow, low pH, higher partial pressure of CO2, and presence of water in wellhead fluid. As mentioned above, alloy steel is more susceptible, metal loss and pits are identified in the choke assembly due to CO2 corrosion.

8.2 CAVITATION CORROSION:

Cavitation is a form of erosion caused by the formation and instantaneous collapse of innumerable tiny vapor bubbles. The collapsing bubbles exert severe localized impact forces that can result in metal loss referred to as cavitation damage. Cavitation damage generally looks like sharp-edged pitting and may also have a grooving appearance. This damage occurs only in localized low-pressure zones. Cavitation is most often observed in pump casings, pump impellers (low pressure side) and in piping downstream of orifices or control valves. It is also found in restricted-flow passages or other areas where turbulent flow is subjected to rapid pressure changes within a localized region. In actual scenario, turbulent flow found in fixed choke with the rapid pressure change which causes cavitation damage in the form of grooves and sharp pits inside the choke. The affected material for this damage includes copper and brass, cast iron, carbon steel, low alloy steels, 300 Series SS, 400 Series SS and nickel base alloys thats why Fixed choke of SS-446 is more susceptible to cavitation damage.









9. CONCLUSION:

Based on the thorough study of data gathered, internal and external visual inspection, NDT and Metallographic results, nature and location of corrosion, it is concluded that the probable causes of wellhead choke assembly failure is the combine effect of CO2 Corrosion and Cavitation . The evidence revealed that this corrosion initiated due to the combined action of corrosion in an aqueous environment containing Co2, and the presence of turbulence in flow of wellhead fluid.

10. ANNEXURES

Annexure A: Report of Positive Material Identification Annexure B: Report of Videoscopy Annexure C: Report of Metallography Annexure D: Defect Sketches

Annexure -A

Positive Material

Identification Report

Sample No Alloy Grade

1.020

Pb

95.580

INDUSTRIAL SERVICES

0.023V 0.014

1.040

CrSi 1.220

Location 1 (Choke

Assembly)Alloy Steel

CrSi

0.073Ti

Location 2

Fe

Project: Root cause Failure Analysis of Choke Failure Object: Choke Assembly

Material: --

Equipment Model: Niton XLt

Elapsed Time(sec)Element % age Composition

1.780

S30

95.000Fe

0.102Mo 0.186

Al 0.890Mn 0.493

ELEMENTAL CHEMICAL COMPOSITION REPORT

Client Name: Mari Petroleum Company Limited (Sujawal Field) Date: 15-01-2014 Sheet: 1 of 2

Minimum Exposure Time: 30 SecJob Ref. No: JKHI-140027

Annex A: PMI Report

Reference: SP-TM-12

Page: 1 of 2Rev. no: 0Approval Date: 30th July2010

POSITIVE MATERIAL IDENTIFICATION

1.020

Alloy Steel

S

Cr

Date: 15-01-2014

Mo

V0.1190.0180.015

30

Name/Sign: Tauqeer Ahmed

Note:

Inspected ByName/Sign: Syed Ali SaquibDate: 15-01-2014

Reviewed by

Ti

Location 2(Choke

Assembly) 0.4990.218

Mn

Location 3(Assembly Cap)

FeSiCrMnMoSVTi

96.290.4231.12

0.6890.2280.0530.03

0.007

Alloy Steel 30

Sample No Alloy Grade

INDUSTRIAL SERVICESReference: SP-TM-12

POSITIVE MATERIAL IDENTIFICATIONAnnex A: PMI Report

Approval Date: 30th July2010

Sheet: 2 of 2

Project: Root cause Failure Analysis of Choke Failure Object: Choke Beam Equipment Model: Niton XLt

Page: 1 of 1Rev. no: 0

ELEMENTAL CHEMICAL COMPOSITION REPORTClient Name: Mari Petroleum Company Limited (Sujawal Field) Date: 15-01-2014

Minimum Exposure Time: 30 SecMaterial: -- Job Ref. No: JKHI-140027

Element % age Composition Elapsed Time(sec)

30

73.380

Si

NbP 0.141V 0.146S 0.744

0.070

1.260Location 1 SS-446

Cr 22.080Fe

Name/Sign: Tauqeer AhmedDate: 15-01-2014

Name/Sign: Syed Ali SaquibDate: 15-01-2014

Note:

Inspected By Reviewed by

Annexure -B

Videoscopy of Choke

Beam

Videoscopy Report of Choke Beam ANNEXURE -B

Pictures of Corrosion inside the fixed choke beam:

Sizing of Pits by Remote Visual Inspection:

Annexure -C

Metallograpghy

Report

JKHI- 140027Date: 30-01-2014

Page: 1 of 1

IN-SITU METALLOGRAPHY REPORT

Sample Preparation: ASTM E-3Object: Choke Assembly Cap

No. of Pages: 01

EQUIPMENT: CHOKE ASSEMBLY

Material.: Alloy Steel

Location: Sujawal Field, MPCL

Surface Condition: Polished

Sample no. 01: Choke Assembly CapTechnique: Reflected Light MicroscopyEtching: 5% Nital

Date: 30-01-2014

Test Method:ASTM E-1351,E-407Ref Drawing No. ---

Observations / Notes

Original Magnification 400 X

Micrograph consists of ferrite phase (White Regions) Alloy carbides (Dark Regions) forming homogenous matrix. No metallurgical anomalies like grain coarsening, micro fissures, voids were observed in the microstructure examined. Microstructure found normal.

This document is issued by the Company under its General Conditions of Service accessible at http://www.sgs.com/terms_and_conditions.htm. Attention is drawn to the limitation of liability, indemnification and jurisdiction issues defined therein.Any other holder of this document is advised that information contained hereon reflects the Companys findings at the time of its intervention only and within the limits of Clients instructions, if any. The Companys sole responsibility is to its Client and this document does not exonerate parties to a transaction from exercising all their rights and obligations under the transaction documents. Any unauthorized alteration, forgery or falsification of the content or appearance of this document is unlawful and offenders may be prosecuted to the fullest extent of the law. SGS Pakistan Private limited, Korangi Industrial Area, Karachi.

Analysed By Reviewed By

Arslan Hafeez khan Mohsin Riaz

Date: Date:

Annexure -D

Sketches

0 3 6 9 0

4525

15

155UPSTREAM NOZZEL OF CHOKE (N-1)

- DEFECTAll dimensions are given in mm.

45

30

20

55

0 3 6 9 0

170DOWNSTREAM NOZZEL OF CHOKE (N-2)


40

0 3 6 9 0

15

80

CHOKE ASSEMBLY


170

30 30

45

03

0

CHOKE ASSEMBLY CAP


6

39

40

Documents

RCFA Report