Figure showing one of the production Platform in Yetagun Field (Marinerthai)
Subsea pipeline transporting gas from Yetagun and Yedana Field Gulf of Martaban Myanmar to Thailand was reported to have leaking in April 2, 2008 (Irrawaddy, Reuter). The operator company reported that there were two cracks causing ruptures found in the line close to Thailand-Myanmar border. Yetugun field was started up for production in 2000, with 400-500 million cubic feet per day gas production (mmcfd), while Yedana Field with 700 mmcfd two years earlier. Gas from these fields are exported to Thailand through 700 km of pipeline system (~80% subsea pipelines).
The leaking was to said not to disrupt Thailand electricity supply as the gas from these fields account only 15 percent of total consumption. However, largely Thailand industrial gas consumer will be in excess of gas shortage of about 5,800 million cubic feet and moreover owner company to suffer about USD 60,000,000 production lost (at natural gas rate = USD 10 per mmbtu).
Yadana: Located in the Gulf of Martaban, in blocks M5 and M6, the Yadana offshore project is in the production phase, supplying Thailand with about 600mmcf/d of natural gas through a 409km pipeline, 345km of it subsea, to the Thai-Myanmar border at Ban I Thong. Partners: PTTEPI (25.5%), TotalFinaElf Myanmar (31.2), Unocal Myanmar (28.3%), Myanmar Oil & Gas Enterprise (15%).
Yetagun: This field is now in production from Myanmar blocks M12, M13 and M14 in the Gulf of Martaban. A 277km gas pipeline, 210km of it subsea, takes gas from Yetagun to the Thai-Myanmar border at Ban I Thong. In 2002, gas production reached 300mmcf/d. Phase III front-end engineering and design has been completed and construction and installation is under way. Partners: Premier, operator (26.6%), Petronas Carigali (30%), Nippon Oil (14.2%), PTTEPI (14.2%) and Moge (15%).
Published for Petroenergy Magazine Edition May-June 2008
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Gas supply and demand gap between gas consumer region (Java) and gas source region (Sumatera, Kalimantan) leads to the expanding of Indonesia gas distribution system (Petroenergy No. 7 Year IV). Existing aging pipeline both upstream and downstream and the new gas distribution system will create a higher risk exposure to the overall Indonesia pipeline system. Significant accidents to pipelines onshore and offshore in recent years should be regarded as a momentum to develop more comprehensive pipeline safety regulation (Ref). A comprehensive pipeline safety regulation surely is one important legislative tool to ensure productivity assurance in oil and gas production and distribution.
Existing Indonesia Pipeline Safety Regulation
Indonesia oil and gas safety is ruled under Act 22 of 2001 concerning Oil and Gas in Article 40. Specifically for pipeline, safety is ruled under Ministerial Instruction (Keputusan Menteri) No. 300/38/M/1997. The later regulation is already provide several basis for pipeline safety but there are other important elements of pipeline safety still not covered. Pipeline constructor and operator adopted technical regulation provided in several pipeline codes and guidelines (ASME B31 series, API, DNV, etc).
- Pipeline Safety Regulation from Other Countries Pipeline regulations that reviewed are from United States (49 CFR 192, 195), United Kingdom (IGE/TD/1), Canada (Z662-94), Australia (AS2885-1987), Germany (TrbF 301, 302), and Japan (Tsusho Sangyo Roppo). Sections that commonly addressed in above mentioned pipeline safety regulations are:
1. Class Location
Pipeline right of way classified into class location according to their failure consequence. Classification of pipeline location in pipeline safety regulations generally by population densities, the proximity of pipelines to public building, and pipe diameter.
2. Material Qualification
The section prescribes general requirements for the selection and qualification of materials for pipeline (steel and non-steel).
3. Pipeline and Pipeline Component Design
Minimum requirements for the design of pipe are prescribed. Design parameter ruled in this sections are: nominal wall thickness, design factor versus class location, longitudinal joint factor, temperature derating, and design limitations of plastic pipe. Pipeline component prescribed by the regulations are: valves, fittings, passage of internal inspection device, supports and anchors, and compressors station.
4. Pipeline Construction
Construction issues ruled are welding of steel pipes or joining method other than welding, transmission lines and mains, structural protection (casing and cover), and underground clearance.
5. Pipeline Corrosion Protection
This section prescribes minimum requirements for the protection of metallic pipelines from external, internal, and atmospheric corrosion. Corrosion protection system parameter by coating or cathodic protection ruled are: coating requirements, and cathodic protection requirements.
6. Pipeline Operation and Maintenance
Operational issues prescribed in this section are: requirements for procedure manual for operation, maintenance, emergency, and personnel qualification which includes:
- Change in class location;
- Public awareness;
- Failure investigation;
- Leakage survey;
- Repair method;
- Inspection and testing;
- Valves and other pipeline components inspection;
7. Pipeline Integrity Management
This section prescribed identification high consequence area (HCA) and integrity assessment method (internal inspection, direct assessment, and re-assessment interval).
Specific aspects addressed in foreign pipeline regulations:
- Design life
In Australia Regulation, at the end of design life, the pipeline is abandoned unless an operator directed approved engineering investigation determines that its continued is safe.
- Third Party Factor
Australian standard has more detailed concept of third party damage including recommended practice to protect pipeline from third party damage.
- Fatigue life
British regulation has a section for requirement of pipeline fatigue strength in cyclic loads;
- Geohazard Issues
Onshore geohazard issues (e.g. earthquake) are prescribed in Japanese Standard.
Technical Basis for Pipeline Safety Regulation
Foreign pipeline safety regulation mentioned before are governed by several technical documents that commonly utilized as code and standards in respective disciplines like follows:
- Material Selection: API 5L series, ASTM, Plastic Pipe Institute;
- Pipeline Design: ASME B16 Series, ASME 31.8, ASME B&PV Codes;
- Pipeline Fabrication and Construction: API 1104, ASME B&PV Codes;
- Pipeline Protection: NACE Cathodic Protection Standards; and
- Pipeline Integrity: API and ASME Pipeline Integrity Standards;
Opportunity for Development of Pipeline Safety Regulation
Indonesia Oil and Gas authority has been preparing new regulation system for oil and gas technical safety in RPP Keteknikan Migas. If pipeline safety will be developed under this new regulation, the opportunity for the improvement of existing pipeline safety regulation should be considered aspects like follow, Table 1:
- More technical requirement rather than normative for pipeline design;
- Quality assurance including welding requirements, inspection, and non destructive tests;
- More emphasize for corrosion protection requirements;
- Pipeline Integrity Management; and
- Geohazard issues, third party factors, and advanced concept of fatigue strength and pipeline design life.
Table – Comparison of Pipeline Safety Regulations
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Reference
1. Code of Federal Regulation Title 49 Part 192 – Transportation of Natural and other Gas by Pipeline: Minimum Federal Safety Standards, US Department of Transportation Pipeline
2. Comparison Of U.S. With Foreign Pipeline Land Use And Siting Standards, F.H. Griffis, New Jersey Institute of Technology, US Department of Transportation, 1996
List of Engineering Failures Contributed by Material Failures, Corrosion, Design Flaw, and Construction Defect in Oil and Gas Production Facilities, Hydrocarbon Processing, and Oil and Gas Distribution
(Part 4 of 5) -Muhammad Abduh (abduh@reksolindo.co.id)
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39. Roncador Brazil – March 15, 2001 (Tank Leaking, Offshore Platform, 2 killed, 8 missed, USD 515,000,000)
Figure Showing P-36 listing and arrangement of EDT
Official investigation report to the fire, explosion, and sinking to P-36 the largest offshore production facility said that the P-36 accident did not occur due to one single cause but was provoked by a series of factors. Chronology of the accident started from the failure of starboard emergency drain tank (EDT). Excessive pressure in Starboard EDT due to a mixture of water, oil, and gas, which caused rupture and leaking the EDT fluids into the fourth level of the column. The unexpected flow through the entry valve of the starboard EDT can be related with the blocking of the vent and the racket absence in the entry valve. The rupture of the EDT caused damage to other vital elements in the column including the sea water service pipe that initiating the flooding of this compartment and released gas to
and ignited explosion. (Source 1, 2, 3, Location)
40. Carson City California US – April 23, 2001 (Pipe Leaking, Refinery, USD 120,000,000/124,000,000)
A pipe segment leak resulted fire in a refinery coker unit. A report said that smoke from the fire rose to over 3,000 feet and the coker unit was shut down for approximately two months. The exact cause of pipe leakin is still under investigation. (Source, Location)
A pipe leak resulted in major explosion at an oil gathering center killing four people and made 18 other severely injured. Three main facilities at the production site were destroyed. Production restored to its normal 500,000 bbl/day a month later. (Source)
42. Brookdale Manitoba Canada- April 14, 2002 (Stress Corrosion Cracking, Natural Gas Pipeline, USD 13,000,000)
A 36-inches diameter natural gas pipeline ruptured at a zone of near neutral pH stress corrosion cracking (SCC). Following the rupture the sweet natural gas ignited. Technical investigation report determined that pipeline ruptured due to overstress extension of pre-existing cracks. The cracks had initiated on the outside surface of the pipe and progressed in a mode of failure of transgranular SCC. The pipeline was constructed I 1970 by double submerged arc welded straight seam pipe by the accordance of API 5L Grade X65. (Source, Location)
43. Moomba Australia – January 1, 2004 (Liquid Metal Embrittlement, Gas Processing Plant, USD 5,000,000)
Figure showing failed HE Nozzle of Moomba Gas Plant (Courtesy of AON)
The gas was released that led to vapor cloud explosion. The gas released was caused by the failure of a heat exchanger inlet nozzle in the liquids recovery plant. The failure of the inlet nozzle was due to liquid metal embrittlement of the train B aluminium heat exchanger by elemental mercury. (Source, Location)
44. Skikda Algeria – January 19, 2004 (Liquid Metal Embrittlement, LNG Plant, 27 killed 72 injured, USD 30,000,000)
Figure showing destroyed Skikda LNG Plant
A report noted that the explosion was the consequence of a catastrophic failure in one of the cold boxes of Unit 40, which led to a vapour cloud explosion of either LNG or refrigerant. The most probable source of ignition was the boiler at the north end of Unit 40. The report concluded that the escaped gas was from the cryogenic heat exchanger. (Source, Location)
45. Humber Estuary Killingholme UK – April 16, 2001 (Erosion Corrosion, Refinery, USD 82,400,000)
On 16 April 2001 a fire and explosion occurred at Humber Refinery following the catastrophic failure of an overhead gas pipe. Investigation was carried by The Competent Authority and the plant operator company by legislative mechanism under Control of Major Hazard (COMAH) Regulation 1999. Humber refinery was one of approximately 1000 major hazard site under this regulation. The competent authority consisted of Health and Safety Executive (HSE) UK and Environment Agency (EA).
Figure showing failed elbow of Humber Estuary Refinery (HSE UK)
The cause of the piping system failure was the erosion corrosion of the 6-inches diameter pipe, known P4363, which carried the overhead line from the De-ethanizer (W413) to the heat exchanger (X452) in saturate gas plant (SGP) unit. The failure occurred down stream of a closely water injection point. Examination to the failed elbow recovered from the damage site showed wall thickness thinning from 7-8 mm to a minimum 0.3 mm. When the pipe failed it burst open catastrophically causing a full bore type of release the pipe contents.
The water injection point was not the original design of the piping system. Water injection to the vapor stream between the top de-ethanizer column and the heat exchanger was addressed to solve the previous problem of salts or hydrates fouling in heat exchanger X452/3. An injection point was created in P4363 by piping water to an existing 1 inches vent point on the pipe without injection quill or dispersal device and made the water entering the pipe as a free jet.
Similar Accident: Wilmington California United States 8 October 1992, North Rhine West Phalia Germany 10 December 1991,Yokkaichi Mie Japan 2 May 1997, Mina Al-Ahmadi Kuwait 25 June 2000. (Source, Location)
Posted by Muhammad Abduh 
Posted by Muhammad Abduh 
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