Pipeline Safety Regulation

May 24, 2008

Muhammad Abduh (PT. Rekayasa Solverindo)

Published for Petroenergy Magazine Edition May-June 2008

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


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

The 50 Major Engineering Failures (1977-2007) Last Part

May 5, 2008

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 5 of 5) – Muhammad Abduh (abduh@reksolindo.co.id)

46. Ghislenghien Belgium- July 30, 2004 (Pipe Leaking, Natural Gas Pipeline, 24 killed, 120 injured)

Figure showing a damaged industrial park as the excess of Ghislenghien Pipeline Explosion

A pipe leak caused a major underground high-pressure natural gas pipeline explosion. Most of the dead are officials and fire-fighters responding to reports of a gas leak. The exact cause of the pipe leak is still not clear. A heat transfer mathematic model can be used to describe a ductile-brittle transition of pipe material due to significant cooling of the surrounding pipe-wall. This brittle transition occurred when the fluid with certain velocity escape through an initial through-wall defect. The significant reduction in the fracture
toughness combined with the accompanying pressure stresses then result in fracture growth and rupture of the pipe segment. (Source 1, 2, Location)

47. Mihama Japan August 9, 2004 (Erosion-Corrosion, Power Plant, 6 killed, 5 injured)

A steam eruption occurred from failed piping system in a pressurized water reactor (PWR). An orifice plate was inadvertently inserted to the pipe network to measure the coolant flow rate. This caused a localized metal loss in cross sectional area of the piping year-to-year, and the stress level became higher, at last plastic collapse was occurred and the pipe segment ruptured. Unfortunately the pipe thickness was not checked for 27 years due to oversights. (Source)

48. Texas City Texas US – March 23, 2005 (High Temperature Hydrogen Attack, Refinery, 15 killed, 170 injured, USD 30,000,000)

Figure showing Severely Damaged Texas City Refinery

On 23 March 2005, 15 people were killed and over 170 harmed as the result of a fire and explosion on the isomerization unit at a refinery plant in Texas City United States. The accident was an explosion caused by heavier-than-air hydrocarbon vapors combusting after coming into contact with an ignition source. The severity of the accident was increased by the presence of many people congregated in the vicinity of origin of explosion. Detailed investigations were carried by the plant operator and United States Chemical Safety Board. From the health and safety perspective high number of fatalities was concluded to be caused by loss of containment, inadequate trailer sitting at the plant layout and the fault of design engineering of the blowdown stack.

Figure showing failed elbow in Texas City Refinery Explosion

The release of gas was originated at the leaking elbow made of carbon steel in the exchanger piping system resid heat hydrotreater unit (RHU). Investigation to this RHU accident determined that inappropriate material as inadvertently installed in a high pressure and high temperature hydrogen line. The failure of the elbow was noted by the mechanism of high temperature hydrogen attack (HTHA). (Source 1, 2)

49. Sidoarjo East Java Indonesia- November 22, 2006 (Pipe Leaking, Natural Gas Pipeline,11 killed)

Aerial view showing location of Sidoarjo rupture pipe nearby mud volcano big hole (KLH)

Natural gas pipeline with 440 psig pressure failed and caused a major explosion. Most of the victims were government officials in an activity of surveying mud volcano site. The mud volcano was a previously major gas blow out event in location near the accident. The most probable cause of pipeline failure was largely associated with geohazard. At least 25 industrial gas consumer affected by the gas supply interuption because of the explosion including national power plant PLN and petrochemical plant Petrokimia Gresik. (Source 1, 2, 3)

50. Free Town Sierra Leone – December 21, 2007 (Pipe Leaking, Natural Gas Pipeline, 17 killed)

A gas explosion on a crowded street killed 17 people. The explosion tore through a crowded shop. There is no clear information on the exact cause of the pipe leaking. (Source)

See also: Part 1, Part 2, Part 3, and Part 4

Implementation of Asset Integrity Management System

May 4, 2008

Muhammad Abduh (abduh@reksolindo.co.id)

Print-Version Published for PetroEnergy Magazine April – May 2008 Edition

Asset integrity nowadays is considered as one important element to improve productivity in oil and gas production facilities (production, refining, and distribution). In the development, asset integrity arise from technical issue (maintenance, inspection, engineering assessment) to a higher level of corporate management policy. Asset integrity can be defined as the ability of the asset to perform its required function effectively whilst safeguarding life and the environment. Asset Integrity Management System (AIMS) is the means of ensuring that people, systems, processes and resources, which deliver integrity, are in place, in use and fit for the purpose over the whole lifecycle of the asset.

As a management process, AIMS process shall include policy development, organizing, planning and implementation, measuring performance, and audit and review, Figure 1. Guideline to develop AIMS for offshore production facilities was developed by a joint industry project between UK Offshore Operators Association (UKOOA), Step Change in Safety, The Health and Safety Executive UK in 2006 publishing Asset Integrity Toolkit.

AIMS elements shall be in accordance to company Quality or HSE Policy. HSE based AIMS has already been implemented by several oil and gas operators in United States and Europe. Asset Integrity Toolkit is also a health and safety based AIMS which is more comprehensive and measurable by several performance indicators that already known well in oil and gas industry. Asset Integrity Toolkit can be proposed as the basis for asset integrity audit for pre-development of asset integrity management system. Asset Integrity Toolkit defines 32 elements of AIMS into 6 six groups as follows:
1.1. Assurance and Verification;
Operators shall define safety critical element (SCE) within the facility. SCE is a term in Safety Case (UK Offshore Installation Safety Regulations SI 2005 No 3117) to refer to:
– Parts of an installation and such of its plant or any part thereof , the failure of which could cause or contribute substantially to a major accident; or
– A purpose of which is to prevent or limit the effect of a major accident.
The assurance process is the duty holders responsibility to set out an assurance scheme that defines and manages the activities which ensure required performance standards of SCE are sustainable. While the verification process is the duty holders responsibility to develop verification scheme that provides the evidence to demonstrate the assurance scheme is operating effectively. Independent reports and comments shall be able to define clearly SCE list, assurance activities applied to SCE, and any failures and or anomalies are in communication with the duty holders

1.2. Assessment/Control and Monitoring;
The process of assessment/control and monitoring should include the following key elements:
– Rigorous risk assessment of potential major hazards and threats from plant equipment and operations to the personnel, the environment, and the asset;
– Identification necessary mitigation and controls in order to lower each of the risks to a level which is As Low As Reasonably Practical (ALARP);
– Recognition of which of these controls takes the form of SCE and assurance that the associated performance standards are continually maintained. Main issue in this element is engineering integrity. The duty holders should develop strategy to maintain the integrity of plant equipment against mechanical failure, fatigue, corrosion, throughout asset lifecycle. Activities ruled under this AIMS element are:

– Asset register (asset information system);
– Risk Assessment (risk based inspection);
– Mitigation Plan (repair, replace,re-engineering);
– Inspection and monitoring (NDT, vibration analysis); and
– Integrity assessment (fitness for service, defect assessment)

1.3. Competence
Personnel with the required levels of competence should be supported by commitment of senior management. Duty holders should develop competence system that should: be able to verifiable by audit of training, recruitment process, formal assessment, provides demonstrable capability within their pre-defined and agreed job description, be in accordance with national or equivalent standards, cover third party contractors.

1.4. Planning
AIMS should be comprehensively planned for successful implementation. The planning and implementation of an Integrity Management System should includes:
– Processes definition required to manage the integrity of asset;
– Resources and Responsibility Allocation;
– Identification performance against the plan;
– Identification SCE should be included;
– Identification business element should be included; and
– Effective prioritization of activities

1.5. Maintenance Management System
Maintenance Management System (MMS) provides the process for managed and control of maintenance program including set of maintenance task and their schedules. Target object of MMS include the following:
– Maintaining the condition, functionality, operability of equipments;
– Reducing failure incidence or mean time between failures, downtime after failures or mean time to repair;
– Reducing critical incidents or near miss accidents;

1.6. Quality and Audit
Quality management and audit should be integrated and aligned in every process embedded in every aspects of asset integrity management through out six lifecycle stages. Quality and audit system as to senior management framework to guide organization toward performance improvement can encompass the four C’s of control (defined roles and responsibilities), communication (clear reporting and record keeping), competence (training and supervision), and co-operation (interface management).

II. Measuring AIMS Performance
AIMS achievement can be measured by using industry key performance indicator (KPI). Setting KPIs to measure AIMS performance, to refer to RIDDOR (The Reporting of Injuries, Diseases and Dangerous Occurrences Regulations 1995), and OGP (The International Association of Oil & Gas Producers), are as follow:
– Dangerous occurrence;
– Very High Potential Incident;
– Loss Time Injury;
– Major Injury;

– Hydrocarbon Release;
– Failure of SCE;
– Safety Critical Maintenance Backlog; and
– Overdue Inspection

1. United Kingdom Offshore Operator Association (www.ukooa.co.uk)
2. International Association of Oil and Gas Producers (www.ogp.org.uk)
3. The Health and Safety Executive UK (www.hse.gov.uk)

The 50 Major Engineering Failures (1977-2007) Part-4

May 1, 2008

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)

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)

41. Rawdhatain Kuwait – January 31, 2002 (Pipe Leaking, Refinery, 4 killed,18 injured, USD 200,000,000)

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)

Figure showing destroyed Humber Estuary Refinery (HSE UK)

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)

Offshore, Platforms, and the Hurricanes

April 30, 2008

1. Statoil Heidrun Platform – North Sea Norway (World Largest TLP, First Application of Composite Riser, 1345m)

2. ConocoPhillips Magnolia TLP – Gulf of Mexico (World Deepest TLP, 1425m)

3. Chevron West Seno – Makassar Strait Indonesia (Asia First TLP, 1021m)

4. BP Thunderhorse – Gulf of Mexico US ( World Largest Floating Platform, 1828m)

5. StatoilHydro Troll West – North Sea Norway (Deepest Concrete Weight Platform, 345m)

Inside one of the Troll Columns

A 25-years happy birthday party in Troll

6. The Friendly Weathers

“The Little Sister” Statoil Sleipner West Field North Sea Norway

“The Three Towers” StatoilHydro Maersk Inspirer North Sea Norway

“Offshore Pirate” Shell Brutus TLP Gulf of Mexico US

” Misty” StatoilHydro The West Venture Cromarty Firth Scotland

“Swamp Clubhoppers” Amerada Hess Glomar Arctic IV Invergordon UK

“Catching the Rain” BP Magnus Platform North Sea UK

” Wake Up Call” Galaxy Jack-Up Cromarty Firth Scotland

7. Adverse Weather

Oseberg A – North Sea Norway at 95 knots

GSF Adriatic VII – Gulf of Mexico US

GSF Adriatic VII After Rita 2005

Chevron Typhon – Gulf of Mexico

Chevron Typhon After Rita 2005

Shell Mars – Gulf of Mexico

Shell Mars After Katrina 2005

BP Thunderhorse After Dennis 2005

Anadarko Rowan Houston – Gulf of Mexico

Rowan Houston After Lili 2002

All Photos from (Oil Rig Photos and Rigzone)

The 50 Major Engineering Failures (1977-2007) Part-3

April 28, 2008

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 3 of 5) – Muhammad Abduh (abduh@reksolindo.co.id)

24. Martinez California US – January 27, 1997 (Creep, Refinery, USD 80,000,000/82,000,000)

An effluent line from reactor in hydrocracker unit failed at pipe body leading to fire and explosion. Released hydrocarbon were auto-ignited because high temperature of the line seconds before explosion. Analysis of the failed pipe noted that the failure mechanism was creep above 1300 °F which expanded the 12-inches pipe circumferentially by 5-inches causing localized bulge in the pipe prior to rupture. (Source)

25. Yokkaichi Mie Japan – May 2, 1997 (Erosion-Corrosion, Petrochemical Plant)

A T-joint of high-pressure piping for recycle ethylene gas failed and lead to explosion. The explosion occurred by the ignition of released ethylene gas by static electricity. Failure was contributed by erosion corrosion event by the evidence of presence of water and a local vortex accompanying a high-speed flow. Erosion corrosion caused a local thinning and the pipe could no longer withstand internal pressure. (Source)

26. Visakhapatnam India – September 14, 1997 (Pipe Leaking, Refinery,50 killed, 27 injured, 100 evacuated, USD 64,000,000)

Piping in loading port and storage tank leaked. The heavier than air gas spread at ground level and ignited. A vapor cloud explosion to this refinery became more severe due to lack of anti-fire foam. The plant layout in which the LPG tanks and pipelines were very close to several administrative building caused large number of fatalities. (Source 1, 2)

27. St Helena California US – December 2, 1997( Corrosion-Pitting, Fuel Pipeline, USD 14,000,000/17,000,000)

36-inches pipe failed with up to 10,000 barrels of gasoline spilled. Both uniform and pit corrosion were found at the failed segment. The pipe was carbon steel with SMYS 52 kpsi, designed at operating pressure 584 psi and maximum allowable pressure at 758 psi. The pressure at the point of failure was 345 psi. (Source)

28. Bintulu Serawak Malaysia -December 25, 1997 (Gas Processing Plant, High Temperature Failure, 12 injured, USD 275,000,000/294,000,000)

Incipient combustion event at air separation unit (ASU) at a gas-to- liquid (GTL) plant and with the presence of liquid oxygen caused the explosive burning of the aluminum heat exchanger elements. The elements ruptured explosively. The plant was shut down for several months for repair. (Source)

29. Longford Victoria Australia -September 25, 1998 (Brittle Fracture, Gas Processing Plant, 2 killed, 8 injured, USD 160,000,000/171,000,000)

Figure Showing GP 905 Heat Exchanger of Longford Gas Plant

Operation error of a bypass valve allowed condensate to spill over into other parts of the system eventually causing the failure of warm oil pumps. Temperature of a heat exchanger decreased sufficiently to lead to material brittle transition. Operator then made error of restarting the warm oil flow which caused the heat exchanger to fracture. An initial release approximately 22,000 pounds of hydrocarbon vapor exploded and made the plant burned for two and a half days. Victoria was said to be in chaos for 19 days. The accident caused a large socio-economic excess. There were 10,000 litigants signed a class action suit that made it a largest class action in Australian legal history. (Source 1,2,3)

30. Berre l’Etang France – October 6, 1998 (Corrosion, Refinery,USD 22,000,000/23,000,000)

A pipe failed due to corrosion and released gas ignited when contacting hot process line. The fire caused the failure of kerosene air cooler and adding more fuel too the fire. The fire created severe damage to 127,000 barrels-per-day crude unit and a 17,000 barrels-per-day reformer. Corrosionwas largely associated with the presence of more corrosive naphtanic acid. (Source)

31. Idjerhe Niger Delta Nigeria – October 17, 1998 (Pipe Leaking,Fuel Pipeline,100 killed)

Pipe leaked a day before the explosion. Large number of victim due to people from surrounding pipeline right of way gathers to fetch the fuel spill. The pipe that burst runs parallel to River Ethiope and has two major foot paths to it from the road. The pipeline was laid in the early 1970. The area is actively cultivated by the local people. Next to the buried fuel pipe is a gas pipeline about 15 meters apart. Poor pipeline maintenance was associated with the leaking. (Source)

32. Knoxville Tennesse US – February 9, 1999 (Brittle Fracture, 15 evacuated, USD 8,100,000)

Figure Showing Circumferential Crack of Knoxville Pipeline (NTSB US)

A pipe failed releasing 53,500 barrels of diesel fuel. The pipe was 10-inches in diameter, API 5L X-42 SMYS 42 kpsi, electric resistance weld (ERW) carbon steel and with 0.25 inches in thickness. Circumferential crack was found at the failed segment. The possible cause for cracking was noted by the low toughness of the manufactured pipe material. The pipe was constructed in 1962 when there was no adequate toughness requirement from available pipe code and design. National Transportation Safety Board had already
given recommendation for toughness requirement to Department of Transportation Research and Special Administration Agency (RSPA) when a similar failure occurred in 1994 in New Jersey. In 2000 responding the request from RSPA, American Petroleum Institute (API) added minimum toughness requirements to API Specification 5L. (Source)

33. Martinez Caifornia US – February 23, 1999 (Corrosion, 4 killed, 1 injured)

Leakage and fire occurred and originated from a heat exchanger. The heat exchganer condensed vapor from a high temperature and high pressure separator at the outlet of the reactor of a fuel oil hydro- desulfurization unit. One heat transfer tube of the fin-fan cooler was was corroded. Corrosion was caused by inadequate re-design of heat exchanger changing service. (Source)

34. Winchester Kentucky US – January 27, 2000 (Crude Oil Pipeline, Fatigue, USD 7,100,000)

Figure showing Winchester fatigue cracked pipeline

A 24-inches pipeline ruptured and released 11,644 barrels of crude oil. Laboratory examination of the failed segment showed a transgranular cracks that had the appearance of typical fatigue progression. The fatigue cracking was caused by a dent in pipe with the combination of fluctuating pressures within the pipe producing high local stress in the pipe wall. (Source)

35. Hunt Texas US- March 3, 2000 (Corrosion, Fuel Pipeline, USD 40,000,000)

28-inches in diameter pipe failed due to external corrosion causing 13,400 barrels of gasoline spill. The failed segment was submerged below ground. Leaking originated at the body pipe. The material was carbon steel with SMYS 52 kpsi, designed at 751 psi to maximum 955 psi. The pressure at the failed segment was 705 psi. (Source)

36. Prince Georges US – April 7, 2000 (Pipe Leaking, Fuel Pipeline, USD 50,000,000/ 57,000,000)

A submerged pipe carrying refined petroleum product failed. At the time of failure, the pipe was 27 years in operation, has SMYS 1.61 kpsi and designed pressured at 550 psi/1600 psi. This pipe failure caused the largest loses of fuel spill that recorded by US DOT PHMSA. A report said that no corrosion significantly susceptible for the cause of failure neither in the weld. (Source)

37. Mina Al-Ahmadi Kuwait – June 25, 2000 (Erosion-Corrosion, Refinery, 5 killed, 50 injured, USD412,000,000/ 433,000,000)

FIgure Showing Mina Al-Ahmadi Refinery Exploded

A condensate line between a NGL plant and refinery failed. The operators were trying to isolate the leaking line and the explosion occurred. Three crude units and two reformers were damaged. Accident to this national biggest oil refinery made an enormous economic looses and excess in sociopolitic when Kuwait oil minister offers resignation. The failed pipe was an aging pipe that suffered erosion-corrosion and slipped through the inspection and maintenance. (Source)

38. Carlsbad New Mexico US – August 19, 2000 (Corrosion-Pitting, Gas Pipeline, 12 killed, USD 100,000,000)

Figure showing micrograph corroded-pit of Carlsbad Pipeline

A 50-years, 30-inch-diameter natural gas transmission pipeline ruptured. The release gas ignited and burned for 55 minutes. Investigation of the failed segment revealed severe internal pit-corrosion as major contributing cause of the failure. At the time of failure the pipe withstand 80% of maximum design pressure. National Transportation Safety recommended amendment in 49 Code of Federal Regulations (CFR) Part 192 to require that new or replaced pipelines be designed and constructed with features to mitigate internal corrosion and to National Association of Corrosion Engineer (NACE) to establish more guidelines to control internal corrosion . Pipeline operator spend USD 15,500,000 for legal fine and USD 86,000,000 for pipeline modifications. (Source)

See also : Part 1, Part 2, Part 4, Part 5

The 50 Major Engineering Failures (1977-2007) Part-2

April 28, 2008

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 2 of 5) – Muhammad Abduh (abduh@reksolindo.co.id)

9. Piper Alpha North Sea UK – July 8, 1988 (Gas Leaking, Offshore Platform, 167 killed, US$965,000,000/1,270,000,000)

It was dominantly operation error when gas leaking from two blind flanges then gas ignited and exploded. A pump from two available pumps was tripped, and an operator inadvertently changing the backup pump with pressure relief valve that had been removed for maintenance. Severity damage of the explosion was due to large part the contribution of oil and gas pipelines connected to Piper Alpha. While the platform was in fire two other platform Tartan and Claymore continued pumping gas and oil. (Source 1,2, Video)

10. Antwerp Belgium – March 7, 1989 (Fatigue/Weld Failure, Petrochemical Plant, US$ 77,000,000/99,000,000)

Explosion is believed initiated from a hairline crack in welded seam of piping at the aldheyde column. Ethylene oxide escaped from the leak, formed polyethylene glycol (PEG) in the insulation material and accumulated for a period of time. Sequential explosion was believed by the chemical mechanism inside the insulating material and PEG. The explosion caused extensive damage to the plant and it was closed for at least 24 months with total business interuption cost up to US$ 270,000,000. (Source, Location)

11. Richmond California US – April 10, 1989 (Weld Failure, Refinery, 8 injured,US$87,170,000/112,000,000)

Failed line carrying hydrogen gas caused a high pressure hydrogen fire and resulted in flame impingement to calcium silicate insulation of the hydrocracker reactor skirt. The reactor which was 10 to 12 feet in diameter and wall thickness of seven inches failed subseqently. The reactor was in maintenance cycle for hydrogen purging. It is believed that leaking started from a failed elbow of 2-inch line at 3,000 psi. (Source, Location)

12. Baton Rauge Louisiana US – December 24, 1989 (Brittle Fracture, Refinery,US$ 68,900,000/89,000,000)

The record for low temperature (10 oF and 700 psi) at the region is believed as the major contributor to the failure of 8-inches pipeline carrying gas mixture of ethane and propane. After few minutes of vapor cloud was ignited and piperack containing 70 lines ruptured subsequently. Also with two storage tanks containing 3,600,000 gallons and 12 small tanks containing 882,000 gallons of lube oil also contribute to subsequent fire. (Source, Location)

13. Coatzacoalcos Mexico – March 11, 1991 (Pipe Leaking, Petrochemical Plant,US$ 91,300,000/112,000,000)

Gas leaking from pipe rack lead to explosion. The first explosion occured and caused additional damage to the pipe rack. Second explosion was more powerful and could be felt more than 15 miles from the facility creating damage to offsite third party facility. The explosion and fire made this vinyl chloride plant, a significant output for Mexico national demand, shut down for seven months. (Source, Location)

14. Dhaka Bangladesh – June 20, 1991 (Weld Failure, Petrochemical Plant, US$ 71,000,000)

The fertilizer plant which was constructed in 1970 suffer significant damage due to an explosion. The failure of a welded joint between carbondioxide stripper and main cylindrical body resulted in the release of high pressure gas which consisted of ammonia, carbon dioxide, and carbamate liquids. (Source)

15. North Rhine Germany – December 10, 1991(Erosion-Corrosion, Refinery, US$ 50,500,000/62,000,000)

A Pipe failed at T-junction in hydrocracker unit resulted in hydrocarbon and hydrogen release. The release of the gas ignited and explosion occured and made severe damage to the hydrocracker unit and adjacent substantial part of the plant. The hydrocracker unit was shut down for seven months. The failure of the pipe was contributed by erosion-corrosion due to plant aging. (Source)

16. Guadalajara Mexico – April 22, 1992 (Corrosion, Fuel Pipeline, 206 killed, 500 injured, 15,000 evacuated, US$ 300,000,000)

Guadalajara, Mexico second largest city, experienced series of ten massive explosion that equals to 7,0 richter scale from fuel pipeline blast. An investigation into the disaster revealed that the most possible cause for the explosion was the interference of fuel pipeline with new water piping system. The fuel pipeline was carbon steel and the sewer system was zinc-coated copper. These two lines were close enough to interfere each-other. Three days before the explosion, there were complaints from the city residents
about gasoline-like smell coming from the water pipe and sewer system. (Source 1, 2, Location)

17. Westlake Louisiana US – July 28, 1992 (Weld Failure/Corrosion, Petrochemical Plant, US$ 25,000,000/30,000,000)

A reactor vessel in urea manufacturing unit exploded. The force of the explosion could be felt in areas up to 10 miles from the plant. The fragmented shell of the column propelled up to 900 feet from their original location. The reactor was constructed 25 years earlier with 90 feet tall and 6 feet in diameter. The shell consisted of 4-inches laminations including 3/8 inches stainless steel liner. The explosion resulted from carbamate leaking at the inside vessel. Improper weld on a bracket supporting a tray inside the reactor created carbamate leak and subsequent corrosion and containment of the vessel. (Source, Location)

18. Wilmington California US – October 8, 1992 (Erosion-Corrosion, Refinery, US$ 73,300,000/96,000,000)

An explosion initiated from hydrogen processing unit. Sequential fire and explosion occured to hydrocracker unit, and hydrode sulfurization. The explosion could be felt approximately 20 miles from the plant. The explosion made the plant operator reduce production capacity to 50 percent from its normal 75,000 barrels per-day. It took 8 months to recover the production capacity. The explosion resulted from ruptered carbon-steel-elbow suffering locally thinning due to long term erosion-corrosion. (Source, Location)

19. Sodegaura Japan- October 16, 1992 (Fatigue, Refinery, 10 killed, 7 injured, US$ 160,500,000/196,000,000)

An explosion from failed heat exchanger in the hydrode-sulphurization unit caused hydrogen release and ignited fire and explosion. Technical investigation to the failure noted a complexity of the failure mechanism. The cause of the failure initiated by repetition of variation of temperature lead to decrease of diameter gasket retainer and bending deformation of rock ring. These events contributed to break out of rock ring and made spouts hydrogen gas. (Source, Location)

20. La Mede, France November 9, 1992 (Pipe Leaking, Refinery, US$ 260,000,000/318,000,000)

A pipe failed at T-junction in hydrocracker unit resulted in hydrocarbon and hydrogen release detection. Subsequent fire and explosion caused severe damage to FCC unit, gas plant, control room, and two new process unit under construction. The explosion also causing offsite damage nearby residential within the radius of 6 miles away. The business interuption loss due to this accident is estimated at US$ 180,000,000. (Source, Location)

21. Baton Rouge Louisiana US – August 2, 1993 (Creep, Refinery Plant, USD 65,200,000/78,000,000)

An elbow in the feed line of coker unit ruptured when feed switching were performed. Other pipes in unit ruptured subsequently releasing more hydrocarbons and fueling more fire to the plant. Because of the accident the coker unit was shut down for three weeks. Investigation to the failed elbow noted that carbon steel elbow was wrong material chosen with less creep resistance instead of 5Cr alloy steel.

22. Simpsonville Sacramento US- June 6, 1996 (Pitting Corrosion, Fuel Pipeline, USD 27,000,000/33,000,000)

An aboveground pipe segment failed by corrosion releasing 22,800 barrels of diesel fuel. The pipe manufactured in 1962 with 36-inches in diameter, 0.28-inches in thickness, and has specified maximum yield strength (SMYS) 52 kpsi. The pressure of pipe at the time of failure was 399 psi, the designed maximum pressure was 803 psi. (Source)

23. Rio Piedras San Juan Puerto Rico – November 21, 1996 (Wrong Material in HCA, Gas Distribution Pipeline, 33 killed, 69 injured, USD 5,000,000)

Polyethylene pipe transporting propane gas to consumer was failed leading to fire and explosion. The explosion occurred in five stories full occupied business center at shopping district Rio Piedras San Juan Puerto Rico. The leaking of plastic pipe was believed due to construction excavation damage around the pipeline. More than 20 pipes and conduits surrounding the plastic pipe which were being constructed, being used and had been abandoned. Construction excavation damage to plastic pipe was rather unavoidable and there should be pipeline design with higher integrity within high consequence area (HCA) like Rio Piedras shopping district. (Source)

See also : Part 1, Part 3, Part 4, Part 5