Stress Corrosion Cracking – Two Cases in a Row

February 19, 2009

The engineers at Reksolindo have an interesting inquiries for failure analysis suffered by different parts of equipment lately. Quitely different operation condition (high temperature and ambient temperature, medium and low carbon steel, marine atmosphere versus caustic feed water).  We are really satisfied for microscopy works that can catch the clear picture of lightning type-branched  small crack surrounding opening tip of main cracks below. The lightning  type and branched of small cracks which are believed in many literature [1,2,3]as the finger-print of stress corrosion cracking mode. And it was very clueful which made us more easier to find the contributing causes .

1. Chloride-SCC in an uncoated medium carbon steel bolt in marine atmosphere


2. HAZ – Caustic SCC at 100-250 °C


Erosion Corrosion – Learning from Humber Estuary

January 27, 2009

Muhammad Abduh (

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).


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 thefailed 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.

There are studies that noted the synergistic effect ofmechanical impingement and electrochemical corrosion result in greater rate of metal loss than the sum of the two mechanism ( S. Zhuo, N. Stack & R.C Newman)

The highest rate of erosion-corrosion occurred in stagnant region, immediately beneath the jet, where the particles impacted the surface at an angle of 90°, This critical erosion-corrosion region in a piping system are found at the outer side of elbow where the fluid impinges the wall directly at an angle 90°.

NACE 34101: Refinery Injection & Process Mixing

One of the generic guidance to overcome the problem of erosion corrosion in refinery process is NACE 34101 which gas already published as recommended practice for the design consideration of  injection system.

RBI Regime was not Effective
This accident also has shown the effect of in-effective implementation of RBI for inspection management. RBI as a comprehensive method shall be supported with complete and adequate data. The ignorance of the operator company for the significant risk contribution of the injection system to the piping were resulted in the failure.

Similar Accidents:

1. Wilmington California United States – October 8,1992
2. North Rhine West Phalia Germany-  December 10,1991
3. Yokkaichi Mie Japan – May 2, 1997
4. Mina Al-Ahmadi Kuwait-  June 25, 2000

The Use of Advanced Materials to Reduce System Cost in Offshore Production Facilities

July 18, 2008

Muhammad Abduh (

The challenge of higher CO2 content in Natuna Alpha-D reservoir recently has seen an economic barrier to the development of this field. But the raise of crude oil price has made the non-prospective drilling like Natuna Alpha-D become prospective as well as the driver from development of exploration and production technology that become more cost-efficient. One of the key issues in development of oil and gas production is the use of advanced materials in deep water drilling and more hostile environment (higher CO2 and H2S content).

The ultimate goal for the use of advanced materials in offshore application is to lower system-cost of oil and gas production facilities. The system-cost should be regarded as life-cycle cost (construction and maintenance) rather than capital expenditure cost (construction). Platform owner conservatively tends to push the capital expenditure as low as possible without comprehensively investigating the potential to reduce system-cost by application of advanced material. Conservative material choice also associated largely due to management of change issue since change of ownership of oil and gas production facilities is quite high.

Pilot project for new material application pioneered by Conoco (now StatoilHydro) for their North Sea production Heidrun TLP. Conoco claimed a significant system cost reduction by applying composites to the several risers. Successful new materials application in this region also supported by certification bodies including Det Norske Veritas by issuing technical guidelines for offshore application of non-steel material. However the expanding use of new materials in other region are still reviewed. Mineral Management Service of United States to be waited by industry for the approval of offshore composite application for producing fields in Gulf of Mexico.

Both technical and economic justifications are needed here. Technical justification for the use of advanced material (stainless steel, nickel alloys, aluminum alloys, composites, concrete, titanium alloys, copper alloys) has been provided adequately. And the economic model to propose the cost-benefit of using alternative materials also already proposed. Model incorporating life-cycle approach and risk factor has
already developed by Craig and Swalm. As seen in Figure 1, by taking risk factor into account we can determine economic choice of material selection for length installed pipelines. Future studies with pipeline failure data representatives will improve the model becomes more accurate and comprehensive.

Figure 1 – Probability Limit Curves for Carbon Steel Failure, clad versus carbon steel for 6-inch pipeline, various pipeline length (Craig)

Steel (low carbon steel) will be ever dominant materials since it has tremendous advantage of a large experience base and strong link between producers, designers, fabricators, and regulators. However there is a challenge in advanced material application due to demands for deep water drilling, oil reservoir rich in CO2 and sulfur, large capacity platforms, and ocean vessels. Choice of materials and the application in offshore structures are listed in Table-1.

Table- 1 Materials and offshore application

A comprehensive world industry leader workshop in New Orleans Louisiana United States in 1997 has drawn several recommendations for the use of breakthrough materials in offshore application as follow:

a. Mooring Systems

– Adequate engineering basis for synthetic ropes and composite strands and updated and unified design standards to accommodate taut mooring system.
– Requirement of updated reliability based safety factors and a coupled hull-mooring dynamic analysis methods.
– Requirements for verification of carbon fiber ropes (lightweight, high axial stiffness, excellent fatigue properties) and more investigation on fatigue strength behavior of steel rope.

b. Riser Systems

– Collaborative efforts are needed for successful use of advanced materials involving end-users, material suppliers, academia, and government.
– System-cost saving must be assessed and emphasized when advanced materials are considered.
– Development NDE/NDT techniques for the changing materials from steel to non steel.
– Development of reelable composite tubulars to minimize costly metallic connectors.

c. Floaters

– For Steel: Materials with higher tensile strength capacity combined with good fracture toughness, more efficient corrosion protection, improvement for weldability, fabrication, quality control, and corrosion resistance.
– For Concrete: more efficient construction method with less manning, more efficient quality control, light weight properties and easy fabrication.
– For Composite: cost efficient fibers, resin, easy fabrication, general qualification of composites as construction material, fire and toxicity safety perspectives.
– For Aluminum and Titanium: alloys with higher structural capacities (ultimate strength, fatigue, crack resistance), and improvement of weldability.

d. Secondary Structures
The use of corrugated or honeycomb construction for secondary structures is recommended because of its lightweight and maintained strength and structural integrity.

e. Hulls
With so many different hull arrangements and purpose hybrid design should be investigated to utilize the best material for certain situation.

f. Pipeline

– Update design code to include limit state design
– Welding Standard for corrosion resistance alloy
– To establish H2S limits for 13% Cr Steel

g. Process Equipment

– Technical barrier for new materials application including design issues, manufacturing and fabrication and costs
– Technical database should be provided to increase the knowledge
– Testing, verification of materials and prototype evaluation should be developed to establish experience base for fabrication and service history of materials.

Several barriers in many cases and regions including in Indonesia that prevent the use of advanced material are:

– Lack of knowledge about materials
– Lack of codes and standards for new materials
– Little experience in the use of many new materials

These barriers become high roadblocks to the potential of system-cost saving of advanced materials. End-users still don’t have enough confidence, fabricators shy away from using some of these new materials because of their ignorance on the weldability and fabricability, and the lack of experience will add a lot to cost. For the successful application of advanced materials there is a requirement to overcome the barriers by providing sufficient knowledge to the stakeholders, organizing technicaland economic justification and more research, development and pilot project to raise the user confidence of new materials application.

1. The Influence of Risk Analysis on The Economics of Carbon Steel and CRA Clad FLowlines, B.D Craig and R.S Thompson, Paper for Nickel Development Institute presented at Offshore Technology Conference Houston Texas US May 1-4 1995.
2. International Workshop on Advanced Materials for Marine Construction, Mineral Management Services DOI US and Colorado School of Mines, New Orleans Louisiana US February 4-7 1997

Offshore, Platform, and the Videos

June 10, 2008

Piper Alpha 1988

Petrobras P-36

BP Thunderhorse

Gulf of Martaban Pipeline Leaking

June 6, 2008

Muhammad Abduh (

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).

Field Information (PTTEP, OilOnline)

  • 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%).
  • Related Post: Palembang Pipeline Leaking – Aging Pipeline to Raise Risk Exposure

    Balongan Unplanned Shutdown

    May 28, 2008

    Muhammad Abduh (

    Balongan LPG Plant, Indonesia largest LPG producer, had a major accident in May 10, 2008 and had to shutdown plant for eighteen days for repair. The accident occured probably because of critical failure in a fluid catalytic cracking unit. Failure consequence is significant as the plant supply 30% of LPG national market and the company is in the excess of 12 million US dollar production loss. As production interruption occurred in a time of government campaign energy conversion from fuel to gas, gas consumer especially food and restaurants industries, and largely household consumer in central to west Java region will suffer the lack of LPG supply in the following days.

    TV News covering Balongan Refinery Shutdown (, MetroTV), LPG Lack of Supply (Liputan6, MetroTV)

    Lesson Learned: Un-anticipated in Service Damage of Process Plant Critical Equipment

    Failure is likely to occur in high pressure system, study by The Health and Safety Executive UK (HSE UK) indicated that inability to predict or inability to anticipate in-service damage as one of the dominant root causes of failure in pressure system. Well established risk management should be able to predict or anticipate in service damage. Risk is a function of failure probability and failure consequence. Risk assessment methodologies are long time developed by American Petroleum Association (API), American Society for Mechanical Engineer (ASME), and Occupational Safety and Health Administration (OSHA), Environment Protection Agency (EPA). Front-end, structurized, and industrial standards risk assessment for process plant are API RP-581 Risk Based Inspection together with API 580 Based Resourced Document.

    We can simply understand that if an equipments have a higher risk profile, than the operator should perform any necessary mitigation to keep the risk as low as reasonably practical. Back to Balongan Refinery case, the FCC is a relatively high risk unit (higher probability of failure and higher of failure consequence). As a high risk unit, operator company should have conducted detailed inspections and comprehensive assessments by means of:

    – Utilizing high resolution inspection tool that should be able to locate and sizing surface or sub-surface defect, uniform or localized defect with the advance technology of field signature method, phased array UT, or multi array sensor.

    – Defect assessment or fitness for service to assess (to study comprehensively) the remaining life of equipment against in-service damage.

    Speculating cost efficiency by reducing inspection or condition assessment cost is rather contra-productive especially in strategic national plant in a time of energy crisis.

    Heat Exchanger In- Service Damages

    May 24, 2008

    1. Excessive mineral deposits on the cooling water side of ammonia reactor effluent gas cooler.

    2. Ice and fouling in a condenser tube.

    3. Shell-side bacteria growth in cooling water heat exchanger

    4. Fin Cooler tubes severly corroded

    5. Deposits build-up on the inside of a heat exchanger tube

    6. Plugged exchanger tube

    7. Scaling on the inside diameter of a cooler tube

    8. Deep Pitting in Exchanger Tubes

    9. Cluster Pitting from Sour Glycol

    10. Shell-side Pitting

    11. Cooler Tube Rupture

    12. Tube Failure Due to Thinning

    13. Shell-side ruptured tube

    14. Wall thinning led to this catastrophic failure of an exchanger tube

    Image Source: Maverick Inspection

    Book on Heat Exchanger Fouling: Heat Exchanger Fouling: Mitigation and Cleaning Techniques