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

2. HAZ – Caustic SCC at 100-250 °C

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.

Erosion-Corrosion
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
Points
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 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).

TO LOWER SYSTEM-COST
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)

MATERIAL OF CHOICE AND OFFSHORE APPLICATION
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

RECOMMENDATIONS
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.

BARRIERS AND ROADBLOCKS
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.

Reference
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

Petrobras P-36

BP Thunderhorse

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)

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 (Liputan6.com, 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.

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

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

-

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

A Part of “Corrosion: Technical and Economic Driver for Indonesia Oil and Gas Industry” Petroenergy Magazine Edition Jan -Feb 2008

–

Corrosion engineering was long time developed in 18th century by Sir Humphrey Davy for copper wooden ships. This engineering discipline then emerged along with development of corrosion resistance material technology, coating, and inspection technologies. Corrosion is a natural tendency of materials to return to their most thermodynamically stable state. This process is usually deteriorative to materials. Corrosion control to prevent this deterioration is by three general ways: control the environment, design the materials, and design a barrier between the material and its environment. A typical approach for corrosion control program applicable for oil and gas industry can be seen in Figure 1.

Figure 1 – Typical Corrosion Control

Knowledge basis for corrosion phenomenon is a thermochemical process. There are eight basic form of corrosion common in petroleum production and process industry, Table 1. Other special form of corrosion that associated with specific hydrocarbon and refining industries are: carburation and metal dusting. Understanding corrosion mechanisms will be much helpful to develop corrosion control practice.

Table 1 -Summarized Corrosion Mode

Corrosion can attack almost all engineering structures equipments and systems: fixed/floating offshore structure, piping system, storage tank, vessel, boiler, etc. Detrimental effects can occur when corrosion accompanied synergistically by mechanical load (static, cyclic). More concern should be given due to stress corrosion cracking, pitting, and intergranular corrosion as these types of corrosion is the most cause of failure in gas pipeline and process industry.

Corrosion Resistance Materials Selection
Beside general requirement in mechanical basis, fabrication, maintainability, and cost, design of materials for corrosion protection should evaluate corrosivity variables as follow but not limited to:

- CO2 content;
- H2S content;
- Oxygen or oxidizing agents content;
- Operating temperature and pressure
- Erosion; and
- Organic Acid and Halide

For many provided guidelines, reference, and recommended practice in oil and gas industry, care should be taken for specific condition of operation variables, environment, and type of equipment and the possibility to introduce specific corrosion mechanism. Output of material selection program is appropriate materials for specific service condition as well as assurance for fabrication and maintainability. Several selection guideline and verification tools considerable for material procurement are as follow:

- Guideline for materials selection for corrosion protection:

> API 5L (general material requirement for oil and gas production)
> NACE MR 0175 (carbon and low alloy selection)
> EFC Document Number 16 (carbon and low alloy for H2S service)
> EFC Document Number 23 (carbon and low alloy for CO2 service)
> Norsok M-001 (corrosion materials for offshore and onshore)
> ISO 15156 Series (corrosion materials for H2S service)
> DNV RP F-112 Draft Version April 2006(duplex stainless steel design for subsea application)
> DNV OS B-101 (corrosion resistant metal for offshore application)

- Corrosion testing of material:

> NACE TM-0177 or EFC Document Number 17 (SCC laboratory test)
> NACE TM-0284 (HIC laboratory test method)
> ASTM G-150:99R04 and ASTM G-0048:03 (critical pitting temperature test method)
> AWS A4.2-91 or ISO 8249 (ferrite number of duplex stainless steel conversion from magnetic measurement)

Protective Coating
Coating is primary corrosion protection method for metals. Corrosion protective performance of coating can be evaluated from the following:

- Mechanical resistance and adhesion;
- Chemical stability;
- Permeability for corrosive agents;
- Electrochemical stability;

Coating for corrosion protection can be broadly divided into: metallic (zinc, chromium, aluminum), inorganic (enamels, glasses, ceramic, glass reinforced lining), and organic coatings (epoxies, alkyd, acrylics, polyurethanes). Steel Structures Painting Council (SSPC) as authorized organization in coating technology provides a series in coating guidelines consist of:

- Surface Preparation Standard;
- Painting System and Coating System Standards Guide and Specification;
- Qualification Procedures and Quality System

Corrosion Inhibitor
Inhibition is alternative corrosion control in oil and gas production, complementary to corrosion resistance material and coating. Exact inhibition mechanism is still in hypothesis until now. Inhibition mechanism once provided by inhibitor molecule that develops a barrier between the corrosive water phase and the metal surface. Most of the inhibitors currently used in producing wells are organic nitrogenous compounds. Dosage of inhibitor mainly based on the corrosivity of the environment (oil well, gas production, transport line). The efficiency of corrosion inhibitor shows a significant effect for lowering corrosion rate. European Federation of Corrosion (EFC) recommended a guideline for the application of corrosion inhibitor as follow:

- Key factors that affect performance:

> Inhibitor efficiency or reduction in corrosion rates;
> Solubility and oil/water partitioning behavior;
> Optimum concentration
> Film stability (flow conditions, temperature)

- Compatibility of the corrosion inhibitor with:

> The production fluids;
> Other chemicals;
> Downstream processing of produced fluids
> All materials in the injection and production systems (e.g elastomers, seals, liners);

- Environmental Issues (biodegradability, toxicity, bioaccumulation)
- Economic (cost, availability of products)

Cathodic Protection
Technology behind cathodic protection (CP) is based on simple principle as to minimize anodic dissolution by application cathodic current. Electrochemistry theory first significant application for cathodic protection was by Sir Humphrey Davy in 1761 for copper wooden ships. The first cathodic protection was applied by Robert J. Kuhn for oil and gas pipeline in New Orleans in 1928. The first cathodic protection standard was drawn in DIN 30676 in 1984. Design of cathodic protection demands accurate information of the nature of the corrosive medium, shape of the structures to be protected, and environment as described in Table 2.

Table 2 – Cathodic Protection design Codes

Deepwater Challenge
Development of offshore cathodic protection requires more detailed guidelines for deepwater platform because of CP design parameter (seawater salinity, dissolved oxygen, temperature, hydrostatic pressure, and presence of calcareous deposits) changes significantly in this depth. Available guidelines from NACE and DNV are applicable and approved for shallow water (<300 meters). Having similar oceanographic characteristic, Indonesian CP designer can share Gulf of Mexico offshore project experience which has reached 900 meter water depth, Figure 2.

Figure 2. Corrosion Protection offshore deepwater challenge
Hydrogen Embrittlement
Hydrogen embrittlement relatively is not a new phenomenon. The loss of ductility due to diffusion of evolved hydrogen from cathodic polarization lead to cracking when component experience load stress and or residual stress, referred as hydrogen induced stress cracking (HISC). The increase use of materials with less proven record in seawater cathodic protection environment has raised the profile of this degradation mechanism in recent years. Another difficulty of cathodic protection for subsea equipments and systems is due to the complexity of subsea component systems. Subsea component that have suffered this failures are: flowlines, manifold hub connector, instrumentation fitting, and circlip fastener. Susceptibility of HISC in several references associated with the effect of residual stress, material and microstructures, cathodic potential parameter (protection potentials and the choose of anodes).

Microstructural features of stainless steel that shall be controlled are: ferrite content, austenite spacing, and grain flow, as recommended in DNV RP F-11221. Resistance to HISC decreases in coarse aligned ferrite-austenite microstructure and or with the presence of third phases (nitrides, alpha prime e.g. in superduplex stainless 25Cr). Therefore more detailed microstructure assessment should incorporate for more accurate and valid results.

Safe cathodic protection design for high susceptibility of hydrogen embrittlement in sea water can be achieved by electrical solution by the use of diode as a potential buffer and by selecting alternative lower voltage of sacrificial anode.

CP System Maintenance

Maintenance of cathodic protection system is important to maintain the protective performance of the system to protected structures. Simple control point for review and maintenance of cathodic protection system are as follow:

- Monitoring of electrical system that include: electrical instruments (power supply, rectifier, transformer, cable connection)
- Monitoring of primary protective coating of the protected structures (pipelines, platform). E.g Pipe-to-soil Potential measurement. Any coating faults can make “overload” protection current. Therefore cathodic protection system should be review: e.g raise the coating breakdown factor ;
- Monitoring protected structure potential. Obtaining CP potential along the protected structures can be difficult in offshore pipelines, which requires diver-man or remote operated vehicle and wired or wireless potential measurement device.

Corrosion Monitoring and Inspection
The main purposes of corrosion monitoring and inspection are:

- Evaluation Purpose:

> Materials under service conditions;
> Control of the production process (periodic, integrated, online assessment);

- Information Basis:

> Material Selection;
> Life assessment (corrosion defect assessment, remaining strength assessment);

Corrosion monitoring for many years utilized for upstream and downstream oil and gas industry involving quite varying technology, from simple chemical coupon to sophisticated automatic inline inspection tools, Table 3. Data combining (fluid corrosivity, corrosion rate, coating fault, metal loss sizing) from these corrosion monitoring activity can be utilized further to assess the overall integrity of engineering structures against corrosion attack.

Table 3 – Corrosion Monitoring Techniques

Table 4 – Aboveground Inspection Tools

Corrosion Assessment
Output of corrosion assessment is a run-repair-replace decision. Methodology for corrosion assessment can be divided into two categories:

- Data evaluation – Information can be provided by inline inspection, NDT inspection, visual examination, and on-site mechanical testing;
- Data evaluation and detailed inspection. More recent direct assessment methodology from NACE and GTI are basically consists of data evaluation (historical data, detailed inspection data) and inspection (indirect inspection, direct examination)

Direct assessment becomes important choice for pipeline integrity management when inline inspection meets geometry restrictions or pressure testing become very expensive. Corrosion direct assessment methodologies and protocol published by NACE are:

- External Corrosion Direct Assessment by NACE RP 0502:2002
- Stress Corrosion Cracking Direct Assessment by NACE RP 0204: 2004
- Internal Corrosion Direct Assessment for Dry Gas will be NACE RP 0104:2005
- Internal Corrosion Direct Assessment for Wet Gas by NACE

Direct assessment (ECDA, ICDA, SSCDA) are typical four step process consists of: pre-assessment, indirect inspection, direct examination, and post-assessment. Simplified ECDA workflow can be seen in Figure 6. Effectiveness of these direct assessments in some references relatively varying. Southwest Research Institute reported that 85% anomalies inspected by inline inspection successfully predicted by dry gas ICDA. Most agree that for more accurate result, alternative validation must be considered as follow:

- NACE External Corrosion Direct Assessment should consider other inspection tools complimentary to tools in selection matrix (analog DCVG, CIPS, Soil Resistivity) ;

- NACE Internal Corrosion Direct Assessment should incorporate alternative probabilistic analysis (e.g. Mechanical Failure by Thacker, Risk Indexing System by Muhlbauer, First Order Reliability Method by Ahmamed and Melchers) to reduce bias from data uncertainty (e.g. the use of pipeline elevation profile map)

Figure 3 – External Corrosion Direct Assessment Work Flow by NACE and TGI

Related Post:

Corrosionomic: Economic Perspective of Iron Rusts and Scales

Corrosion Morphology

Download Print Version, 935.6 KB

]]> http://abduh137.wordpress.com/2008/05/18/corrosion-crash-course/feed/ 0 abduh137 http://abduh137.wordpress.com/2008/05/05/the-50-major-engineering-failures-1977-2007-last-part/ http://abduh137.wordpress.com/2008/05/05/the-50-major-engineering-failures-1977-2007-last-part/#comments Mon, 05 May 2008 02:27:11 +0000 Muhammad Abduh http://abduh137.wordpress.com/?p=129 ]]> 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