Corrosion In Oil And Gas Industry_rev06titlingedit

CORROSION: TECHNICAL AND ECONOMIC DRIVER FOR INDONESIA OIL AND GAS INDUSTRY 1. Aswin Tino (MottMac Abu Dhabi, [email protected])* 2. Dr. Ir. Slameto Wiryolukito (Material Science and Engineering Research Group ITB,, [email protected])** 3. Muhammad Abduh (PT. Rekayasa Solverindo, [email protected])***

I. Introduction Major reasons to concern about corrosion are: safety and economic. Several modes of corrosion can be detrimental and can lead to catastrophic accident to people safety and environment conservation. Several researches in United States and Europe highlighted corrosion as biggest internal damage contributor to engineering structures. A significant economy impact of corrosion and corrosion control also reported. Indonesia Oil and Gas Industry have already invested lot of money in development of facilities upstream and downstream that including offshore/onshore production platforms, refining facilities, and petroleum distribution networks. This paper will present a overview of the activity in corrosion control in global oil and gas industry and searching for the driver for implementation of more effective and economic corrosion control strategy in Indonesia. 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 Program

II. Corrosionomic Corrosion itself and efforts in fighting destruction effect of corrosion to materials has significant implication in economic and business process (corrosionomic). Method for estimating the corrosion impact to national economy was proposed by: - Uhlig Method that more emphasize in production aspects; - Hoar Method that more emphasize in sectoral contribution; - In/Out Method that also estimate indirect cost of corrosion; 1//11

The economy of corrosion in was studied by Battelle (1995) 1 and CC Technologies (2002) 2 in United States and in Japan by Society of Corrosion Engineering and Japan Association of Corrosion Control (1997) 3 , Figure 2. Corrosion cost distribution of both countries differs significantly and remarkably can be effected by the estimating the indirect cost. Indirect cost in high oil and gas economic like United States country definitely must be higher than Japan.

Figure 2. Corrosion Cost Distribution in US and Japan

Battelle found that most expenditure in US is due to extensive development and application of corrosion resistant alloy (CRA) materials (56%) and protective coating (30%). Cathodic protection program which has significant impact on protection system and complimentary to protective coating contribute only 4% of the total corrosion cost. Slight different magnitude also contributes by corrosion inhibitor application and development of non-metal materials (e.g plastic pipe, fiber reinforced plastic). In/Out method, one of the methods used by CC Technologies divided corrosion cost into two categories: - Direct Cost that made up of: ¾ Cost of Design, Manufacturing and Construction: materials selection, coating, sealants, inhibitor, cathodic protection, including labor cost and equipment; ¾ Cost of Management: inspection, rehabilitation, repair, and loss of productive maintenance; 1

Holbrook, D., Economic Effects of Metallic Corrosion in the United States, http://www.battelle.org/pr/12corrode.html , 1-1-1996, Battelle Memorial Institute 2 Koch M. P. H G. H.,.. Brongers N. G. Thompson Y. P. Virmani J. H. Payer, Corrosion Cost and Preventive Strategies in the United States, 2002 3 Survey of Corrosion Cost in Japan, Committee on Cost of Corrosion in Japan, Tokyo, 1997

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Indirect Cost includes loss productivity because of outages, delays, failures, litigation, and taxes of the overhead corrosion cost.

Oil and gas sector contributed 18% to total US national corrosion cost. Detailed for this sector, the study showed that the activity for transporting and storage of gas and liquid contributing the highest corrosion cost (79,6%), followed by refining activities (14,8%), and exploration to production (5,6%), Table 1. The study also has conservatively estimated that total corrosion cost doubled by indirect cost. Both studies agree that effective corrosion control can save up to 40% of total corrosion cost. Effectivity of corrosion control program is determined by how much of indirect cost can be saved, Figure 3. Table 1a. Cost of Corrosion in United States Oil and Gas Sector (CC Technologies, 2002)

Different corrosion cost distribution in Japan can be explained further in economic aspects of respective industries (e.g. transportation, manufacturing, oil and gas, energy, infrastructure) compared with United States.

Figure 3. Corrosion Control Cost Distribution and Measurement of Effectivity

If we can conservatively make a simple assumption, that oil and gas economic characteristic relatively similar, corrosion control and management in Indonesia perform as well as in US and both technical and legislative regulation as strict as in United States, corrosion cost (direct and indirect) in Indonesia oil and gas sector estimated to reach 1,12% of Indonesia Gross Domestic Product (GDP). This figure if we extrapolated to Indonesia GDP in 2006 4 equals to USD 3,74 billion. Cost saving through better corrosion control programs equals to USD 1,5 billion.

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Significant impact of corrosion to the economy could be happened for Indonesia oil and gas industry. If so this issue should be able to raise the level of concern and awareness amongst the stakeholder (material producers, EPC companies, operator, and policy maker). As we can learn from the fact above, a large amount of money can be saved firstly by shifting paradigm of “corrosion as maintenance issue” to new paradigm “corrosion control as integrated company plan”.

III. Corrosion Mode Knowledge basis for corrosion phenomenon is a thermochemical process. There are eight basic form of corrosion common in petroleum production and process industry, Table 2. 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. 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 5,6 , Figure 4. Table 2. Summarized Corrosion Mode 7, 8 , 9

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Congleton, J., Stress Corrosion Cracking of Stainless Steels, in Shreir, L. L., Jarman, R. A., and Burstein, G. T. (eds.), Corrosion Control. Oxford, UK, Butterworths Heinemann, 1994, pp. 8:52–8:83 6 Gas Pipeline Incidents – 6th EGIG Report 1970-2004 Document Number EGIG 05.R.0002, European Gas Pipeline Incident Data Group, Groningen, 2005 7 Schwenk, W, Fundamentals and Concepts of Corrosion and Electrochemical Corrosion Protection, Handbook of Corrosion and Cathodic Protection, Houston , 1971 8 Roberge, R Pierre, Corrosion Engineering, New York, 1999 9 Schweitzer, Phillip A, Fundamentals of Metallic Corrosion Atmospheric and Media Corrosion of Metals, Sound Parkway Florida, 2007

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Corrosion in oil and gas production in many references simply categorized as sour corrosion in H2S service and sweet corrosion in CO2 service. Stress corrosion cracking become special concern in sour gas pipeline due to its potential for pipeline failure.

IV. 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: ¾ API 5L (general material requirement for oil and gas production) ¾ NACE MR 0175 (carbon and low alloy selection) ¾ EFC Document Number 16 (carbon and low alloy for H2S service) ¾ EFC Document Number 23 (carbon and low alloy for CO2 service) ¾ Norsok M-001 (corrosion materials for offshore and onshore) ¾ ISO 15156 Series (corrosion materials for H2S service) ¾ DNV RP F-112 Draft Version April 2006(duplex stainless steel design for subsea application) ¾ DNV OS B-101 (corrosion resistant metal for offshore application)

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Corrosion testing of material ¾ NACE TM-0177 or EFC Document Number 17 (SCC laboratory test) ¾ NACE TM-0284 (HIC laboratory test method) ¾ ASTM G-150:99R04 and ASTM G-0048:03 (critical pitting temperature test method) ¾ AWS A4.2-91 or ISO 8249 (ferrite number of duplex stainless steel conversion from magnetic measurement)

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(a) (b) Figure 4 Stainless Steel Failure by Corrosion in Process Industry, 3b.Gas Pipeline Corrosion Failure (EGIG)

V. Protective Coating Coating is primary corrosion protection method for metals. Corrosion protective performance of coating can be evaluated from the following 10 : - 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 VI. 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 11 . 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 12,13 . European Federation of Corrosion (EFC) recommended a guideline for the application of corrosion inhibitor as follow: - Key factors that affect performance: ¾ Inhibitor efficiency or reduction in corrosion rates; ¾ Solubility and oil/water partitioning behavior; ¾ Optimum concentration ¾ Film stability (flow conditions, temperature). 10

Heim, G; Schwenk, W, Coatings for Corrosion Protection, Handbook of Cathodic Corrosion Protection, Houston, 1971 11 EFC Publication Number 39, The Use of Corrosion Inhibitors in Oil and Gas Production. 12 3. A. J. McMahon and D. M. E. Paisley, Corrosion Prediction Modelling, BP Sunbury Report, ESR.96.ER.066, November, 1997. 13 J. Mendoza-Flores and S. Turgoose, A rotating cylinder electrode study of cathodic kinetics and corrosion rates in CO2 corrosion, Corrosion '95, Paper No. 124, NACE International,

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- Compatibility of the corrosion inhibitor with: ¾ The production fluids; ¾ Other chemicals; ¾ Downstream processing of produced fluids ¾ All materials in the injection and production systems (e.g elastomers, seals, liners); - Environmental Issues (biodegradability, toxicity, bioaccumulation) - Economic (cost, availability of products) VII. 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 14 . 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 3. 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 15 , Figure 5. 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 16 . 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) 17, 18 , 19 , 20 . 14

The History of Corrosion Protection, W.V Baeckman, Handbook of Cathodic Corrosion Protection, Houston, 1971 Fairhurst, D, Offshore Cathodic Protection. What We Have Learnt, Journal of Corrosion Science and Engineering. www.umist.ac.uk/corrosion/jcse, UK 2004. 16 Fairhurst, D Murphy W and Amon C, The Failure of Minor Components with Disappropriate Consequences. UK Corrosion 98 17 Festy D, Cathodic Protection of Steel in Deep Sea: Hydrogen Embrittlement Risk and Cathodic Protection. NACE Corrosion Paper No 01011 2001 18 Woolin P and Murphy W, Hydrogen Embrittlement Stress Corrosion Cracking of Superduplex Stainless Steel, Paper 01018 Corrosion 2001, Houston 19 A.Pourbaix Supermartensitic Steels ’99, S99-33 Page 283 “Cathodic Protection of Supermartensitic 13 Cr Stainless Steels Without Hydrogen Damage” 20 12 R.Lye. Materials Performance P 24, October 1988, “Current Drain to Cathodically Protected Stainless Steels in Seawater” 15

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Microstructural features of stainless steel that shall be controlled are: ferrite content, austenite spacing, and grain flow, as recommended in DNV RP F-112 21 . 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. Cathodic Protection Maintenance Table 3. Summarized Cathodic Protection Designs and Guidelines

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. VIII. Corrosion Monitoring and Inspection The main purposes of corrosion monitoring and inspection are - Evaluation Purpose: ¾ Materials under service conditions; ¾ Control of the production process (periodic, integrated, online assessment); - Information Basis: 21

DNV RP F-112, Design Of Duplex Stainless Steel Subsea Equipment Exposed to Cathodic Protection, Draft Issue April 2006

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¾ Material Selection; ¾ 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 4. 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.

Figure 5. Offshore Cathodic Protection Challenge

Table 4.a. Corrosion Monitoring Techniques

Table 4.b. Aboveground Inspection Techniques

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IX. 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 22 , 23 , 24 . 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)

Corroded Pipeline Rehabilitation 22

Cathodic Protection, Coatings, and the NACE External Corrosion Direct Assessment (ECDA) RP 0502-2002, Journal of Corrosion Science and Engineering, Dr J M Leeds Pipeline Integrity Management Ltd, Corbett House, Swan Lane, Hindley Green, Wigan. WN2 4EY. UK, 2004 23 Internal Corrosion Direct Assessment of Gas Transmission And Storage Lines, Narasi Sridhar, Ben Thacker, Amit Kale, and Chris Waldhart,Southwest Research Institute for Research and Special Programs Administration Office of Pipeline Safety (OPS),2004 24 SSCDA Prediction Model for Cathodically Protected Onshore Gas Transmission Pipeline with Coal Tar Enamel Coating, Jamalee Ahmad, Musfizree, Mustaffa, Khairul Ismail, and Dr. Melor Murni Mohamed Mustakim, Petronas Group Technology Solution, 2nd NDT & Corrosion Management Asia Conference 2006 Singapore.

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Requirement for pipeline rehabilitation program has already governed in several design guidelines (ASME B31.8 for gas transmission pipeline and ASME B31.4 for liquid pipelines, API 1107). Pipeline operator prefer conservatively replace pipeline segment if the malfunction is a leak or stress concentration. For corroded pipeline under safety criterion sleeve-weld repair become the choice. Besides standardized method in above guidelines considerable alternative technique for for pipeline rehabilitations 25,26 are: - Field coating removal by Borehole Reconditioning System (BRS) is a high power water blast plus air abrasive blast to remove old coating; - Clock Spring Method. A non-welded sleeve in a form composite coil consists of glass fiber wrap, adhesive, inter-layer filler material, and additional coating. X. Conclusion Corrosion cost to the national economy gives a significant number. Indonesia oil and gas industry can save up to USD 1,5 Billion through better managed corrosion control. Higher level of effectivity and efficiency of corrosion control can only be achieved if corrosion placed as integrated plan of the company more than just maintenance issue. Integrated plan of corrosion control in Indonesia can chase the global opportunity in corrosion control, methodologies and technologies that cover broad scope ranging from material management, protective coating and inhibition, cathodic protection, corrosion monitoring and inspection, and corrosion assessment. Acknowledgement The Authors would like to extend their most sincere gratitude to all sources for open-for-public technical papers to develop this paper. About the Authors * Corrosion Engineer at Mottmac Abu Dhabi Uni Arab Emirate ** Senior Lecturer at Material Engineering and Mechanical Engineering ITB *** Material Engineering Consultant to PT. Rekayasa Solverindo

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John, Robin., "Field Recoating Using the 3 Layer System", Proceedings of the 7th Annual Pipeline Monitoring & Rehabilitation Seminar, February 6-9, 1 995 26 Kelty, W., Paul., "Composite Sleeves for Pipeline Integrity: Part II", Proceedings of the 7th Annual Pipeline Monitoring & Rehabilitation Seminar, February 6-9, 1 995.

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Figure 6. Simplified NACE External Corrosion Direct Assessment with supporting guidance by GTI PIM ECDA Protocol (shaded).

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