Advanced Materials in Oil and Gas Production 2
DNV GL STRATEGIC RESEARCH & INNOVATION POSITION PAPER 2-2014
ADVANCED MATERIALS IN OIL AND GAS PRODUCTION SAFER, SMARTER, GREENER
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ACKNOWLEDGEMENT The authors would like to acknowledge the valuable input from Dr. Mariano Iannuzzi, Dr. Ramgopal Thodla, Dr. Fei Tang, Dr. Jose Ramirez, and Mr. Bjørn-Andreas Hugaas.
Contact: Liu Cao e-mail: Liu.Cao@dnvgl.com Narasi Sridhar e-mail: Narasi.Sridhar@dnvgl.com Feng Gui e-mail: Feng.Gui@dnvgl.com Address: DNV GL Strategic Research & Innovation 5777 Frantz Rd. Dublin, OH 43017 USA
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CONTENT ACKNOWLEDGEMENT 2 Contacts 2
INTRODUCTION 4 Severe Well Characteristics 4 Materials 6
Nanocrystalline Materials 8 Bulk Metallic Glass 10 Diamond-like Carbon 12 Summary and Other Possibilities 15 Challenges 16
MATERIALS SELECTION IN OIL AND GAS PRODUCTION
Use of Standards and Codes Challenges of Standards
CASE STUDY: Selection of Corrosion Resistant Alloys (CRA) for Severe Wells
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INTRODUCTION The oil and gas industry is exploring in deeper waters and at greater depths beneath the ocean floor, both of which will require the development of new technologies and materials as well as extending the operation limits of existing materials. Although the industry has developed a considerable knowledge regarding the performance of various conventional metallic alloys, more systematic procedures for materials selection are required to accelerate their application and to reduce the safety risk and environmental impact of deep and ultra-deep deployments. This document looks into the different challenges and the most promising emerging materials technologies associated with drilling and production of oil and natural gas from ultra-deep reservoirs, with a focus on down-hole systems.
SEVERE WELL CHARACTERISTICS Wells can be in deep water (water depths ranging from 2000 to 3000 m are not uncommon in Brazil and the Gulf of Mexico) as well as drilled to great depths below the ocean floor. Wells can also extend their horizontal reach by as much as 6000 m. The well descends into the production zones through a series of casings of reduced diameter. Each casing is held in place by cementing to prevent the caving in of the bore hole and also permit the use of various well intervention devices. The production tubing is the last piece of tubing that enters the inner-most casing and essentially hangs from the top from a thick-walled tubing hanger. The annulus between the production tubing and the innermost casing is filled with a high density brine to force the hydrocarbons to flow through the tubing.
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Figure 1. Schematic drawing of off-shore drilling structure.
Figure 1. Schematic drawing of off-shore drilling structure. â€“
The casings are generally made of carbon steel (or alloy steel), but the production tubing for the severe wells are typically made of corrosion resistant alloys (CRA). From an advanced materials selection perspective, the well depth below the floor is more important than the water depth, although deeper waters will require more conservative choices due to the cost of any repair. Wells are generally characterized as High Pressure High Temperature (HPHT), ultra-HPHT, or x-HPHT depending on the bottom hole pressure and temperature. Although not always correlated with temperature and pressure, the environmental chemistry of the water can range from sweet (hydrogen sulphide below measurable limit, which is about 0.5 ppm at present) to extremely high in hydrogen sulphide (several hundred bars of partial pressure). There can also be elemental sulphur
Figure 2. Schematic drawing of different depths of drilling well. Figure 2. Schematic drawing of different depths of drilling well.
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ÂŤ From an advanced materials selection perspective, the well depth below the floor is more important than the water depth Âť
present if the hydrogen sulphide concentration exceeds certain levels. The elemental sulphur is an oxidizing agent that increases the corrosivity of environment. The total dissolved solids (mostly present as chloride salts, treatment chemicals, and organic compounds, etc.) can range from a few hundred ppm in condensed water to as much as 400,000 ppm in produced water. In some wells, organic acids (mainly acetic acid) may be present, increasing corrosivity and cracking tendency of materials. Impurities, such as mercury may be present in small concentrations and affect the cracking tendency as well. In addition to production fluids, the materials may be exposed to well completion fluids (typically highly concentrated chlorides, bromides, and formate salts of sodium, potassium, calcium and zinc mixed with inhibitors such as thiocyanates), stimulation fluids (highly acidic solutions of hydrochloric, hydrofluoric acids) for short periods of time, and injected water containing carbon dioxide. The composition of the water will change with the life of the well. In this regard, new wells usually have waters with low concentration of dissolved solids. As the well ages, however, the concentration of dissolved solids increases and highly concentrated brines are commonly found.
MATERIALS Advanced materials can be conventional metallic materials, non-conventional materials (metallic or non-metallic), or a combination of these. For HPHT conditions, polymeric materials are mainly used for soft seals and need to be replaced during refurbishment at intervals. Monolithic ceramic materials do not have the fracture toughness and may be employed mainly as coatings. Therefore, this position paper deals mainly with metallic materials. These can be either monolithic alloys of Fe-Ni-CoCr-Mo-W, claddings or coatings of these alloys on less expensive substrates such as low alloy steel, and coatings of novel materials such as diamond like carbon (DLC) on these substrates. In the subsequent pages, the salient features of these materials and the challenges in incorporating these materials in severe wells are described. Recommendations are made for reducing the barriers for insertion.
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Max. P > 103 MPa Max. T > 177 C
Other species (mercury, etc.) Organic acids
Hydrogen Sulfide Figure 3. A spider chart of characteristics of deep well environment.
Max. P > 206 MPa Max. T > 230 C
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ADVANCED MATERIALS In the last a couple of decades, there have been a number of stronger, lighter and multifunctional materials developed in the laboratory. Advanced materials are meant to be those materials which have at least one property that is significantly superior to the conventional alloys. Their unique properties, without exception, originate either from the non-equilibrium microstructure or from the innovative chemical composition. Three types of advanced materials are picked as the most promising for applications in oil and gas production.
NANOCRYSTALLINE MATERIALS Enhancement of both strength and toughness can be achieved simultaneously by reducing the grain size, schematically shown in Figure 4. In contrast to conventional metallic alloys with typical grain sizes in the range of 10 to 100 μm or even higher for some cast materials, nanocrystalline (NC) materials
are characterized by grain size of typically 10-100 nm. However, a softening effect by grain boundary sliding begins to take a dominant role when grain size is further reduced under 10 nm. In principle, processing of bulk nanocrystalline alloys can be accomplished by either the ‘‘two step bottomup’’ methods which assemble nanoscale clusters and subsequently consolidate into bulk material, or the ‘‘one step top-down’’ methods which break down the bulk microstructure into the nanoscale, as illustrated in Figure 5. The consolidation step involved with high pressure and heat should be carefully done without significant coarsening of the grain size and introduction of artifacts.  In contrast, “one-step” processes such as electrodeposition and mechanical attrition, are beneficial for the dense and artifact-free NC materials.
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Strength Toughness Ductility
Decreasing Grain Size Figure 4. shows schematically the effects of decreasing grain size on several material properties.  Optical image of coarse-grained iron specimen: (left) annealed, (middle) as cast, and (right) SEM image of nanocrystalline iron deposit. 
Compared to their microcrystalline counterparts, NC metals in general exhibit high yield strength and hardness, excellent wear resistance, and enhanced superplasticity. However, the expected ductility increase is typically limited by processing artifacts. Fracture and fatigue resistance are found to be superior as well.  Due to the high portion of grain boundaries, high temperature creep rate of NC materials may be increased by the enhanced diffusivity. NC materials are therefore not heat treatable. The increased diffusivity of NC materials, on the other hand, contributes to faster protective passive film formation and thus increases corrosion resistance.  NC materials are mainly limited to coatings and thin films due to the difficulty of retaining the ultra-small grain sizes in thick cross-sections. NC coatings are used to improve hardness and toughness coupled with better corrosion and wear resistance
for structural applications, i.e. Fe/Ni-W, WC-CoCr, TiN/TiCN, yttria-stabilized zirconia (YSZ) and other metallic or cermet nanostructured coatings. It is likely that NC materials would see service in specialty applications such as valve seats and stems, components of compressor or pump, and surfaces such as the riser tensioning system where wear and corrosion resistance are required. Nowadays, more than a dozen of companies in U.S. are involved in the manufacture of nanostructured materials on an industrial scale and probably more than 1600 organizations world-wide are involved in the development, production, and services related to such materials. [9, 10]
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Figure 5. Schematic drawing to illustrate “bottom-up” and “top-down” fabrication methods of nanocrystalline materials.
BULK METALLIC GLASS Combined with some desirable properties of metals and the formability of glasses, bulk metallic glasses (BMG) exhibit attractive properties which result from their amorphous state. In theory, any metallic alloy can form a glassy state by extremely rapid solidification. However, such extreme cooling rates yield thin materials in small quantities. BMG strictly refers to those multicomponent alloys system developed since 1980’s with high glass forming ability (GFA). GFA stands for the ability of forming larger than 1 mm thickness of material in the glassy state at relatively low cooling rate (< 100 K/s), Figure 6.
Figure 6. Typical various alloy systems of BMG’s were reported with critical casting thickness for glass formation and the calendar year when the first synthesis was discovered. [11, 12]
Fabrication methods of BMG’s all result from different non-equilibrium processing techniques to avoid crystallization. Solidification processes via direct casting and thermoplastic forming (TPF) are the most widely used.  Direct casting requires
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Figure 7. High Velocity Oxy-Fuel (HVOF) process is used to coat a container with SAM1651 amorphous metal with quality assurance monitoring the thickness and roughness of BMG coating. 
relatively rapid cooling from melting temperature to glass transition temperature by bypassing crystallization. In the TPF, BMG’s with high GFA can be thermoplastically formed in their supercooled liquid state above its glass transition temperature. [13, 14] Decoupled cooling and shaping in TPF provides a wide window of time and temperature that facilitates better control over the process. Because of the absence of grain microstructure, well-defined crystal defects, and chemical inhomogeneities, BMG’s possess outstanding mechanical properties compared to their crystalline counterparts, such as much higher tensile strengths and hardness, near theoretical high yield strength with more than 2% elastic deformation, lower Young’s modulus, low internal friction and wear coefficients, high fracture strength, and superior fatigue resistance. [15, 16] Some BMG alloy systems, e.g. Zr-, Pd–Cu-, Fe-, and Mg-
based systems, also possess excellent corrosion resistance and repassivation ability under extremely corrosive environment.  However, due to the highly constrained plastic flow and the lack of microstructural features , BMG’s usually are ‘‘brittle’’ and lack plasticity under tension, which results in low fracture toughness and impact resistance . It is suggested that applications with small dimension would benefit the most from BMG’s with enhanced plasticity and the low material cost.  In oil and gas production, BMG can be used on valves and springs, strengthened edges of tools, wear resistant surface of drill head, high corrosion resistant coating, pipes for mass flow meter, precise miniature parts of pressure sensors, etc. [14, 15, 20] Due to their high cost and low impact toughness, the primary use of BMG will be limited to small critical components with high demand of performance. A
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recently developed Fe-based BMG (Fe–Ni–Cr–C–B) with an exciting combination of moderate cost and properties may have a greater resistance to localized corrosion than a conventional Ni-22%Cr-9%Mo3%W alloy. [17, 20, 21] Thermal spray-coated layer of high performance Fe-based BMG’s (SAM2X5, SAM1651) were developed to protect substrate under fairly aggressive conditions, in Figure 7. It has been suggested that 316L stainless steel plates coated with these Fe-based amorphous metals layer outperform conventional Ni-Cr-Mo alloys, but at a third of the cost. 
content, as shown in Figure 9. In general, DLC films with high sp3/sp2 ratios show better mechanical properties, whereas with lower sp3/sp2 ratios it exhibits better electrical and optical properties.  The excellent chemical inertness of DLC films makes them a promising coating material as a physical barrier in corrosive environment. The most attractive features of DLC films are: i) their wide range of properties that can be tailored by deposition methods with doping, ii) low cost to coat, and iii) low deposition temperature, i.e. almost any materials can be DLC coated at room temperature.
DIAMOND-LIKE CARBON Diamond-like carbon (DLC) involves a variety of amorphous carbon materials containing a significant fraction of sp3 electron configuration in the carboncarbon bonds, lending these materials similar mechanical performance of diamond. The properties of DLC films are determined by the ratio of sp3 and sp2 electron configuration of bonding and hydrogen
Depending on the carbon source and deposition process, there are two main types of DLC films in Table 1: i) hydrogenated amorphous carbon (a-C:H) and ii) hydrogen-free tetrahedral amorphous carbon (ta-C). The a-C:H was earlier developed from hydrocarbon plasma. The hydrogen is required to tie-up the dangling bonds and to keep the carbon in sp3 bonding configuration for obtaining “diamondlike” properties. The a-C:H films are relatively soft
Figure 8. Comparison of carbon-carbon bonding and structure of diamond (sp3), graphite (sp2) and DLC coating (mixed sp2/sp3). [wikipedia.org]
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Figure 9. Ternary phase diagram of C, H system showing a-C:H, ta-C and other forms of DLC film. 
of sp3 carbon, ta-C film exhibits high hardness and wear resistance close to those of diamond. As complement to a-C:H, ta-C shows lower friction coefficients for most surfaces (0.1–0.15) especially in a humid environment, and much higher thermal stability.  The only drawback of ta-C films is their high intrinsic compressive internal stress arising from the ion bombardment for the formation of metastable sp3 bonding, which often limits the maximum thickness of an adhesive ta-C film to less than 1 μm. 
compared to diamond, and exhibit some of the lowest friction coefficients (0.001-0.1) and wear coefficients in the dry and lubricant-free conditions (but increase considerably with humidity).  Recently improved by a filtering technique, ta-C films were able to be deposited from pure carbon source with good quality at comparable growth rates of a-C:H film. Due to a predominant fraction
In addition to carbon and hydrogen, DLC films can be doped with nitrogen (N-DLC or CNx films), silicon (Si-DLC), fluorine (F-DLC), and metal atoms (MeDLC). [28, 29] Most modifications have been made to DLC are to reduce its high internal compressive stresses, to increase the adhesion between film and substrate, to decrease its surface energy for further lowered friction coefficients, or to modify its electrical properties.
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sp3 content, %
H content, %
Density, g cm-3
Young’s modulus, GPa
Fracture toughness, MPa m1/2
Residual stress, GPa
Thermal stability, °C
* 1 oxidization temperature in air, 2 oxidization temperature in vacuum or inert gas. Table 1. Comparison of structure and properties of a-C:H and ta-C DLC films with those of diamond and graphite. [25, 27, 28]
Figure 10. a) Selection of automotive engine components that have been coated successfully with DLC.  b) DLC (WC/C multilayer) coated spur gear.  c) Hydrogen-free DLC coating for tools. [americanmachinist.com]
DLC are mainly used as a hard, low friction, long-lasting, wear and corrosion resistant coating material. Commercial suppliers offer DLC coatings of varying composition, deposited in different processes. DLC film has been widely used in automobile industry as a reliable tribological coating. In oil and gas industry, the applications of DLC films can be expanded to drilling tools, the chemical pumps or multiphase pumps, valves, thread connections, elastomer seals, and so on.
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SUMMARY AND OTHER POSSIBILITIES Certain mechanical properties of these three types of advanced materials are illustrated in an Ashby diagram, Figure 11, in comparison with conventional metals and ceramics. These advanced materials stand out above those conventional counterparts with enhanced hardness or strength, which is desirable for oil and gas industry In addition, there are a few novel materials drawing attentions for their promising applications in the oil and gas production. 1. High catalytically active nanoparticles can be used
as high performance inhibitor in upstream and catalyst for chemical processes in downstream.
2. Self-assembled monolayers (SAMs) are organic
molecules that have strong chemisorption to metal surface and spontaneously aligned to form a monolayer, which makes SAMs an inexpensive and versatile surface coating. 3. Concept of smart coating is similar to chromate
conversion coating, which is developed with ability to â€œsmartlyâ€? heal or release corrosion inhibitor from coating damage. 4. Shape memory alloy (SMA) could be used as
critical component of safety valves or other applications trigged by temperature variation. 5. Precipitation hardenable CRA provide unique
combinations of strength via heat treatment and
Figure 11. Hardness or yield strength is plotted against bulk elastic modulus for conventional metals, ceramics, and three types of advanced materials discussed in this section.
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corrosion resistance. This enables them to be used for components requiring thick sections, such as tubing hangers, and complex geometries. Issues such as quality variations due to production process and limits of performance still need to be addressed in a systematic manner for these materials. 6. As a combination of different materials to
produce distinct properties from each individual components, composites are expected to fulfill the functionality of 1+1>2, e.g. flexible risers or flowlines in oil and gas industry. 7. The capability of aluminum alloys in offshore
drilling processes is being explored by major aluminum producer as lighter weight alternatives to steel. However, there is a need to address the susceptibility to corrosion of proprietary aluminum alloys in sour and sweet environments and develop preventive coatings or other treatments.
8. Titanium alloys have been explored as light-weight,
highly corrosion-resistant alternative to CRA, ideal for applications of drilling risers or high pressure heat exchangers. The data of titanium alloy are however still limited. Increased use of titanium alloy is dependent upon the scale of availability at reduced cost. CHALLENGES Most of advanced materials are in the non-equilibrium state, which means thermal stability is a critical concern. Nanocrystalline metals have limited working temperature about a few hundred °C depending on the melting temperature of component. The a-C:H films have limited working temperature up to 350 °C, and ta-C films are more stable up to 1000 °C. BMG’s have a glass transition temperature of about 500 °C. Fortunately, those temperature limits are above those encountered in the oil and gas production.
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The other main challenge results from the intrinsic behavior of materials: high strength is usually achieved at the cost of ductility or toughness, and vice versa. The ultra-high strength metals usually do not possess sufficient toughness to resist environment assisted cracking. The balance of hardness and ductility needs to be tuned specifically to meet the engineering requirement. This may be solved by a composite structure consisting of a softer second phase or multilayers structure of NC, BMG and DLC coatings. The variability in the structure and performance of materials is a concern and would require careful acceptance and quality control testing. At present, the characterization and testing methods of advanced materials sometimes do not fit the oil & gas applications. For example, there are over 200 testing methods to evaluate performances of DLC films , in which scattered results are expected. Few documents are specifically addressing the
synergistic effect of corrosion and mechanical performance. Other than basic immersion tests and electrochemical tests, the standardized accelerating tests of environmentally assisted cracking, fracture and fatigue are critical to materials selection in the oil and gas industry. Industry accepted test methods will contribute to accelerated insertion of advanced materials.
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MATERIALS SELECTION IN OIL AND GAS PRODUCTION The materials selection in oil and gas industry typically follows industry standards and operator’s own technical specification. The use of technical standards is supplemented, where necessary, by fit-for-service testing. Because of safety and other consequences, the choice of materials is usually highly conservative. Although conservative materials choice ensures safety, there are other risks associated with such a choice: ■■ If a more corrosion resistant alloy than required is specified, it results in increased project costs as well as potential delays in procuring the needed materials, fabrication, etc. ■■ If a higher than necessary derating of the material is assumed (i.e. if it is assumed that the material strength decreases faster with an increase in temperature than is true), it would require building thicker-walled piping that, in turn, would drive up the project costs significantly without providing any extra benefit. Nevertheless, actual statistics on materials properties are not incorporated in the standards and design codes. ■■ Additionally, the bottom hole environmental conditions can become more severe as the well ages. It is possible that the chloride concentration increas-
es with time as the hydrocarbons are withdrawn and the hydrogen sulfide concentration can also increase. In such a case, an originally conservative choice may no longer be adequate. Therefore, it is important that the selection process is informed by the range of conditions that can be encountered during the life of the well as well as by the performance of materials in these environments..
USE OF STANDARDS AND CODES NORSOK M-001, ISO 13628-1, and the relatively new ISO 21457 are used as general guidance on corrosion evaluations and materials selection for the standard types of equipment and facilities. ISO 21457 is being pushed by European oil companies and begins to play an increasing role. The NORSOK standard provides detailed materials selection criteria, while the ISO standards provide more general information and are best regarded as a guidance document.  ISO15156 / NACE MR0175 is handled with ballots by experts in a maintenance panel and a supervision committee to update the standard and provide interpretations of inquiries to the standard. Individual new alloy usually takes
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INDUSTRY STANDARDS There are nearly 1140 different standards worldwide particularly focusing on the offshore petroleum industry , however only a few of them can be used as reference of material selection. NORSOK M-001: Materials selection, 2004 (Rev. 4). It provides general principles, recommendations, requirements and guidelines for materials use and corrosion protection in oil and gas production and processing facilities.
2 to 3 years of balloting for the acceptance, and another 2 to 3 years to be included in the document. In addition, International Oil and Gas Producer Association (OGP) encourages and supports ISO/TC67 on developing ISO standards on an international level, which are based on several other sources , such as American Petroleum Institute (API), National Association of Corrosion Engineers (NACE), American Society for Testing and Materials (ASTM), American Society of Mechanical Engineers (ASME), European Standards (EN), NORSOK and DNV, etc. The code design standards most commonly used for offshore pipelines are DNV-OS-F101, API 5L / ISO 3183, API 5D and BS-PD-8010. API 5D is specifically applied to drilling pipes. All of these focus on line pipe specifications, manufacturing and testing requirements, proper operation and recommended practices, rather than material selection. Only DNV-OS-F101 is a more comprehensive document, covering from concept development and design to the abandonment of pipeline system. Many purchaser, contractors and operators use these, or have their own company specifications based around those officially published ones.
ISO 15156 / NACE MR 0175: Materials for use in H2S-containing environments in oil and gas production, 2009 (Rev. 2). It is a standard specified for selection of various grades of carbon steel (part 2) and corrosion resistant alloys (part 3) for sour oil and gas production. Sometimes qualification testing is required for a particular case. ISO 13628-1: Design and operation of subsea production systems—general requirements and recommendations, 2005. Amendment 1, “Materials and corrosion protection.” ISO 23936: Non-metallic materials in contact with media related to oil and gas production, which includes ISO 23936-1: Thermoplastics, 2009 and ISO 23936-2: Elastomers, 2011. It provides general requirements, recommendations for the selection and qualification of non-metallic material for service in oil and gas production, and gives guidance for the quality assurance, resistance to the deterioration in properties.
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CHALLENGES OF STANDARDS 1. Performances of materials at boundaries of environment conditions are not well documented in the standards, due to the lack of mechanistic understanding of corrosion failure. Due to the increasing use of CRA’s and their high global prices, materials selection is usually driven by economic and project risk considerations. As a result, materials are pushed towards their application limits. Alloy composition will also approach the lower specification limit to reduce cost. Sometimes this may affect the expected materials performance. In fact, environmental conditions may change over time, which also
require the exploration of material’s performance limit and distribution of failure probability around boundary conditions. 2. The limits defined in different standards are not
well aligned with each other. Some are caused by different testing and evaluation methods, some are caused by inconsistent requirement from a variety of companies and operators. In the global market, oil and gas industry forces the increase in the reliance on international standards rather than national standards and operators’ specifications. The provision of more international standards is
INDUSTRY STANDARDS ISO 21457: Materials selection and corrosion control for oil and gas production systems, 2010. It is the only ISO standard that covers over 80% of normal needs related to materials selection and corrosion control in the upstream oil and gas industry, which identifies relevant degradation mechanisms and materials options. It was based on NORSOK M-001 and internal documents from different operators, in line with ISO 15156/NACE MR0175 and ISO 23936.  EEMUA 194: Guidelines for materials selection and corrosion control for subsea oil and gas production equipment, 2012 (3rd Edition). It provides an overview of the current knowledge of the principles and practices
of materials selection and corrosion control for underwater oil and gas production equipment and related facilities. EFC Publication 16: Guidelines on Materials Requirements for Carbon and Low Alloy Steels for H2S-Containing Environments in Oil and Gas Production, 2009 (3rd edition) and EFC Publication 17: Corrosion Resistant Alloys for Oil and Gas Production—Guidance on General Requirements and Test Methods for H2S Service, 2002 (2nd edition). These guideline documents are generally complementary to ISO 15156 / NACE MR 0175, but separately developed. They contain a wider scope and more details in testing.
Company Specification: All companies actually have their own technical practices for materials selection in the anticipated environment conditions. These technical specifications are prepared by company itself and are built on industry standards, recommended practices, company experience and lessons learned, which caters to both general needs and special applications. In an OGP report of 2011 , the average number of specification per company is 816 and it keeps growing. Companies with large research facilities typically initiate a test program to filter a few most likely alloy candidates, which process can easily require 1 to 3 years at considerable expense.
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driven by the regulators, and the harmonization of different relevant standards remains essential for this purpose.
performance of weld components also depends on a number of variables, i.e. welding process, welding parameter, and selection of consumables. Data of welded CRAâ€™s is limited.
3. The limitations addressed in the standards cover
the most conventional materials, but these limits may need to be revised for unconventional materials. 4. Corrosion performance and environment assisted
cracking resistance of weld joints are usually not considered in the standards of materials selection and welding procedure qualification. Other than base material and specific environment, the
5. The failure analysis provides valuable information
to advise the materials selection and can serve as input for the recommendation to reduce the cause of failure. There is a need for a framework and tools to incorporate field experience and company-specific information in materials selection practices.
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CASE STUDY: SELECTION OF CORROSION RESISTANT ALLOYS (CRA) FOR SEVERE WELLS This case study is the result of an ongoing joint industry project (JIP). Corrosion Resistant alloys (CRAâ€™s) are defined as alloys protected by an oxide film that renders them more resistant than carbon steels to general corrosion in the environments relevant to oil and gas production. In contrast, carbon steel exhibits high general corrosion rates in these environments and has to be protected using either a corrosion-resistant coating or a chemical inhibitor that forms a protective film or raises the pH of the environment. For HPHT conditions, conventional polymeric coatings are not adequate and chemical inhibition is not feasible.
Sress Corrosion Cracking is controlled by local corrosion and plastic deformation
Sulfide Stress Cracking requires Hydrogen generated by corrosion - for CRA this will happen below depassivation pH
SCC SSC O2+2H2O+4e- <=> 4OH-
Hydrogen Stress Cracking requires galvanic coupling with steel to generate hydrogen
H++e- <=> 1 H2 2
Temperature Figure 12. Three types of EAC have been observed depicted on an electrochemical potential-pH (Pourbaix) diagram. These regions are alloy and environment specific.
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Performance limits for highly alloyed austenitic stainless steels in ISO 15156. The data points indicate the specification limits. The cracking mode is likely to be a mix of various EAC, depending on the environmental variables, including ones not explicitly mentioned in this diagram, such as pH and potential. No data are indicated above or below these limits, thus probabilistic information around the limit state is missing.
Another method to delineate the performance of CRA’s is to identify regions in the carbon dioxide – hydrogen sulfide pressure space. However, carbon dioxide pressure is much less influential for the performance of the high-end alloys and in any case, these boundaries are derived from sparse data.
DNV GL © 2013
Figure 13. Schematic illustration of performance limits of CRA’s in terms of environment conditions described in the standards.
Although CRA’s are passive in most oil and gas environment, they can be susceptible to localized corrosion in the form of pitting or crevice, and a number of environmentally assisted cracking (EAC) failures, in Unfortunately, in current standards, such as ISO15156 for materials selection in H2S containing environments, these corrosion phenomena are often intermingled. Materials are typically specified in terms of temperature, dissolved chloride concentration, and gas-phase H2S partial pressure. The limits specified for alloys are based on laboratory tests and field experiences, mostly using statically-loaded specimens. Therefore, such limits often lead to uncertainties in alloy selection.
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Pre-Cracks or crevices
Figure 14. Failure acceleration vectors need to be considered for laboratory accelerating tests to evaluate long-term performance of materials in oil and gas production.
Redox species or applied potential
Figure 15. SEM microphotographs of fracture region of slow strain rate test specimens. Left: No dynamic strain, Right: with dynamic strain. Environment: 0.3 molal NaCl, 85Â°C, -100 mV vs. SCE.
In order to assess the long-term performance of materials in oil and gas production systems from short-term laboratory tests, suitable failure acceleration vectors have to be found in Figure 14. The challenge in accelerating the tests is to understand the mechanism of acceleration and relate that to field conditions. Most often, C-ring tests are performed over a prescribed time period (typically 720 hours, but sometimes much longer)
under near yield conditions in an environment that is higher in chloride, lower in pH, and higher in hydrogen sulfide partial pressure than expected in the field. Unfortunately, C-ring testing may not produce dynamic strain that is responsible for stress corrosion cracking (SCC) over a sufficiently long period of time; therefore long test times may not produce any SCC. In the field, periodic dynamic strain can be expected due to pressure, temperature,
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Pitting/ Crevice Critical Potential
Time (Environmental Variables)
E (mV vs. SCE)
Figure 16. Schematic drawing to show the relation of three parameters on controlling the occurrences of localized corrosion and EAC failures.
Figure 17. The effect of applied potential on crack growth rate (CGR) for a CRA in the environment.
or other fluctuations. The effect of dynamic strain on cracking susceptibility is shown in Figure 15.
The validity of this approach can be seen in the effect of controlled potential on crack growth for a CRA, in Figure 17. The crack growth rate measured using a compact tension fracture mechanics specimen in environment shows a clear decrease as the potential is reduced below the critical repassivation or protection potential (Erp or Eprot, respectively) determined independently on an unloaded specimen in the same environment. Other research also demonstrated that SCC of stainless steel 316L in chloride environment only occurs at potential values above the repassivation potential of the steel in the environment.  The ability to model the critical potential of a martensitic stainless steel CRA in a range of environments containing hydrogen sulfide, carbon dioxide, and chloride has been demonstrated. 
What is lacking in all these testing methods is a systematic conceptual framework under which one can understand the acceleration vectors. One conceptual framework for when SCC can occur in CRAâ€™s is to consider three fundamental parameters required to act conjointly to cause cracking: corrosion potential, critical potential and strain rate, as depicted in Figure 16. The corrosion potential is the electrochemical potential the alloy attains under free corroding conditions. It is more positive if there are oxidizing species, such as elemental sulfur and as the protective film on the alloy improves with exposure time. The critical potential is a characteristic of the alloy exposed to an environment and is governed by the concentrations of chloride, hydrogen sulfide, organic species, etc. The strain rate is a function of imposed loading as well as the plastic deformation characteristics of the alloy. For example, high imposed loads, especially above yield and higher temperatures produce greater strain rates as the material creeps. Some alloys work-harden more than others, in which case the strain rate will decrease rapidly with time. These three parameters can be measured and modeled. Therefore, by measuring these parameters for a few combinations of materials and environments, a wider range of material-environment combinations can be modeled.
The ongoing JIP, as discussed briefly in this case study has shown that assessing the longtime performance of advanced CRAâ€™s is possible, that a conceptual framework used to experimentally derive the necessary parameters for modeling has been developed, and that such a modeling framework can be used to develop a rational method for CRA and other advanced materials selection.
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THE FUTURE Although carbon steel will continue to serve the bulk of the oil and gas industry needs well into the future, advanced metallic and non-metallic materials will be needed to enable operations in severe well environments and catalyze new developments in this sector. However, the experience base with advanced materials, even conventional corrosion resistant alloys, is sparse. Many performance issues involving materials quality, oil and gas production environments, long-term evolution and sustainability, etc. need to be resolved. Many of the advanced materials, such as nanocrystalline metallic, BMG and DLC are most likely to be used as coatings and overlays in specialized equipment. It provides a solution for metal to metal seal in high well pressure and severe well environment, which prevents sealing surface damage and improve durability. Nevertheless, their corrosion resistance as well as plastic deformation behavior to production chemicals needs to be examined, which will be considerably influenced
by their chemical composition and manufacturing methods. Their quality, thermal stability, and galvanic interactions with substrate metals will also be a factor. It is recommended that a systematic examination of these promising materials be performed to identify special testing requirements for inclusion in materials selection standards. One of the important barriers for wider deployment of these materials may be the lack of a proper performance assessment approach. A case study involving conventional metallic alloys and the development of a systematic method for testing is presented in this position paper. Although still at a developmental stage, this approach promises to systematize short-term laboratory accelerating tests and long-term performance assessment of these alloys. The conceptual approach will enable the oil and gas industry to better assess the longterm risk of materials as the well ages. Performance assessment is also a challenge for polymer materials which are mainly used for soft seals in the oil and gas
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ASME B&PV Code Initial Manufacturing
Developed since 1980
ASME B&PV Code
1983 Interest in Oil & Gas
Figure 18. A timeline shows brief history of two Ni-Cr-Mo-W type alloys from development to standardization.
industry. The current operation routine of exposed seals is to replace them during refurbishment at intervals and replaced seals are just trashed. The efforts have been tried to apply service history, testing procedure, and performance assessment to improve material qualification and design codes. Eventually, the concept of Integrated Computational Materials Engineering (ICME) that is emerging as a new paradigm for materials integration in the design process  should be adopted in the oil and gas industry. It is a discipline that integrates experimental work, and computational models to accelerate the process and to reduce the cost of developing materials, systems, manufacturing processes, technologies or products. The ICME process has been shown to produce a 3:1 to 9:1 return on investment in the automotive, aerospace, and nuclear industries. Adoption of ICME in the oil and gas production system will encounter many challenges, not the least of which is the severe environmental conditions these materials have to
operate in. Materials performance models combined with microstructural models will be essential enablers of ICME. The current recognized materials, such as C-Mn steels, alloy steels, duplex steels, and a number or CRAâ€™s will continue to serve as the main materials in offshore and subsea applications for many years (>50 years). As illustrated in Figure 18, it usually takes 5 to 10 years for a new alloy from development to commercialization and finally gets in the standards. It is believed that more time is often needed to get full industry acceptance for the warranted conservatism. In our ultimate framework, this time span for introducing new advanced materials or further developing existing materials can be considerably shortened by computer-integrated modeling process, well-established systematic testing methods, and proper long-term performance assessment approaches.
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31 ďťż Advanced Materials in Oil and Gas Production
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1 Advanced Materials in Oil and Gas Production
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DNV GL strategic research & innovation position paper 2-2014