Selecting fluid system components for use in sour oilfields

The conditions under which oil and gas are brought from their reservoirs to the surface can be outright hostile to many common materials used in fluid system components employed in industry. Potentially dangerous mechanisms include localised corrosion, stress corrosion cracking (SCC) and sulphide stress cracking (SSC).

SSC has become increasingly common as more sour reservoirs are being developed - for example, those in the northern part of the Caspian Sea that contain up to 20% hydrogen sulphide (H₂S). Ageing reservoirs can also turn sour as abiotic and biotic reactions take place. This article describes how to select the optimal materials of construction for components that need to perform reliably for many years in the demanding sour environments of oil and gas exploration and production.

Localised corrosion Pitting corrosion or crevice corrosion occurs when the chromium-rich passive oxide film on an alloy surface breaks down in a chloride-rich environment (Figure 1). Higher chloride concentrations, more acidic environments and elevated temperatures all increase the likelihood for breakdown of this passive film. The higher an alloy’s pitting resistance equivalent number (PREN), the higher its resistance to localised corrosion. The most frequently used relationship for calculating PREN is: PREN = %Cr + 3.3(%Mo + 0.5%W) + 16%N where %Cr means percentage of chromium etc.

Figure 1: Cross-section of 316 stainless steel tubing showing deep corrosion pits on the outer surface.

Values of PREN for frequently used alloys with typical compositions are shown in Table 1.

Table 1: Pitting resistance equivalent number (PREN) for frequently used alloys.

Alloy	316	317	2205	2507	254SMO	AL6XN	825	625	C-276
PREN Value	24	29	35	43	43	44	31	51	74

Stress corrosion cracking (SCC)

In the presence of chloride ions, for example in a marine environment, certain alloys are susceptible to SCC, or chloride ion-induced SCC. The chloride ion interacts chemically with the material at the very tip of a crack where tensile stresses are highest, making it easier for the crack to propagate.

This failure mode can destroy a component at stress levels that are below the yield strength of an alloy, and final failure can occur suddenly. For SCC to occur, three conditions must be met simultaneously: the material must be susceptible to SCC; the fluid must be capable of inducing SCC; and a tensile stress must be present that is greater than a critical tensile stress. Some alloys are considerably more prone to SCC than others, with nickel content playing a major role. Austenitic stainless steels like 304 (8-10% nickel) and 316 (10-14% nickel) are particularly susceptible (Figure 2). Carbon steels, nickel base alloys and duplex stainless steels are highly resistant to SCC. Sulphide stress cracking (SSC)

Figure 2: Photomicrograph of chloride-induced stress corrosion cracking in 316 stainless steel (100x magnification).

Raw oil can be contaminated with undesirable compounds. When H₂S and large quantities of carbon dioxide (CO₂) are present, the unrefined fuels are said to contain ‘acid gas’ because these gases form acids when mixed with water. The term ‘sour gas’ is used for unrefined fuels containing H₂S - a very corrosive, toxic and flammable gas.

The requirements for SSC to occur include: a susceptible material; a sufficiently sour fluid (H₂S concentration above a threshold); and a tensile stress above a critical level. An increase in the following parameters can contribute to the rate at which SSC occurs: material properties such as tensile strength and hardness; hydrogen ion concentration in the fluid (pH-value); H₂S partial pressure; total tensile stress (applied and residual); temperature; and exposure time.

On an atomic scale, SSC is a special case of hydrogen embrittlement. When a susceptible metal surface comes into contact with sour gas, the H₂S molecules react to form metal sulphide and hydrogen atoms. The latter diffuse into the material at the tip of the crack at which tensile stresses are highest. Hydrogen diffusion and accumulation in the lattice, on interfaces and on grain boundaries reduce the material’s ability to deform plastically, leading to hydrogen embrittlement that facilitates crack propagation.

In sour environments such as mixtures of oil + seawater + H₂S, SCC and SSC can pose a synergistic threat. Crack propagation caused by the chloride ion interaction with the tensile-loaded crack tip may proceed more readily if the material ahead of the crack tip has been embrittled by atomic hydrogen. The term ‘environmental cracking’ describes the synergistic actions of SCC and SSC.

Selecting materials for resistance to SCC and SSC

‘Petroleum and natural gas industries - Materials for use in H₂S-containing environments in oil and gas production‘ (ISO 15156), an international standard published in 2003, consists of three parts:

• Part 1: General principles for the selection of cracking resistant materials
• Part 2: Cracking-resistant carbon and low alloy steels, and the use of cast irons
• Part 3: Cracking-resistant CRAs (corrosion-resistant alloys) and other alloys

This standard gives requirements and recommendations for selecting and qualifying metallic materials for service in equipment used in oil and gas production and in natural gas-sweetening plants in H₂S-containing environments. It addresses all mechanisms of cracking that can be caused by H₂S, including SSC and SCC, and other forms of hydrogen-induced cracking.

Prequalified materials listed in the standard can be used for the intended service without performing additional laboratory testing. All listed materials with documented microstructural characteristics (such as annealed or strain-hardened) and properties (such as hardness) have performed satisfactorily in field installations or in laboratory tests carried out under defined environmental conditions.

In this standard, alloys are identified by material groups, and within each group, by materials type or as individual alloys. Acceptable metallurgical conditions and environmental limits are given for which alloys are expected to resist cracking. Environmental limits are given for H₂S partial pressure, temperature, chloride concentration, in-situ pH and elemental sulphur. Key points for general and downhole applications are summarised below for the material groups of austenitic stainless steels, highly alloyed austenitic stainless steels, solid solution nickel-based alloys, and duplex stainless steels.

Austenitic stainless steels

Austenitic stainless steels comprise one material group that includes common alloys 304, 316, 317, 321 and 347. In addition, alloys 309, 310, Nitronic 50 and cast alloys such as CF8 and CF8M are part of this material group. Free-machining austenitic stainless steels that have elevated levels of sulphur are specifically excluded.

In terms of environmental limits, a maximum use temperature of 60°C is permitted along with a maximum H₂S partial pressure of 100 kPa with no limit on the maximum chloride concentration. When the maximum chloride concentration is limited to 50 mg/L, the material can be used without restrictions on temperature and H₂S partial pressure.

ISO 15156 provides more detailed guidelines for austenitic stainless steels that are used to produce valve stems, seal rings and gaskets, and as components in compressors or in subsurface applications. Strain-hardened 316 stainless steel may be used in surface applications for compression fittings, instrument tubing and control line tubing without restriction on temperature, H₂S partial pressure, chloride concentration or in-situ pH in production environments. The standard cautions that some combinations of the values of these parameters may not be acceptable.

Highly alloyed austenitic stainless steels

Highly alloyed austenitic stainless steels comprise another materials group. If used for any equipment and components, alloys like 254SMO and AL6XN are permitted in their solution-annealed state. For downhole tubular components, the alloys must have been solution annealed and may be in the cold-worked condition with a maximum hardness of 35 HRC. These alloys may be used in surface applications for compression fittings, instrument tubing and control line tubing without restriction on temperature, H₂S partial pressure, chloride concentration or in-situ pH in production environments.

Solid solution nickel-based alloys

ISO 15156 defines five material types for solid solution nickel-based alloys based on the Cr, Ni, Mo and W content of the alloy and its metallurgical condition, that is, solution annealed or cold worked. Commonly used alloys 825, 625 and C-276 can be used in the solution-annealed or annealed condition for any equipment or component at any combination of temperature, H₂S partial pressure, chloride concentration and in-situ pH occurring in production environments. For downhole tubular components, cold-worked alloys 825, 625 and C-276 can be used if their hardness does not exceed 40 HRC and their yield strength is not above specific limits. Alloy C-276 can be used at higher temperatures and H₂S partial pressures than alloy 625, which in turn is qualified for higher operating conditions than alloy 825.

Duplex stainless steels Duplex stainless steels are divided into material types with lower PREN between 30 and 40 and higher PREN above 40 to 45. If used for any equipment, the alloys must be in the solution-annealed and liquid-quenched state, and have a ferrite content between 35 and 65%. Maximum use temperature is 232°C for both material types. Maximum H2S partial pressure is 10 kPa for alloys with PREN between 30 and 40, and 20 kPa for alloys with PREN above 40. If used as downhole tubular components, the materials can be in strain-hardened condition with a maximum hardness of 36 HRC. The lower PREN alloys can only be used up to a maximum H2S partial pressure of 2 kPa, and the ones with PREN above 40 up to 20 kPa and a maximum chloride concentration of 120,000 mg/L. Manufacture of fluid system components Producing fluid system components that comply with all aspects of ISO 15156 requires the use of high-quality raw materials, careful testing and prudent choice of manufacturing methods.

Figure 3: Examples of process interface valves and instrumentation manifolds for sour gas service available in alloys 326, 245SMO, 825, 625, 2205 and 2507.

Alloys must have gone through a controlled solution annealing process and their microstructural quality must be assessed with tests such as ASTM A262, which probes austenitic stainless steels for intergranular corrosion, or ASTM A923, which qualifies duplex stainless steels for absence of detrimental intermetallic phases. Austenitic stainless steels should be free of martensite and contain ideally no, or at most 2%, ferrite because these phases are more susceptible to hydrogen embrittlement than austenite.

A sufficient number of hardness measurements must be performed and an average hardness value calculated that must not exceed the respective allowed maximum value. No individual hardness reading is allowed that is greater than 2 units on the Rockwell C hardness scale above the allowed maximum hardness. When components are welded, care must be taken to perform hardness measurements on the welds following the procedures described in ISO 15156. Where solution-annealed materials are required, any cold drawing of bar or cold rolling of plate must be avoided. Cold deformation of surfaces is acceptable only if it is caused by processes such as burnishing that do not impart more cold work than typical machining operations. Identification stamping with low-stress stamps is acceptable, but sharp V-stamping should not be performed in high-stress areas.

Figure 4: Tube fittings and instrumentation valves for sour gas service made from alloys 825, 625 and 2507.

Conclusion

Choices surrounding material selection and manufacturing of fluid system components for service in sour gas environments are complex. End users must define the prevailing sour gas service conditions, including those of steady-state processes and of potentially unintended exposures. Beyond material properties, several factors affect the susceptibility of a material to cracking in sour fluids: H₂S partial pressure, in-situ pH, chloride concentration, presence of elemental sulphur, temperature, galvanic effects, mechanical stress and time in contact with an aqueous solution. End users should understand ISO 15156 requirements to select the optimal material of construction of a fluid system component.

When a customer orders a specific valve, fitting or other fluid system component for sour gas service, the manufacturer should perform a product review in which all wetted parts are evaluated against standard requirements; for example, for type of material, manufacturing processes and maximum hardness. Such a review ensures the products selected for sour gas service meet ISO 15156 requirements, as well as the customer’s requirement for durability, excellent performance and reliable service.

*Gerhard Schiroky received his PhD in Materials Science and Engineering from the University of Utah. He has authored numerous technical publications on diverse topics, including fluid dynamics and materials science, and is named on over 20 patents.

By Gerhard Schiroky, Senior Scientist, Swagelok Company