1 Introduction to subsea production system

The offshore oil and gas industry began in 1947 when Kerr-McGee completed the first “out of the land” well successfully in the Gulf of Mexico off the coast of Louisiana in just 4.6 m of water (Bai and Bai (2012); Burleson 1999). Offshore exploration and production technology have been gradually expanded in the decades since, and the venture for finding oil has moved to deep water areas (MODEC 2019). Platforms or ships classified as floating production, storage, and offloading (FPSO) ships have been used for development and production of offshore fields in the water (Sotoodeh 2019a).

A subsea production system contains subsea completed wells, subsea wellheads, production trees, and subsea manifolds, as well as equipment and control facilities for well operation (Bai and Bai 2012; Sotoodeh 2019a). Completed wells are those which have been drilled and are ready for production. The pressure-containing components at the surface of oil and gas wells, collectively called the well head, provide an interface for drilling, completion, and testing of the wells (Sotoodeh 2019a). The surface pressure control of the well head is done during assembly of the valves, pipe, and fitting commonly called a “Christmas Tree” (Sotoodeh 2019a).

Subsea manifolds are used to simplify the subsea system by minimizing the usage of a subsea pipeline and risers as well as optimizing the fluid flow (Bai and Bai 2012; Sotoodeh 2019a). Manifolds are the arrangement of piping, valves, actuators, and fittings designed to integrate, distribute, and control the flow of the fluid (Bai and Bai 2012; Sotoodeh 2019a). Manifolds are installed on the subsea bed to gather production from different wells or inject water or gas into the wells for advanced oil recovery (Bai and Bai 2012; Sotoodeh 2019a).

Figure 1 shows a subsea production system including a manifold and a Christmas trees. The manifold collects the produced oil and gas, for example from Christmas trees, and integrates them into the flowline. The well flow line, commonly called simply “flow line,” is the next part of a pipeline system after the well head. The subsea valves are not only located on the subsea manifolds and Christmas trees. Subsea distribution units (SDUs) distribute hydraulic supplies, electrical power, and chemicals to the subsea facilities (Bai and Bai 2012) including the manifolds, which contain many small-sized valves. SDUs connect to the termination of the subsea umbilical, which is the main component for power and signal transmission between topside and subsea (Bai and Bai 2012).

Fig. 1
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Subsea production system (Courtesy: Springer)

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2 Types of subsea valves

Through conduit gate (TCG) valves, which can be slab (see Fig. 2) or expanding gate, are very commonly used for subsea manifolds and Christmas trees (Bai and Bai 2012; Sotoodeh 2019a; Praveen et al. 2018).

Fig. 2
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Slab gate valve

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A slab gate valve, shown in Fig. 2, is welded to the pipe through pup pieces at both ends of the valves. Slab gate valves are used for on/off purposes and should not be used for fluid control or throttling. Using gate valve for flow control leads to vibration as well as wearing of the valve internals. The body, bonnet, and stem of slab gate valves, as well as other valve types, are pressure-containing parts, meaning that failure of these parts can lead to leakage of the fluid to the sea (American Petroleum Institute (API 6DSS 2017). The stem, which transfers the force or torque (force × distance) of the valve operator to the disk and valve internals should be made of materials with high mechanical strength (this will be explained later in more detail).

The body and bonnet of the subsea valves are in continuous contact with sea water, so the external parts of the valves including body and bonnet are protected by coating as well as cathodic protection. The disk of the gate valve has a hole on the top that acts as the port of the valve. The disk of the slab gate valve with a hole on the top is called reverse port which is applicable for fail safe closed actuated valves. Fail safe closed mode of actuator operation refers to a condition in which the actuator and the valve are getting closed in case of losing hydraulic supply fluid. When the stem of the reverse port valve with fail safe closed actuator moves downward as a result of operator (actuator) force, the port of the disk is completely aligned with the pup piece and the piping diameter, so it allows fluid passage (open position). On the other hand, when the stem moves upward, the solid part of the disk will slide in front of the fluid and stop the flow. The body and bonnet of the valves are bolted together.

Cathodic protection is a technique which is used for subsea equipment including piping and valves to protect them from external corrosion due to sea water. Sea water is very corrosive media or environment which can create different types of corrosion such as pitting. Corrosion in general means losing an electron so in cathodic protection a less Nobel metal is used as an anode which is corroded and the electron is transferred to protected valve or piping which plays the role of cathode. Coating is another way of subsea equipment protection against corrosion which involves in applying a layer or multiple layers of painting on the external surface of subsea equipment such as piping and valves.

Ball valves (see Fig. 3) are used widely in subsea for stopping and starting fluid flow. The closure member in the valve is a ball with a hole inside it, rather than a disk in a gate valve, which rotates 90° (quarter turn) for opening and closing. When the ball bore is aligned with the fluid passage, the valve is open. Turning the ball 90° turns off the flow.

Fig. 3
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Ball valve

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Axial check valves (see Fig. 4) are another type of subsea valves used mainly on chemical injection lines. Fluid problems in deep water such as hydrate formation, condensate, and wax are critical issues (Bai and Bai 2012). Thus, chemicals such as corrosion indicators, hydrate inhibitors, scale inhibitors (Bai and Bai 2012), etc., are used in the offshore sector of the oil and gas industry to assure production efficiency (Bai and Bai 2012). Hydrates are substances containing water that can be made in gas services at cold temperature. Methanol is one of the most common chemical inhibitors used to prevent hydrate formation. A check valve (e.g., axial check) is installed on the chemical injection line to be opened by the pressure of the chemicals, which prevents the process fluid from backing up into the chemical line (Sotoodeh 2015). The flow enters the valve from the right side in Fig. 4, overcomes the spring force, pushes the disk off the seat, and passes through the venturi (narrow) area of the valve. The valve will be closed when the fluid flow stops, and the spring pushes the disk back onto the seat.

Fig. 4
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Axial check valve (Courtesy: Valve world)

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3 Material selection

Material corrosion is a significant risk and a costly phenomenon in the offshore sector of the oil and gas industry, including subsea. Corrosion can have severe negative consequences including loss of assets, loss of production due to plant shut down, and loss of human life, as well as health, safety and environmental (HSE) problems such as environmental pollution. The subsea environment includes a chloride-containing marine atmosphere that can cause severe corrosion of piping and valve facilities. Material selection is a critical part of engineering design in order to choose the best material option for products such as piping and valves that will satisfy the design life of the product and prevent material failure due to corrosion, loads, erosion, etc. The complexity of the material selection is increased by several technical parameters and considerations such as corrosion, erosion, weight, mechanical strength, and cost.

Different parameters should be considered for material selection of subsea valves (Maligas 2011).

  • Fluid service in the valve, including corrosive compounds like \({\mathrm{CO}}_{2}\) and \({\mathrm{H}}_{2}\)S;

  • Service fluid pressure and temperature;

  • Galvanic corrosion due to the contact of two different metals with different electrical potential;

  • Crevice corrosion in the grooves (sealing areas) of non-corrosion-resistant materials such as carbon steel;

  • Overlay welding (partially or fully) of corrosion-resistant alloys (CRAs) on carbon and low alloy steels;

  • Material availability and cost;

  • Non-metallic sealing materials and their compatibility with operating temperatures and chemical fluids;

  • Design life of the plant as well as the valve;

  • Coating and cathodic protection for external protection of materials and

  • Compatibility of the materials with injection fluids

Chart 1 shows the major aspects of the material selection or key parameters in the material selection for piping and valves in the subsea and offshore industry.

Chart 1
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Key factors in valve material selection in offshore

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4 Body and bonnet material selection

The material selection for valves usually begins with the body or body and bonnet. Some valves such as axial check valves have only a body but gate valves have both body and bonnet. Body and bonnet are made from the same materials in almost all cases. Solid carbon and alloy steels such as ASTM A 350 LF2 (low temperature carbon steel) or ASTM A181 F22 (2.25% chromium and 1% molybdenum low alloy steel) are suitable and economical choices for large bore valves above 2″ size in non-corrosive chemical services such as methanol and MEG (mono-ethylene glycol).

The advantage of using low alloy steel in F22 is to reduce the thickness and weight of the valve body and bonnet as well as the total weight, compared to carbon steel. It should be noted that a CRA material such as Inconel 625 should be overlaid on the carbon steel body and bonnet grooves’ sealing areas to prevent crevice corrosion. Crevice corrosion refers to the local attack on the metal surface due to a gap or crevice. Crevice corrosion can happen on the valves’ sealing areas, seat pockets, etc. Figure 5 shows the body of a subsea ball valve in ASTM A694 F60 (low alloy steel material), and the grooves in the internal section of the valve body are overlaid with Inconel 625 (partially cladded).

Fig. 5
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Subsea ball valve body

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Although solid Inconel 625 maybe selected for the body of valves, a more economical choice is to use carbon or low alloy steel body valves with fully Inconel 625 overlay in 3 mm, for example. Depositing a thick layer of Inconel 625 (UNS N06225) on carbon or alloy steel substrate provides a good resistance against different types of corrosion for the body and bonnet of the valves used in production lines (oil and gas services). It is more economical to use 25 chromium super duplex body and bonnet valves rather than carbon steel with partially or fully cladded Inconel 625 for valves that are 3″ or smaller based on an end user experience.

Martensitic stainless steel, which is 13% chromium and 4% nickel, provides high mechanical strength and higher general corrosion resistance compared to carbon and alloy steels. This material is not selected for body and bonnet of the subsea valves but it might be used for the valve stem, which is a pressure-containing part.

Additionally, austenitic stainless steel (SS) such as grade 316 is not generally suitable for subsea valves. The main weak point of austenitic stainless steel is corrosion against chloride, which does exist in the offshore environment. It should be noted that even SS316—which has higher resistance to chloride compared to other grades such as SS304, SS321 and SS347—is at a high risk of pitting and chloride stress cracking corrosion in a marine environment.

Pitting corrosion is a form of localized corrosion that produces attacks in the form of spots or pits (Perry 1999). Chloride stress cracking corrosion (CLSCC) is a type of environmental cracking corrosion caused by the simultaneous action of chloride in the environment, tensile stress in the material, and susceptible material (Perry 1999; Jepsen and Grumsen 2014). Figure 6 shows a CLSCC of a 316 austenitic stainless-steel bolting in offshore environment. The same type of corrosion can occur for body and bonnet of the valves in stainless steel 316 material.

Fig. 6
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CLSCC of austenitic bolting in offshore (Courtesy: Valve World magazine)

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Because of their relatively high mechanical strength and corrosion resistance, 22 chromium duplex and 25 chromium super duplex are suitable materials for the body and bonnet of subsea valves. These two materials are categorized as ferrite-austenitic stainless steels. 25Cr super duplex provides better corrosion resistance and higher mechanical strength compared to 22Cr duplex. In fact, super duplex is a high alloy duplex stainless steel with a pitting resistance equivalent number (PREN) higher than 40. PREN is a predictive measurement of a stainless-steel resistance to localized pitting corrosion based on the chemical composition (National Association of Corrosion Engineers (NACE) MR0103 2007) PREN is calculated using Eq. 1:

$${\text{PREN }} = {\text{ Chromium }} + { 3}.{\text{3 Molybdenum }} + {\text{ 16 Nitrogen}}.$$
(1)

A higher PREN value indicates more resistance to localized corrosion types such as pitting and chloride stress cracking corrosion (National Association of Corrosion Engineers (NACE) MR0103 2007) Duplex and super duplex have limited resistance against \({\mathrm{H}}_{2}\)S (refer to ISO 15156/NACE MR0175) (National Association of Corrosion Engineers (NACE) MR0103 2007) and cannot withstand more than 1.5 psi and 3 psi \({\mathrm{H}}_{2}\)S partial pressure, respectively (International Organization for Standardization (ISO) 2001) Alternatively, Inconel 625 as a solid for small size valves (2″ or 3″ valves and smaller) or overlay on carbon/alloy steel is a good choice for the valves’ body and bonnet in \({\mathrm{H}}_{2}\)S sour services. 25Cr super duplex is subject to hydrogen-induced stress cracking (HISC) in a subsea environment. HISC occurrence requires three parameters of tensile stress in material, susceptible microstructure, and hydrogen source (Solnordal et al. 2009) (see Fig. 7). Subsea metallic components could be connected to a cathodic protection system to prevent corrosion. The source of hydrogen is related to a cathodic protection system in which atomic hydrogen can diffuse into susceptible material such as duplex, super duplex, or nickel alloy 725 and 718 (Solnordal et al. 2009).

Fig. 7
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HISC affecting parameters (Courtesy: Det Norske Veritas)

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To mitigate the risk of HISC occurrence for duplex and super duplex materials, DNV recommends the guidelines offered in standard DNV-RP-F112 (Solnordal et al. 2009).

6MO (Molybdenum) is a super austenitic stainless steel with a high level of molybdenum (6%) and nitrogen that provides high resistance to pitting and crevice corrosion as well as higher strength compared to conventional austenitic stainless steel such as 316 (Solnordal et al. 2009). 6MO is a common valve body material in the Norwegian offshore industry in topside sector for flare lines in which the operating temperature can be less than − 46 °C. Gas flaring is a combustion device to burn associated undesired and extra hydrocarbons in the form of liquid or gas in many industrial operations, including oil and gas. The pressure of gas service in the flare line is reduced, which leads to temperature reduction. As per Gay-Lussac’s law, the pressure of a given amount of gas held at constant volume is directly proportional to the Kelvin temperature. As the pressure goes down, the temperature goes down, and vice versa. 22Cr duplex and 25Cr super duplex are very common materials for piping and valves in process fluids such as hydrocarbon liquids and gas in the topside sector. However, both duplex and super duplex materials are proposed for a minimum temperature of − 46 °C according to American Society of Mechanical Engineers (ASME B31.3), process piping code, so they are not suitable for a flare line in most cases.

Inconel 625 or alloy 625 as a weld overlay or solid is a very common nickel alloy material for the body and bonnet of subsea valves with high amount of \({\mathrm{H}}_{2}\mathrm{S}\) where other options such as carbon and low alloy steel, as well as ferritic-austenitic materials such as duplex, are not suitable. Alloy 625 has approximately 65% nickel, 22% chromium, 9% molybdenum and 4% niobium (NORSOK M-001 2004). In general, Inconel 625 is a nickel-based super alloy with high strength properties and resistance to corrosion including \({\mathrm{H}}_{2}\mathrm{S}\) and \({\mathrm{CO}}_{2}\) and elevated temperature. The more expensive nickel alloy for the body of valves is Inconel 725, which is a nickel–chromium-molybdenum-niobium alloy with high corrosion resistance and age-hardening heat treatment for achieving high mechanical strength. Therefore, although Inconel 725 has almost the same corrosion resistance as Inconel 625, it has much higher corrosion resistance. Age-hardening, heat-treated nickel alloys including Inconel 725 are susceptible to HISC corrosion. Other types of nickel alloys such as Inconel 718, X750 and Hastelloy are not practical and not commonly used for subsea valves’ bodies and bonnets.

5 Stem material selection

The stem material should have high mechanical strength, especially in case of actuation. An actuator is a component installed on the top of industrial valves for automatically moving and controlling the valve (Sotoodeh 2020). 17–4 PH or 13Cr-4Ni martensitic stainless-steel stem materials are very commonly used for carbon steel body valves in onshore units such as refineries and petrochemical plants. However, the usage of 17–4 PH steel material should be prohibited in the offshore sector of the oil and gas industry due to the risk of chloride stress cracking corrosion. 17–4 PH with UNS S17400 is a martensitic precipitation-hardened stainless steel that contains approximately 17% chromium, 4% nickel, and 4% copper. The sensitivity and corrosion resistance of 13Cr-4Ni to chloride stress cracking corrosion is much less than 17-4PH probably due to lower hardness value of 13Cr-4Ni compared to 17-4PH. This is the reason why 13Cr-4Ni is used for topside valves in an offshore environment rather than 17-4PH. However, where the usage of 13Cr-4Ni stem materials is prohibited in a subsea environment, super duplex, Inconel 718, and 725 may be selected instead for subsea application. It should be noted that there is a high risk of HISC associated with super duplex and Inconel 725 stem materials, so it is recommended to apply HISC analysis on them according to DNV-RP-F112 “Duplex stainless steel—design against hydrogen induced stress cracking” (Sotoodeh 2019b). The DNV standard does not cover Inconel 718 and 725 materials (Sotoodeh 2019b) so a separate guideline should be prepared to address HISC prevention for hard nickel alloys. It should be noted that 13Cr-4Ni is the preferred choice of material over 13Cr since it has superior toughness that improves the resistance of material in low temperature, which reduces the risk of being cracked due to corrosion attacks such as chloride and hydrogen sulphide. 25Cr super duplex is a high mechanical strength material almost the same as 13Cr-4Ni martensitic stainless steel. This stem material may be used for the valves in carbon steel and low alloy steel, 22Cr duplex, and 25Cr super duplex body materials. However, if the strength of 25Cr super duplex is not enough as a result of valve actuation and higher torque requirements, high strength nickel alloys such as Inconel 718 and 725 can be used, as explained later in this article.

Inconel 625 could be a stem material for Inconel 625 body valves where a high force or torque (force x distance) is not applied to the valve stem from the operator. The valve operator could be either manual or actuated (automatic). Generally, actuators provide higher force/torque than manual operators, as mentioned earlier in this paper. Inconel 625 stem can be upgraded to higher strength nickel alloys such as Inconel 718 and 725. Inconel 718 stem material may be rejected in some cases for subsea valves due to its relatively low resistance against pitting and chloride stress cracking corrosion types.

Inconel 718 is a high-strength material with relatively high corrosion-resistant nickel chromium alloy (Sotoodeh 2019c). This material is composed of approximately 52.5% nickel, 20% chromium and 3% molybdenum. Fabrication and welding of this alloy is easy, and it has good resistance to fatigue (Sotoodeh 2019c). Two common heat treatments for this alloy are solution anneal and age hardening. When it comes to corrosion resistance, this material is not good at sea water services compared to Inconel 625 and Inconel 725. Thus, some end users may avoid using Inconel 718 in contact with sea water. Inconel 725 is a nickel–chromium-molybdenum-niobium alloy that is highly resistant to corrosion and the heat treatment is age-hardening for high strength (Special Metals Corporation 2005). Thus, it can be concluded that the properties of Inconel 725 are very useful for applications of high mechanical strength and corrosion resistance. This material can resist many types of corrosion including crevice, pitting, sweet, and sour corrosion, which are associated with \({\mathrm{CO}}_{2}\) and \({\mathrm{H}}_{2}\) S, respectively. Inconel 725 has similar corrosion resistance to Inconel 625, but it has the advantage of having a higher mechanical strength compared to Inconel 625.

6 Trim material selection

The removable and replaceable valve internal parts that are in contact with fluid are collectively referred to as “trim.” The most important trim materials are seats and closure members of the valves. A closure member is the component in contact with the fluid that enables opening and closing of the valve. In a ball valve, the closure member is the ball; in both gate and axial flow check valves, the closure member is a disk. The main guideline for trim material selection is that the material chosen should have the same corrosion resistance as the body and bonnet material as a minimum (American Petroleum Institute (API) 600 2015; American Petroleum Institute (API) 602 2015)

As an example, the minimum trim material for a valve body in 25Cr super duplex stainless steel would be 25Cr super duplex. This means that selecting 22Cr duplex trim for 25Cr super duplex body/bonnet valve would not be acceptable and would be in conflict with valve standards. 22Cr duplex with 22% chromium has less chromium compared to 25Cr super duplex which contains 25% chromium. Generally, less chromium in a stainless steel means less corrosion resistance. In addition, a higher amount of molybdenum in 25Cr super duplex increases the resistance of this material against pitting and chloride stress cracking corrosion (National Association of Corrosion Engineers (NACE) MR0103 2007; International Organization for Standardization (ISO) 15156 2001). As outlined in ISO 15,156 and NACE MR 0103, super duplex has a higher corrosion resistance than 22Cr duplex in an environment containing \({\mathrm{H}}_{2}\mathrm{S}\) (National Association of Corrosion Engineers (NACE) MR0103 2007; International Organization for Standardization (ISO) 15156 2001).

Valve internals could be in contact with sea water, and 13Cr-4Ni is at a high risk of chloride stress cracking corrosion. Thus, usage of this material should be prohibited for subsea valve internals and stems. Austenitic stainless-steel materials such as SS316 are not common for subsea valve internals for the same reason, as they are not used for body and bonnets, which have a high risk of chloride stress cracking corrosion. Super duplex seats and closure member materials are very common for super duplex body valves. HISC analysis based on DNV requirements should be applied by valve suppliers for this type of material. Seats and closure members of the valves are usually not pressure-containing parts, so it is not really necessary to use hard and high mechanical strength nickel alloys such as Inconel 718 and 725 for internals. However, Inconel 625 is a very common trim material for the valves manufactured in Inconel 625 for the body and bonnet.

7 Bolting materials

Bolting material requirements are outlined according to API 20E specifications for carbon and alloy steel bolting, and API 20F specifications for CRA bolting (American Petroleum Institute (API) 2015; American Petroleum Institute (API) SPEC 20E 2017). All carbon steel and low alloy steel bolt and nuts such as ASTM A193 B7/B7M/L7/LM bolts and ASTM A194 Gr.4 or 7 nuts should be externally coated with electro-deposited zinc plate or zinc-nickel plate. The hardness level of the bolting material should be controlled based on NACE MR 0175 if the bolts will be used for sour service fluid. Super duplex is a common CRA bolting that can be used under the insulation to mitigate the risk of corrosion under insulation (CUI). Corrosion under insulation is a severe form of localized corrosion that happens to carbon and low alloy steel materials. This form of corrosion occurs when water is collected and accumulated under the insulation.

8 Pup piece materials

The valve pup pieces are located on both ends of the valves, and they are welded to the connected piping in the fabrication yard. The best choice for pup piece material is to select the same material used for the connected piping material. Having the valve pup piece material the same as the piping material facilitates the welding between similar materials and mitigates the challenges associated with welding between dissimilar materials. For example, valve pup pieces may have pup pieces in carbon steel, super duplex, and Inconel 625.

9 Spring materials

Inconel X750 is a nickel–chromium superalloy that is heat treated through precipitation hardening by adding aluminium and titanium. This material can withstand many cycles and is very popular for use in valve springs. In subsea valves, springs are used to provide sealing of the valve by pushing the disk to the seat in an axial check valve, or pushing the ball to the seat in a ball valve. Inconel X750 may be rejected for subsea valves due to its low corrosion resistance in sea water and the associated risk of pitting. Thus, alternative materials such as Elgiloy (cobalt alloy) or Inconel 625 may be proposed for use in a valve spring. More precisely, Elgiloy is a cobalt, chromium and nickel alloy containing approximately 40% cobalt, 20% nickel, 15% nickel, 7% molybdenum and the rest are iron and manganese. This material is used for springs because of its resistance to corrosion and fatigue, as well as its high strength.

10 Hardfacing materials

Hardfacing is a method for improving the wear resistance of a metal through depositing hard-facing alloys such as Stellite, tungsten carbide, or Ultimet on a core material (Nesbitt 2007; Sotoodeh 2019d). Hardfacing involves different processes such as weld overlay, spraying, or lasering to mitigate the risk of erosion, galling, and cavitation (Sotoodeh 2019d). Wearing during the operation is common when metallic parts like valves’ closure members and seats are contacting and moving. This wearing can be intensified when the fluid service contains particles and corrosive (Smith and Zappe 2003). Therefore, it can be concluded that valve internals such as seats and closure members are more prone to corrosion as well as erosion, wearing, and galling (Smith and Zappe 2003; American Petroleum Institute (API) 2014). Thus, the closure member and seats are usually hardfaced with the following materials:

  • Stellite 6 UNS R30006 (Cobalt alloy) is the most common hardfacing alloy used in the valve industry due to its outstanding hardness. The weak point of Stellite is that it should not be used in sea water services.

  • Ultimet (UNS R31233) is another cobalt alloy with very high wearing resistance that is suitable for sea water services. Ultimet contains other compounds like chromium, nickel, molybdenum, iron, and tungsten. Enough adhesion of Ultimet to the core material could be a challenge based on an end user experience (Sotoodeh 2019d).

  • Tribally, which is another nickel and cobalt alloy, is an alternative to Ultimet for hardfacing the materials used in sea water services.

  • Tungsten Carbide (TC) with chemical formulas of WC contains tungsten and carbon atoms. This type of hardfacing is applied through thermal spray coating and very common type of coating on the ball and seat contact surfaces of ball valves. Different thicknesses for TC overlay such as 150 micron or 300 microns maximum can be applied on the core materials.

11 Conclusion and recommendations

This article focused on material selection for subsea valves mainly located on manifolds and Christmas trees. Different parts of the valves such as body/bonnet, stem, internals (seats and closure members), pup pieces, bolting, and springs have been included in this discussion for suitable material selection to prevent failure and increase the reliability. Table 1 summarizes the proposed materials plus their advantages and disadvantages.

Table 1 Subsea valves material selection summery table
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