Materials Selection for Deepwater Gate Valves

In years past, the materials used to handle corrosive service in the sea faced mainly the challenges of hydrogen sulfide (H₂S), carbon dioxide (CO₂) and chlorides. With deepwater well drilling, the newer subsea systems being drilled also need to handle chemicals that will minimize paraffin, asphaltene, hydrates and scale formation as well as provide corrosion inhibitions. These chemicals, however, have adverse effects on metallic and non-metallic materials, and the problem is compounded when materials have to handle produced fluids, annular fluids and the injected chemicals. Also, with subsea systems, the effects of hydrogen embrittlement from the cathodic protection system have to be taken into account. For this reason, choosing the materials to be used in gate valves for subsea is especially challenging.

WHAT GOES INTO THE CHOICE

In selection of materials for subsea gate valves, the following must be considered:

Composition of produced fluids in contact with valves and internal parts—all wetted parts
Service temperatures
Operating pressure ranges
Galvanic effects from contact of dissimilar materials
Crevice corrosion at seal and flange faces
Temperature and chemical resistance for non-metallic materials
Cathodic protection (CP) on materials
Effectiveness of coatings on materials
Weldability for weld overlay
Material availability and cost
Compatibility of materials with injected fluids

VALVE BODY MATERIALS

Several organizations provide recommendations for the selection of materials for valves. These include the National Association for Corrosion Engineers (NACE) and American Petroleum Institute (API).

NACE only covers metallic material requirements for resistance to sulfide stress cracking (SCC) for oilfield equipment, which is not intended to include design specification. (Other forms of corrosion and other modes of failure are outside the scope of NACE’s standard and should be considered in design and operation of equipment.) NACE also has requirements for low-alloy materials exposed to sour service. For example, the organization requires that hardness for alloy materials be limited to HRC 22 maximum. Nickel content is limited to 1% maximum, and NACE also has proposed heat treatment such as normalized, normalized and temper, and quench and temper.

API has several standards, such a specification 17D “Specification for Subsea Wellhead and Christmas Tree Equipment,” which uses the material requirements of API 6A.

Specification API 6A covers a number of specific areas for subsea valves, including strength, impact and quality testing. Strength level depends on the pressure rating of the equipment. For example, for flanged end connections, equipment used to pressure levels of 10,000 psi must be manufactured from material having a minimum yield strength of 60,000 psi. Equipment exceeding 10,000 psi pressure must be designed using equipment with specified yield strength of 75,000 psi (refer to API 6A Table 5.2).

Once the fluids that will be produced have been determined, valve selection can occur. Besides the challenges the fluids will produce, as well as the temperatures and pressures involved, the service conditions must also be considered. This includes how long the equipment might be exposed to seawater. Alloy steel will handle most benign conditions, including low CO2 for short periods of time, but even short seawater exposure can cause corrosion of critical components. This is especially true if seawater is trapped in those components and cannot be flushed out in a timely manner. Even with benign conditions, there is need for long-term life—in many cases over 25 years.

Valves as specified using API and NACE standards to handle strength and corrosive requirements can be grouped as follows with typical materials and applicable service conditions:

When environments call for stainless steels such as 410 and F6NM, they may have similar corrosion resistance in oilfield environments; however, they have significant differences in weldability. Stainless 410 in the wrought and welded condition has lower impact toughness than F6NM. Welds of 410 have lower toughness, and depending on the operation, F6NM is often used if there is a risk of Joule Thomson effect (the temperature change of a gas or liquid forced through a valve or porous plug while kept insulated so that no heat is exchanged with the environment) at the wellhead. Even though stainless steels such as 410 and F6NM have good corrosion resistance and can handle mild corrosive conditions, weld overlay of critical sealing surfaces with corrosion-resistant alloy (CRA) is used to minimize pitting.

Duplex Stainless-steel Components

Although duplex stainless steels have good corrosion resistance in most environments, the use of these materials is limited for wellhead equipment because of the danger associated with sigma formation during heat treatment in large section thicknesses. Improper heat treatment not only results in poor corrosion resistance, but also poor toughness property. Duplex stainless steels require a satisfactory balance between ferrite and austenite both in the wrought and welded structures. Super duplex is specified where the Pitting Resistance Index (PRE) exceeds 40, whereas duplex is specified for thin components.

When the environment is severe—exceeding limits of carbon, stainless and duplex materials, several options are available, including using solid nickel-based alloys such as Alloys 925, 718, 725 and others or the use of alloy steel with full weld clad on all wetted areas. The factors to be considered with this option include cost, delivery, manufacturability and adequate corrosion resistance. A summary of uses of material and their benefits/limits is as follows:

Low Alloy (American Iron and Steel Institute [AISI] 4130, AISI 8630, 2¼ Cr – I Mo, ASTM International [ASTM] A694 F60)

Adequate for benign service – low CO₂
Weldable
Critical sealing areas require overlay with CRA material such as Alloy 625
Good toughness
Hardenability depending on alloy and section thickness

Stainless Steel (410 SS, F6NM)

Good corrosion resistance for many applications
Low toughness for 410 SS but high with F6NM
Good hardenability
Critical sealing areas require overlay with CRA

Duplex Stainless Steels

Good corrosion resistance in most production fluids
High resistance to stress corrosion cracking in chloride environment
May exhibit corrosion problems when welded if not solution-annealed properly
Good toughness
Exhibits problems when heat treated in large sections
May exhibit hydrogen embrittlement due to CP

Nickel Alloys (CRA)

Excellent corrosion resistance in all environments
Difficulties in machining
Expensive
Difficult to weld repair in aged condition
Critical sealing surfaces do not require overlay
Nickel is subject to content limits in NACE specifications, though this applies only to low alloy steels.

Each of these alloys has successfully been used for subsea valves, and all have some type of environmental limitation. For subsea valves, three options have been standardized to handle all conditions. This is based on the three environments mentioned initially (H₂S, CO₂ and chlorides). Options are as follows:

Alloy steel with selective cladding on all sealing surfaces using a CRA material such as Alloy 625. This option will handle H₂S with low CO₂. Cladding is used on surfaces to minimize pitting in critical sealing locations from chlorides that may be present in produced fluids.
Stainless steel with selective cladding on all sealing surfaces using a CRA material. This option will handle CO2 with limited H2S, for pitting resistance with chlorides that may be present in produced fluids.
Alloy bodies with cladding on all process wetted surfaces (Figure 4). This option will handle the most severe environments encountered during production. Although this option is the most expensive, it is the most versatile and can be used for water injection in the future to enhance production.

In addition to materials for the valve bodies, special consideration must be given to materials for miscellaneous components or the “jewelry” that is necessary in subsea systems. These components include gates, seats, stems, gaskets and fasteners. Materials for such components include stainless in the 3XX grades, copper alloys, 6Mo and nickel-based alloys such as UNS NO8825, S66286, S21800, NO9925, NO7718, NO7750, R30035, R30003 and titanium.

With miscellaneous materials where the components are small, special consideration must be given in the areas of corrosion and galling. For subsea equipment, all areas of corrosion must be taken into account. This includes pitting corrosion, crevice corrosion and galvanic corrosion.

In using these component alloys, consideration of the following is needed:

Crevice and Pitting Corrosion

Crevice and pitting corrosion are a major concern. Pitting is characterized by attacks that occur at small discrete areas mainly in neutral to acidic solutions containing chlorides. These attacks appear quite minor at the surface, but have a larger cross-section area deeper in the metal. These pits can propagate quickly, leading to perforation.

Pitting can occur in sealing areas such as seat pockets and gaskets. Chloride ions facilitate a local breakdown of the passive layer, especially if there are imperfections in the metal surface. A break in the passive film may be considered as a galvanic cell, in which the bare metal becomes the anode, while the surrounding area with the undamaged passive layer becomes the cathode. This unfavorable anode-to-cathode surface area ratio causes rapid corrosion of the anode. Because of the risk of pitting and crevice corrosion occurring in sealing areas, selective weld overlay is necessary for sealing surfaces when alloy or stainless-steel bodies are used.

Additional tools have been used in selecting alloys for subsea systems. These include:

The use of the pitting resistance equivalent (PRE) number for a stainless steel composition
The critical pitting temperature (CPT)
The critical crevice temperature (CCT)

Where pitting could be an issue, a PRE formula has been developed, commonly expressed as:

PRE = %Cr + 3.3 %Mo + 16 (%N)

Even though PRE expressions are based on accelerated laboratory tests performed on perfectly heat-treated base materials, the formula provides a basis for comparing alloy compositions and thus selecting alloys.

Table 1. Pitting Resistance Equivalent vs. Critical Crevice/Pitting Temperature
Alloy	CCT	CPT	PRE
316SS	0	15	24
Alloy 825	5	30	29
Alloy 625	30 – 35	>85	52
Alloy 725	35	>85	47
254-SMO	35 – 40	70–80	46
25-6Mo		65–70	46
Alloy 59	>85	>85	76
Alloy 686	>85	>85	76

CPT and CCT

A common method of comparing corrosion-resistant stainless steels and alloys is to measure the lowest temperature at which corrosion occurs to determine the CPT and the CCT. Table 1 gives the approximate CCT and CPT temperatures for various stainless materials based on their PREs and shows that the CCT and CPT of stainless steels will increase with their PREs, which is directly related to their alloying content.

For gasket materials, lower strength, pitting and crevice corrosion resistance are issues that require consideration for materials with high PRE. In many cases for subsea application where the ring groove is overlaid with a CRA, the use of UNS N08825 is marginal. The material does not have sufficient corrosion resistance and is susceptible to corrosion if untreated seawater is used. In such applications, higher alloy materials should be considered, such as UNS N06625.

Fasteners

Material choices for subsea bolting are limited. Historically, bolts were manufactured from either ASTM A193 B7 or ASTM A320 L7. In both cases, the materials are identical and within the composition of low alloy AISI 4140-4142. The only difference is the impact requirements where A320 is specified for low temperatures. For subsea applications, several options can be used for the protection of alloy steel. These include the use of coatings for corrosion protection in seawater or the use of a CP. With the use of coatings, intimate contact with the CP system is not so important, providing the flange connections are also low-alloy materials. A properly applied coating that is developed for use in seawater should be adequate. In cases, however, where a coating is not used, it is important the CP is effective over the full length of the bolt. Each bolt must be connected to the CP system.

CHEMICAL TREATMENT AND INJECTION

During operation, all subsea equipment at one time or another comes in contact with injected chemicals. Although the number of materials used for wellhead applications is limited, the number of injected chemicals is numerous. Injected chemicals can include paraffin inhibitors, asphaltene dispersant, asphaltene solvent, scale inhibitors, corrosion inhibitors, biocides and combination products. These chemicals are used to control corrosion, hydrates and wax formation. They all have proprietary additives, which chemical suppliers add as a selling point for their products. The chemicals are sold to an end user for specific applications. This is an area in subsea applications that requires close cooperation between end users, equipment manufacturers and chemical suppliers. In the development of these chemicals, testing should be performed by the chemical supplier to ensure their chemicals will have no adverse effects on the materials with which they may come into contact.

To address the effects of all fluids used in a subsea production system, developing a matrix of the equipment along with possible materials of construction is worthwhile, along with listing the possible chemicals with which the equipment/materials may come in contact. The matrix can list whether or not the materials will be exposed to the chemicals and if these materials are compatible. Each material needs to be evaluated with each chemical it may contact. Table 2 shows how that can work for the tubing head:

Table 2. Fluid Compatibility
Part: Tubing head body Alloy: Alloy steel, stainless or CRA
	Compatible	Exposed
Paraffin inhibitor	No	N/A
Asphaltene dispersant	Flow back	Okay
Scale inhibitor	Yes	Yes
Asphaltene solvent	None	N/A
Hydrate inhibitor	None	N/A
Control fluids	None	N/A
Production fluids	None	N/A
Annulus fluids	Yes	Okay

Such a table is made for each appropriate component. Testing by the chemical supplier can be performed accordingly.

WEAR AND GALLING-RESISTANT COATINGS

Wear and galling are issues for gate valves as well as any other component where materials come in contact with each other. The problem is compounded with subsea gate valves as a majority of the components are fabricated from stainless steel, which are prone to galling. For gates and seats, spray coatings have proven to provide the necessary galling resistance.

Both thermal spray and welded coatings have proven to provide satisfactory results.

Thermal spray coating is a series of processes that apply a consumable in the form of a spray of finely divided molten or semi-molten droplets to produce a coating. The characteristics that distinguish thermal spray processes from weld overlay are as follows:

A mechanical bond occurs between the coating and the substrate.
Spray deposits can be applied in thinner layers than welded coatings.
No degradation occurs on the substrate with thermal spray coatings.

The most common thermal spray process used for coatings on wellhead equipment is that of the high-velocity oxygen fuel (HVOF) process. With HVOF, coatings are projected on the substrate in the semi-molted condition at high velocities—resulting in high hardness, strong bond strength and high durability. Common coatings applied using HVOF include 88WC-12Co, 83WC-17Co. These types of coatings are used for wear, although they are also required to be resistant to corrosive conditions to which they’ll be subjected. HVOF coatings can be applied to any substrate material.

HVOF coatings, although they have strong bond strength, do not have a metallurgical-type bond with the substrate. Thermal spray coatings can have porosity, and thus the substrate should be corrosion resistant as well. In cases where a metallurgical bond is required, other coating processes need to be utilized for the application of wear-resistant type coatings. These processes can include plasma transferred arc and laser.

CONCLUSION

With environments becoming more severe, special attention is needed in choosing materials for subsea applications. This ranges from selecting the best body material to meet the required life of the project to the small details required of cap screws. Selecting the main valve materials often is not an issue because of the extensive history available on subsea equipment. Special attention, however, is required on details. This includes appropriate control in areas of galvanic, pitting and crevice corrosion, as well as hydrogen embrittlement of materials from the CP system. These details must be taken into account to ensure correct selections.

Manuel Maligas is an independent consultant in materials and corrosion for oil and gas, and a fellow of ASME International. He retired after 23 years with FMC technology where he was senior material specialist. Reach him at metengr@sbcglobal.net.

REFERENCES

M. Maligas, E. Hibner, “Highly Corrosion Resistant Weld Overlay for Oil Patch Applications,” Corrosion/94, Paper 62 (Houston, TX: NACE International).
M. Maligas, “Use of Corrosion-Resistant Weld Overlays for High Pressure Applications,” OTC 7521, Offshore Technology Conference 1994.
M. Maligas, J. Vicic, S. Olsen, and P. Nice, ”Material Selection for Wellhead Equipment Exposed to Chlorinated and Natural Seawater,” Corrosion/96, Paper 80 (Houston, TX: NACE International).
G. Byrne, R. Francis, G. Warburton, M. Maligas, “The Selection of Superduplex Stainless Steel for Oilfield Applications,” Corrosion 2004, paper 04123.
M. Maligas, P. Woolin, “Testing of Superduplex Stainless Steel for Sour Service,” Corrosion 2003, paper 03132.