Introduction

A valve is a mechanical component in a piping system that is used for safety purposes, and/to open and close the fluid passage, prevent the return of fluid and control flow [1,2,3]. Valve failure is a big risk and a costly phenomenon in the offshore sector of the oil and gas industry with severe negative consequences such as loss of asset, loss of production due to plant shutdown, health, safety and environmental (HSE) issues such as hydrocarbon (oil and gas) spillage, environmental pollution and loss of human life. Different types of valve failure have occurred in the Norwegian offshore industry for various reasons, such as poor material selection and corrosion, mechanical failure of valve components due to high stresses and loads and lack of coating, lack of inspection. [4]. The aim of this paper is to review and critique some of the wrong material selection approaches for industrial valves in the offshore sector of the oil and gas industry that lead to corrosion and valve failure, and to provide an appropriate material selection solution to mitigate these failures. The term offshore means “off the coast”; it refers to the development of oil and natural gas fields under the sea or ocean [5]. Material selection failures were selected for this paper because material selection is an essential engineering task in both the design and failure analysis of the components [6]. In addition, materials in the offshore industry are exposed to severe internal and external corrosion. The offshore environment is very corrosive due to the presence of seawater and the chloride-containing environment [7]. Untreated oil coming into the offshore facilities from the well contains high amounts of undesirable by-products such as \( {\text{CO}}_{2} \) and \( {\text{H}}_{2} {\text{S}} \) [7, 8]. Thus, the paper will highlight the essence of material selection in terms of failure analysis and prevention. This review does not cover valve failures due to mechanical loads or lack of inspection; future research is proposed for the analysis and prevention of these types of failures.

A Review of Corrosion Failure Types

External Corrosion Threats

External corrosion mechanisms are largely dictated by the environment in which the asset or valve is installed [9]. The offshore environment is corrosive, containing chloride due to the presence of seawater which can cause different types of corrosion such as pitting and chloride stress cracking corrosion (CLSCC) [10]. As the name implies, pitting is localized corrosion that leads to the development of cavities or pits on metal surfaces [11, 12]. Figure 1a illustrates pitting corrosion in the form of holes on piping. CLSCC is another type of corrosion that is caused and accelerated by applied or residual stress in the material illustrated in Fig. 1b [11, 12]. Stresses that are introduced during fabrication due to welding and fast cooling, and stresses induced by tightening of bolts and rivets are categorized as residual stress [12]. CLSCC occurrence depends on three parameters: susceptible material such as stainless steel 304, a corrosive environment (such as the offshore atmosphere) and stress illustrated in Fig. 2. One should bear in mind that higher temperatures accelerate and exacerbate the effects of CLSCC; austenitic stainless steel and 22Cr duplex are not recommended for use at temperatures above 60°C and 100°C, respectively, in the offshore industry [13, 14]. The most common ways to prevent CLSCC and pitting corrosion are to select suitable material and to use coating [15]. Valves, piping and structures installed in the subsea environment are at high risk of external corrosion like pitting and CLSCC due to the corrosive seawater atmosphere [16, 17].

Fig. 1
figure 1

A Piping pitting corrosion (Courtesy: Nu flow Midwest). B Valve bolt CLSCC (Courtesy: Valve World)

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Fig. 2
figure 2

Effective factors for CLSCC occurrence (Courtesy: Swagelok)

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Cathodic protection is a technique used to protect the metallic surface of subsea components and structures. Anodes in zinc, magnesium, or aluminum are used as sacrificial metals to be corroded and produce electrons for the protected component (e.g., piping, valve or structure). Figure 3 illustrates the cathodic protection of a piece of piping through a sacrificial anode in zinc. The chemical reactions in the anode and cathode are given in Formulas 1 and 2, respectively:

Fig. 3
figure 3

Subsea piping cathodic protection (Courtesy: Subsea Pipeline)

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Formula 1

Chemical reactions in the anode

$$ {\text{Zn}} \to {\text{Zn}}^{2 + } + 2{\text{e}}^{ - {[16]}} $$

Formula 2

Chemical reactions in the cathode

$$ 1/2{\text{O}}_{2} + {\text{H}}_{2} {\text{O}} + 2{\text{e}}^{ - } \to 2 {\text{OH}}^{ - {[16]}} $$

Extra electrons released from the anode are transferred to the cathode and react with oxygen and water according to Formula 2. Releasing \( {\text{OH}}^{ - } \) increases the pH of the seawater due to its alkalinity behavior. Fundamentally, cathodic protection acts against corrosion as metal loses electrons in corrosion and cathodic protection has an “electron give back process” [18]. The other interpretation of the cathodic protection process around the cathode is that \( {\text{OH}}^{ - } \) forms a protective layer of \( {\text{CaCo}}_{3} \) with calcium in the seawater. The negative effect of cathodic protection occurs when an excessive number of electrons are released from the anode. In that case, the extra electron(s) can generate hydrogen close to the anode due to reactions with water that cause hydrogen-induced stress cracking (HISC) corrosion for subsea components such as valves [19]. HISC mitigation strategies will be explained later in this article.

Internal Corrosion Threats

Untreated oil delivered to the offshore facilities from the well can contain a high number of undesirable by-products such as \( {\text{CO}}_{2} \) and \( {\text{H}}_{2} {\text{S}} \) [7, 8]. \( {\text{CO}}_{2} \) corrosion, also known as sweet corrosion, causes metal loss in non-exotic materials such as carbon steel, so adding extra thickness to the piping and valves—a practice called “corrosion allowance”—is proposed for carbon and low alloy steels [8]. A standard amount of 3 mm corrosion allowance is proposed to be added to piping and valves in carbon steel material according to Norsok, the Norwegian petroleum standard [8, 13, 14, 20]. Adding more corrosion allowance such as 6 mm is not proposed since it makes the piping and valves thicker and heavier. The alternative solution is to use corrosion-resistant alloys (CRAs) such as 22Cr duplex instead of carbon steel. This practice is common in the Norwegian offshore industry [8, 20, 21]. Many different models and software may be used to calculate the \( {\text{CO}}_{2} \) corrosion rate, all of which are based on the “Dewaard and Milliams” model [8, 22]. Additionally, the Iranian petroleum standard (IPS) [23] as well as Norsok standard M-506 [24] provide a calculative model for \( {\text{CO}}_{2} \) corrosion prediction.

\( {\text{H}}_{2} {\text{S}} \) is the most dangerous compound in the oil and gas industry since it is both toxic and corrosive. Even a small concentration of \( {\text{H}}_{2} {\text{S}} \) may cause irritation to the eyes, nose and throat and even kill a person. The corrosion mechanism of \( {\text{H}}_{2} {\text{S}} \) normally results in a crack that can propagate rapidly and cause material failure (Fig. 4). Other mechanisms of \( {\text{H}}_{2} {\text{S}} \) corrosion such as sulfide stress cracking (SSC) or hydrogen-induced stress cracking corrosion (HISC) can corrode metallic facilities and components such as equipment, valves and piping. The main standard that addresses \( {\text{H}}_{2} {\text{S}} \) corrosion is ISO 15,156 [25], formerly known as NACE MR-0175 [26]. In general, the different \( {\text{H}}_{2} {\text{S}} \) corrosion prediction strategies can be summarized as hardness control and reduction, suitable material selection for the \( {\text{H}}_{2} {\text{S}} \)-containing process environment and implementation of a suitable heat treatment [25, 26].

Fig. 4
figure 4

Pipeline \( {\text{H}}_{2} {\text{S}} \) crack

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Case Studies of Valve Material Failure

This section reviews a representative set of materials failures of industrial valves and presents corrosion prevention strategies. The cases involve valves installed under the water (subsea) and on floating production storage and offloading (FPSO) platforms.

Case #1: External Corrosion of a Coated Cast Iron Gear Box

A gear box is defined as a set of gears inside a casting; a gear box may be installed on the top or side of valves for manual operation by an operator [27]. A handwheel installed on the gear box acts as the means for exerting the input torque [27]. A manual gear box may be coupled with an electrical actuator; this type of installation is outside the scope of this paper. An actuator is a machine or component installed on the top of an industrial valve to automatically move and control the valve [28]. The gear box is not exposed to any fluid or internal corrosion. Traditionally, the gear box of the valves is made of cast iron or carbon steel coated in zinc rich epoxy in the Norwegian offshore industry (Fig. 5a) [4]. As shown in the figure, the coating had been removed and the gear box exhibited rust and corrosion. The corrective action to mitigate corrosion would be to select a type 316 stainless steel gear box instead (Fig. 5b) of gear box manufactured from a coated cast iron or carbon steel. The gear box is not in contact with the fluid service flowing through the valve and the gear box temperature is the same as the atmospheric temperature which is less than 60 °C. Therefore, CLSCC should not be a risk for a gear box in SS316 [13]. The other advantage of selecting type 316 stainless steel for the gear box is to preclude a coating implementation.

Fig. 5
figure 5

A Coated cast iron gear box corrosion in the Norwegian offshore industry (Courtesy: Valve World). B Stainless steel 316 gear box to be used instead of cast iron gear box to prevent corrosion (Courtesy: Valve World)

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Case #2: Using Low Alloy Hot Dip Galvanized Coating for Exotic Valve Body Materials

In the second example, low alloy hot dip galvanized bolts were used on exotic valve body materials such 22Cr duplex, 25Cr super duplex and 6MO valves. The zinc coating of the hot dip galvanized bolts can be removed, and the low alloy bolts are not corrosion resistant in an offshore environment (Fig. 6) [4]. Corrosion of the bolt leads to failure of the relatively expensive valves in exotic materials. The solution to this problem is to use super duplex bolts for the valves instead of low alloy hot dip galvanized bolting. Super duplex bolting can provide approximately the same mechanical strength as low alloy bolts such as grades B7 or L7 [4].

Fig. 6
figure 6

A low alloy steel bolting exhibited severe corrosion in offshore environment after the loss of zinc coating

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Case #3: Galvanic Corrosion Between the Valve Stem and Stem Key in Two Different Materials

Galvanic corrosion can be categorized as both internal and external. This type of corrosion, also called bimetallic corrosion or dissimilar metal corrosion, is defined as an electrochemical process in which one metal corrodes when it is in contact with another in an electrolyte environment [29]. The two types of materials have a different electrical potential and nobility, so the less noble metal experiences an increase in corrosion rate due to more coupling and contact with the more noble one [29]. This process is exactly the same as the corrosion of less noble zinc in cathodic protection to protect the more noble steel explained in Sect. 2.1 of this paper. The presence of an electrolyte as a substance that produces an electrically conducive solution such as water is essential.

The third case involves the corrosion and rusting of a valve stem key manufactured from low alloy grade AISI 4140 steel coupled to a valve stem in 22Cr duplex in a humid environment (Fig. 7) [4]. The valve stem was a pressure-containing component that transferred the force from the valve operator to the valve internals, such as a closure member, to provide its movement [30]. At a minimum, it included bodies, end connections, bonnets/covers and stems [30]. A part’s failure to function as intended resulted in a release of the contained fluid into the environment. The stem key, which shows the direction of the ball (closure member) and provided the connection between the stem and the valve operator such as a gear box or actuator, must have high mechanical strength and corrosion resistance [4]. AISI 4140 is an alloy steel that contains different alloys such as chromium, molybdenum and manganese with a mechanical strength even higher than 22Cr duplex [31]. The key point is that the stem key is covered by a valve operator such as a gear box, so the stem key should not be in contact with the corrosive offshore environment during valve operation. However, the coupling of the stem and key could be in contact with humidity during valve assembly. Selection of a stem key in 22Cr duplex, the same as the stem material, can prevent galvanic corrosion due to the coupling of these two components.

Fig. 7
figure 7

Galvanic corrosion between the valve stem and stem key

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Case #4: Stress Cracking Corrosion of 17-4 PH Stem Material

A valve stem should have high mechanical strength, especially in the case of valve automation (actuation) [10]. Type 17-4 PH is a martensitic stainless steel with high mechanical strength and hardness containing approximately 17% chromium, 4% copper and 4% nickel. This material is widely used for the stem material of carbon steel body valves in onshore units such as refineries and petrochemical plants [10]. However, usage of this material should be avoided in the offshore sector of the oil and gas industry, including subsea, due to the high risk of chloride stress cracking corrosion (CLSCC) [10, 32]. Alternatively, high mechanical strength nickel alloys such as Inconel 718 and 725 are proposed for stem materials.

Case #5: Pitting and Stress Cracking Corrosion of Inconel X750 Spring for Subsea Valves

Different types of valves such as a ball valve, through conduit gate and axial valves are used in the subsea sector of the oil and gas industry [10, 19]. Springs play an essential role in the sealing of subsea valves. As an example, a spring is typically installed behind the disk of an axial check valve; where it pushes the disk toward the seats and keeps the valve in closed position. Springs are installed behind the seats of the ball and through conduit gate valves. They provide force to push the seats against the closure member (ball or gate) and prevent leakage from the valve ball and seat contact toward the valve cavity. Inconel X750 is a nickel chromium super alloy that is heat treated through precipitation hardening by adding other compounds such as aluminum and titanium [10]. This material is a very popular spring material due to its high mechanical and fatigue resistance, especially during the high number of cycles typical in the onshore and offshore (non-subsea) sectors [10]. However, this material has low pitting and CLSCC corrosion resistance so it can be corroded easily when in contact with seawater. Subsea valves are not filled with seawater fluid during operation. However, subsea equipment such as valves should be designed for long-term wet storage in seawater during installation [33]. In addition, scheduled delays, especially in the start-up or installation of a ship or platform connected to the subsea modules may extend the wet storage of subsea facilities as well as valves in the sea [33]. Thus, the use of more corrosion-resistant spring material such as Elgiloy (cobalt alloy) or Inconel 625 is proposed [10]. Elgiloy UNS R30003 contains 40% cobalt, 20% chromium, 15% nickel and 7% molybdenum [10]; it has a high level of mechanical strength as well as fatigue and corrosion resistance.

Case #6: HISC Corrosion of Duplex, Super Duplex, and Hard Nickel Alloys

HISC mechanism was explained earlier in this paper. Specific materials such as duplex and super duplex, as well as hard nickel alloys such as Inconel 718 and 725 are susceptible to HISC [34,35,36]. Det Norske Veritas (DNV) has developed a guideline for the design of duplex components based on the DNV-RP-F112 standard to avoid HISC [37]. The proposal in this paper is to apply HISC analysis based on the DNV guideline for sensitive duplex and super duplex materials. This could cover the parts of the valve subject to cathodic protection, such as the body and bonnet, in sensitive material. HISC analysis is a stress and strain analysis done through a finite element analysis (FEA) according to the DNV standard [37]. Fig. 8 illustrates stress analysis on a subsea axial check valve as a part of HISC evaluation. One of the weak points associated with the DNV standard is that it does not cover hard nickel alloys; therefore, a separate guideline should be developed to mitigate HISC for hard nickel alloys such as Inconel 725.

Fig. 8
figure 8

A stress analysis as a part of HISC on an axial check valve is illustrated

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Case #7: Graphite Packing Corrosion of a Butterfly Valve in the Seawater

Butterfly valves are used to stop and start fluid flow, especially in utility services such as water, since these valves are compact, light and relatively cheap [38]. Additionally, butterfly valves may be made in wafer or flangeless design according to API 609 standard which can save weight and space compared to flanged end butterfly valves [38,39,40]. Valve packing is defined as a stem sealing used as a barrier to prevent stem leakage to the environment [1]. Stem or valve packing is made of several rings in different materials such as graphite or Teflon (PTFE). Graphite packing can be used for a wider range of pressure and temperature compared to PTFE packing, and is more compatible with chemical and process fluid [2]. Graphite is very noble material that can cause the galvanic corrosion of other metallic materials with which it comes in contact, especially in the case of valve stems in seawater service [41]. The implemented solution to prevent galvanic corrosion is to isolate the graphite packings installed around the valve stem with a PTFE or lip seal as illustrated in Fig. 9. A lip seal is a robust sealing made of PTFE in white color that is energized by an internal spring made in Elgiloy or Inconel 625 [41]. The gland and gland flange illustrated in Fig. 9 are in a nickel aluminum bronze material that provides sufficient force on the packings to make them expand axially in order to seal the stem area and prevent the leakage of internal fluid to the environment.

Fig. 9
figure 9

The isolation of graphite packings with a lip seal to mitigate galvanic corrosion of valve stem is shown (Courtesy: Valve World)

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Conclusion and Recommendations

The paper reviews some of the major material failures due to corrosion associated with industrial valves in the offshore industry. The outcome of the reviewed corrosion cases would be valve failure, which would potentially lead to other problems such as environmental pollution and loss of production. Referring to cases #1, 2 and 3, it can be concluded that the use of carbon and low alloy steel should be limited in the offshore environment. The use of 22Cr duplex is very common for different parts of industrial valves in the Norwegian offshore industry where \( {\text{H}}_{2} {\text{S}} \) corrosion is not a major risk. However, usage of duplex and super duplex is associated with the risk of HISC, so the guideline given by DNV-RP-F112 should be applied for valves. HISC risk is also applicable to hard nickel alloys such as Inconel 718 and 725 which are not covered by the DNV standard. Therefore, a separate guideline for nickel alloys susceptible to HISC is proposed in this paper. The other conclusion is that usage of martensitic stainless steels such as 17-4PH should be avoided in the offshore industry due to pitting and CLSCC risk. Other materials with low pitting corrosion resistance such as Inconel X750 should also be avoided in the subsea environment. Graphite, as a very noble material, can cause galvanic corrosion of the metals with which it comes in contact, especially in seawater. A real industrial case was briefly reviewed in this paper which proposed the isolation of graphite packing in a butterfly valve by an O-ring or lip seal to prevent contact with the seawater.

Proposals for Future Research

  1. 1.

    Separate research is proposed to review \( {\text{H}}_{2} {\text{S}} \) corrosion mitigation strategies for industrial valves. Using Inconel 625 cladding or a weld overlay on carbon steel is one of the approaches used to prevent hydrogen-induced cracking (HIC) as a type of \( {\text{H}}_{2} {\text{S}} \) or sour corrosion.

  2. 2.

    The lack of a guideline or standard to prevent HISC corrosion on hard nickel alloys such as Inconel 718 and 725 is obvious in the subsea sector of oil and gas.

  3. 3.

    Having high mechanical strength is very essential for the bolting used for valves. Separate research is proposed to make sure that super duplex bolting can provide sufficient mechanical strength.

Acknowledgment

I would like to express my gratitude to my partner, Ms. Tamara Zhunussova, for her great support.