A review on internal corrosion of pipelines in the oil and gas industry due to hydrogen sulfide and the role of coatings as a solution

2.1 Material degradation and crack formation

In their dry state, neither CO₂ nor H₂S exhibit corrosive properties; however, upon dissolution in water, they precipitate the formation of corrosive solutions. This corrosion process initiates the thinning of pipes and induces metal embrittlement. Over time, this degradation can progress to pipe ruptures, with severe consequences including explosions as the weakened metal fails to withstand the operational pipeline’s elevated pressures (Goodwin et al. 2015). Carbon dioxide corrosion primarily occurs through pitting, where localized areas of corrosion develop rather than a uniform coating across the entire pipe surface. The resultant FeCO₃ can form a protective scale layer, effectively shielding the pipe from further corrosion. However, this protective layer may degrade over time, leading to the exposure of the underlying metal and subsequent corrosion. This phenomenon, known as mesa corrosion, results in the formation of deep, sharply edged pits in the pipe; the term “mesa” is adopted from the same terminology used to characterize widely recognized geological formations (Han et al. 2010).

Due to hydrogen sulfide, pipelines typically experience two common types of failures: hydrogen-induced cracking (HIC) and sulfide stress cracking (SSC) (Mohtadi-Bonab et al. 2013). When H₂S dissolves in water, it dissociates to release hydrogen ions (H⁺), which contribute to the formation of an acidic environment. These hydrogen ions then undergo a reduction reaction at the metal surface, where they are reduced to atomic hydrogen. The atomic hydrogen penetrates the metal and causes hydrogen embrittlement at defect sites, significantly reducing the pipeline’s service life. While the corrosion product layer formed on pipelines can decrease the penetration rate of corrosive agents, thereby slowing down further corrosion of steel (Castaneda et al. 2009), the corrosive ions H⁺, HS⁻, and S²⁻ generated from H₂S dissociation can permeate this protective layer and reach the substrate, continuing the corrosion process. Research by Lei et al. (2018) indicates that the growth of the corrosion product layer can be hindered by the accumulation of hydrogen blisters at the interface between the substrate and the barrier film, which subsequently reduces the corrosion resistance of the pipeline. Figure 4 illustrates the impact of hydrogen on the passivation behavior of metals, with the hydrolysis equilibrium reaction of H₂S shown below.

Figure 4:

Impact of hydrogen on metal passivation. Reprinted with permission from (Lei et al. 2018). Copyright@2018, Elsevier.

Sulfide stress cracking (SSC) is exclusively observed in aqueous environments containing H₂S. Typically, failure is a brittle fracture occurring in regions under applied or residual tensile stress. The formation of atomic hydrogen, which is required for SSC, arises during the corrosion reaction between iron and H₂S. High-strength steels (yield strength ≥ 550 MPa) and hardened heat-affected zones in welded joints have been documented to experience SSC failure at room temperature. Elevated environmental temperatures have been identified as advantageous in reducing the susceptibility of steels to SSC (Steinberg and Kane 1982).

Both stress corrosion cracking (SCC) and sulfide stress cracking (SSC) involve the degradation of metal due to chemical processes. SCC arises from the combined effect of corrosion and mechanical stress, which is primarily stress-controlled, while SSC occurs in the presence of hydrogen sulfide (H₂S) and strain, being primarily strain-controlled. Both types of corrosion result in cracking of the material, leading to structural integrity issues and potential equipment failure. SSC is characterized by hydrogen embrittlement caused by stress and the penetration of atomic hydrogen into metal lattice structures due to corrosion by wet H₂S. The conditions necessary for SSC involve tensile stress, a material with structural imperfections, and when the hydrogen atoms enter and contact with a corrosive atmosphere containing hydrogen sulfide. These may lead to the formation of cracks. Hydrogen atoms are encouraged to enter the metal’s lattice structure when H₂S is present, and the protective layer against corrosion frequently breaks and separates from the metal surface. This process occurs even in the absence of plastic strain, as hydrogen permeation and trapping can cause embrittlement independently of localized deformation (Tale et al. 2021).

Sour gas has harmful effects on metallic materials, including components not intended for primary structural support and low alloy steels. In sour gas systems, corrosion is the main cause of material degradation. It is electrochemical in nature, and it is initiated by the presence of H₂S. It depends on different factors such as the partial pressure, pH, and temperature. Even a low amount of H₂S, as little as a 0.82 (ppm), can cause SSC (Shimamura et al. 2022). When sour gas contains elemental sulfur or iron sulfides formed from the interaction of corrosion, H₂S, and steel, it increases the chance of localized corrosion such as pitting or crevice corrosion in the material. These substances accelerate corrosion as catalysts and diminish the quality of steel by interacting with preexisting inclusions, which form during steel elaboration rather than during service. Sour gas corrosion processes tend to accelerate at high temperatures and help the material to degrade. This degradation reduces mechanical properties like strength and ductility, ultimately leading to equipment failure and material loss (Li et al. 2021a).

3.1 Plasma diffusion techniques

Nitriding has traditionally been used to harden the surfaces of austenitic stainless steels, but this process at temperatures above 500 °C typically reduces the material’s corrosion resistance due to chromium nitride precipitate formation. Recently, it has been found that carbon can also effectively alloy with these steels, leading to the development of a low-temperature plasma carburizing process that enhances both wear and corrosion resistance. Plasma-based chemical heat treatments such as carburizing, nitriding, or carbonitriding enhance the corrosion resistance of metals in CO₂/H₂S environments embedding interstitial atoms into the metal surface, which slows the corrosion rate (Bell and Sun 2002). Li et al. (2018) employed low-temperature liquid nitriding on 304 austenitic stainless steel, creating a triple-layered structure consisting of an oxide layer on top, a nitrogen-enriched middle layer, and a carbon-rich bottom layer, as shown in Figure 6.

Figure 6:

Layered structure and corrosion resistance of nitride 304 stainless steel. Reprinted with permission from (Li et al. 2018). Copyright@2018, Elsevier.

This layered structure reduces hydrogen diffusion and decreases the number of atoms penetrating the material, enhancing its resistance to hydrogen embrittlement. Additionally, the nitride layer reduces the formation of corrosive products, and the active nitrogen atoms can combine with H⁺ to prevent a drop in pH, thereby slowing the corrosion rate from H₂S (Li et al. 2018). 304 stainless steel demonstrates improved resistance to hydrogen embrittlement due to its austenitic structure, which impedes hydrogen absorption and diffusion. The addition of the nitride layer further strengthens this resistance by acting as a physical barrier against hydrogen ingress (Martin et al. 2011). After soaking in a saturated hydrogen sulfide (H₂S) solution prepared according to NACE TM0177-2005 standard (Solution A) for 720 h, and without applying external stress, the cross section of the untreated sample displayed numerous pits and cracks with extensive corrosion product formation (Li et al. 2018). In contrast, the nitrided sample’s cross section showed no pits or cracks, and only minimal corrosion products were formed, indicating that nitriding significantly improves the corrosion resistance of 304 stainless steel in H₂S environments. To further enhance the resistance of stainless steel against crevice and pitting corrosion in chloride-containing solutions, low-temperature gaseous nitriding introduced a 26 μm thick S-phase (expanded austenite) layer (Li et al. 2021c), raising the pitting potential and improving crevice corrosion performance. The Fe₃O₄ layer formed effectively blocks corrosive ions, making it difficult for the corrosion medium to penetrate the steel. Plasma carburizing and nitriding not only significantly increase the hardness and fatigue resistance of stainless steel but also enhance its inherent corrosion resistance, making these techniques excellent options for surface treatment (Borgioli et al. 2024).

3.2 Surface modifications coating technologies

Plasma-assisted carburizing, nitriding, or carbonitriding significantly boosts the corrosion resistance of metals in environments rich in CO₂ and H₂S. However, these treatments can increase the brittleness of pipelines, making them less suited to withstand the abrasive conditions encountered in oil and gas extraction. Pipeline coating technologies not only shield the substrate from corrosive agents but also reduce wear on the inner walls, proving to be highly effective protective measures in oil and gas extraction processes.

Ni–P coatings have garnered significant attention in the oil and gas corrosion field due to their superior corrosion resistance in acidic environments, facilitated by the formation of hypophosphite ions (Sun et al. 2019). Uncoated L360 steel, a linepipe-grade material commonly used in oil and gas pipelines, exposed to an H₂S/Cl⁻ environment (>2,300 ppm H₂S, 5 wt% NaCl, and 0.5 wt% CH₃COOH) for 1,440 h undergoes severe corrosion, forming pits over 50 μm on the surface as shown in Figure 7.

Figure 7:

Corrosion impact on uncoated L360 steel in H₂S/Cl⁻ environment. Reprinted with permission from (Li et al. 2021b). Copyright@2021, Elsevier.

However, the application of Ni–P coatings drastically reduces the corrosion rate, with nickel dissolution forming corrosion products such as NiS and Ni₃S₂, which adhere to the outer layer of the coating. This prevents direct contact between the corrosive medium and the chemical plating. Stable NiO and Ni(OH)₂ passivation layers act as barriers, effectively slowing down the corrosion rate. After 720 h in an H₂S/Cl⁻ environment, only micrometric pitting is observed, and uniform corrosion develops only after 1,440 h (Li et al. 2021b). Even under high-temperature, high-pressure CO₂/H₂S/Cl⁻ conditions, Ni–P coatings continue to exhibit excellent corrosion resistance (Sun et al. 2019). Sulfides react with the coating during the mass transfer process of corrosion, depleting the sulfides and allowing only a minimal number of corrosive agents to penetrate the protective corrosion product layer and induce pitting. The dense corrosion product layer combined with the extended corrosion pathway greatly slows down the corrosion rate, enhancing the pipeline’s durability in oil and gas extraction environments.

Coatings serve a similar function to corrosion products in slowing the substrate’s corrosion rate by blocking corrosive agents from penetrating the base material. Moreover, coatings, compared to corrosion product layers, are denser and provide a better barrier effect. Some coatings, like Ni–P, can also absorb some corrosive ions, offering more effective protection of the substrate from both aspects. Beyond Ni–P coatings, Wang et al. (2016) have shown that Ni–Cr–Mo coatings prepared using a high-power diode laser on an X70 substrate exhibit stable anticorrosion properties in simulated H₂S and CO₂ solutions. Dushik et al. (2016) have identified hard W–C coatings prepared via chemical vapor deposition as promising due to their extremely low porosity of 0.02 % and excellent corrosion resistance from tungsten. These coatings were tested in 25 % hydrochloric acid (HCl) solution and 25 % HCl solution saturated with hydrogen sulfide (H₂S), environments that simulate conditions in chemical and oil and gas industries.

3.3 Plasma coating technologies

While coating technologies have shown exceptional corrosion resistance in CO₂/H₂S environments, applying these coatings on the inner surfaces of pipelines during oil and gas extraction remains a challenge. Using hollow cathode plasma enhanced chemical vapor deposition (HC-PECVD), diamond-like carbon (DLC) films can be deposited inside pipelines. These DLC coatings are highly chemically inert and do not react with acids, bases, or salts (Wei et al. 2019; Wei et al. 2021a; Zhang et al. 2018), providing effective protection for the inner walls of pipelines under high-temperature, high-pressure gas environments containing both CO₂ and H₂S. Wang et al. (2013) have successfully created ultra-thick DLC coatings exceeding 50 μm through a multilayer structure design that manages compressive and tensile stresses. These coatings have been successfully applied to various pipe materials and diameters, including 304 stainless steel, aluminum, cast iron, and U-shaped pipelines (Wei et al. 2021b), as illustrated in Figure 8. Corrosion tests conducted under neutral salt spray for 480 h and 720 h, and high-temperature, high-pressure CO₂ environments showed no significant damage to the coatings, as depicted in Figure 9. The corrosion morphology after salt spray tests indicates that DLC coatings have excellent corrosion resistance and long-term stability. Enhancements in corrosion resistance can be further achieved by doping the films with elements such as fluorine and nitrogen (Wei et al. 2022). The application of DLC films using HC-PECVD to pipeline interiors offers a promising new method to mitigate corrosion in oil and gas field environments.

Figure 8:

Applications of ultra-thick DLC coatings on various pipeline materials. (a) Schematic view and SEM image of the (S_ix-DLC/S_iy-DLC)_n/DLC film with a thickness of 52.8 μm. Reprinted with permission from (Wang et al. 2013). Copyright @ 2013 by American Chemical Society. (b) Si-DLC films deposited on the internal surface of SS304 pipes with various diameters. Reprinted with permission from (Zhang et al. 2018). Copyright @ 2018 by IOP publishing Ltd. All rights reserved.

Figure 9:

Durability of DLC coatings under high-temperature, high-pressure CO₂ exposure (coating morphology on the inner surface of stainless pipe). Reprinted with permission from (Zhang et al. 2018). Copyright @ 2018 by IOP Publishing Ltd. All rights reserved.

3.4 Alloying of metal pipelines

Enhancing the corrosion resistance of metal pipelines in the oil and gas industry can be achieved through alloying with elements. These elements effectively reduce pitting and stress corrosion cracking by altering the morphology of corrosion products to form denser layers, which improve resistance (Davoodi et al. 2011; He et al. 2009). Researchers have conducted a study on the alloying of Ni, Cr, Mo, and Fe alloys in H₂S–Cl⁻ environments. Their findings indicate that the alloyed molybdenum reduces stress corrosion cracking (SCC) and pitting corrosion susceptibilities of the Ni, Cr, Mo, and Fe alloy in these conditions. The study specifically used alloys with compositions of 60 % Ni, 16 % Cr, and 8–16 % Mo with Fe as the balance (Tomio et al. 2015). Research has shown that in CO₂/H₂S environments, Cr-rich corrosion products like Cr(OH)₃ enhance the protective barrier (Dong et al. 2020), and Ni-based alloys form protective layers of NiS and Ni oxides (Zhao et al. 2011). Titanium alloyed low-carbon steels have been noted to produce very dense and uniform protective films, substantially increasing their resistance to corrosive media (Yu et al. 2020). The introduction of Mo in Ni–Cr–Mo–Fe alloys has been particularly effective; it forms molybdenum sulfide during corrosion, which has excellent cation selectivity that helps reduce the activity of corrosive agents like H₂S and promotes the formation of protective chromium oxide layers, thus mitigating both pitting and stress corrosion cracking (Clayton and Lu 1986; Tomio et al. 2015). The effectiveness of these alloying strategies is illustrated in Figure 10, which shows the significant reduction in corrosion rates and the durable nature of the developed alloys. These innovations underscore the ongoing research focus on developing alloy steel pipelines that balance corrosion resistance with mechanical strength and cost-efficiency for harsh oil and gas environments. The microstructure of Ni, Cr, Mo, and Fe alloys features a two layer surface film, consisting of an outer molybdenum sulfide layer and an inner chromium oxide layer. This arrangement greatly enhances SCC resistance by reinforcing the protective oxide film in H₂S–Cl⁻ conditions (Tomio et al. 2015).

Figure 10:

Impact of alloying elements on corrosion resistance in Ni–Cr–Mo–Fe alloys. Reprinted with permission from (Tomio et al. 2015). Copyright@2015, Elsevier.

3.5 Corrosion inhibitors

Injecting corrosion inhibitors is a cost-effective and simple method to control corrosion in oil and gas extraction. Liu et al. (2013) conducted a comprehensive study on four bis(benzimidazole) derivatives containing different heteroatoms and their corrosion inhibition effects on N80 steel in H₂S solutions. They found that a stable adsorption monolayer of inhibitors on the inner walls of pipelines could slow down both anodic dissolution and cathodic reduction reactions. The effectiveness of corrosion inhibitors is closely linked to their adsorption properties, as they prevent corrosive media from contacting the pipeline walls, thus mitigating corrosion (Abboud et al. 2012). Consequently, Zhuoke et al. (2021) undertook a series of experiments to enhance the adsorptive capabilities of inhibitors and synthesized bis-Manich base TZBM containing a thiazole ring. It is an organic compound synthesized to enhance the adsorption properties of corrosion inhibitors. It incorporates a thiazole ring and functional groups capable of forming coordinate bonds with metal surfaces, thus improving its corrosion inhibition performance. The N and O atoms in TZBM molecules feature lone pairs of electrons that can enter the iron’s hybrid orbitals to form coordinate bonds, creating a stable six-membered ring structure that firmly adheres TZBM to the pipeline surface. An illustration of TZBM adsorption on Fe surfaces is shown in Figure 11.

Figure 11:

Adsorption mechanism of TZBM on Fe surfaces. Reprinted with permission from (Zhuoke et al. 2021). Copyright@2021, Elsevier.

However, due to the potential environmental pollution from corrosion inhibitors, their widespread use is limited. Thus, nontoxic, environmentally friendly corrosion inhibitors have received significant attention. Researchers exploring the corrosion inhibition properties of plant extracts such as banana peel, pomegranate peel, and citrus peel have found them effective in acidic environments containing HCl and H₂S(O)₄ (Ibrahim et al. 2012; Pradeep Kumar and Mohana 2014). Building on this, Zhang and Zhao (2018) further discovered the corrosion inhibitory effect of citrus peel in brine solutions containing CO₂ and H₂S. While various environmentally friendly inhibitors have been identified that are effective in acidic CO₂/H₂S environments, there is still a lack of research on their performance under the high temperature and pressure conditions of simulated oil and gas field environments. Additionally, the effects of external factors like temperature, pH, moisture content, and flow rate on their inhibition performance are not well-studied. Therefore, the development of eco-friendly corrosion inhibitors and their effectiveness in simulated real-world oil and gas field conditions will be a prominent area of future research.

4.1 FBE epoxy coating

FBE, a thermoset compound, represents a high-performance anticorrosion coating tailored for protecting both small and large diameter pipelines operating at moderate temperatures, offering exceptional protection (Kehr and Enos 2000). The FBE coating systems deliver effective protection within a moderate temperature range of −40 °C to 85 °C. Applied either in wet or dry powder form, typically at thicknesses ranging from 400 to 600 μm, onto the preheated steel pipe surface. Upon application and curing, the epoxy film forms an exceptionally robust surface with strong adherence to the steel substrate. Characterized by its homogeneous nature, the FBE protective layer demonstrates outstanding resistance to chemical reactions (Gbarnjah 2014). In general, standalone FBE coatings prove to be an optimal choice when accompanied by efficient construction and installation practices, along with controlled backfill aggregate, particularly in scenarios where operating temperatures remain below 65 °C (150 °F). For more demanding environmental conditions, such as higher temperatures or extreme installation circumstances, options like dual and multilayer FBE systems are available. Alternatively, in certain cases, a three-layer system comprising an FBE base layer, an adhesive, and a thick polyolefin layer may be specified. While these systems offer enhanced damage tolerance and an expanded high-temperature operating range, there are concerns among some researchers regarding their compatibility with cathodic protection measures. It is effective against general corrosion but is less effective in preventing stress corrosion cracking (SCC) due to its inability to address localized stresses and microstructural factors driving SCC (Kehr and Enos 2000).

FBE coating is predominantly employed as a unified corrosion protection layer. Fusion-bonded epoxy coatings demonstrate exceptional adhesion to steel, possess commendable chemical resistance, and importantly, do not inhibit the effectiveness of cathodic protection measures applied to the pipe. Despite its toughness, when installation damage arises, it can be promptly identified and resolved. FBE coating systems have a commendable history of installation with minimal damage. Considering both the extent of damage and repair costs, FBE coatings may offer the most economically viable solution to address field and construction damage. The application of FBE coating follows a straightforward process, which is one of its key advantages (3M 2015):

1. Cleaning: The pipe undergoes a thermal pickling process at 725 °F (385 °C), followed by blast cleaning according to NACE No. 1/SSPC-SP 5 standards, utilizing hardened steel grit or an appropriate mineral abrasive (Davis 1994).

2. Priming: In corrosive pipelines with high pressure, temperature, and CO₂ or H₂S, a primer is essential. For both phenolic and water-based systems, the primer is applied before heating. With phenolic primers, preheating removes volatile solvents and initiates partial curing. Precise control of this step is crucial for proper coating performance; overheating or full curing before FBE application can lead to inadequate adhesion. Water-based primers require application at temperatures below water’s boiling point. To prevent flash rusting, pipes are preheated to around 150 °F (66 °C) or undergo oil-free, compressed-air drying after application. If using induction coils for heating, the primer should be almost dry before entering the coil (Nayyar et al. 2000).

3. Heating: The pipe is heated to the temperature range recommended by the coating material supplier, typically around 350 °F (177 °C) for internal coatings.

4. Applying FBE: Various application techniques can be employed depending on the configuration of the component to be coated (Nayyar et al. 2000):

   1. In the fluidized bed method, powder is aerated in a chamber using airflow, and the heated component is then dipped into the aerated powder.

   2. In the flocking method, powder is sprayed onto the component using compressed air.

   3. In the electrostatic spray technique, powder is sprayed onto the preheated component using compressed air. An electrostatic charge is applied to enhance powder usage efficiency.

5. Curing: For heavy-walled items, typically ¹⁄₈ in (3.2 mm) thickness or more, some FBE systems utilize the metal’s heat retention to achieve curing without requiring postcure facilities. Phenolic primer systems usually necessitate a postcure heating step to complete the primer’s chemical reaction. Water-based primer systems rely on the fusion-bonded epoxy for postcure conditions, typically aligning with the application temperature range. However, for metal prone to outgassing like cast iron, it’s vital to postcure at a temperature below the application temperature. For instance, a component lined at 400 °F (204 °C) might undergo postcuring at 350 °F (177 °C). In extreme cases, a preheating outgassing step may be necessary, involving several h at 660–725 °F (350–385 °C), before cooling to the application temperature and applying the lining (Nayyar et al. 2000).

6. Cooling: Cooling is accomplished either by spraying water on the outside and/or inside of the pipe or by letting it cool in ambient air (3M 2015).

7. Inspection: After cooling is finished, but before storage, the pipe must undergo continuity inspection following NACE Standard RP0490-01. A steel spring or conductive rubber search electrode is used for this purpose. Additionally, the coating thickness is measured using calibrated gauges to ensure it meets the specified minimum thickness (3M 2015).

In summary, FBE coating is a protective layer applied to pipelines to combat corrosion and ensure their long-term functionality, especially in transporting various fluids like oil, gas, and water. Its significance lies in preserving the integrity of pipelines. FBE offers multiple benefits, including corrosion resistance, increased durability, improved flow efficiency, and decreased maintenance expenses. Moreover, it aids in environmental protection by preventing leaks and spills. The lifespan of FBE coating on pipelines varies based on factors such as environmental conditions, usage, and application quality, but it can endure for decades with proper application and upkeep. Although highly durable, FBE coatings may require periodic inspections and touch-up repairs to address damage or wear, thereby prolonging their effectiveness against corrosion. Regular maintenance is crucial for extending the coating’s lifespan and ensuring continued pipeline protection.

4.2 Phenolic coatings

Phenolic coatings, particularly those based on novolac phenolic resins, have proven to be highly effective in combating internal corrosion in pipelines exposed to hydrogen sulfide (H₂S). These coatings are well-suited for the harsh conditions found in oil and gas environments, where high temperatures and corrosive elements like H₂S and CO₂ are prevalent. The inherent chemical stability, high-temperature resistance, and excellent barrier properties of phenolic coatings make them a reliable choice for protecting pipeline infrastructure from the detrimental effects of H₂S. Studies have shown that phenolic coatings not only resist the permeation of corrosive ions but also maintain their integrity in extreme conditions, significantly reducing the risk of corrosion-related failures in pipelines (Hao et al. 2020; Jiang et al. 2023). A coating is referred to as phenolic coating if it contains phenolic acids, which are identified by the presence of carboxylic acid in their molecular structure (Altemimi et al. 2017). These are further broken down into hydroxycinnamic and hydroxybenzoic acids, of which 3-hydroxy, 4-hydroxy, 2,4-dihydroxy, and gallic acids are typical examples. The two primary classes of phenolic acids are hydroxybenzoic acids, which don’t have a side chain, and hydroxycinnamic acids, which have a double bond in the side chain. P-coumaric, caffeic, ferulic, and sinapic acids are the primary components of hydroxycinnamic acids (Altemimi et al. 2017). Phenolic compounds possess distinct beneficial properties that are attributed to their molecular structure, specifically the quantity and location of hydroxyl groups on the ring. The chemical characteristics of phenolic compounds can be altered through substitution, which will also affect their solubility, stability, and reactivity (Mu’azu et al. 2017). Figure 12 shows the chemical structure of the phenolic acid substitution patterns of phenolic compounds (Mu’azu et al. 2017).

Figure 12:

Phenolic acid structure. Originally published in (Mu’azu et al. 2017) under the terms CC BY 4.0 license. Available from: doi.org/10.3390/ijerph14101094.

Phenol is obtained by several synthesis procedures and fractional coal tar extraction methods. The industrial synthesis process for producing phenols uses a variety of commercial methods. Below is a detailed explanation of some of the highly typical processes seen in industries like Dow, Raschig, and Cumene (Dodiuk and Goodman 2014). Phenolic coatings have limited flame propagation, stability at high temperatures, and are quite inexpensive (Gourichon et al. 2008; Guilleminot et al. 2008). They are utilized as flame-retardant coatings in a variety of industries, including electronics, aircraft, automotive, and oil and gas industry. In the coatings industry, phenolic coatings are frequently referred to as a “workhorse,” this is because of their ability to offer resistance against substances like chemicals, indirect moisture, and even wet conditions (Gourichon et al. 2008; Guilleminot et al. 2008). Phenolic coatings can be categorized into two main types: novolac phenolic coatings and resole phenolic coatings.

4.2.2 Resol phenolic coatings

Resol phenolic coatings have demonstrated significant effectiveness in combating internal corrosion in pipelines exposed to hydrogen sulfide (H₂S). Due to their robust chemical resistance, thermal stability, and strong adhesive properties, these coatings provide a reliable barrier against the harsh corrosive environments typically found in the oil and gas industry (Pilato 2013). The ability of resol phenolic coatings to form a highly cross-linked polymer network under various curing conditions enhances their durability, making them well-suited for protecting pipeline infrastructure from the detrimental effects of H₂S (Zaldivar et al. 2022). Their widespread applicability in demanding environments underscores their importance in maintaining the integrity of pipelines subjected to corrosive agents like hydrogen sulfide (Grenier-Loustalot et al. 1996). Resoles, also known as single-stage phenolics, are created when phenol reacts excessively with formaldehyde in the presence of an alkaline catalyst as shown in Figure 13, such as sodium hydroxide, ammonia, or sodium carbonate (Allen and Ishida 2001; Ismail et al. 2020). A phenol to formaldehyde molar ratio of between 1: 1 and 1: 1.3 is typically utilized (Allen and Ishida 2001). Although reaction products are typically liquids, they can be vacuum-dried at low temperatures to produce a solid intermediate if needed. Resoles can have a broad variety of molecular weights and compositions, depending on the kind and quantity of catalyst, molar ratio, and reaction conditions (Allen and Ishida 2001). As a result of their ability to cure in a heated mold without the need for an extra catalyst or curing agent, resoles are regarded as single-stage phenolic resins. Water is released as a byproduct of the polycondensation reaction known as thermal polymerization, which needs temperatures between 130 and 200 °C. They are also highly cross linked, which helps them excel high temperature applications (Allen and Ishida 2001). Resol are usually liquid while novolac are solid (Pizzi and Ibeh 2014).

Figure 13:

Phenol and formaldehyde reaction with an acid and base catalyst. Reprinted with permission from (Allen and Ishida 2001). Copyright@2001, Elsevier.

One of the earliest low-cost synthetic resins, resole phenolic resin has excellent mechanical, solvent, and weather resistance qualities (Sandhya et al. 2019). These qualities make it a great option for a wide range of applications in the automotive, aerospace, and thermal insulation industries. They are also very advantageous for composite preparation due to their fire smoke, low toxicity characteristics (Sandhya et al. 2019). These coatings are used where high temperatures are required.

One of the primary disadvantages associated with these coatings is their inherent lack of durability, particularly noticeable during their curing process (Kandola and Horrocks 2001). A significant issue arises as water is generated during this stage, which poses a challenge due to the potential for this water to become trapped within the composite material (Kandola and Horrocks 2001). In the unfortunate event of a fire, the presence of this trapped water can lead to the generation of steam, creating internal pressure that induces microcracks and delamination, compromising the material’s structural integrity (Kandola and Horrocks 2001). After undergoing the curing process, phenolic coatings may experience a transformation, becoming brittle and stiff. This change in their physical properties can lead to issues such as cracking or chipping when subjected to mechanical stress (Allen and Ishida 2001). Therefore, to enhance the durability and structural integrity of phenolic resins, it is common practice to incorporate fillers or other reinforcements into the formulation. Such measures help to mitigate the brittleness associated with phenolic coatings, ensuring better overall performance and longevity (Allen and Ishida 2001). Various factors, including temperature, humidity levels, and the duration of the curing process, all play significant roles in influencing the extent of cross-linking reactions and, consequently, impact the overall effectiveness and quality of the coating (Ebnesajjad 2011).

4.3 Epoxy–phenolic coatings

Epoxy–phenolic coatings are hybrid coatings that combine the properties of both epoxy resins and phenolic resins. Epoxy resins are widely used in various industries; however, they are known for their limitations, including poor heat resistance and toughness. To address these issues and enhance overall performance, numerous research studies have been conducted to develop new formulations, additives, and manufacturing techniques, aimed at mitigating these weaknesses and optimizing the properties of epoxy resins (Zhao et al. 2022). However, because the phenolic resin contains a high concentration of aromatic cycles, which are known for their stability and heat resistance, the material exhibits excellent thermal properties when exposed to elevated temperatures (El Gazzani et al. 2016).

Aldehyde groups present in phenolic resin play a significant role in enhancing the intermolecular cross-linking of the epoxy resin by forming strong chemical bonds with the epoxy groups (Zhao et al. 2022). This reaction not only boosts the overall structural integrity but also contributes to the enhanced durability and performance of the resulting composite material. However, epoxy–phenolic curing is done at high temperature around 120–240 °C. In a recent study, the performance of phenol-epoxy coatings was improved through postcuring, which involved exposure to 120 °C for up to 40 days (Zhao et al. 2022).

The findings imply that the presence of hydrogen, chloride, hydrogen sulfide (H₂S), and carbon dioxide (CO₂) ions exerts minimal influence on the degradation of epoxy–phenolic inner coating tubing as the concentration of ions increases (Deng et al. 2022). Despite this observation, it is noteworthy that the detrition of organic coatings can experience a notable escalation due to elevated flow rates when subjected to 120 °C conditions. This suggests that while the ion concentrations themselves have limited impact on the failure mechanisms observed, environmental factors such as temperature and flow play a crucial role in accelerating the breakdown of protective coatings (Wu et al. 2020). Therefore, it becomes apparent that a combination of ion concentration and external conditions contributes to the overall deterioration of the coatings, highlighting the complex interplay of various factors in the degradation process.

The rate at which ions and water penetrate the coating is crucial in determining its durability and longevity. This process plays a significant role in the overall performance of the coating, as the speed at which it fails is directly influenced by how quickly these substances can permeate through its protective layers. When exposed or damaged holes are present, this penetration process is accelerated (Wu et al. 2020).

4.4 Urethane

Urethane coatings have proven to be effective barriers against the corrosive effects of hydrogen sulfide (H₂S). The application of urethane coatings provides a protective layer that resists the permeation of H₂S, thereby preventing its interaction with the metal surface and mitigating corrosion (Vakili et al. 2024). This protective capability makes urethane coatings a valuable solution for prolonging the lifespan of pipelines exposed to H₂S, ensuring safety and reducing maintenance costs. Studies have shown that urethane coatings exhibit excellent adhesion, chemical resistance, and durability, making them suitable for use in harsh environments where H₂S is present (Mohtadi et al. 2003). These properties underscore the potential of urethane coatings as an effective measure to combat internal corrosion caused by H₂S in pipelines and other industrial systems. They are essential in environments where H₂S, a highly corrosive gas often present in oil and gas extraction and processing, poses significant material degradation risks (Chikezie Nwaoha 2017).

Polyurethane coatings are employed primarily due to their excellent chemical resistance, mechanical strength, and flexibility, which make them ideal for the harsh conditions inside pipelines (Polyurethane Coating: Uses, Types, Advantages, and Disadvantages 2024). The coatings form a barrier that prevents H₂S and other corrosive substances from coming into contact with the metal surfaces of pipelines, thereby prolonging the infrastructure’s operational life and enhancing safety (Bickham 2020).

In the oil and gas sector, PU coatings are specifically applied within the internal surfaces of pipelines that transport crude oil or natural gas. These pipelines are often located in extraction units and refineries where the presence of H₂S is a common challenge (Solovyeva et al. 2023). The internal coating of these pipelines is critical as it directly interacts with the transported materials, which may contain corrosive elements like H₂S (Samimi 2012).

To ensure that polyurethane coatings effectively protect against H₂S corrosion, they must comply with industry standards such as ASTM D16, which provides guidelines for the classification, requirements, and testing of protective coatings in the oil and gas industry (D16 Standard Terminology for Paint, Related Coatings, Materials, and Applications 2024). Following such standards ensures that the coatings are capable of withstanding specific environmental conditions, including the presence of H₂S (Standard Recommended Practice Liquid-Applied Internal Protective Coatings for Oilfield Production Equipment 1994).

Polyurethane coatings can be classified based on type and additive content. Additives are typically included to reduce costs, but it is important to note that cost-reducing additives can also decrease quality. Adding 10–20 % filler material (such as tar) can effectively lower costs with minimal impact on coating properties. However, increasing filler content to 40 % or more significantly reduces costs but also substantially degrades the coating’s performance. Common fillers in 100 % solid polyurethane include raw oil, asphalt, or tar pitch. It is crucial to note that tar pitch is carcinogenic (Samimi 2012). Table 4 shows a comparison of effectiveness tests for different coating types, highlighting the differences in performance and cost between epoxy and polyurethane coatings.

Urethane, a key component in polyurethane, contributes significantly to the coating’s performance due to its robustness and chemical resistance (Polyurethane Coating: Uses, Types, Advantages, and Disadvantages 2024). Researchers and manufacturers have experimented with various formulations to enhance the efficacy and durability of PU coatings: