Corrosion and Scaling in Geothermal Heat Exchangers

Abstract

Geothermal power is an attractive and environmentally friendly energy source known for its reliability and efficiency. Unlike some renewables like solar and wind, geothermal energy is available consistently, making it valuable for mitigating climate change. Heat exchangers play a crucial role in geothermal power plants, particularly in binary cycle plants, where they represent a significant portion of capital costs. Protecting these components from deterioration is essential for improving plant profitability. Corrosion is a common issue due to direct contact with geothermal fluid, which can lead to heat exchanger failure. Additionally, temperature changes within the heat exchanger can cause scaling, reduce heat transfer efficiency, or even block the tubes. This review critically examines the challenges posed by corrosion and scaling in geothermal heat exchangers, with a primary focus on three key mitigation strategies: the application of corrosion-resistant alloys, the utilization of protective coating systems, and the introduction of anti-scaling agents and corrosion inhibitors into the geothermal fluid. The paper discusses recent strides in these approaches, identifying promising advancements and highlighting impending obstacles. By bridging existing knowledge gaps, this review aims to offer valuable insights into material selection, heat exchanger design, and the progression of geothermal energy production. Ultimately, it contributes to the ongoing endeavor to harness geothermal energy as a sustainable and enduring solution to our energy needs.

1. Introduction

Geothermal power production presents an appealing energy resource characterized by low cost, minimal environmental impact, and global availability [1,2]. Its continuous availability throughout the day and year makes it a pivotal player in climate change mitigation compared to other renewables like solar and wind energy [3]. Geothermal energy holds immense growth potential. Nevertheless, it falls short of the International Energy Agency’s (IEA) Net Zero Emissions by 2050 Scenario, which demands a 13% compound average annual growth rate in geothermal power generation from 2020 to 2030 [4].

In 2015, global geothermal power plant capacity reached 12,635 MWe (megawatt electrical), projected to rise to 21,443 MWe by 2020 [5]. Although geothermal energy presently contributes a small fraction to the overall energy mix, it is set to expand due to its advantageous attributes for a sustainable energy future: widespread availability, base-load capacity without storage, minimal land footprint, and low emissions [6]. A current challenge in harnessing geothermal resources for power generation relates to managing corrosive geothermal fluids. Geothermal power plants extract energy from deep underground water pumped to the surface. During its underground residence at elevated temperatures (150–300 °C), the water interacts with subsurface rock reservoirs, leading to high salinity and acidity/alkalinity. These characteristics cause corrosion and scaling issues in wells and surface installations, long recognized as economic concerns [7,8].

Heat exchangers are among the most critical components in geothermal power plants, particularly in organic Rankine cycle (ORC) power plants [9], where heat exchangers account for a substantial portion of capital costs. Consequently, protecting these components from in-service deterioration is essential to enhance plant profitability. The protection of heat exchangers presents formidable challenges due to the array of potential damage mechanisms. Corrosion is a prevalent issue, occurring due to direct contact with geothermal fluid that can result in complete heat exchanger failure [10]. Additionally, the temperature drop within the heat exchanger invariably leads to scaling, which can impede heat transfer efficiency [11] or completely obstruct the heat exchanger tubes [12].

These challenges first emerged in the 1980s [13], prompting extensive investigations into mitigation strategies. However, accessing this wealth of information has proven challenging, as no comprehensive review consolidates the advances in degradation mitigation for geothermal heat exchangers. Accessible information is pivotal for material selection, heat exchanger design, and, by extension, the advancement of geothermal energy production. Therefore, to bridge this knowledge gap, this review aims to provide a comprehensive overview of published research on the corrosion and scaling of geothermal heat exchangers.

2. Heat Exchangers in Geothermal Power Plants

2.1. Types of Geothermal Plants

Geothermal power plants use subsurface heat sources to produce electricity. Each plant is different and adapts to the geothermal source available. Relevant parameters include the type of geothermal fluid (liquid, vapor), temperature, and pressure. These parameters define the plant design that will convert heat into electricity most efficiently. Four main types of geothermal plants can be distinguished.

• Dry Steam Power Plants: These plants use high-pressure, high-temperature steam directly from underground reservoirs to turn turbines and generate electricity. The steam is separated from any liquid water or brine that may be present in the reservoir. Dry steam plants are the oldest and most straightforward type of geothermal power plant. Vapor-dominated fields with such plants include Larderello and Monte Amiata (Italy), The Geysers (California), and Kamojang (Indonesia) [14].
• Flash Steam Power Plants: In these plants, high-pressure, high-temperature water from the geothermal reservoir is released into a lower-pressure environment, causing it to “flash” into steam. The steam is then used to drive a turbine. The remaining water is usually reinjected into the reservoir. Flash steam plants are the most common type of geothermal power plant [15].
• Binary Cycle Power Plants: Binary cycle plants use lower-temperature geothermal fluids, typically in the range of 93–166 °C. Instead of directly using the hot fluid to drive a turbine, they transfer the heat to a secondary fluid with a lower boiling point (such as isobutane, isopentane, or water and ammonia). This secondary fluid vaporizes and drives a turbine, which generates electricity. Binary cycle plants are more flexible in terms of the heat source they can use [16].
• Hybrid Systems: Some geothermal power plants combine different technologies, such as binary cycle systems with flash steam systems. These hybrid systems can optimize power generation by efficiently using both high-temperature and lower-temperature resources. These plants are generally designed to optimize the exploitation of the geothermal source at hand accounting for parameters such as pressure, temperature, composition, and nature of the fluid.

In Dry Steam Power Plants and Flash Steam Power plants, geothermal fluid is directly used to activate the turbine hence no heat exchangers are required. Heat exchangers are mainly used for Binary Cycle Power Plants, which require the heat to be transferred from the low-temperature geothermal fluid to the organic working fluid, as illustrated in Figure 1. In these plants, the heat exchanger is a critical component for efficiently transferring heat and maximizing the conversion of geothermal energy into electricity.

2.2. Types of Heat Exchangers

The most common heat exchanger design used in geothermal power plants include:

• Shell and Tube Heat Exchangers: Shell and tube heat exchangers are frequently used in geothermal power plants, especially in binary cycle and hybrid systems. They are known for their versatility and effectiveness in handling high-temperature and high-pressure geothermal fluids. In binary cycle power plants, these heat exchangers are used to transfer heat from the geothermal fluid to the secondary working fluid (e.g., isobutane or isopentane) to drive a turbine.
• Plate Heat Exchangers: Plate heat exchangers offer compact designs and efficient heat transfer capabilities, making them suitable for transferring heat between the geothermal fluid and the secondary working fluid.
• Ground Heat Exchangers: They are used in geothermal heat pumps. The heat exchanger is in direct contact with the ground and allows heat transfer with the thermal fluid cooling/heating the building. This type of heat exchanger is mostly used for domestic applications and will not be covered here.

The choice of heat exchanger type in a geothermal power plant depends on factors like the temperature and pressure of the geothermal fluid, the characteristics of the secondary working fluid in binary systems, and the overall plant design.

2.3. In-Service Degradation

Heat exchangers in geothermal power plants are exposed to harsh operating conditions, including high temperatures, pressure fluctuations, and the presence of corrosive substances in geothermal fluids. These conditions can lead to various degradation mechanisms over time. The main degradation mechanisms for heat exchangers in geothermal power plants include:

• Corrosion: Corrosion occurs when the metal surfaces of heat exchanger components react with the corrosive constituents present in geothermal fluids leading to impairment of the metal. These corrosive constituents, such as hydrogen sulphide (H₂S), CO_2, and other acidic compounds, can deteriorate the heat exchanger’s metal surfaces, leading to thinning of the materials and potential leakage. Corrosion can be mitigated via material selection, coatings, and water treatment.
• Scaling: Scaling occurs when minerals and solids dissolved in the geothermal fluid precipitate and form deposits on heat exchanger surfaces. Common scale-forming minerals include calcium carbonate, silica, and various metal sulphides. Scaling reduces heat transfer efficiency, increases energy consumption, and can lead to mechanical damage if left unchecked. Regular cleaning or anti-scaling treatments are necessary to mitigate scaling.
• Fouling: Fouling involves the accumulation of organic or inorganic materials on the heat exchanger surfaces, which can reduce heat transfer efficiency. Organic fouling may include microbial growth or algae, while inorganic fouling can result from particulate matter suspended in the geothermal fluid. Periodic maintenance, cleaning, and filtration can help prevent fouling.
• Erosion: Erosion occurs when high-velocity geothermal fluid, containing abrasive particles, impinges on heat exchanger surfaces. Over time, this can lead to material loss and reduced heat transfer efficiency. Proper design and material selection can mitigate erosion, but some degree of wear is expected in high-velocity flow areas.
• Hydrogen Embrittlement: In some geothermal environments with high H₂S content, hydrogen embrittlement can occur. Hydrogen can diffuse into the metal microstructure of heat exchanger components, making them brittle and susceptible to cracking and failure. Prudent material selection and control of hydrogen exposure are essential to prevent this type of degradation.

3. Environmentally Induced Degradation in Geothermal Plants

Geothermal Fluid Composition

Conventional geothermal fluids exhibit significant potential for corrosion due to the presence of various species or moeities. These species include hydrogen or hydronium ions (resulting in low pH levels), carbon dioxide (CO₂), hydrogen sulphide (H₂S), ammonia (NH₃), chloride ions (Cl⁻), and sulfate ions (SO₄²⁻), to name a few. Geothermal fluids generally maintain a low oxygen content due to the nature of their source underground, which is largely anoxic. The precise composition of geothermal fluids is location-dependent, often varying significantly due to the local geology. While rough estimates can be made based on geological factors such as sedimentary or volcanic origins, the exact composition is typically determined via drilling. Chloride concentrations tend to be lower in basaltic rock reservoirs [17] and higher in sedimentary rock formations [18]. Volcanic zones tend to promote the acidification of geothermal fluids, which may lead to enrichment in metals like iron, aluminum, calcium, magnesium, sodium, manganese, uranium, and thorium through the corrosion and dissolution of surrounding rocks [19].

The degradation of geothermal systems and the selection of materials depend heavily on thermodynamic parameters (temperature, pressure, phase, etc.) and fluid composition. To facilitate the selection process, efforts have been made to classify geothermal brines based on their composition, thermodynamic parameters, and phase. Common classification indices include total key species (TKS) or total dissolved solids (TDS), which sums the concentrations or combines the content of relevant chemical species in parts per million (ppm). Nogara et al. [20] proposed a geothermal brine classification, building upon the work of Ellis et al. [21] and Sanada et al. [22], as outlined in

Table 1. Classification of geothermal fluids revised by Nogara et al. [20], reproduced with permission from Elsevier.

Class	Fluid Characteristics	TKS (ppm)	Chloride Fraction (%)	pH	Volume of Gas in Vapor Phase	Temperature Inlet/Outlet (°C)	Total Alkalinity (ppm CaCO3)
I	Hyper saline, high temperature	>100k	99	<5/	<2.5	326/199	-
II-A	Acidic liquid dominated (Acid sulfate)	1k–60k	15–99	>3	-	-	-
II-B	Acidic liquid dominated (Acid chlorine)	500–40k	20–99	<3	-	-	-
III	High salinity, neutral pH	10k–20k	45–99	5–6	-	178–300/149–191	-
IV	Moderately saline, neutral pH, liquid dominated	500–10k	45–99	>5	<2.5	137–280/121–199	-
V-A	Low salinity, low pH, neutral pH	<5k	3–72	6.7–7.6	-	49–96/49–96	207–1239
V-B	Low salinity, low pH, alkaline pH	<5k	3–72	7.8–9.85	-	120–205/120–205	<210
VI-A	Vapor dominated without HCl	<1	-	-	<5	160–182/177–250	-
VI-B	Vapor dominated with HCl	-	-	-	-	-	-

. This classification considers the TKS index, salinity, acidity, and the phase of geothermal fluids.

4. Corrosion in Geothermal Environments

Corrosion presents a critical challenge in geothermal plants due to the aggressive nature of geothermal fluids. These fluids typically contain highly corrosive ions like chloride (Cl⁻) and may contain dissolved gases such as H₂S and CO₂. Moreover, elevated temperatures and dynamic flow conditions can accelerate corrosion by facilitating the mass transport of corrosive species and corrosion products. Corrosion is a multifactorial phenomenon that is inherently challenging to predict. In corrosion scenarios, the decision often revolves around accepting generalized and predictable corrosion or minimizing corrosion rates by opting for corrosion-resistant alloys (CRAs). The latter, however, exposes the system to unpredictable localized attacks. The former typically involves the use of cost-effective carbon steel (CS), a preference when replacement costs are low and outweigh the use of more expensive CRAs. Replacement costs are closely tied to the corrosion rate or unexpected corrosion-related failure, making it essential to determine the type of corrosion susceptible to occurring in the geothermal system.

4.1. Uniform Corrosion

Uniform corrosion, also known as general corrosion, is characterized by a relatively even and consistent corrosion attack that affects the entire exposed surface of a metal component. This type of corrosion typically occurs when geothermal fluids directly interact with metal surfaces over an extended period. Corrosion rates are commonly quantified in millimeters per year (mm year⁻¹). Uniform corrosion is preferred over localized corrosion due to its predictable nature, which can be factored into design considerations. In general, an acceptable corrosion rate falls below 0.3 mm year⁻¹ [23,24]. However, even this corrosion rate can be considered fairly high as such high corrosion rates would require significant corrosion allowance. Estimating the corrosion rate is particularly crucial when uniform corrosion poses the primary threat.

Under conditions of active dissolution, where soluble corrosion products are continuously exposed to the metal, the corrosion rate depends on thermodynamic factors such as temperature and acidity/alkalinity (pH). The corrosion rate increases with rising temperature and decreasing pH. However, in practical scenarios, even uniform corrosion becomes complex due to the deposition of corrosion products on the metal surface. In geothermal applications, the corrosion rate is influenced by various factors, including fluid composition, temperature, pH, pressure, metal material, and fluid flow characteristics. Uniform corrosion is commonly associated with carbon steels in geothermal plants, and some CS corrosion rates are detailed in

Table 2. Corrosion rates of CSs in geothermal environments.

Material	Test Conditions	Fluid	CR * (mm y−1)
J55 CS * [25]	Mass loss, PCO2 = 5 MPa, 65 °C	Synthetic, static	0.4
API L80 steel [26]	Tafel PP + LPR *, deaerated, 180 °C	Synthetic, static	0.02
API L80 steel [27]	Mass loss, 100 °C	Synthetic, static	0.308
	Mass loss, 200 °C		0.052
CS [28]	Tafel PP *, 30 °C	Real (TDS 161 mg/L, pH 4.68), static	0.23
		Real, 1.9 m s−1 flow	1
C45 CS [29]	Mass loss, CO2 sat., 80 °C–160 °C	Synthetic, liquid	1.4–3.9
		Synthetic, vapor	0.09–0.16
API P110 CS [30]	Topography measurements, CO2 sat., 80 °C	Synthetic, 500 rpm stirring	5
C45 CS [24]	Mass loss, CO2 purged, 80 °C	Synthetic, static	0.95
		Synthetic, static, with Ca2+	0.67
S235 JR steel [31]	Mass loss, CO2 purged, 70 °C	Synthetic, static	0.16
	Mass loss, CO2 purged, 150 °C		0.24

* CR = corrosion rate, CS = carbon steel, PP = potentiodynamic polarization, and LPR = linear polarization resistance.

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The influence of temperature on the corrosion rate of CS in geothermal environments is not straightforward and can vary based on specific conditions. Nikitasari et al. [28] and Huttenloch et al. [29] observed that the corrosion rate tends to increase with rising temperature and decreasing pH. However, the presence of protective corrosion product layers can mitigate corrosion if they are sufficiently dense and adherent. For instance, Huttenloch et al. [29] noted a reduction in the corrosion rate at 160 °C compared to 80 °C and attributed this to the formation of a denser carbonate corrosion product layer [29]. Similar observations of lower corrosion rates at higher temperatures were reported for API L80 steel [26,27], although explanations were not provided.

Mundhenk et al. [30] identified different corrosion mechanisms at various temperatures (80, 120, and 160 °C) for API P110 steel. Corrosion was uniform at 80 and 160 °C, with a corrosion rate an order of magnitude lower at 160 °C. At 120 °C, corrosion was more localized. The corrosion products identified at 80 °C consisted of a Fe₃C network, retained from the original metal microstructure, and impregnated with porous FeCO₃, offering limited corrosion protection. Above 160 °C, a more protective crystalline Fe-oxide film formed, further lowering the corrosion rate [32]. Aristia et al. [31] also observed a reduction in the corrosion rate at 150 °C compared to 70 °C, attributed to the formation of a dense crystalline FeCO₃ layer. At 70 °C, the corrosion product formation included chukanovite (Fe₂(OH)₂CO₃) and siderite (FeCO₃), which are less dense and, therefore, less protective.

In the liquid phase, the flow rate of the fluid significantly affects the corrosion rate, with increasing flow rate correlating with higher corrosion rates [28]. However, in the vapor phase, temperature is the dominant factor and the impact of flow rate is negligible [29]. In the vapor phase, corrosion is primarily induced by the formation of carbonic acid in condensed water in the presence of CO₂. The presence of oxygen can accelerate corrosion, particularly when introduced during maintenance operations [26].

4.2. Localised Corrosion

Unlike uniform corrosion, localized corrosion is highly unpredictable and characterized by a rapid rate of metal penetration that can lead to premature component failure. Only a small section of the material is affected, with two primary forms of localized corrosion: pitting and crevicing.

Pitting corrosion occurs when the protective oxide film or deposit layer is breached at a local point, exposing a small area of the metal to the corrosive environment. The exposed metal dissolves, creating a pit that serves as an anode relative to the surrounding protected outer surface. Pitting is an autocatalytic process, where pit growth creates conditions that further encourage pit development [33]. Detecting pitting corrosion is challenging as it often results in minimal weight loss, making it difficult to identify. The formation of a pit can have severe consequences for the structural integrity of a component, as it represents a stress concentration feature. Under specific conditions, stress and pitting can interact, leading to stress corrosion cracking (SCC). Typically, pitting is associated with alloys like stainless steel, Ni-alloys, and titanium alloys that rely on the formation of a protective oxide film for corrosion resistance. Pitting corrosion is a stochastic phenomenon linked to material defects (such as slip planes, grain boundaries, or inclusions), design issues, or environmental factors.

Crevicing differs from pitting in terms of its initiation mechanism, which originates from geometric considerations. Crevicing occurs in narrow, enclosed spaces on the metal surface. This type of corrosion is often characterized by accelerated metal loss within the crevice or gap, driven by differences in oxygen (aeration cell) concentration, pH, or other factors between the crevice and the surrounding environment [34]. Crevices can form due to poor component design or after the deposition of scale deposits. Localized corrosion is exacerbated by the presence of chemical species in the geothermal fluid that promote depassivation, such as Cl⁻, SO₄⁻, and H⁺ (low pH) [35].

4.3. Mechanically Assisted Corrosion

Mechanically assisted corrosion refers to a phenomenon where corrosion processes are accelerated due to the influence of mechanical forces, usually tensile stress. This acceleration can take different forms depending on the nature of the mechanical load. When the mechanical load involves erosive forces, it is specifically termed erosion–corrosion. Conversely, when cyclic stress is a contributing factor, it is referred to as corrosion fatigue. In systems where passivation is a key element of corrosion protection, mechanically assisted corrosion processes are believed to disrupt the protective passive film, thereby increasing the corrosion rate. In erosion–corrosion scenarios, corrosion is expedited by the relative motion between the metallic surface and the corrosive medium. This medium can take various forms, including fluids carrying suspended solid particles and/or bubbles, steam, or combinations thereof. This relative motion continually removes the passive film or corrosion products, exposing fresh metal surfaces to the corrosive medium [36]. Consequently, areas with higher flow velocity experience a faster rate of erosion–corrosion. In geothermal systems, erosion–corrosion occurs in high-velocity and pressure fluid conditions and may lead to distortion of heat exchanger tube shapes [12].

Corrosion fatigue, on the other hand, results from the combined effect of alternating stresses and exposure to a corrosive environment [37,38]. This mechanism is particularly significant in passivating metals, where stresses can facilitate pit formation. These pits act as stress concentrators and initiation sites for fatigue cracks. Corrosion fatigue typically leads to brittle fractures through the growth of transgranular cracks. In geothermal systems, sources of cyclic stress contributing to corrosion fatigue have been identified, such as steam turbine vibrations and the periodic expansion/contraction of pipelines due to fluctuations in the temperature of the transported steam or fluid [10].

4.4. Hydrogen and Hydrogen Related Stress Corrosion Cracking

Hydrogen cracking is a phenomenon characterized by the diffusion of hydrogen atoms into the crystalline lattice structure of a metal, causing subsequent damage. Hydrogen can originate from various sources, including manufacturing processes or as by-products of corrosion reactions (such as cathodic reactions involving reduction in water) [39,40]. These hydrogen atoms when inside the metal can recombine to form molecular hydrogen (H₂), which occupies a significantly larger volume than the atoms. This localized accumulation of hydrogen can create areas of elevated stress within the metal, potentially initiating and propagating cracks. Under the influence of tensile stress, these cracks have the potential to propagate, ultimately leading to the brittle failure of the material. In the presence of certain substances, such as hydrogen sulphide (H₂S) or arsenic compounds, the hydrogen cracking process accelerates. These substances act as recombination poison and delay the formation of molecular hydrogen (H₂), extending the residence time of atomic hydrogen on the metal surface thus increasing the probability of atomic hydrogen ingress in the metal. When this phenomenon occurs in an environment saturated with H₂S, followed by cracking of the metal in the presence of stress, it is commonly referred to as Sulphide Stress Cracking (SSC).

SCC shares similarities with hydrogen cracking with both qualifying as environmentally assisted cracking (EAC). The key difference is that corrosion serves as the catalyst for crack initiation and propagation in SCC. SCC requires both a corrosive environment and sustained surface tensile stress on a susceptible material [41,42]. Crack initiation can result from various factors, including the formation of a pit or crevice, microstructural defects, or high local stress. Once the crack initiates, the combined effects of the corrosive environment and stress accelerate crack propagation. Hydrogen cracking and SCC can occur simultaneously, further enhancing crack propagation.

5. Scaling

The economic viability of geothermal plants is frequently challenged by the precipitation of mineral phases, commonly known as scales, from geothermal fluids [7,43]. These scale deposits are not to be confused with those formed by corrosion products. In geothermal environments, the most prevalent scale deposits include silica [44], silicates [45], carbonates [46,47,48], sulfates [49], sulphides [50,51], as well as native metals like arsenic (As) [52], lead (Pd) [53], and antimony (Sb) [51].

Scaling occurs due to changes in geothermal fluid thermodynamic properties, such as temperature, pressure, and pH, during the energy production process. Heat exchangers, where fluid temperatures drop significantly, are particularly susceptible to scale formation, as shown in Figure 2. This presents a major challenge as scales act as thermal insulators [54]. Furthermore, scale buildup can reduce effective tube diameters or completely block them, diminishing plant productivity [12]. Scales can also lead to the accumulation of toxic chemicals, introducing additional risks and cost challenges during the operational phase. Notably, the presence of Ra 226 and Pb 210 radionuclides in some scale products classifies them as Naturally Occurring Radioactive Material waste (NORM classification), increasing disposal costs [55]. Additionally, scale formation significantly impacts the corrosion of surface installations in geothermal power plants [11]. Regular maintenance operations are necessary to remove scales, often requiring manual hydroblasting to clean tubes [54]. For instance, the geothermal plant at Soultz-sous-Forêts needs to be stopped three times a year to perform scale cleaning operations [56]. The introduction of oxygen during this process can lead to corrosion issues [26].

Silica scale (SiO₂) is a common product in geothermal plants due to its abundance in the rock reservoir and high solubility at elevated temperatures [51]. Silica precipitation is primarily influenced by temperature changes reducing solubility or an increase in silica concentration due to partial fluid flashing [50]. Calcium carbonate (CaCO₃) such as calcite and aragonite, is the predominant carbonate deposit in geothermal plants. The solubility of calcium depends on temperature and CO₂ pressure [51], resulting in calcite deposits near the fluid flashing point or in heat exchangers. Metallic sulphide scaling often occurs in volcanic or high Cl⁻ containing environments, such as Reykjanes (Iceland) [57] or Salton Sea (California) [18], due to the interaction between metals and H₂S present in the geothermal fluid. Common sulphide scales in geothermal environments include bornite (Cu5FeS₄), chalcocite (Cu₂S), barite (BaSO₄), galena (PbS), sphalerite (ZnS), and pyrite (FeS₂) [51,53].

Figure 2. Examples of scaling in heat exchangers: (a,b) Soultz-sous-Forêts plant (France), heat exchanger and scaling in the tubes, from [11] (CC BY); (c) Molasse Basin (Germany), cemented carbonate scale fragments clogging a heat exchanger after a few months of service, from [58] (CC BY).

Figure 2. Examples of scaling in heat exchangers: (a,b) Soultz-sous-Forêts plant (France), heat exchanger and scaling in the tubes, from [11] (CC BY); (c) Molasse Basin (Germany), cemented carbonate scale fragments clogging a heat exchanger after a few months of service, from [58] (CC BY).

In geothermal power plants, pressure primarily diminishes during the vertical transfer of fluids from the reservoir to the surface. Within tube and shell heat exchangers, the pressure is typically maintained between 18 and 25 to avoid detrimental degassing [59]. The pressure drop across the heat exchanger is influenced by the presence of rough scale deposits, leading to drag effects, yet it remains constrained within the range of approximately 3.5–5 bar [54]. Under these conditions, temperature predominantly governs mineral solubility, with pressure exerting a secondary influence. Nevertheless, pressure significantly impacts gas solubility, and any alterations in pressure conditions can result in CO₂ degassing. CO₂ degassing is highly undesirable since it raises acidity levels by forming carbonic acid and promotes precipitation of calcite [58]. To mitigate CO₂, it is advisable to operate geothermal systems at higher pressures (18–25 bar). However, turbulence-induced localized pressure fluctuations can still cause degassing and exacerbate calcite precipitation, as reported by Bosh et al. [58].

Information on scale precipitation mechanisms may be obtained using geochemical modeling software such as PHREEQC Version 3. PHREEQC is an open-source geochemical modeling software developed by the United States Geological Survey (USGS), designed for the scientific analysis of complex chemical reactions in aqueous systems [60,61]. Its accessibility has imposed it as a widely used tool in the field of geochemistry to calculate hydrochemical parameters such as mineral saturation states and dissolved gas partial pressures to better understand scale precipitation [32,53,58,62,63,64]. However, this software does not yet model corrosion processes.

6. Degradation Mitigation for Heat Exchangers

The degradation of geothermal heat exchangers during service can result in either complete component failure or reduced efficiency, necessitating maintenance operations. Failure typically stems from corrosion, erosion, or a combination of both, while the need for maintenance commonly arises from scaling. Both scenarios increase the operational costs of the plant and require mitigation. Three primary mitigation strategies have been explored: employing corrosion-resistant alloys, applying coatings, and adding scale/corrosion inhibitors to the geothermal fluid.

6.1. Corrosion Resistant Alloys

Using CRAs in heat exchangers is a common approach for mitigating corrosion in geothermal plants. Initially, titanium alloys and stainless steels found application in tube and shell heat exchangers for geothermal binary cycle plants, such as those in the Salton Sea reservoir (California) [65]. More information on materials for geothermal heat exchangers is given in

Table 3. Materials used for geothermal heat exchanger applications.

Material	Coating System	Key Insights
CS * [52]	-	Failure due to arsenic precipitation leading to galvanic corrosion
Titanium alloy [52]	-	Frequent cleaning required due to scaling
316L SS * [10]	-	Failure due to SCC * in the Cl− rich environment
904L SS, 254 SMO, DX 2205, SDX 2507, Alloy 825, TiGr2 [11]	-	Scaling independent of alloy used
316L SS, 254 SMO, Titanium, Inconel 625 [66]	-	Subsurface crackingTitanium not suitable due to erosion
Cupronickel (CuNi10Fe) [12]	-	Failure due to hydrogen embrittlement and sulphide stress cracking
316L SS [67]	Ni-Al2O3 Nanocomposite
304 SS [68]	SiO2, SiO2-FPS * and TiO2	Coating reduces fouling and corrosion
CS [69,70]	PTFE-blended PPS * system with a zinc phosphate (ZnPh)	-
CS EN 10028:2, P265G, 316L SS [71]	fluoropolymer-based and phenolic-based composite epoxy/sol-gel	Low impact from coatings on the overall thermal conductivity
CS [72]	PPS/PTFE/MWCNT *	Super-hydrophobic surface obtained
CS [9]	Ni-P-PTFE	-
CS 1015 [73]	Ni-W-P	Calcites and aragonites formation, good antifouling
CS 1015 [74]	Ni-Cu-P-PTFE	Good anti-corrosion and mechanical properties.

* CS = carbon steel, FPS = heptadecafluorodecyltri–isopropoxysilane compound, MWCNT = multi-walled carbon nanotube, SCC = stress corrosion cracking, and PPS = polyphenylenesulphide.

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Among CRAs, stainless steels (SS) are the most cost-effective, with the 316L grade being widely employed in geothermal heat exchangers [75]. However, 316L SS is not suitable for applications combining high-temperature and H₂S-containing environments [76]. The protective Cr-rich passive film destabilizes as the temperature increases from 30 °C to 130 °C. This destabilization was attributed to the replacement of the Cr-oxide film with a less protective Ni-rich film combined with the preferential adsorption of S instead of O at higher temperatures. In contrast, Inconel 625, a corrosion-resistant nickel-based alloy, is recommended for use in sulfur-rich, higher-temperature environments [77].

Stainless steel heat exchangers are also susceptible to environmentally assisted cracking, including hydrogen-induced stress cracking (HISC) and stress corrosion cracking (SCC). For instance, the SCC susceptibility of an HP-13Cr SS increases with rising temperature and CO₂ pressure, as reported by Qi et al. [42]. Yang et al. [10] also identified SCC as the cause of failure in a 316L SS tube and shell heat exchanger after a year of service.

Super austenitic stainless steels like 254 SMO are favored for geothermal applications, offering improved corrosion resistance in aggressive environments, such as those rich in Cl⁻ [78] or acidic [79] substances.

Davíðsdóttir et al. [66] examined the suitability of four CRAs (316L SS, 254 SMO, titanium ASTM Grade 2, and Inconel 625) for heat exchanger applications in two geothermal environments. Reykjanes (Iceland), a volcanic area, and Chaunoy (France), a sedimentary basin, served as test locations. In the Reykjanes geothermal site, the samples underwent testing within a pressure vessel at conditions of 18 bar and 200 °C, resulting in a dual vapor/liquid phase fluid. Conversely, at Chaunoy, the samples were positioned in a flow-line pipe, exposed to high salinity geothermal water with traces of oil at 9.5 bar and 94 °C, with a flow rate of 6.25 L s⁻¹. The two fluids had different acidity levels a lower pH of 5.15 at Reykjanes and a pH of 7.15. at Chaunoy. Overall, the exposure conditions at Reykjanes are more aggressive due to higher acidity, temperature, pressure, and the presence of two phases in the fluid. On 316L SS, different layers formed at Reykjanes and Chaunoy. At Reykjanes, the deposit comprised an inner Cr and Mo-rich layer with an outer layer dominated by Fe oxides after exposure. In contrast, the corrosion layer at Chaunoy consisted of a single layer of Fe, O, and Cr with scattered defects across the surface, accompanied by traces of S and Si. Inconel 625 specimens exhibited subsurface cracks with depleted Cr and Ni content at both Reykjanes and Chaunoy. While the exact cracking mechanism was not definitively explained, the authors suggested that rapid temperature changes combined with the presence of brittle inclusions could be plausible causes. The 254 SMO alloys experienced localized attacks during exposure at Reykjanes, manifesting as pits, Cr-rich cracks, and subsurface voids containing O and S. Similar subsurface cracks were observed after exposure at Chaunoy, with the crack path aligning with Al and Si inclusions. The titanium material also exhibited subsurface cracking after Reykjane exposure and suffered from erosion in both exposure conditions. The authors concluded that titanium grade 2 was unsuitable for these geothermal conditions. All four materials displayed signs of degradation, primarily in the form of cracks, which necessitate further investigation to ascertain their root causes. Long-term exposures and reports on the evolution of thermal conductivity are imperative for qualifying these materials for heat exchanger applications.

CRAs are effective for corrosion mitigation but do not address scale formation. For example, the titanium plate heat exchanger at Huka Prawn Farm requires frequent mechanical cleaning due to scale deposits [52].

6.2. Protective Coating Systems

While CRAs are commonly used in heat exchangers, they can be expensive and may require replacement due to corrosion-induced failures. Moreover, their thermal conductivity is notably lower than that of CS, as shown in

Table 4. Thermal conductivity of common metal alloys used for geothermal heat exchangers.

Alloy	Carbon Steel	Stainless Steel	DX Stainless Steel—2205	Nickel Alloys	Titanium—Grade 2	Nickel Alloys
Thermal conductivity (W m−1 K−1)	40–50	16–20	19	9–12	16.4	9–12

, resulting in reduced plant yields [70]. To reduce capital costs and increase the efficiency of heat exchangers, there is a potential to replace CRAs like titanium alloys and stainless steels with CS. However, as shown in Table 2, the corrosion rates of CSs in geothermal brines often exceed the acceptable rate of 0.3 mm year⁻¹ [23]. In dynamic flow conditions with real geothermal brine, corrosion rates can surpass 1 mm year⁻¹ [28], rendering such corrosion rates economically unviable due to the frequent need for heat exchanger replacement. In many cases, plain CS cannot be employed for heat exchangers due to its high corrosion rate and the formation of corrosion or scale products that impede heat transfer. As a solution, protective coating systems are applied to mitigate corrosion and scaling while taking advantage of the favorable thermal conductivity and cost-effectiveness of CS.

Protective coating systems primarily fall into three categories: organic, inorganic, and hybrid. Organic coatings offer corrosion protection via polymerization and crosslinking but are less effective at high temperatures [80,81]. Inorganic coatings consist mainly of ceramics, metals, metal oxides, or insoluble inorganic salts, exhibiting excellent thermal stability [82,83]. Ceramic coatings exhibit superior resistance to corrosion and wear at elevated temperatures [84]. Inorganic–organic hybrid coatings were developed to combine the superior corrosion protection of organic coatings with the thermal stability and mechanical resistance of ceramics and metals [85,86,87,88,89].

Numerous protective coating systems are documented in the literature, with Fanicchia et al. [90] identifying 23 organic and 20 inorganic coating systems for geothermal applications. For heat exchanger protection, the coating must possess excellent thermal conductivity, corrosion resistance, and anti-scaling/fouling properties. Achieving superhydrophobicity, often through multi-scale fractal features [84], or with the addition of PTFE fillers [72], is highly desirable to enhance these properties.

The utilization of coated CS for heat exchangers in geothermal power plants has been explored since the 1990s. Gawlik et al. [69,70] conducted tests on polymer-based coatings to safeguard CS tubes within a heat exchanger at the Hoch geothermal power plant in the Salton Sea reservoir, California. Their findings identified two promising systems: polyphenylene sulphide (PPS) and phenolic-based coatings. These coatings exhibited robust corrosion protection and had low bond strength with geothermal scale deposits, facilitating the cleaning process.

In a more recent study, Losada et al. [71] further explored phenolic coating systems along with two fluoropolymer-based paints and epoxy/sol-gel systems for the protection of geothermal heat exchangers. Their objective was to identify potential candidates to replace or enhance the existing heat exchanger at the Balmatt geothermal plant in Belgium, constructed using stainless steel. The base metals used were P265G CS and 316L stainless steel. The coatings underwent testing in a synthetic geothermal fluid at 130 °C and 40 bar for 570 h. The phenolic-based paint system exhibited strong adhesion with limited defects, but its surface energy increased after exposure, possibly reducing its scaling mitigation capability. Furthermore, electrochemical corrosion tests indicated that this coating allowed electrolyte permeation, rendering it unsuitable for corrosion mitigation. Consequently, the phenolic-based coating was not considered promising, while epoxy-based and fluoropolymer-based coatings demonstrated suitability. These coatings exhibited thermal resistances similar to or lower than the fouling factor currently used for the stainless steel heat exchanger (0.0004 m²K W⁻¹), with thermal conductivities ranging from 0.25 W m⁻¹ K⁻¹ (fluoropolymer-based) to 0.63 W m⁻¹ K⁻¹ (epoxy-based), as well as providing excellent corrosion protection and anti-fouling properties due to their low surface tension (<30 mN m⁻¹).

PPS coatings, initially identified as promising candidates for heat exchanger protection by Gawlik et al. [69,70], were subsequently enhanced by incorporating carbon fillers [91,92]. The addition of carbon fibers, approximately 7.4 μm in diameter and 3 mm in length, at varying concentrations (0.2, 0.5, 1.0, and 1.5 wt.%) to the PPS system, applied on AISI 1008 CS, was tested for 14 days in synthetic geothermal fluid (200 °C, 20,000 ppm CO₂, 13 wt.% NaCl) using electrochemical impedance spectroscopy (EIS). The optimal carbon fiber content was found to be 0.5 wt.%, which improved corrosion performance compared to pure PPS. This adjustment also enhanced thermal conductivity by 60% and mechanical properties, with performance improvements ranging from 1.5 to 2.6 times that of pure PPS. However, concentrations exceeding 0.5 wt.% resulted in excessive porosity, leading to solution permeation. This coating system was subsequently applied to protect CS tubes in heat exchangers at the Puna Geothermal Venture power plant in Hawaii [93]. The preparation of the substrate, either zinc phosphate layer application or galvanization, proved to be a critical factor in coating performance. Galvanized tubes experienced paint delamination after four weeks of service, leading to a 70% decline in heat transfer performance compared to its original state, surpassing the decline of 43% observed in uncoated CS.

Further developments in PPS/carbon coating systems were carried out by Yang et al. [72] for high-performance heat exchangers in geothermal plants. The study focused on a PPS/PTFE/MWCNT (multi-walled carbon nanotube) composite coating with varying MWCNT loadings (0 to 10 wt.%). The authors achieved a super-hydrophobic surface with a maximum water contact angle of 171° at 5 wt.% MWCNT, in contrast to 80° and 103° for pure PPS and PPS/PTFE, respectively. The optimal loading range for MWCNT was between 3 and 5 wt.%, as concentrations above this range led to detrimental aggregation, affecting mechanical properties.

Several organic coating systems have seen long-term service, as exemplified at Soultz-sous-Forêts in France. Here, an undisclosed polymeric paint system was employed for the protection of Organic Rankine Cycles (ORC) heat exchangers from 2008 to 2012 [94]. Initially, the paint system displayed promise in reducing scaling. However, in 2012, the appearance of paint blistering and spallation (Figure 3) raised concerns. Chemical analysis of detached paint fragments revealed varying compositions between the surface exposed to geothermal fluid and the underlying steel substrate. The fluid-exposed surface contained strontium-rich barite (Ba1-xSrxSO₄), galena (PbS), and minor mixed sulphides ((Fe, Sb, As)Sx). In contrast, the substrate surface exhibited a mixture of iron oxides, hydroxides, and/or carbonates, indicating underlying substrate corrosion. Consequently, it was concluded that paint systems held potential for scaling and corrosion protection but required optimization for specific service conditions. To address this need, the study explored a range of new thermosetting and thermoplastic paint systems designed for exposure to geothermal fluid at 160 °C and 20 bar for 6 months, including an epoxy mixed with PTFE. However, the paper did not report the results of these tests.

Metallic coatings, particularly electroless nickel plating-based systems, are intensively investigated for geothermal applications. This process entails the chemical deposition of a nickel–phosphorus alloy onto a substrate, offering a cost-effective solution that does not require a power supply, unlike electrodeposition. Studies have shown that Ni, Ni-P, and Ni-W-P coatings effectively reduce calcium carbonate scaling when compared to surfaces such as PVC, CS, 316 stainless steel, and copper in heat exchangers [95,96]. Interestingly, Ni-based coatings predominantly exhibited aragonite scaling, while non-Ni surfaces were primarily covered in calcite. Ren et al. [73] explored the impact of a Ni-W-P coating on fouling formation in a heat exchanger, reporting a significant reduction in fouling. Exposure to boiling tap water for 24 h resulted in a threefold reduction in fouling, attributed to the role of corrosion products and features (e.g., cracks and pits) as fouling catalysts. The presence of the coating effectively mitigated corrosion, subsequently reducing fouling. In this study, aragonite preferentially deposited on uncoated mild steel, whereas calcite dominated on Ni-W-P-coated steel, contrasting with previous observations [95,96], necessitating further investigation.

The addition of PTFE to the Ni-P system enhances corrosion and scaling protection by increasing hydrophobicity. Fanicchia et al. [97] assessed electroless plated Ni-P/Ni-P-PTFE coatings on CS for safeguarding geothermal heat exchangers. In their study, conducted by the Geo-Coat consortium, the corrosion resistance of these coatings was evaluated in a simulated geothermal environment using electrochemical tests at 25 °C in a 3.5 wt.% NaCl solution with a constant pH of 4. The results indicated that Ni-P/Ni-P-PTFE coatings exhibited exceptional performance, displaying the lowest corrosion rates compared to all other coatings tested. Furthermore, their corrosion rate was comparable to that of the 254 SMO bulk alloy. However, the promising performance observed in the controlled environment did not align with the outcomes of exposure tests conducted in real geothermal environments, as later reported by the same research group requiring further investigation.

Cheng et al. [74] investigated a Ni-Cu-P-PTFE coating system applied to CS. They identified an optimum PTFE loading of 12 mL L⁻¹, beyond which pore content increased due to the presence of PTFE particles, outweighing the hydrophobicity benefits. Pores in the coating were shown to decrease thermal conductivity, mechanical properties (microhardness and elasticity modulus), and corrosion resistance. While the corrosion rate of a CS heat exchanger coated with the Ni-Cu-P-PTFE system decreased from 1 mm year⁻¹ to 0.16 mm year⁻¹ in 10% HCl, no information was provided regarding localized corrosion resistance. Thus, this coating requires further testing in geothermal environments.

Ceramic coatings are commonly used for their chemical stability and good mechanical performance. They can serve as fillers in organic or metallic coatings or act as the primary matrix. Various ceramic fillers, such as Al₂O₃ [98], TiO₂ [99], SiC [100], and ZrO₂ [101], have been used to enhance wear and corrosion resistance in coating systems. These insoluble particles play a crucial role in reducing corrosion-induced damage by impeding the propagation of corrosion features [67]. Ceramic coatings offer significant promise for safeguarding geothermal heat exchangers, particularly due to their effective corrosion protection in highly corrosive environments. For instance, a Pd-Ni-TiO₂ coating has been utilized on 316L stainless steel to mitigate corrosion damage in hot dilute sulfuric acid (20 wt.% H₂SO4 solution at 60 °C) [102]. Ceramic coating systems have been explored in the GeoHex project for geothermal applications [84,103,104]. TiO₂ and TiO₂/Al₂O₃ coatings were deposited on CS using suspension plasma spray (SPS) and solution precursor plasma spray (SPPS). SPPS was favored for better stoichiometric control as it employs precursor particles, and introduces micro- and nano-features, like columns and lamellae, improving hydrophobicity. The results indicated that SPPS-deposited TiO₂/Al₂O₃ coatings displayed hydrophobic properties (water contact angle 126°), making them more promising for geothermal heat exchanger protection compared to hydrophilic TiO₂ coatings (water contact angle 18°).

In a study conducted by Song et al. [68], various ceramic coatings, including TiO₂, SiO₂, and SiO₂-FPS (a heptadecafluorodecyltri–isopropoxysilane compound), were applied to AISI 304 stainless steel using sol-gel and liquid phase deposition (LPD) methods. These coatings were assessed for their effectiveness in mitigating scaling and corrosion in heat exchangers exposed to hot-dry-rock (HDR) geothermal water. The experiments were conducted in two types of simulated geothermal fluid from the Yingshen area of China. One fluid was rich in calcium carbonate for scaling tests, while the other closely resembled real geothermal water, containing HCO₃, Cl⁻, and Na⁺ ions. The fluid temperature at the heat exchanger inlet was maintained at 150 °C during exposure experiments, which lasted up to 21 days. The results indicated that when exposed to the scaling-specific fluid, LPD TiO₂ and sol-gel TiO₂ coatings reduced fouling by 48% compared to the uncoated 304 alloys. Furthermore, when tested with the simulated real geothermal fluid, sol-gel SiO₂ and SiO₂-FPS coatings demonstrated a reduction in fouling of over 30% compared to the bare substrate. Electrochemical tests conducted on these coatings also revealed a substantial reduction in corrosion rates, approximately 60%, in comparison to the Type 304 stainless steel substrate. These promising results suggest practical applications for these coatings for in-service protection of geothermal heat exchangers, as concluded by the authors.

6.3. Anti-Scaling Agents and Corrosion Inhibitors

Inhibitors for scaling (anti-scaling agents) and corrosion are commonly employed in the oil and gas industry. Anti-scaling agents are classified into two main categories based on their function: inhibitors, which hinder crystallization, and dispersants, which disperse mineral crystals once formed. Inhibitor-type anti-scaling agents, including phosphonates and polycarboxylates [105], are particularly effective in controlling barite formation. On the other hand, dispersant-type anti-scaling agents excel in reducing metal sulphide scaling [56]. Corrosion inhibitors predominantly consist of organic compounds that interfere with either the anodic or cathodic corrosion reactions, forming a protective barrier on metal surfaces [24]. Among these, nitrogen-based organic surfactants like imidazolines and amines, commonly used in the oil and gas industry to protect mild steel [106], have been extensively applied to mitigate the corrosion of CS in geothermal environments [107].

A recent study by Huttenloch et al. [29] examined the performance of commercial inhibitors at temperatures of 80 °C and 160 °C in artificial brines. Their effectiveness and resulting corrosion rates were found to depend on factors such as the nature of the active species, temperature, and hydrodynamic conditions. In static conditions, an imidazoline-based product exhibited greater efficiency than an amine-based counterpart, achieving up to 77% efficiency at 200 ppm and 80 °C. However, when stirred, one amine-based product displayed higher efficiency. Nevertheless, some increase in the corrosion rate was observed after product application, especially at elevated temperatures, suggesting that the products or their dosing methods require further optimization.

Spinthaki et al. [108] assessed the efficacy of a methacrylate-structured, grafted co-polymer known as PEGPHOS-LOW in preventing the precipitation and deposition of common geothermal scales, such as silica, silicates, sulphides, and calcium carbonate. The selection of this inhibitor was based on previous tests involving similar co-polymers containing polyethylene glycol (PEG) and phosphonate grafts. The study employed four artificial geothermal brines designed to simulate saturated geothermal well fluids. PEGPHOS-LOW, comprising 34 PEG20 grafts and 14 phosphonate grafts, served as a dual-scale control additive, inhibiting scale formation and dispersing scale particles. While PEGPHOS-LOW exhibited dose-dependent scale inhibition and dispersion properties, high concentrations were required for effective performance due to the pronounced scaling propensity of the brine.

A comprehensive testing campaign was initiated in the Upper Rhine Graben geothermal plants to efficiently mitigate scaling and corrosion using anti-scaling agents and corrosion inhibitor additives [109]. In the initial phase of the project (SUBITO project), anti-scaling agents were assessed to prevent barite deposition [110,111]. Several anti-scaling agents involved phosphonic acid-based formulations, while others remained undisclosed. Seven sulphide anti-scaling agents and four corrosion inhibitors were evaluated at two geothermal power plants: Insheim (Germany) [53] and Soultz-sous-Forêts (France) [56]. The results demonstrated that antiscalant compatibility varied between the two plants. The most suitable antiscalant at Soultz proved incompatible at Insheim, leading to system clogging attributed to the higher temperature and calcium concentration of the Insheim geothermal fluid [109]. While sulfate scaling, such as barite, was effectively reduced using fluid-compatible sulfate anti-scaling agents at both plants, the surface installations encountered the formation of thin, brittle black scales (approximately 3–5 mm thick) on pipe walls. These scales comprised PbS, elemental Pb, As, Sb, and minor oxide minerals, raising concerns due to the toxicity of Pb, As, and Sb. Additionally, the deposition of metallic lead and arsenic could result in heat exchanger failure due to galvanic corrosion [112]. In the project’s second phase, the highest scale reduction was achieved using a combination of barium sulfate antiscalant and amine- and imidazoline-based corrosion inhibitors, resulting in a scale mass reduction of 60 to 70% (scale thickness < 1 mm after 4 months) [29]. Additionally, the use of corrosion inhibitors effectively prevented localized corrosion incidents [109]. However, amine-based inhibitors, such as Cetamine G815, exhibited reduced efficiency in the presence of Ca⁺ ions, emphasizing the significance of inhibitor concentration, with maximum efficiency reported at 200 ppm [24].

Several factors hinder the widespread adoption of inhibitors in geothermal plants. Existing studies may lack completeness (e.g., medium temperature data or undisclosed inhibitor nature) or may be outdated, necessitating the exploration of improved products. Moreover, there is limited knowledge regarding behavior at high temperatures (<160 °C), and the potential impact of inhibitors on localized corrosion remains insufficiently investigated despite concerns that they may induce localized corrosion [113,114].

6.4. Failure Cases of Heat Exchangers

Julian et al. [52] highlighted a CS heat exchanger failure at a plant in the Taupo Volcanic Zone, New Zealand. CS heat exchangers are typically employed in situations where the geothermal fluid’s temperature exceeds 180 °C, minimizing silica scaling, while stainless steel is used for lower-temperature fluids. In this instance, three heat exchanger tubes developed pits and perforations after 24 months of operation, with elevated arsenic levels detected near the pits. The authors attributed the perforation to galvanic corrosion induced by elemental arsenic deposition. Slow flow conditions in the middle tube row of the heat exchanger led to gas buildup (CO₂, H₂S) in the upper part of the tube and ammonia in the lower part of the liquid phase, resulting in acidification of the condensing water between them. Countermeasures included redesigning the heat exchanger for uniform flow through multiple tubes.

Stainless steel is a common material for heat exchangers but can experience localized corrosion in Cl⁻ rich environments. Yang et al. [10] recently reported a case of SCC failure in a tube and shell heat exchanger made of 316L stainless steel after one year of service (inlet temperature of 120 °C). The resulting crack is shown in Figure 4a. The failure resulted from multiple factors, including poor material quality and environmental conditions. SCC initiation was influenced by the unstable passive film, which was compromised by lower levels of nickel and molybdenum compared to standards, along with the presence of Cl⁻ in the secondary fluid. The authors recommended replacing 316L stainless steel with the more SCC-resistant 2205 duplex stainless steel, relieving residual stresses before service, and reducing Cl⁻ content in the secondary working fluid. Wang et al. [115] demonstrated the superior SCC resistance of 2205 duplex stainless steel in a copper chloride environment at elevated temperatures (200 °C).

Morake et al. reported the premature failure of a cupronickel (CuNi10Fe) shell-and-tube heat exchanger after only five months of service. Operating at 144 °C (inlet) to 27 °C (outlet) at a pressure of 2 bars, the failure was attributed to thermally induced fatigue, exacerbated by the presence of H₂S in the geothermal fluid, resulting in sulphide-induced SCC as shown in Figure 4b. Thermal fatigue has also been identified as a cause for early heat exchanger failures in various materials, including copper [116], stainless steel [117], and low ferritic stainless steel (ASTM A213 grade T11) [118]. While these failures did not occur in real geothermal environments, it underscores the importance of considering thermal fatigue in geothermal heat exchangers, particularly when dealing with H₂S-rich fluids. Residual stresses remain a critical parameter to address in such cases, as highlighted in the failure reported by Yang et al. [10].

7. Conclusions

Heat exchangers play a crucial role in geothermal power plant efficiency. However, their direct exposure to geothermal fluid, subject to varying thermodynamic conditions throughout its course, poses significant challenges related to scaling and corrosion. Additionally, heat exchangers must maintain optimal thermal conductivity, necessitating clean surfaces free from fouling, scales, and corrosion products. Addressing these challenges involves three primary methods: using CRAs, employing coating systems, and introducing anti-scaling agents and corrosion inhibitors to the geothermal fluid.

CRAs are widely used to solve corrosion problems in geothermal heat exchangers. EAC and residual stress relief must be considered during the design and manufacturing stages. CRAs, while effective against corrosion, do not prevent scaling and tend to be costlier with lower thermal conductivity compared to carbon steel.

Coating systems offer a promising solution as they can mitigate both scaling and corrosion. Coated carbon steel, in particular, emerges as an attractive option for geothermal heat exchangers due to the combination of affordability and the good thermal conductivity of carbon steel. Numerous coating options, including inorganic, organic, and hybrid varieties, exist. However, most coatings have yet to undergo rigorous testing in service conditions, encompassing large and intricate surfaces, dynamic fluid behavior, and temperature cycling. The ideal coating should possess high thermal conductivity while reducing corrosion to acceptable levels, striking a balance between maintenance and production costs.

General recommendations include designing heat exchangers with flexibility to adapt to unforeseen issues, given the complexity of geothermal systems that prevent perfect anticipation. In the case of tube and shell heat exchangers, minimizing the presence of convoluted “U” shapes is recommended to enhance the ease of cleaning procedures [54]. Proactive planning should encompass the possibility of component replacement necessitated by corrosion-induced failures, requiring convenient access to the heat exchanger and straightforward dismantling procedures. Additionally, allowing regular visual inspections to monitor the potential accumulation of scale deposits may pre-empt complete obstructions. Employing a combination of mitigation strategies, such as anti-scaling agents, inhibitors, and coating systems, can maximize efficiency. Due to the multitude of parameters influencing corrosion and degradation (e.g., steam-to-liquid ratio, corrosive ions, temperature, pressure, particles, fluid velocity), in situ testing is imperative for material suitability assessment. Accurately replicating in-service conditions in the laboratory is highly complex and may yield unrepresentative results if not precisely modelled. Critical parameters to replicate include fluid velocity, aeration, temperature, pressure, concentrations of key ions (e.g., Cl, Ca), and dissolved gases (e.g., H₂S, CO₂).