Enhancing the Safe Management of Oil–Gas Gathering and Transportation Stations to Ensure Efficient Petroleum Transportation and Storage

Abstract

Corrosion and scaling critically threaten the safety and efficiency of oil–gas gathering stations. Through field inspections, water chemistry analysis, scale characterization, and corrosion simulation in Yanchang oilfield, this study identifies severe localized damage in key components—such as valves, bends, and injection pipelines—with service lives of only 1–2 years. Analysis of over 200 scale samples revealed that CaCO₃ (42 wt%) and CaSO₄ (23 wt%) were the predominant scale types. High salinity >56,000 mg/L, Cl⁻ >31,000 mg/L, and Ca²⁺ promote under-deposit pitting, galvanic corrosion (e.g., Cu–steel couples), and erosion-corrosion at high-velocity zones. Simulations based on OLI Analyzer Studio (a professional thermodynamic simulation software for electrolyte solution and high-salinity brine systems) reveal that the carbon steel (the primary material for the process pipelines and water injection pipelines in the studied oil–gas gathering and transportation stations) has a corrosion rate rising from 0.078 mm/year at 25 °C to 1.94 mm/year at 90 °C. Despite common use of coatings and cathodic protection, these measures often fail to address site-specific failure mechanisms. The study advocates a tailored mitigation strategy combining material compatibility, real-time water monitoring, optimized filtration, and component-level design. This integrated approach enhances asset reliability and operational safety in onshore oilfields.

1. Introduction

Oilfield technology has advanced alongside economic growth, with a growing focus on achieving efficient production. Oil and gas gathering stations play a central role in modern oil production by managing the transportation and storage of petroleum. However, ensuring their safe and reliable operation remains a major challenge [1].

Currently, oilfield gathering and transportation stations face a range of operational challenges that pose significant risks to oilfield exploitation. Corrosive fluids flowing through pipelines can cause erosion, wall thinning, and corrosion, which are further exacerbated by factors such as microcell corrosion and soil corrosion [2,3]. Most oil pipelines are metal-based and outer wall corrosion arises from chemical interaction with carbon dioxide and hydrogen sulfide, primarily in buried pipes The synergistic effect of CO₂, H₂S, and high chloride brines can lead to accelerated localized and uniform corrosion, particularly under high-pressure conditions [4]. Meanwhile, inner wall corrosion is primarily caused by the presence of water contained in crude oil, forming a water film on the inner pipeline wall. The metal pipe-line material itself contains iron and impurity elements [5,6], leading to ongoing electrochemical corrosion due to the potential difference and close contact between iron and impurities [7]. The process pipelines, water injection pipelines and transportation pipelines of the oil–gas gathering and transportation stations in Yanchang Oilfield are predominantly fabricated from carbon steel, which is widely used in onshore oilfields for its cost-effectiveness and engineering applicability, but is highly susceptible to corrosion and scaling in high-salinity brine environments. Overall, addressing the challenges posed by corrosion in oil–gas gathering and transportation stations is crucial to maintaining the safe and efficient functioning of oilfields.

During the usage of tank bodies, various corrosions can occur, with the most severe often found at the tank’s bottom [8]. The corrosion at the tank bottom is predominantly caused by microbial and electrochemical factors, with continuous pitting corrosion eventually leading to perforation. By contrast, pitting corrosion also represents the primary form of external corrosion on the tank top, which is mainly attributed to the interaction between the oil and gas inside the tank and the ambient oxygen. In addition to tanks, various equipment used in the oil and gas industry are susceptible to corrosion which include: ① Pipelines, ② Three-phase separators, ③ Pressure vessels, ④ Storage tanks and silos, ⑤ Valves and Piping components [9]. In addition to tank bodies, the three-phase separator is a crucial pressure vessel equipment used for the three-phase separation of oil, gas, and water [10]. During its operation, the high liquid flow rate, often containing sediment, can cause erosion and wear on the separator and safety valve inlet [11].

In oil and gas gathering and transportation stations or systems, fluctuations in temperature, pressure, and the oil–gas–water equilibrium foster an environment conducive to the deposition of various inorganic and organic scales. These deposits can accumulate in subterranean reservoirs, wellbores, casings, and production tubing, leading to severe pipeline blockages, reduced productivity, and impeded production. Consequently, scaling has emerged as a prevalent challenge in oilfields nationwide [12].

The composition of scales in gathering and transportation stations varies depending on the quality of the produced liquid, and their formation mechanism is primarily governed by the precipitation-dissolution balance of refractory inorganic salts and formation minerals in water. Our team has conducted extensive research, collecting and analyzing over 200 scale samples from stations in oilfields such as Zhongyuan, Yanchang, and Changqing. The results, summarized in Figure 1, indicate the following composition distribution: ① Calcium carbonate scale (CaCO₃), accounting for approximately 42 wt% of the samples; ② Calcium sulfate scale (CaSO₄), comprising about 23 wt% of the samples; ③ Barium sulfate and strontium sulfate scale (BaSO₄, Ba_0.75Sr_0.25SO₄), accounting for around 18 wt%; ④ Magnesium carbonate scale (MgCO₃), representing about 7 wt%; ⑤ Corrosion products and other main samples account for roughly 10 wt%. All the results can be totally shown in Figure 1 below.

To prevent pipe blockages caused by fouling, regular pipe cleaning is essential, with a routine frequency of once a month and, in some cases, an extended interval of once every six months [13].

Effective measures to control scale formation in gathering and transportation systems include the use of chemical inhibitors, mechanical cleaning methods, and proper pipeline design and maintenance [14,15]. By implementing suitable scale management strategies, the oil and gas industry can mitigate the detrimental effects of scale formation and ensure smooth and efficient operations [16].

Based on the above analysis, this research group has recognized the significance of various influencing factors in the actual environment that affect corrosion and scaling processes. Identifying the primary controlling factors is crucial for mitigating or resolving corrosion and scaling issues. In this study, the focus is on the corrosion and scaling challenges present in the process pipelines and valves of a conventional oil–gas gathering and transportation station located in northern Shaanxi Province, China.

Many existing studies lack comprehensive evidence and tend to focus primarily on predicting scaling trends and the impact of individual influencing factors [17]. However, understanding the role of single factors in harsh environments, as well as the primary corrosion mechanisms under the synergistic influence of multiple factors, remains essential. Therefore, there is an urgent need for a comprehensive analysis of the real and complex corrosion environmental factors to identify the dominant damage mechanisms and support corrosion management and preventive strategies in oilfield water injection systems.

To this end, the most probable influencing factors were systematically identified from the multitude present in the complex field environment. This study employed a combination of methods, including on-site corrosion inspection, water quality analysis, scale sample characterization, scanning electron microscopy (SEM), and corrosion trend simulation. These approaches enabled the determination of the main controlling factors for corrosion in waterflood pipelines, followed by a comprehensive discussion and analysis of the underlying corrosion mechanisms.

As summarized in

Table 1. Common Corrosion Failure Components at Gathering Stations.

Number	Installation Location	Service Life	Operational Temp. Range/°C
1#	Three-Phase Outlet Valves	One year	25–40 (15)
2#	Three-Phase Separator Outlet Valves	One year	25–40
3#	Valve Copper Sleeve Detachment	One year	20–35
4#	Vertical Disc-Sealing Butterfly Valve	One year	25–40
5#	378 Injection Water Pipeline and Joints	Two years	25–40
6#	Transportation Pipe	One and a half year	30–40
7#	Partial Bending Pipes in Gathering Pipelines	One and a half year	30–40
8#	Eccentric Reducer	One and a half year	30–40
9#	Crude Oil Pipeline	One and a half year	30–40

, which compiles field observations of corrosion and scaling from various stations in the area, key equipment exhibits severely limited service life due to these issues. Specifically, the outlet valve of the three-phase water chamber requires replacement after approximately 1 year, the oil removal settling cylinder after 1.5 years, and the 3#378 waterflood pipeline—having the longest service life—after only 2 years. All components show evident signs of corrosion and scaling.

These findings are intended to inform and guide the development of effective anti-corrosion management strategies and preventive measures for the waterflood pipeline system in the region.

2. Experimental Procedure

In this manuscript, several common corrosion failure components at gathering stations were investigated and their installation location and duration time during operation are shown in Table 1.

All the above corrosion failure components (pipelines, valves and their accessories) take carbon steel as the main structural material, with copper sleeves used in the valve stem matching parts to form Cu–steel galvanic coupling structures. Water quality was assessed using a comprehensive set of physical, chemical, and biological indicators. The obtained data were then benchmarked against the pertinent national water quality standards to determine the level of compliance. The analytical methodology, including the choice of parameters and techniques, was designed in accordance with these standard guidelines and adapted to address the specific objectives of this investigation. The surface and cross-sectional morphologies of the corrosion products and scale layers were examined using a field-emission scanning electron microscope (FE-SEM, model: Zeiss Sigma 300, Zeiss, Oberkochen, Germany). Accelerating voltages of 5 kV and 15 kV were applied for high-resolution imaging and EDS analysis (Energy Dispersive Spectroscopy), respectively, with working distances maintained between 5 mm and 10 mm. Imaging was performed at magnifications ranging from 50× for macroscopic features to 50,000× for microstructural details. For cross-sectional analysis, selected corroded pipe samples were cut, mounted in conductive resin, and polished using a series of silicon carbide papers followed by diamond suspensions down to 0.25 µm. To prevent charging, all samples were sputter-coated with a thin gold layer prior to SEM observation. Energy-dispersive X-ray spectroscopy (EDS) was carried out using an Oxford Instruments X-MaxN 80 detector attached to the SEM. Elemental composition and distribution were acquired at multiple points and areas on each sample, with a typical spectrum acquisition time of 60 s per point. The EDS data were processed with the AZtecLive software (v4.3, Oxford Instruments, Abingdon, UK) suite to quantify the proportions of major elements (e.g., Fe, Ca, O, C, Cl, Si) in the scale and corrosion products [18].

3. Results and Discussion

3.1. Macroscopic Inspection of Corrosion Deposits in Gathering Station Components

The separator is a crucial piece of equipment in the surface system of oil and gas fields. Its primary function is to separate the transported medium into three phases and eliminate free water and impurities. The separated free water and impurities are stored temporarily in the liquid bag located at the lower part of the separator, which creates a highly corrosive environment [18].

The three-phase outlet valve serves as a vital component of oilfield facilities, with corrosion predominantly occurring within its valve cavity. Given the valve’s connection to the oil pipeline, its cavity is frequently subjected to scale deposition from produced water, alongside sediment accumulation and erosion-corrosion. The buildup of corrosion products and mixed sediments derived from produced water can induce valve cavity blockage, which in turn leads to valve malfunction, as illustrated in Figure 2. Furthermore, Outlet pressure Valve 2 is operational on three separators, tasked with separating water from the collected oil and gas mixture. The valve cavity in this case is subjected to erosion from high-velocity sewage sediment and a small amount of unseparated crude oil. Consequently, the outlet valve becomes clogged with sediment and corrosion products, as depicted in Figure 2. These instances of corrosion and sediment accumulation underscore the significance of employing effective corrosion protection measures and regular maintenance of critical equipment in the oil and gas industry. Implementing corrosion-resistant materials and proactive cleaning and inspection practices can help extend the service life and reliability of essential components like separators and outlet valves, ensuring smooth and efficient operations in oil and gas fields [19].

Figure 3 illustrates the macro-corrosion morphology of the valve copper sleeve trip. The valve copper sleeve is positioned alongside the valve stem. The copper sleeve, featuring an internal thread, and the valve stem, with an external thread, engage in relative motion to control the opening and closing of the valve plate. The valve copper-sleeve trip is chiefly caused by galvanic corrosion of the steel stem threads. Additionally, during the relative movement between the copper sleeve and the valve stem, wear is inevitable, resulting in damage and failure of the thread within the copper sleeve. Consequently, the steel threads are almost completely stripped, whereas the copper sleeve retains its dimensions.

Moreover, the relative motion between the copper sleeve and the valve stem during operation induces mechanical wear. This wear progressively damages the threads of the copper sleeve, ultimately leading to its failure. To mitigate this issue, it is crucial to incorporate corrosion and wear resistance into the design and material selection for the valve stem and copper sleeve. Effective countermeasures include applying corrosion-resistant coatings or opting for compatible material pairing to minimize galvanic corrosion risk. Furthermore, establishing a routine maintenance and inspection schedule is essential for the early detection of wear and corrosion, enabling timely intervention to preserve the long-term integrity and reliability of the valve system.

Figure 4 depicts a center vertical straight plate seal butterfly valve used in the ex-traction line with a service life of one year. This device is designed to rotate a disc-shaped butterfly plate within the valve body around its own axis, allowing for opening, closing, or flow regulation. In oil and gas pipelines, the valve primarily serves the purpose of cutting off and intercepting flow. The failure of the valve occurs at the center disc of the butterfly plate. Corrosion products and sediment tend to accumulate and rust the disc, hindering its normal rotation and leading to valve failure. As the valve operates in an environment with potential exposure to corrosive substances and sediments carried by the fluid medium, the center disc is particularly susceptible to corrosion and sediment deposition.

Over time, the accumulation of corrosion products and sediment on the disc can cause it to become immobilized, preventing its proper rotation and hampering the valve’s functionality [20]. This loss of mobility and operation can result in flow disruptions, leakage, or complete valve failure, affecting the overall efficiency and safety of the ex-traction line. To address this issue and enhance the performance and longevity of the butterfly valve, regular inspection and maintenance are essential. Implementing proper cleaning procedures and protective measures, such as the use of corrosion-resistant materials or coatings, can help mitigate the impact of corrosion and sediment deposition on the valve’s critical components. Additionally, prompt identification and rectification of any early signs of corrosion or sediment buildup can prevent severe damage and ensure the reliable operation of the valve in the oil and gas pipeline system.

In the late stage of oilfield production, declining reservoir pressure can prevent crude oil from flowing naturally. To maintain extraction, water is injected to repressurize the reservoir. This process, known as waterflooding, involves pumping water from surface sources into the formation to enhance oil recovery. The waterflood pipeline, shown in Figure 5, is designed to deliver this injection water.

Over a period of two years in service, the waterflood pipeline encountered an issue due to the high salinity of the injected water, coupled with sediment present in the water. These factors led to the blockage of the pipeline. The presence of high salinity in the water can lead to the deposition of salts and other dissolved minerals on the inner surface of the pipeline, gradually reducing its diameter and restricting the flow of water. Additionally, when the injected water contains sediment, it can settle and accumulate within the pipeline, further exacerbating the blockage. The pipeline blockage impedes the efficient delivery of water to the formation, ultimately affecting the oil extraction process. Reduced water injection rates can lead to decreased formation pressure, resulting in diminished oil production. To prevent and manage pipeline blockages in waterflood systems, it is essential to implement appropriate water treatment and filtration measures. Removing impurities, including sediment and salts, from the injected water can help reduce the potential for pipeline blockages. Additionally, regular inspection and cleaning of the waterflood pipeline can help maintain its efficiency and ensure uninterrupted water injection to the formation, optimizing oil recovery and prolonging the productive life of the oilfield.

Figure 6 displays a section of fine pipe installed on the oil removal setting cylinder, which has been in service for one and a half years. Upon macroscopic examination, it becomes evident that the inner part of the pipeline is severely blocked by sediment and corrosion products, rendering it unusable. Over the course of its service life, the fine pipe has been exposed to various factors that contribute to its blockage: Sediment Accumulation: The pipeline is likely used to transport fluids with a high sediment load. As these sediments settle over time, they gradually build up on the inner surface of the pipe, reducing its cross-sectional area and hindering the smooth flow of fluid. The corrosion process generates corrosion products, which can also accumulate within the pipeline, further contributing to the blockage. The combination of sediment accumulation and corrosion product deposition has resulted in the significant blockage observed in the pipeline, rendering it ineffective for further use. To prevent similar blockages in pipelines, it is crucial to implement regular maintenance and cleaning practices. Periodic inspection and cleaning can remove sediment and corrosion products, ensuring the pipeline’s continued functionality and preventing a decline in fluid flow. Additionally, selecting corrosion-resistant materials for pipelines, when feasible, can help prolong their service life and reduce the risk of blockages caused by corrosion products [21].

Figure 7 and Figure 8 illustrate two sections of the gathering and transportation pipeline: a bent pipe and a reducer pipe, respectively. These components are primarily used to transport collected crude oil or separated wastewater. However, both the bending and reducing parts of the pipeline are susceptible to failure due to specific factors. From the bent pipe shown in Figure 7, the bending pipe is subjected to the influence of high-speed fluid flow, which can lead to failure at the bending part of the pipeline. The high-speed fluid creates pressure imbalances and turbulent flow patterns, which can cause stress concentrations at the bending, leading to fatigue failure over time. Additionally, if the bending is not adequately designed or supported, it may be vulnerable to deformation or structural damage.

The reducer pipe shown in Figure 8 is designed to decrease pipeline diameter to regulate fluid flow. However, this geometry can itself become a failure point. The diameter reduction increases fluid velocity, leading to erosive wear on the inner surface, which over time weakens the pipe. Exacerbating this mechanical degradation, both reducer and bent pipes are susceptible to internal corrosion from aggressive transported media, such as crude oil or wastewater. This corrosion progressively compromises the pipe’s structural integrity, potentially resulting in leaks, fractures, or total failure.

To prevent failure in these critical sections of the gathering and transportation pipeline, it is essential to use materials with adequate strength and corrosion resistance. Proper design and support of bent pipes are essential to mitigate stress concentrations. Additionally, implementing corrosion prevention and monitoring measures, such as protective coatings, cathodic protection, and regular inspection, can help extend the service life and reliability of the pipeline. Regular maintenance and replacement of worn or damaged components are also crucial to ensuring the safe and efficient transportation of crude oil and wastewater.

As shown in Figure 9 above, a straight pipe is installed on the oil removal settling tank to transport oily wastewater from the production process. After one and a half years of service, the pipeline exhibited severe corrosion, most notably in its middle section. This corrosion led to the accumulation of corrosion products and sediment, which ultimately blocked the pipeline.

The corrosion observed inside the pipeline can be attributed to the corrosive nature of the transported oily sewage. Such localized attack, including pitting and under-deposit corrosion, is a common failure mode in oil and gas pipelines that demands targeted mitigation approaches [22,23]. The presence of corrosive components and chemicals in the sewage can lead to the gradual degradation of the pipeline’s inner surface, resulting in the formation of corrosion products such as rust and scale. As corrosion progresses, the pipeline’s structural integrity is compromised, making it more susceptible to damage and blockage. Additionally, the accumulation of sediment inside the pipeline exaggerates the problem. Oily sewage can carry solid particles and sediments, which settle over time and combine with the corrosion products to form a thick layer of deposits. This sediment build-up narrows the pipeline’s diameter, obstructing the flow and impeding the efficient transportation of the sewage.

To address this issue, it is crucial to implement proper corrosion prevention and control measures. Using corrosion-resistant materials for the pipeline and applying protective coatings can help slow down or prevent corrosion formation. Regular inspection and maintenance are vital to identify and address corrosion at its early stages, reducing the risk of blockage. Furthermore, implementing appropriate filtration and cleaning processes can help remove sediment and blockages from the pipeline, ensuring the smooth flow of the oily sewage and minimizing downtime and operational disruptions.

3.2. Water Quality Analysis

Water chemistry analysis was performed using inductively coupled plasma optical emission spectrometry (ICP-OES) for cations (Ca²⁺, Mg²⁺, Na⁺, K⁺) and ion chromatography (IC) for anions (Cl⁻, HCO₃⁻, SO₄²⁻). Total mineralization was derived from the ionic sum and confirmed by gravimetric evaporation at 180 °C.

Table 2. Water Quality Analysis Results of Water Samples at Different Locations in the Oilfield Gathering and Transmission System.

Contents	1# Three-Phase Separator Outlet	2# After Natural Sedimentation Filtration
pH	7	7.5
Cl− (mg/L)	31,551	33,146
HCO3− (mg/L)	705	722
SO42− (mg/L)	1153	27.4
Ca2+ (mg/L)	3323	3497
Mg2+ (mg/L)	130	146
Na+ + K+ (mg/L)	18,982	20,282
Mineralization (mg/L)	56,000	61,000

and

Table 3. Predicted scaling tendency of major salts in the produced water. (The scaling tendency index is derived from OLI simulation; an index > 0 indicates a tendency to precipitate, with higher values representing greater scaling potential.).

Scaling	Scaling Tendency Index	Operational Temperature Range/°C
CaCO3	1.00 × 100
CaSO4.2H2O	1.00 × 100	0.0–126.0
CaSO4	7.84 × 10−1	0.0–455.0
NaCl	1.08 × 10−2	0.0–350.0
Na2SO4·10H2O	8.73 × 10−3	0.0–32.4

present two representative water samples from key stages of the oilfield gathering and transportation process, with their analysis offering insights into system corrosion potential.

Sample No. 1: Outlet Water from Three-Phase Separator. This sample, representing untreated water immediately after oil separation, shows high concentrations of chloride, calcium ions, and salinity. These parameters indicate a strongly corrosive environment for carbon steel pipelines, highlighting the critical need for effective corrosion control from the initial stage of the transportation system.

Sample No. 2 (Water Sample Filtered by Walnut Shell after Natural Settlement): This water sample has undergone some treatment by filtration using walnut shells after natural settlement. While this treatment has improved the water quality slightly compared to Sample No. 1, the analysis still shows notable amounts of chloride ions, Ca²⁺ ions, and salinity. These elements continue to pose a potential risk of corrosion to the carbon steel pipelines in the oil gathering and transportation system, even after the filtration process.

Notably, the concentrations of chloride ions (Cl⁻) and total salinity increased in Sample #2 after walnut shell filtration. This is attributed to a concentration effect, as water removal during treatment enriches dissolved ions. Walnut shell filtration is a standard physical process aimed at removing suspended solids and oils, not dissolved salts. Conversely, the sharp decrease in sulfate (SO₄²⁻) is likely due to the precipitation and removal of insoluble sulfate scales (e.g., CaSO₄, BaSO₄). These results demonstrate that while conventional filtration improves water clarity, it does not mitigate corrosion induced by high dissolved chloride content, highlighting the need for more comprehensive management strategies. Gathering and transportation system indicates the potential for strong corrosion towards the carbon steel pipelines. Moreover, the high concentration of Ca²⁺ ions promotes severe scaling, and the resulting scale deposits can facilitate under-deposit corrosion, synergistically worsening the damage caused by the high-chloride environment. This underscores the critical importance of implementing effective corrosion control strategies to mitigate the damage caused by the corrosive elements present in the water. To address these challenges and ensure the longevity of the pipeline system, the adoption of aluminum-based sacrificial anodes is a promising solution. These anodes can act as sacrificial elements, offering protection to the carbon steel pipelines by corroding themselves instead. By sacrificial corroding, the anodes prevent the pipelines from undergoing direct corrosion, effectively safeguarding the infrastructure and maintaining its integrity.

3.3. Corrosion Kinetics Simulation

Simulation Parameters and Assumptions: The corrosion and scaling simulations were conducted using the OLI Analyzer Studio software (Version 11.5). The input water chemistry was based on the ionic composition of Sample #1 (Three-Phase Separator Outlet) from Table 2. Key model assumptions included: (1) thermodynamic equilibrium for scaling predictions; (2) use of the MSE (Mixed Solvent Electrolyte) property package for high-salinity brine; (3) carbon steel as the corroding material with a homogeneous surface. Simulations were performed under closed-system conditions at 1 atm, with temperature varied from 25 to 90 °C and flow velocity as specified. The simulated pH (6.61) differs from the field-measured pH values (7.0 and 7.5) in Table 2. This difference arises because the OLI simulation calculates the thermodynamic equilibrium pH under closed-system conditions at 25 °C and 1 atm, accounting for all ionic interactions including carbonate species. In contrast, the field pH reflects instantaneous values influenced by open-system effects, temperature changes, and CO₂ release. The simulated pH thus indicates the inherent acidic tendency of the brine, which is key for understanding long-term scaling and corrosion behavior, rather than replicating a specific field reading.

Based on the corrosion water quality data and the simulation results obtained from the OLI Analyzer (v4.0) corrosion simulation software, the pH value of the simulated solution at 25 °C and 1 atmosphere pressure is 6.61, indicating that the solution is acidic. The density of the solution is 1.038 g/mL. The scaling mechanism of the water sample can be analyzed based on the combined effects of flow velocity, temperature, pressure and wall shear stress, as shown in Table 3. Understanding these mechanisms is essential for developing effective inhibition strategies, as detailed in comprehensive reviews of water-formed deposits [24,25]. From the table, it is observed that for the scaling trend analysis of the produced water sample, the generation trend of CaCO₃ (calcium carbonate) is at its maximum, with a value of 1. This indicates that calcium carbonate is the primary scaling component in the produced water sample. Scaling occurs when the concentration of calcium and carbonate ions in the water reaches a point where calcium carbonate starts to precipitate out of the solution, forming scale deposits on the inner surfaces of pipelines and equipment [26].

The acidic nature of the water can lead to the dissolution of calcium carbonate, which may explain why the scaling trend of CaCO₃ is at its maximum. The dissolved calcium carbonate can subsequently precipitate out of the solution as the pH of the water changes due to various factors such as temperature, pressure, or chemical interactions. Understanding the scaling mechanism is crucial for managing scaling issues in the oil-field water injection system. Proper treatment and control measures can be implemented to prevent the formation of scale deposits and ensure the efficient and reliable operation of the system. Regular monitoring of water quality and scaling trends can also aid in identifying potential scaling problems early on, allowing for timely and effective intervention [27,28]. Although the uniform corrosion rate of carbon steel is only 0.078 mm/yr at 25 °C, it rises sharply to 1.94 mm/yr at 90 °C—approximately 25 times higher. More importantly, under-deposit pitting, galvanic coupling (e.g., Cu–steel), and erosion-corrosion can locally accelerate penetration by an additional 10–50-fold. SEM thickness measurements of the removed scales reveal maximum residual pit depths of 2.3 mm, which aligns well with the observed 1–2-year service lives of the components listed in Table 1 and illustrated in Figure 2, Figure 3, Figure 4, Figure 5, Figure 6, Figure 7, Figure 8 and Figure 9.

Based on the ion concentration index obtained from the water sample, various analyses can be conducted to understand the corrosion mechanism more comprehensively. These analyses include electrochemical and kinetic analysis, potentio-pH diagram (Pourbaix diagram) generation, corrosion product analysis and prediction, polarization curve prediction, and corrosion trend prediction. The Pourbaix diagram also reveals the generation mechanism of corrosion products and passivation films.

The Pourbaix diagram (Figure 10) is constructed for a fixed temperature of 20 °C and maps the thermodynamic stability regions of iron and its potential corrosion products (e.g., Fe²⁺, Fe₃O₄, Fe₂O₃, FeS) in the studied brine as a function of potential and pH. It helps identify the conditions under which protective films or corrosive species are stable. It is crucial to note that this diagram, by its conventional construction, is specific to a single temperature and does not depict a temperature-dependent trend. The significant effect of temperature on the corrosion kinetics (i.e., the rate of metal loss) is independently and quantitatively demonstrated by the OLI simulation results presented in Figure 11, which shows the corrosion rate increase from 0.078 mm/y at 25 °C to 1.94 mm/y at 90 °C. These corrosion products are typical of the corrosion behavior of carbon steel in corrosive environments. Fe₂O₃ is commonly known as rust and is formed when iron reacts with oxygen and water. FeS, on the other hand, is likely formed due to the presence of sulfur-containing compounds in the water, leading to the formation of iron sulfide. Both Fe₂O₃ and FeS are corrosion products that can accumulate on the surface of carbon steel, contributing to the deterioration of its structural integrity over time. By understanding the corrosion products and the overall corrosion mechanism, measures can be taken to mitigate corrosion in the oilfield water injection system. These may include selecting corrosion-resistant materials, implementing protective coatings, controlling water quality parameters, and regular inspection and maintenance of equipment and pipelines. By applying the insights from the analysis, corrosion-related issues can be effectively managed, extending the lifespan and reliability of the oilfield infrastructure.

Figure 11 illustrates the corrosion rate of carbon steel under different ambient temperatures. At 25°C, the corrosion rate is measured to be 0.0777 mm/year, while at 90°C, the corrosion rate significantly increases to 1.938 mm/year. This temperature-dependent acceleration is consistent with the known behavior of carbon steel in corrosive media, including environments containing H₂S, where both temperature and acid gas concentration critically influence corrosion kinetics. The data from Figure 11 reveals Enhanced mass transport: Higher temperatures increase the diffusion rate of corrosive species.

The increase in corrosion rate with temperature can be attributed to several factors:

(a)

Accelerated Chemical Reactions: Higher temperatures can accelerate chemical reactions at the metal–water interface, leading to increased metal dissolution and corrosion. Elevated temperatures can enhance the mobility of ions in the water, making them more reactive with the metal surface.

(b)

Decreased Protective Film Formation: At higher temperatures, the formation of protective passive films on the metal surface may be inhibited. These passive films act as barriers that protect the metal from further corrosion. In the absence of a robust passive film, the metal is more vulnerable to corrosion.

(c)

Decreased Protective Film Formation: Elevated temperatures can inhibit the formation of stable passive films on the metal surface. Since these films serve as a protective barrier, their compromised integrity or absence significantly increases the metal’s susceptibility to corrosion.

(d)

The significant increase in corrosion rate observed at higher temperatures highlights the importance of considering temperature as a critical parameter in man-aging corrosion in the oilfield water injection system. Measures such as temperature control, material selection, and appropriate corrosion inhibition strategies become crucial in preventing accelerated corrosion under elevated temperature conditions. Implementing effective corrosion prevention and control practices can help mitigate the detrimental effects of temperature-induced corrosion and ensure the long-term integrity and reliability of the system.

Figure 12 presents the simulated corrosion rates of carbon steel under different flow velocities. The results show a linear increase in corrosion rate with flow velocity, reflecting the contribution of flow-accelerated corrosion and erosion–corrosion mechanisms. Based on the analysis results, several conclusions can be drawn regarding the pipeline materials in the gathering and transportation stations in the Yanchang area:

High Salinity: The water in the pipeline generally exhibits high salinity [3.5% wt%–10 wt%NaCl], which can promote the formation of scale deposits. As noted previously, the predominant scale type is calcium carbonate (CaCO₃).

Corrosion Under Scale: Pipeline materials undergo significant corrosion beneath the CaCO₃ scale. Corrosive ions in the water, such as chloride ions, can accelerate this corrosion process, particularly under the scale layer.

Formation of Iron Oxides: The corrosion process under the scale layer results in the formation of iron oxides, such as Fe₂O₃, which are typical corrosion products for carbon steel materials exposed to corrosive environments.

Accelerated Corrosion with Flow Velocity: The loose and cracked nature of the scale layer exacerbates the corrosion problem. As flow velocity increases, the corrosion damage and failure of the pipeline materials accelerate. Higher flow velocities can lead to increased turbulence and more aggressive corrosion processes, contributing to the deterioration of the pipeline. Considering these conclusions, it becomes evident that effective corrosion prevention and mitigation strategies are crucial to maintaining the integrity and reliability of the gathering and transportation stations in Qingyang area. Additionally, appropriate water treatment methods may be employed to control the scale formation and reduce the impact of corrosive elements in the water, ultimately safeguarding the operation and safety of the oilfield system.

3.4. Corrosion Characterization Analysis

3.4.1. Scale Sample Analysis

In addition to SEM and EDS analyses, electrochemical impedance spectroscopy (EIS) is also a widely used technique for studying corrosion mechanisms in steel structures, providing insights into interfacial reactions and corrosion kinetics.

The scale stripping was carried out on 9 different macroscopic corrosion samples, and the scale samples were tested using an atomic absorption spectrophotometer. Analysis of Figure 13 indicated high concentrations of calcium and iron compounds in all scale samples, confirming significant scaling and corrosion. The presence of BaSO₄ crystals, despite the absence of soluble Ba²⁺ in the outlet water (Table 2), shows that barium was entirely precipitated as insoluble sulfate scale within the system. These results, along with the detection of Fe₂O₃ and SiO₂, highlight the combined scaling and corrosion challenges in the pipelines. At the same time, the scale sample analysis also revealed the presence of BaSO₄, Fe₂O₃, and other corrosion scaling problems, resulting in serious internal corrosion of the pipeline. Additionally, the XRD spectra of the scale samples showed the presence of SiO₂ in the pipeline.

Overall, the analysis of the scale layer’s morphology and composition provides valuable insights into the corrosion and scaling processes in the reduced diameter tube (sample 8#). Understanding these processes is crucial for developing effective corrosion prevention and mitigation strategies to ensure the long-term integrity and reliability of the pipeline system. Chemical inhibition strategies, such as the use of phosphonates and polymeric inhibitors, have been widely studied for their effectiveness in controlling CaCO₃ and CaSO₄ scaling under high-salinity conditions.

3.4.2. Corrosion Surface Analysis

The micromorphology and composition of corrosion products on the inner walls of tubes 7# and 8# were analyzed in situ to gain insights into the corrosion process. Figure 14 and Figure 15 present the results of the analysis. The corrosion layer on the inner walls of the tubes exhibits varying thickness, indicating non-uniform corrosion across the surface. The scale layer appears loose with numerous cracks, suggesting weak binding force and adhesion of the scale layer to the tube’s inner surface [29]. This weak adhesion can contribute to the detachment and shedding of the scale layer over time.

Figure 16 illustrates the Energy Dispersive X-ray Spectroscopy (EDS) analysis results of the cross-section of the scale layer sample. The EDS analysis reveals a uniform composition of the scale layer, consisting of iron oxides, calcium carbonate, and a significant number of chloride ions. The presence of iron oxides, such as iron (III) oxide (Fe₂O₃) or iron (II) oxide (FeO), indicates the involvement of iron in the corrosion process, which is typical in ferrous materials subjected to corrosion. The formation of iron oxides is a result of the corrosion reaction between the metal surface and the surrounding environment, usually involving oxygen and moisture. The presence of calcium carbonate (CaCO₃) in the scale layer indicates that the water in contact with the tube contains dissolved calcium ions and carbonate ions. Calcium carbonate often forms scale deposits in pipes and equipment due to the precipitation of calcium and carbonate ions from the water. The significant number of chloride ions in the scale layer is concerning because chloride ions are known to accelerate the corrosion process. Chloride ions are highly corrosive to metals, especially in the presence of oxygen and moisture. They can lead to pitting corrosion and increase the overall corrosion rate.

The analysis of the scale layer’s composition provides valuable information about the corrosive environment and the materials involved in the corrosion process. Understanding the composition and micromorphology of the corrosion products helps in identifying the underlying causes of corrosion and aids in the development of effective corrosion prevention and mitigation strategies to protect the tubes and prevent further damage.

In Figure 17 and Figure 18, the scale layer formed by corrosion on the cross-section of Sample 8# appears loose and contains numerous cracks, indicating poor adhesion to the substrate. This weak adhesion is likely attributed to the non-uniform manner in which the scale formed during the corrosion process, which can promote cracking and detachment. In contrast, the surface morphology of the corrosion layer on the Sample 8# cross-section is relatively dense, suggesting that the corrosion acted more uniformly on the material and resulted in a compact layer of corrosion products. Additionally, a large number of corrosion pits and pits are observed, indicating localized attack and material degradation. The analysis suggests that when Sample 8# was subjected to high-velocity flow, a significant amount of iron oxide and SiO₂ products remained within the corrosion layer. This implies that the high-velocity fluid likely removed some of the corroded material, thereby exposing fresh metal surfaces and facilitating further corrosion.

In Figure 19, the EDS analysis results of the cross-section of scale layer samples show that the composition of the scale layer is homogeneous. It consists of iron oxides, calcium carbonate, and a large number of chloride ions. This composition is consistent with the previous analysis and confirms the presence of iron oxide, likely formed during the corrosion process, and calcium carbonate, which is a common component of scale deposits. The significant presence of chloride ions in the scale layer is a concern as chloride ions are known to accelerate the corrosion process. Their presence can lead to pitting corrosion, which can further weaken the material and result in localized damage. Overall, the analysis of the scale layer’s morphology and composition provides valuable insights into the corrosion and scaling processes in the reduced diameter tube (sample 8#). Understanding these processes is crucial for developing effective corrosion prevention and mitigation strategies to ensure the long-term integrity and reliability of the pipeline system.

4. Conclusions and Recommendations

4.1. Main Conclusions

Through integrated methods including on-site corrosion investigation, water quality analysis, scale sample characterization, scanning electron microscopy, and corrosion kinetics simulation, this study has identified the key controlling factors and underlying mechanisms of corrosion in oilfield water injection pipelines. The primary findings are summarized as follows:

Chloride-Induced Corrosion: The elevated chloride ion (Cl⁻) concentration in the water is the main corrosive agent responsible for attacking carbon steel pipelines.

Calcium-Based Scaling: Concurrently, high concentrations of calcium ions (Ca²⁺) promote the predominant formation of CaCO₃-type scale (see Figure 1 and Table 3).

Under-Deposit and Localized Corrosion: These scales, together with other deposits such as BaSO₄ and corrosion products (e.g., Fe₂O₃), create heterogeneous surfaces and occluded zones that induce severe under-deposit and localized corrosion.

Corrosion Morphologies: The observed corrosion features include both under-scale corrosion and erosion–corrosion, particularly in sections exposed to high-velocity flow.

High-Mineralization Environment: In the Changqing area, the water in gathering station pipelines exhibits high total mineralization, further accelerating scaling and corrosion processes.

Influence of Temperature and Flow: Corrosion simulation confirms that within a certain temperature range, the corrosion rate of carbon steel increases with rising temperature. Additionally, higher flow rates significantly exacerbate corrosion damage.

4.2. Targeted Recommendations for Corrosion Mitigation

Based on the corrosion patterns we’ve identified, here are some practical steps for the most vulnerable parts: For valves suffering from galvanic corrosion, consider swapping out copper sleeves with solid stainless steel or ceramic-coated alternatives. Adding an epoxy or zinc-aluminum thermal spray coating to the inner surfaces can also help prevent pitting under deposits. When dealing with scaling and corrosion in water injection lines, setting up real-time monitoring for calcium and chloride ions—paired with OLI scaling prediction—can give early warnings. Installing self-cleaning walnut-shell filters that backflush every 48 h or less will keep sediment under control. In bends and reducers where erosion-corrosion is an issue, switching to silicon carbide elbows or lining with ultra-high-molecular-weight polyethylene makes a difference. Keeping flow velocity below 2.5 m/s through careful pipe sizing also slows down wear. On a system level, placing wireless corrosion sensors at key points and feeding that data into the station’s control system allows for predictive upkeep. Creating a corrosion-control matrix that links each component’s failure mode to its ideal material, coating, and monitoring plan turns ad hoc fixes into a managed, sustainable system.