Introduction

Matrix acidizing stands as a pivotal method in well stimulation, entailing the injection of an acid system beneath the formation’s fracturing pressure to eliminate formation damage and/or augment permeability around the well (Nasr-El-Din et al. 2007; Zhang et al. 2021). The fundamental objective of matrix acidizing revolves around minimizing pressure drops in the near-wellbore region, thereby fostering heightened production rates (Guo et al. 2007). Acidizing procedures have been implemented to enhance well productivity by either eliminating damages in sandstone formations or forming wormholes in carbonate formations. This process subsequently enhances permeability in the vicinity of the wellbore (Gidley 1985). Hydrochloric acid (HCl) emerges as the acid of choice for carbonate matrix acidizing, owing to its potent reactivity with calcite and dolomite, coupled with its cost-effectiveness (Keihani Kamal et al. 2024; McLeod 1984). While HCl effectively dissolves calcium and dolomite minerals, its swift reaction kinetics entail rapid (Buijse et al. 2003). Hydrochloric acid reacts rapidly with carbonate minerals at temperatures exceeding 200 °F, preventing the formation of wormholes and leading to surface dissolution as a result of high acid consumption. Acid treatment poses significant challenges in tight gas sandstone reservoirs with complex mineral compositions. The mineralogy of sandstone is intricate, comprising clays, feldspars, carbonates, iron minerals, and other components (Mahmoud et al. 2018; Mahmoud 2017). The accumulation of condensate, also known as condensate blockage, exerts a profound impact on gas relative permeability and consequently on well productivity (Kniazeff and Naville 1965; Kumar et al. 2006; Najafi-Marghmaleki et al. 2016). Condensate saturations near the wellbore may escalate to 50–60%, posing a critical concern in the development of several gas condensate reservoirs (Mott et al. 2000). Condensation occurs as reservoir pressure plummets below the dew point pressure, resulting in the buildup of liquid hydrocarbons around the wellbore, substantially diminishing gas condensate well inflow performance, even in lean reservoir fluids. Regardless of reservoir permeability, condensate blockage remains a significant challenge (Kamali et al. 2022). Numerical compositional simulations conducted by Allahyari confirmed a more pronounced decrease in well deliverability in low-permeability gas reservoirs compared to their high-permeability counterparts (Allahyari et al. 2012). Tight carbonate gas condensate reservoirs pose unique challenges, where flow channels are obstructed by escalating condensate saturation, particularly when the bottom hole flowing pressure dips below the dew point pressure, leading to condensate accumulation around wells (Afidick et al. 1994; Ayyalasomayajula et al. 2005; Kniazeff and Naville 1965; Najafi-Marghmaleki et al. 2016). Nowrouzi et al. (2020) investigated wettability alteration in gas-condensate reservoirs using R134A and R404A gases. Their findings indicate that these gases can modify reservoir rock wettability towards gasphilic properties, potentially enhancing gas-condensate production and suggesting future applications with fluorine-coated nanoparticles (Nowrouzi et al. 2020). Shayan et al. (2022) focused on green methods for enhanced gas condensate recovery. Their study on wettability alteration using nanoparticles, renewable energies, thermochemical reactions, and CO2 injection demonstrated significant improvements in mitigating condensate blockages in gas reservoirs (Shayan et al. 2022). Rylance et al. (2023) researched transient pressure analysis in fractured wells to improve liquid condensate recovery and hydrocarbon relative permeabilities. They emphasized chemically-infused gas applications for optimizing displacement and the role of propped hydraulic fracturing in developing retrograde gas-condensate reservoirs (Rylance et al. 2023).

The high surface tension of water or acid solutions hampers penetration and recovery, which can be mitigated by adding alcohol to lower surface tension in acid solutions (Travaloni-Louvisse et al. 1990). Alcohols in acidizing fluids aid in removing water and condensate blocks, improving fluid recovery, reducing water and condensate content, and mitigating acid reactivity. Isopropanol and methanol are widely utilized alcohols in acidizing, with typical concentrations of 20% by volume for isopropanol and 25% by volume for methanol (Economides and Nolte 1989). The addition of alcohol in treatment fluids diminishes capillary forces within the reservoir, facilitating the removal of liquid phases (Asay and Kim 2007; Hampton and Nguyen 2010). Moreover, the reactivity of acids is moderated by alcohol addition, with the retardation rate contingent upon the type and quantity of alcohol added, typically requiring a substantial volume of alcohol—20% or more—to yield positive outcomes (Hussnain et al. 2019). According to the findings of Hussnain et al. (2019), the minimum surface tension is achieved at a methanol concentration of 20%. Beyond this concentration, there is no significant decrease in surface tension, and costs begin to escalate.

However, considering the nature of the reservoir under study, characterized by tight formations prone to condensate blocking, it becomes imperative to determine the optimal methanol concentration that effectively mitigates formation damage. Hence, a meticulous selection process led to the determination of 20% volume as the ideal concentration of methanol. This concentration not only ensures the reduction of surface tension to its minimum but also guarantees the thorough elimination of formation damage, thereby optimizing operational efficiency. In Barnum’s research on a gas condensate reservoir, the productivity of the gas well declined rapidly, reaching zero once the bottom hole flowing pressure fell below the dew point pressure (Barnum et al. 1995).

Liangui Du et al. developed a method for increasing gas relative permeability, which is reduced by condensate and water blockages (Du et al. 2000). Al-Anazi et al. discovered that methanol was successful in eliminating both condensate and water and restoring gas production in low-permeability limestone cores (Al-Anazi et al. 2002). A methanol treatment applied to a gas condensate well in the Hatter’s Pond field was found to improve both gas and condensate production (Al-Anazi et al. 2003). Al-Anazi et al. carried out coreflood tests in Saudi Arabian gas condensate reservoirs to investigate the relative permeability loss caused by water and condensate blockage. The chosen solvent, isopropyl alcohol, and its combination with methanol resulted in condensate blockage clearance, a delay in the condensate blockage, and an increase in gas production. Methanol-water combinations were inefficient at reducing condensate blockage and increasing gas production. Methanol worked well in removing water from the cores. Isopropyl alcohol and its combination with methanol performed well just like pure methanol (Al-Anazi et al. 2005). Zhouhua Wang et al. endorsed; Both CO2 injection and methanol injection are effective for removing the condensate blockage. It is shown that CO2 injection can more effectively remove the condensate blockage by the experimental results of gas permeability recovery times, GOR, and pressure difference decrease value (Wang et al. 2018). Asgari conducted simulations to assess the impact of methanol treatment on condensate blockage using the cubic-plus-association (CPA) equation of state. The findings indicated that methanol treatment has the potential to enhance gas permeability by a factor ranging from approximately 1.3 to 1.6 (Asgari et al. 2014). Alzate et al. studied the influence of alcohol-based and inhibited diesel on gas effective permeability. They noticed that the relative permeability was enhanced by adding alcohol and inhibiting diesel (Alzate et al. 2006). Methanol, a volatile polar compound, can dissolve in water and oil, facilitating water evaporation and decreasing interfacial tension. Asgari conducted experimental research on methanol injection application. The findings revealed that gas relative permeability saw an increase ranging from approximately 30–60%. Moreover, a more significant decrease in gas relative permeability was observed in the presence of water saturation (Millán et al. 2007).

In their 2023 study, Xu et al. investigated wax deposition dynamics in condensate gas systems, particularly emphasizing particulate deposition mechanisms. Their research elucidated the significant influence of temperature differentials on wax deposition rates in condensate gas environments (Xu et al. 2023). Bowen Shi et al. (2024) conducted a study on the effect of interface structure and behavior on fluid flow characteristics and phase interaction in the petroleum industry. Their research provides insights into the complex dynamics of fluid flow and phase behavior, offering valuable implications for optimizing processes in the petroleum sector (Shi et al. 2024).

Despite advancements in reservoir engineering, condensate blockage remains a significant challenge in low-permeability gas reservoirs, particularly those with low pressure and temperature conditions. This study aims to bridge this gap by introducing a novel acid treatment strategy that enhances the injectivity index, thereby improving gas production. The research flow is structured to first identify the optimal acidizing agent through mineralogical analysis and dissolution tests, followed by the formulation of different acid systems, including variations with methanol. The core of the research involves comprehensive wettability alteration tests and coreflood experiments to measure the incremental permeability and evaluate the effectiveness of these systems in permeability enhancement and condensate blockage reduction. Table 1 presents a comparative analysis of strategies for mitigating condensate blockage in gas reservoirs.

Table 1 Comparative analysis of condensate blockage mitigation strategies in gas reservoirs
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Materials

Rock samples

The decision to use formation cores instead of outcrop samples for this study was made due to the unavailability of the latter, aiming to obtain repeatable and robust results. The core plugs, sourced from the Sarajeh formation in the central region of Iran, were carefully selected for experimentation. Three core plugs (1–4 H(d), 2–4 H(d), 3–2 H(a)) were chosen, each with a length of 50.5 mm and a diameter of 37.5 mm, originating from varying depths within the formation. The experimental properties of the cores are detailed in Table 2.

Prior to conducting any treatments or measurements, it was crucial to ensure that the core samples were free from any contaminants that could potentially impact the results. To achieve this, a meticulous cleaning process was carried out using a Soxhlet extraction method with methanol and toluene as solvents. This thorough cleaning process effectively removed any traces of drilling fluids, hydrocarbons, and salts from the cores, restoring them to a natural state as much as possible. Following the cleaning process, X-ray diffraction (XRD) analysis was performed on the dry rock samples to determine the mineralogical composition. The XRD results, depicted in Fig. 1, confirmed that the predominant mineral present in the samples was calcite, making up the majority of the sample composition.

Table 2 Core sample properties
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Fig. 1
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Abundance of available minerals

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Formation water

The formation water utilized in the coreflood test was sourced from the Sarajeh gas field in Qom, Iran. To ensure accurate results, clean formation water was specifically chosen for the Inductively Coupled Plasma (ICP) elemental analysis. The results of the ICP elemental analysis, as outlined in Table 3, provide insights into the compositions of a 15 to 20 cc sample of the formation.

Table 3 Formation fluid compositional analysis
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Condensate

The condensate, which was utilized to simulate blockages in the core plugs, was also sourced from the Sarajeh gas field in Qom, Iran. The composition of the condensate is detailed in Table 4, providing a clear overview of its components for experimental purposes.

Table 4 Condensate compositional analysis
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Acids and alcohol

In this study, a range of liquids were employed, including hydrochloric acid at concentrations of 7.5 wt%, 15% wt%, 20% wt%, and 28% wt%. Additionally, two solutions were tested: HCl 7.5 wt% + MeOH and HCl 15 wt% + MeOH, aimed at addressing the damage resulting from condensate blockages. Methanol was incorporated as an additive to regulate and decrease surface tension during the experimentation process.

Methods

Acid solubility testing

Based on factors such as the type of formation damage, rock type, temperature, and reservoir pressure, various acids are employed for well-stimulation. Utilizing the correct acid not only aids in damage removal but also leads to a significant increase in production rates. (Lv et al. 2021). In carbonate rocks, hydrochloric acid is typically used at a concentration of 15 wt% due to its high dissolving power, allowing it to react completely with calcium and magnesium minerals. (Al-Anazi et al. 1998; Garrouch et al. 2017; Kiani et al. 2021; Muecke 1982; Sokhanvarian et al. 2017). Lower concentrations of hydrochloric acid are commonly used to remove sediments, salt plugs, and emulsions, while higher concentrations are employed to create deeper and wider pathways in reservoir rock (AlMubarak et al. 2015). Despite its high dissolving power, hydrochloric acid may react with metal surfaces, leading to the formation of iron deposits due to its corrosive nature (Askey et al. 1993; Ituen et al. 2019). Alcohols are often added to acidizing fluids to eliminate water/condensation blocks, enhance fluid recovery, and delay acid reactivity (Chacon and Pournik 2022; Mahadevan and Sharma 2005). Isopropyl alcohol and methanol are the most commonly used acidizing alcohols, with methanol being the preferred choice due to its ability to reduce the surface tension of the solution, allowing the acid to penetrate smaller pore sizes effectively (Al-Anazi et al. 2006; McLeod and Coulter 1966). In a study conducted by Muhammad Sana-ul Hussnain et al., the impact of methanol on reducing surface tension was investigated. The study revealed that concentrations of methanol exceeding 20 vol% did not result in a further decrease in surface tension. It is important to note that due to its flammability, the use of methanol at high concentrations requires strict safety measures and caution (Hussnain et al. 2019). Acid solubility tests were conducted to observe the reactions of the rock with different acid systems. The first step was to optimize the concentration of hydrochloric acid. To conduct the solubility test and determine the endpoint of the reaction, as well as the ideal ratio of rock to hydrochloric acid, a specific amount of rock needed to be dissolved in a defined quantity of hydrochloric acid. Thus, in addition to the stoichiometric ratio of 1:3, a higher volume of hydrochloric acid for each concentration was required to calculate the appropriate acid volume. As a result, two ratios above the stoichiometric ratio (1:5 and 1:7) were considered in this study. The solubility test involved dissolving a thin section sample in 7.5, 15, 20, and 28 wt% hydrochloric acid at the reservoir temperature in an oven for different durations − 30 min, 60 min, 90 min, 120 min, and 360 min. Figure 2 illustrates the thin sections and test bottles used for the solubility test. Following the reaction, the remaining sample was dried in a convection oven to determine the weight loss (solubility) as a percentage of the original sample weight. The test contents were filtered using a 149 µ filter paper. Once the optimal ratio of rock to acid was determined, the best concentration from the options of 7.5, 15, 20, and 28 wt% had to be selected. Experiments were then conducted for 24 h at 100 °C (reservoir temperature) with varying concentrations of acid. After identifying the optimal concentration of hydrochloric acid, solubility tests were also performed by mixing methanol with the two selected acids at a volume ratio of 20:80 at reservoir temperature for durations of 30, 60, 90, 120, and 360 min.

Fig. 2
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Thin section and equipment used for dissolution test

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pH

The pH value can be a crucial factor in determining the optimal volume and duration of the reaction. When considering pH changes, if the reaction is endothermic, it suggests that higher temperatures will result in lower pH levels. Conversely, if the reaction is exothermic, it will lead to an increase in pH. The significance of monitoring the pH is to establish the endpoint of the reaction and its extent. In this phase, the pH of the acidic solutions was monitored, and all fluids were tested using a pH meter to measure their pH levels.

Coreflood experiments

Coreflood tests were conducted to assess the efficacy of various acid compositions in improving core permeability, as well as to replicate the phenomenon of condensate blockage and the level of formation damage caused by such blockage. Figure 3 illustrates a schematic of the experimental setup. The tests were carried out on reservoir cores extracted from a gas well. These samples were initially saturated with brine, and the saturation technique was employed to determine the porosity (Sw 0.3). Three core flooding experiments were conducted under reservoir conditions (212 °F (100 °C) and 2,500 psig). The initial step involved using water to measure core permeability. Subsequently, after the initial saturation and establishment of relative condensate permeability, the core was treated with an acid system comprising either HCl/methanol or HCl. To mitigate the corrosive nature of all acids used, a corrosion inhibitor (CI) was applied as a precautionary measure.

Fig. 3
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High-pressure/High-temperature acid core flooding system

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Wettability alteration and interfacial tension

Wettability refers to the tendency of a liquid to spread and adhere to a solid surface. Oil and gas reservoir materials can be either carbonate or sandstone. Typically, sandstone formations exhibit water-wet properties, while carbonate formations are oil-wet. In water-wet formations, sand grains are coated with a thin layer of formation water, which remains in place due to surface tension. Hydrocarbons move into the pores and migrate to the surface in these formations, while the water within the pores remains stationary. Conversely, formation water is trapped within the pores of oil-wet formations, leading to reduced permeability. Changes in wettability (water or oil) are often permanent. One method of determining wettability is through measuring the contact angle. A contact angle test is utilized to ascertain whether a hydrocarbon fluid sample will exhibit wetting characteristics on rock surfaces in the presence of formation water and under reservoir conditions. A drop of formation water is introduced onto the surface of aged reservoir rock in the presence of formation fluid, and the resulting contact angle of the drop indicates the wettability. A contact angle between 0 and 75 degrees is considered hydrophilic, while a range of 75 to 105 degrees is neutral, and 105 to 180 degrees is hydrophobic (Dandekar 2013). In the context of matrix stimulation for gas wells, the surface tension of solutions containing hydrochloric acid (HCl) is significant. Lower surface tension is essential to diminish capillary forces that result in trapping condensate within the formation. Reduced surface tension allows fluids to flow more freely and may even lead to miscibility. However, during acid treatments, the surface tension between the acid and hydrocarbon can hinder acid penetration into the rock. The use of a surface tension reducer can decrease the surface tension between two phases. Surface tension measurements were conducted using a pendant drop instrument model.

Results and discussion

Solubility and pH

In this part, the results of HCl dissolution are reported in Fig. 4.

Fig. 4
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Dissolution of calcite in different concentrations and volume

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Acid solubility tests were conducted to assess the response of the formation to different acid systems. These tests involve using a specified amount of a sample to determine the change in mass after it reacts with acid. Understanding the formation characteristics and the results of solubility tests can aid in predicting the impact of acid treatment. Two primary acid systems were evaluated. The first system consisted of hydrochloric acid in various concentrations, while the second system involved a mixture of methanol and HCl at a volume ratio of 20:80, respectively. As shown in Fig. 4, the maximum solubility for concentrations of 7.5 wt%, 15 wt%, and 20 wt% occurred at a 1:7 ratio, with a 1:5 ratio being optimal for the concentration of 28 wt%. The lower acid dissolution observed for the 28% concentration compared to other acids in Fig. 4 can be attributed to the formation of carbon dioxide during the reaction between the acid and rock surfaces. There are three key steps that influence the acid-rock reaction, as illustrated in Fig. 5 (Elsayed et al. 2019). This reaction proceeds via diffusion rather than a controlled process, as the rate of step 2 is significantly faster than steps 1 and 3. In low concentrations, when acid reacts with calcite, the released carbon dioxide moves from the rock surface to the solution surface, enabling more interaction between the rock and the acid. However, at higher concentrations like 28%, the formed carbon dioxide remains on the rock surface, inhibiting further acid reaction. Therefore, the dissolution rate of acid with a concentration of 28% is slightly lower compared to other concentrations.

Fig. 5
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Acid reaction with rock surface

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The pH level of the acid post-reaction plays a significant role in determining the optimal volume of acid and the endpoint of the reaction. Figure 6 depicts the pH changes over time for hydrochloric acid concentrations of 7.5 wt%, 15 wt%, 20 wt%, and 28 wt%.

Fig. 6
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pH after reaction for different concentrations

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As depicted in Fig. 6, the initial pH of the hydrochloric acid solution is low, but it gradually rises as the acid is consumed over time until it is completely utilized. Following the solubility experiments, samples of the effluent fluid were collected to assess the likelihood of precipitation. The pH values of these collected samples were analyzed to determine the maximum solubility and reaction duration. When the acid system interacts with the rock to dissolve calcite and dolomite, the pH of the acid solution increases until all the acid is depleted. Figure 6 illustrates the pH of the effluent samples post-solubility testing for varying concentrations and rock-to-acid ratios. Within a timeframe of 120–150 min, all acids are consumed, and the pH stabilizes. The pH range of HCl at different concentrations falls between − 1.3 and 1.7. Once the optimal rock-to-acid ratio is determined, the next step is to select the most suitable concentration among 7.5 wt%, 15 wt%, 20 wt%, and 28 wt%. Figure 7 displays the relationship between calcite solubility and acid concentration.

Fig. 7
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Dissolution of calcite for different HCl concentrations

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According to the results of acid solubility tests, the thin sections exhibited dissolution rates of 53.02%, 60.36%, 62%, and 62.66% in HCl solutions of 7.5 wt%, 15 wt%, 20 wt%, and 28 wt%, respectively (refer to Fig. 7). It is evident from Fig. 7 that the concentrations of 20 wt% and 28 wt% demonstrated 3% higher solubility compared to the 15 wt% concentration. Consequently, the optimized concentration of hydrochloric acid was determined to be 15 wt%. Except for the 15 wt% HCl solution, the 7.5 wt% concentration was selected as the secondary concentration. Upon establishing the ideal concentration of HCl, a solubility test was conducted by mixing methanol with the two chosen acids (HCl 7.5 wt% and HCl 15 wt%) in a volume ratio of 20:80. The dissolution rates of HCl 15 wt%, HCl 15 wt% + MeOH, and HCl 7.5 wt% + MeOH are depicted in Fig. 8.

Fig. 8
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Rate of dissolution over time

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As depicted in Fig. 8, although HCl 15 wt% exhibits a high dissolution rate, it only dissolves approximately 60% of the thin sections after 360 min. The addition of methanol to both HCl 15 wt% and HCl 7.5 wt% reduced the interfacial tension of the solution, allowing the acid to penetrate more effectively into the thin section. HCl 15 wt% + MeOH was able to dissolve 64.745%, while HCl 7.5 wt% + MeOH, due to the lower concentration of HCl, continued to react and dissolved 70.56% of the thin section. Hence, HCl 7.5 wt% + MeOH and HCl 15 wt% + MeOH were found to be more soluble than HCl 15 wt%. In conclusion, the solubility studies have revealed that for low-permeable gas condensate reservoirs, HCl 7.5 wt% + MeOH is the most effective option. The pH of the effluent sample following the solubility test is illustrated in Fig. 9.

Fig. 9
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pH variations throughout time

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Figure 9 displays the pH levels of HCl 7.5 wt% + MeOH and HCl 15 wt% + MeOH following the solubility test. The presence of methanol in the solution has an impact on the initial pH values. Consequently, both HCl 7.5 wt% + MeOH and HCl 15 wt% + MeOH exhibit higher pH values in comparison to HCl 15 wt%. The pH range for HCl 7.5 wt% + MeOH ranges from − 0.2 to 0.1, while for HCl 15 wt% + MeOH, it ranges from − 0.5 to -0.3. Given that HCl 7.5 wt% + MeOH utilizes a lower amount of hydrochloric acid than HCl 15 wt% + MeOH, the resulting pH of the former solution is higher.

Coreflood

Carbonate cores extracted from reservoirs were utilized for coreflood tests under conditions of 212 °F and 2,500 psig. The impact of various acid systems on permeability was investigated by comparing the permeability values before and after the injection of the acid system into the core while maintaining consistent flow conditions. Before placement in the core holder, the core plugs were saturated with brine and condensate. The experiment was conducted under a constant confined pressure of 1,000 psi to ensure stability. To remove entrapped air from the pipes, the flow lines were flushed with brine. The initial brine permeability of the core was determined before the introduction of the acid. Subsequently, the acid was injected and the flow continued until a steady pressure drop across the core was achieved, enabling the evaluation of the acid treatment’s effect on permeability. The results were analyzed by plotting the pressure drop against time. The pressure drops resulting from the injection of HCl solutions of 15 wt%, HCl 15 wt% + MeOH, and HCl 7.5 wt% + MeOH were measured and presented in Figs. 10 and 11, and 12, respectively. Considering the limitations of the core samples, it is recommended that each core be assigned a specific acid treatment for optimal results.

Fig. 10
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Pressure drop versus time for HCl 15 wt%

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Fig. 11
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Pressure drop versus time for HCl 15 wt% + MeOH

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Fig. 12
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Pressure drop versus time for HCl 7.5 wt% + MeOH

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Figures 10 and 11, and 12 depict the pressure variations measured by different sensors along the core plug. The plug holder is equipped with three sensors: Inlet-Outlet, Pressure Table 1, and Pressure Table 2. Initially, as the fluid reaches the back of the plug, resembling a well, the Inlet-Outlet sensor begins recording pressure drops on both sides of the plug. Pressure Table 1 and Pressure Table 2 also indicate pressure changes. Until the fluid reaches Pressure Table 1 and Pressure Table 2, these sensors exhibit less pressure drop compared to Inlet-Outlet. Given that Pressure Table 1 is closer to the entry point of the plug, where the fluid reaches first, its pressure drop aligns with that of Inlet-Outlet sooner. Subsequently, as more fluid infiltrates the plug and reaches the second sensor, Pressure Table 2’s pressure drop aligns with those of Inlet-Outlet and Pressure Table 1. The subsequent dissolution of rock results in the observance of three declining trend curves. The significant decrease in flooding pressure post-treatment indicates the successful establishment of flow. To ensure the CO2 reaction product remains in solution during injection, a minimal pressure level is maintained using a pressure regulator. Following the measurement of initial permeability with formation water, condensate was injected into the plug in two stages to assess formation damage. Given that condensate blockage is a common cause of such damage, and gas has a limited impact on formation damage, the experiments in this section were conducted in the presence of condensate. Subsequently, the secondary permeability of the plugs was determined post-condensate injection by introducing formation water in the same direction as the primary permeability. The primary and secondary permeability outcomes for carbonate plugs are detailed in Table 5.

Table 5 Air permeability coreflood analysis
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The results derived from the secondary permeability calculations for the three plugs, namely 1–2 H(b), 1–4 H(d), and 2–1 H(a), indicated a reduction in permeability by 52.35%, 39.90%, and 47.07%, respectively, due to the penetration of condensate into the plugs. In order to enhance permeability, it was imperative to dissolve a portion of the rock and eliminate the condensates within the pores through acid injection. The solubility tests conducted revealed that HCl 15 wt%, HCl 7.5 wt% + MeOH, and HCl 15 wt% + MeOH exhibited superior solubility compared to other acid types. Consequently, coreflood tests were executed using these selected acids. The desired acids were supplemented with corrosion inhibitors, corrosion inhibitor intensifiers, iron control agents, and surface tension reducers at volume percentages of 1.5, 1.5, 1, and 2, respectively. Following the injection of HCl 15 wt%, HCl 7.5 wt% + MeOH, and HCl 15 wt% + MeOH into the core plugs, the resulting increase in permeability was measured at 30.86%, 68.72%, and 16.98% relative to the initial state, and 174.59%, 180.73%, and 121.43% compared to the condition post-formation damage. The outcomes of the coreflood tests indicated that HCl 7.5 wt% + MeOH, owing to its lower interfacial tension and effective penetration of pore throats, exhibited the highest increase in permeability. Despite possessing lower dissolution power compared to HCl 15 wt%, the combination of HCl 7.5 wt% with methanol facilitated greater efficiency in removing condensate blockages than HCl 15 wt% and HCl 15 wt% + MeOH. Furthermore, following the dissolution test results (Fig. 8), HCl 7.5% + MeOH demonstrated higher solubility than other acids under comparable conditions. Evidently, as permeability increases, the contact between the acid and the core surface is enhanced, leading to improved dissolution of calcite and subsequently higher permeability values. However, it is essential to acknowledge that the extent of dissolution is influenced by various factors, including mineralogy, acid concentration, and solvent power.

Notably, due to variations in mineral concentrations and initial permeability among the core plugs, HCl 15 wt% proved to be more effective in augmenting permeability compared to HCl 15 wt% + MeOH.

Wettability alteration

The contact angle test is utilized to evaluate the wettability of rock under reservoir conditions in the presence of formation water and hydrocarbon fluids. The core sample was placed in the wetting apparatus and immersed in condensate from the tank. A droplet of formation water was then deposited onto the core surface, and the contact angle was determined by imaging the droplet and using Digimize software. This test was conducted before and after the acid injection test. Figures 13, 14 and 15 display the images captured during this test.

Fig. 13
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Contact angle of 1–2 H(b) before and after acidizing

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Fig. 14
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Contact angle of 1–4 H(d) before and after acidizing

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Fig. 15
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Contact angle of 2–1 H(a) before and after acidizing

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The data from Figs. 12, 13 and 14 indicates that the initial contact angles of 1–2 H(b), 1–4 H(d), and 2–1 H(a) before the injection of HCl 15%, HCl 7.5% + MeOH, and HCl 15% + MeOH were measured at 107°, 120°, and 127°, respectively. Following the injection of these acids, the contact angles were measured at 78°, 70°, and 77° for 1–2 H(b), 1–4 H(d), and 2–1 H(a), respectively. The neutral or hydrophobic contact angles observed before acid injection shifted towards hydrophilicity post-injection, indicating a change in wettability. This transformation was most pronounced in the case of HCl 7.5% + MeOH, which exhibited the lowest contact angle. Upon interaction with the rock surface, the acid caused it to become more hydrophilic over time. This hydrophilic nature facilitates the passage of condensate through pore throats, leading to increased production. Since acid is a water-based fluid, it tends to react effectively with water-wet rocks, resulting in altered wettability from oil-wet to water-wet. The addition of methanol to HCl solutions was found to reduce interfacial tension significantly. Specifically, a 15% HCl solution exhibited an interfacial tension of 6.188 dyne/cm. When methanol was introduced, the interfacial tension decreased to 5.322 dyne/cm for the 15% HCl solution with methanol, and further dropped to 3.567 dyne/cm for the 7.5% HCl solution with methanol. These results highlight the effectiveness of methanol in lowering interfacial tension in acidizing fluids, which is beneficial for enhancing fluid recovery in reservoir engineering applications.

Conclusions

This study has presented a novel approach to address condensate blockage in low-permeability gas reservoirs by designing an optimized acid system. The primary goal was to enhance the injectivity index to improve gas production. The investigation included a series of experimental tests, such as X-ray diffraction (XRD), Inductively Coupled Plasma (ICP), solubility tests, wettability alteration, and coreflood tests, to measure the incremental permeability—a strong indicator of efficiency. The main findings of this study are as follows:

  • Solubility tests indicated that thin sections dissolved at varying rates in different HCl concentrations: 53.02% in HCl 7.5 wt%, 60.36% in HCl 15 wt%, 62% in HCl 20 wt%, and 62.66% in HCl 28 wt%. Results demonstrates that 20 wt% and 28 wt% concentrations are 3% more soluble than 15% concentrations. Consequently, HCl 15 wt% was chosen as the optimized concentration, with HCl 7.5 wt% selected as the secondary concentration.

  • The addition of methanol to HCl 15 wt% and HCl 7.5 wt% decreased the interfacial tension, allowing for complete penetration of the acid into the rock. HCl 15 wt% + MeOH dissolved 64.745% of the thin section, while HCl 7.5 wt% + MeOH dissolved 70.56%, indicating that the latter’s lower HCl concentration facilitated continuous reaction and higher dissolution. Thus, HCl 7.5 wt% + MeOH proved to be more effective for low-permeability gas condensate reservoirs.

  • Coreflood tests with HCl 15 wt%, HCl 7.5 wt% + MeOH, and HCl 15 wt% + MeOH resulted in permeability increases of 30.86%, 68.72%, and 16.98% from the initial state, and 174.59%, 180.73%, and 121.43% from the damaged state, respectively. HCl 7.5 wt% + MeOH achieved the highest permeability increase due to its lower interfacial tension and enhanced penetration into the pore throats.

  • Contact angle measurements before and after acid injection revealed a shift from neutral or water-wet to more water-wet conditions. Initial contact angles were 107°, 120°, and 127° for HCl 15%, HCl 7.5% + MeOH, and HCl 15% + MeOH, respectively. After acid injection, the angles were reduced to 78°, 70°, and 77°, respectively. The most significant wettability change was observed with HCl 7.5% + MeOH, indicating its potential to enhance hydrocarbon recovery by facilitating the removal of condensate blockage.

In conclusion, the study underscores the efficacy of HCl 7.5 wt% + MeOH in improving permeability and reducing condensate blockage in low-permeability gas reservoirs, marking a significant contribution to the field of reservoir engineering.