Composite Acid Treatment for Mitigating Formation Damage in Gas Storage Reservoirs

Abstract

Severe permeability reduction caused by drilling-fluid contamination has significantly impaired injectivity and deliverability in the K gas storage reservoir. This study aims to restore reservoir performance through the optimization and application of a composite acid system. A series of laboratory evaluations combined with core-flow experiments, continuous core scanning, and NMR T₂ analysis were conducted to assess acid performance and elucidate damage-removal mechanisms and pore–throat evolution. The results show that the optimized composite acid exhibits favorable compatibility, effective corrosion and precipitation control, a strong clay-stabilization capacity, and high permeability restoration. Core-scale experiments and NMR analyses indicate that the acid selectively removes near-wellbore and deep plugging while restoring pore–throat connectivity without inducing excessive dissolution or framework damage. Field application further confirms the laboratory findings, demonstrating substantial improvements in gas injection and production performance, along with enhanced reservoir energy retention and recovery. Overall, the proposed composite acid system provides an effective and practical solution for mitigating formation damage and improving the long-term injectivity and deliverability of gas storage reservoirs.

1. Introduction

Underground gas storage (UGS) facilities are critical to national energy security and supply stability [1]. However, long-term injection–withdrawal cycles and complex fluid disturbances often induce clay migration, scale deposition, and organic film formation, leading to pore–throat blockages and the degradation of injectivity and deliverability [2]. Restoring near-wellbore seepage capacity while preserving reservoir-framework stability therefore remains a key challenge in UGS operations [3].

Acidizing is widely used to reopen near-wellbore flow channels [4,5]. Conventional hydrochloric and mud acids react rapidly but may cause framework over-etching, secondary CaF₂/fluorosilicate precipitation, and poor flowback performance, especially in low-pressure and water-sensitive reservoirs [6]. To overcome these issues, composite acid systems combining retarded, organic, and fluoboric acids with corrosion inhibitors, iron stabilizers, clay stabilizers, and diversion agents have been developed to achieve controlled reactivity and reduced precipitation risk [7]. Laboratory and kinetic studies indicate that such systems can improve pore connectivity, extend effective reaction depth, and maintain stimulation efficiency under harsh reservoir conditions [8,9,10]. In particular, fluoboric acid enables gradual HF release and suppresses CaF₂ precipitation [11], while organic acid systems have demonstrated more uniform acidizing behavior in field applications [12].

To better understand blockage removal and permeability enhancement mechanisms, recent studies have employed advanced pore-scale characterization techniques in UGS and near-wellbore sandstone reservoirs. Nuclear magnetic resonance (NMR) T₂ analysis has been widely used to quantify pore-size distribution and connectivity changes during cyclic injection–production processes [13,14]. Complementarily, CT and micro-CT imaging have provided direct visualization of pore–throat evolution following acid treatment or water sensitivity, revealing microscale flow-path enlargement and structural deformation [15,16]. Further integration of CT-based pore-network reconstruction with permeability analysis has demonstrated the strong linkage between microstructural reorganization and macroscopic flow behavior [17,18]. More recently, real-time NMR techniques have enabled the dynamic monitoring of fluid migration and pore-structure evolution in near-wellbore regions, offering time-resolved insights into pore–throat responses during fluid invasion [19].

Despite these advances, most existing studies have focused on static before–after comparisons or single-scale characterization, with limited integration between dynamic blockage-removal processes, localized pore–throat evolution, and overall seepage performance. In particular, the quantitative linkage between flow-based deplugging behavior, spatially resolved pore connectivity restoration, and permeability recovery in UGS reservoirs remains insufficiently established.

To address these gaps, this study integrates flow-based deplugging experiments with continuous core-scale scanning and nuclear magnetic resonance (NMR) T₂ analysis to systematically investigate near-wellbore damage removal mechanisms in sandstone gas storage reservoirs. By tracking pore-structure evolution across the initial, damaged, and post-treatment states, this study establishes a multiscale framework linking macroscopic permeability recovery with local and microscopic pore–throat responses, providing an experimental basis for optimizing damage-removal strategies in UGS applications.

2. Experimental Details

2.1. Experimental Materials and Equipment

2.1.1. Materials

Core samples were collected from three representative wells (K1, K2, and K3) in the K gas storage reservoir, where drilling-fluid-induced formation damage was most severe. The experimental reagents included a series of functional additives (corrosion inhibitors, iron-ion stabilizers, clay stabilizers, and diverting agents [20,21]) and four types of acids: hydrochloric acid, fluoboric acid, polyprotic acids [22], and hydrofluoric acid.

These materials were selected to reproduce the mineralogical sensitivity and damage characteristics of the target reservoir and to enable the systematic evaluation of acid compatibility, damage-removal efficiency, and framework protection. Distilled water was used as the base fluid, and all working fluids were prepared following field application practices in the K gas storage facility.

2.1.2. Experimental Equipment

A suite of laboratory and core-scale experimental techniques was employed to characterize the mineral composition, evaluate acid performance, and investigate formation damage-removal mechanisms.

X-ray diffraction (XRD) analysis was used to determine the mineralogical composition of the core samples, providing the basis for acid system selection and clay-sensitivity assessment. Interfacial tension measurements were conducted to evaluate the diverting and flow-distribution capability of the composite acid system.

Core acidizing and damage-removal experiments were performed using a core acid fluid loss apparatus, which simulates acid flow and reaction processes under representative reservoir temperature and pressure conditions. This setup enables the quantitative evaluation of acid penetration, plugging removal, and permeability restoration during flow-through treatment.

To characterize spatial variations in permeability before and after damage removal, a large-scale continuous core scanning system was employed. This nondestructive technique allows for the rapid assessment of axial and circumferential permeability evolution and is particularly suitable for evaluating heterogeneity changes induced by acid treatment.

In addition, a full-diameter nuclear magnetic resonance (NMR) system was used to analyze pore–throat structure evolution in the initial, damaged, and treated cores. NMR T₂ spectra provide insights into pore-size redistribution and enable identification of the dominant pore classes contributing to permeability recovery.

Detailed schematics and component descriptions of the experimental apparatus are provided in Figure 1 and Figure 2 to support reproducibility.

2.2. Experimental Methods

The experiments were conducted under simulated reservoir conditions of the gas storage field, with a formation pressure coefficient of 1.27, a formation temperature of 76 °C, and an injection fluid density of 1.4 g/cm³. A pressure differential of 4 MPa was applied during the flow-through deplugging experiments. This value was determined based on the calculated difference between the in situ formation pressure and the bottom-hole flowing pressure under typical injection and production conditions in the target reservoir. Therefore, the selected pressure differential represents an equivalent near-wellbore pressure gradient in field operations, ensuring consistency between laboratory experimental conditions and actual reservoir flow environments, and the confining pressure was maintained 2–4 MPa higher than the injection pressure.

2.2.1. Gas Permeability Measurement Procedure

Gas permeability was measured using a steady-state nitrogen flow method to quantify permeability changes before damage, after damage, and after acid treatment. Core samples were mounted in a core holder under confining pressure, and nitrogen was injected at controlled inlet pressures. Gas flow rates were measured repeatedly, and the average value was used to calculate permeability.

Initial permeability (K₀), damaged permeability (K₁), and post-treatment permeability (K₂) were determined for each core. Based on these values, the damage removal rate and permeability recovery were calculated as follows:

$$K={\displaystyle \frac{2Q\mu L{P}_0}{A(P_1^2-P_2^2)}}\times 100$$

(1)

Calculation of the damage removal rate:

$$J={\displaystyle \frac{K_2}{K_1}}\times 100\%$$

(2)

Calculation of permeability recovery:

$$R_k={\displaystyle \frac{K_2}{K_0}}\times 100\%$$

(3)

where K₀, K₁, and K₂ represent the initial, post-damage, and post-treatment permeabilities, respectively. The calculated indices reflect the extent of permeability impairment caused by drilling-fluid contamination and the effectiveness of acidizing treatment in restoring flow capacity.

2.2.2. Acid Dissolution Experiment

Acid dissolution experiments were conducted to evaluate the mineral-dissolving capacity of different acid systems. A known mass of reservoir rock powder was reacted with acid solutions at 76 °C for 120 min. After the reaction had taken place, insoluble residues were separated by filtration, dried to a constant weight, and weighed.

The acid dissolution rate was calculated based on the mass loss of the rock powder:

$$R_W={\displaystyle \frac{m_0+m_1-m_2}{m_0}}\times 100\%$$

(4)

This test provides a quantitative assessment of the acid’s ability to dissolve reservoir minerals and mitigate solid-phase plugging.

2.2.3. Acidizing Flow Experiment

Flow-through acidizing experiments were performed to simulate formation damage removal under reservoir-relevant conditions. Drilling-fluid-damaged cores were placed in the core holder, and the confining pressure was maintained at 2–4 MPa higher than the injection pressure. Fluids were injected sequentially following a typical field acidizing procedure: base fluid → pre-flush → treatment fluid → post-flush → base fluid.

Throughout the experiment, permeability evolution was continuously monitored to evaluate the dynamic response of the core to acid treatment. This method enables assessment of both near-wellbore and deeper damage removal under controlled flow conditions.

3. Results and Analysis

The mineral composition of the core samples was analyzed using X-ray diffraction (XRD). Based on the whole-rock XRD results, four acids—hydrochloric acid, organic acid, polyprotic acid, and fluoboric acid—were selected as the base acids for dissolution experiments. The acid dissolution tests on rock powder were used to preliminarily determine the recommended concentration of the main acid. Considering the characteristics of the K gas storage reservoir (primarily interbedded Yi/Meng formations with strong water sensitivity and a low-condensate gas reservoir controlled by both structure and lithology) and the composition of the field working fluids, the optimal concentration of the main acid was selected.

To ensure that the acid could effectively remove formation damage while maintaining good compatibility, preserving the reservoir skeleton, and minimizing potential damage to the equipment and downhole tubulars, appropriate amounts of additives were incorporated into the acid system. The composite acid system was then subjected to comprehensive performance evaluation.

3.1. Mineralogical Composition of Core Samples

An X-ray diffraction (XRD) analysis was conducted on three representative core samples (K1–K3), and the quantitative mineral compositions are summarized in

Table 1. Mineralogical composition of reservoir samples by X-ray diffraction (XRD).

Sample Number	Depth (m)	Mineral Content (%)
		Clay Minerals	Barite	Quartz	K-Feldspar	Plagioclase	Calcite	Dolomite	Siderite	Pyrite
K1	3021	33.1	0	26.7	5.4	34.8	0	0	0	0
K2	3023	48.2	0	23	0	24.4	4.5	0	0	0
K3	3026	39.1	0	32	0	22.5	6.5	0	0	0

and Figure 3. All samples are dominated by quartz, clay minerals, and feldspars, with minor carbonate minerals.

The relatively high clay content (>33% in all samples) indicates a strong sensitivity to water-induced swelling and particle migration, which can significantly reduce pore–throat connectivity. In addition, feldspars constitute a considerable fraction of the framework minerals, particularly in sample K1, making the reservoir susceptible to acid–mineral reactions that may alter the pore structure if not properly controlled. Carbonate minerals are present only in minor amounts and mainly act as cementing phases.

These mineralogical characteristics suggest that a single conventional acid is insufficient for effective and safe damage removal. Clay-rich intervals require effective clay stabilization and controlled dissolution, while feldspar-rich zones benefit from acids capable of slow and selective silicate dissolution to avoid framework collapse. Therefore, hydrochloric acid, organic acid, polyprotic acid, and fluoboric acid were selected as candidate main acids to address carbonate removal, clay stabilization, and controlled silicate dissolution. Subsequent acid dissolution experiments were performed to evaluate their dissolution efficiency and determine the optimal acid composition and concentration for the target reservoir.

3.2. Optimization of the Main Acid in the Acid System

Rock powders and filter cake samples obtained from formation damage experiments in the K gas storage reservoir were used to evaluate the dissolution performance of different acids. The objective was to determine appropriate acid types and concentrations that balance effective damage removal with preservation of reservoir mechanical integrity.

3.2.1. Comparative Evaluation of Acid Dissolution Performance

Dissolution experiments showed that all tested acids exhibited increasing dissolution rates with increasing concentration; however, their dissolution mechanisms and associated formation risks differed significantly. Hydrochloric acid mainly dissolves carbonate cement, organic acid and polyprotic acid promote silicate and clay-related dissolution, while fluoboric acid provides controlled HF release and deeper penetration.

Excessively high acid concentrations, although yielding higher dissolution rates, were not selected due to the risk of excessive framework etching, clay destabilization, and potential permeability damage. Conversely, low concentrations resulted in insufficient removal of drilling-fluid-induced plugging. Therefore, concentration selection was based on achieving effective dissolution while maintaining formation stability rather than maximizing the dissolution rate.

3.2.2. Determination of Optimal Acid Concentrations

As shown in Figure 4, based on the experimental results and reservoir mineralogical characteristics, the following concentrations were selected:

Hydrochloric acid (10%): Lower concentrations showed limited carbonate dissolution, while higher concentrations provided marginal additional benefit and increased corrosion risk.

Organic acid (equivalent to 0.5–1.5% HF): Higher concentrations caused excessive dissolution and posed a risk of weakening the sandstone framework.

Fluoboric acid (≈10%): This provided effective dissolution with controlled HF release; higher concentrations increased reaction intensity without significantly improving penetration depth.

Polyprotic acid (≈4%): Efficient dissolution was achieved while limiting clay reactivity; higher concentrations significantly increased the dissolution rate but raised concerns regarding framework stability.

To facilitate comparison, the performance and selection rationale of each acid are summarized in

Table 2. Comparison and selection criteria of main acids.

Acid Type	Primary Function	Dissolution Trend	Reason for Rejecting Lower Concentration	Reason for Rejecting Higher Concentration	Selected Concentration
HCl	Dissolve carbonates, maintain low pH	Low–moderate	Insufficient carbonate removal	Limited additional benefit, higher corrosion	10%
Organic acid	Dissolve clays and silicates	High	Inadequate damage removal	Excessive framework weakening	0.5–1.5% HF equivalent
Fluoboric acid	Controlled HF release, deep penetration	Moderate–high	Insufficient silicate dissolution	Excessive reaction intensity	~10%
Polyprotic acid	Clay protection, controlled silicate dissolution	Moderate–high	Weak dissolution effect	Risk of framework degradation	~4%

.

3.3. Dissolution Experiments of Composite Acid Systems

An effective acid system should not only enlarge pore throats but also efficiently remove plugging materials from the pores. In the K gas storage field, the drilling mud used on site exhibits high viscosity, while the core permeability is low, resulting in thin filter cakes. Large amounts of these filter cakes were collected and subjected to dissolution experiments. Using the previously optimized concentrations of individual acids, the dissolution of filter cakes showed that the acids retained good effectiveness in breaking down the mud cakes.

Based on the preliminary determination of optimal concentrations from single-acid dissolution experiments and considering reservoir conditions, composite acid systems more suitable for the reservoir were formulated. Dissolution experiments were then conducted on both rock powders and filter cakes to identify the optimal composite acid formulation.

Three preliminary composite acid formulations were tested:

Composite Acid 1: 10% HCl + 0.5% HF + 8% fluoboric acid

Composite Acid 2: 10% HCl + 1% HF + 8% fluoboric acid + 4% polyprotic acid

Composite Acid 3: 10% HCl + 0.8% HF + 10% fluoboric acid + 4% polyprotic acid

The dissolution experiments using these composite acids on rock powders and filter cakes are summarized in Figure 5, showing the comparative dissolution rates for each formulation.

The dissolution experiments conducted on both rock powders and filter cakes demonstrate that Composite Acid 2 and Composite Acid 3 exhibit superior damage-removal efficiency compared with other tested formulations, with dissolution rates of 16.09% and 21.75%, respectively. Although Composite Acid 3 shows a higher overall dissolution capacity, the performance difference between the two systems indicates distinct acid–rock interaction characteristics rather than simple dissolution strength.

Composite Acid 2, containing a higher effective HF activity, promotes rapid mineral dissolution but may increase the risk of excessive framework etching in clay-rich sandstone reservoirs. In contrast, Composite Acid 3 incorporates a higher proportion of fluoboric acid, which releases HF in a controlled manner and enhances deep penetration while suppressing secondary precipitation and clay destabilization.

Considering the relatively high clay mineral content and strong water sensitivity of the K reservoir, Composite Acid 3 provides a more favorable balance between effective damage removal and reservoir framework preservation. Therefore, Composite Acid 3 was selected as the optimal formation damage removal system for subsequent laboratory evaluation and field application. This comparison highlights that the selection of Composite Acid 3 was not based solely on dissolution strength, but on its superior compatibility with reservoir mineralogy and its ability to mitigate formation damage while maintaining long-term reservoir stability.

3.4. Comprehensive Performance Evaluation of the Composite Acid System

To ensure effective formation damage removal while minimizing adverse effects on the reservoir and downhole equipment, the optimized composite acid system was evaluated with respect to its compatibility, corrosion inhibition, iron stabilization, clay stabilization, and secondary precipitation control. These indicators were selected as they directly govern acid injectivity, reaction controllability, and long-term reservoir integrity under field conditions.

3.4.1. Compatibility and Corrosion Control Performance

The composite acid system exhibited good compatibility with all functional additives, remaining clear and stable without phase separation or precipitation after static aging at both an ambient temperature and the reservoir temperature of 76 °C. This confirms the chemical stability of the formulation during surface preparation and downhole placement.

Corrosion inhibition performance was evaluated using representative tubing steels (P110, 3CrP110, 13CrP110, and L480). As is shown in Figure 6, corrosion rates of the fresh composite acid were below 3 g/(m²·h), while those of the spent acid were below 0.2 g/(m²·h), both being well within industry-accepted limits. These results demonstrate that the composite acid maintains sufficient reactivity for damage removal while effectively protecting tubular materials during injection and flowback.

3.4.2. Iron Stabilization and Diverting Performance

The composite acid system showed strong iron-control capability, achieving an average iron stabilization capacity of 304 mg/mL with a 1% iron stabilizer dosage, exceeding standard performance requirements. This capability effectively mitigates the risk of iron hydroxide precipitation during acid flowback.

In addition, the incorporation of the diverting agent resulted in low and stable surface tension values for both fresh and spent acid (23–24 mN/m), indicating favorable diversion behavior and uniform acid placement during treatment.

3.4.3. Clay Stabilization and Secondary Precipitation Inhibition

As is shown in

Table 3. Evaluation of clay stabilization performance of the composite acid system.

Acid System	Soil Sample	Swelling Volume of Bentonite (mL)	Anti-Swelling Rate (%)
Fresh Water	Bentonite	5.6	/
Kerosene		0.4
Composite Acid 3		0.7	94.23

, clay stabilization tests indicate that Composite Acid 3 achieves a high anti-swelling efficiency of 94.23%, effectively suppressing clay hydration and migration in the clay-rich sandstone reservoir.

Secondary precipitation inhibition experiments further demonstrate the superiority of the composite acid system over conventional mud acid. As is shown in

Table 4. Inhibition rate of fluoride precipitation by composite acid solution.

Acidizing Fluid System	After CaCl2 Addition	Adjust pH to 3	Adjust pH to 5	Heated for 2 h	Inhibition Rate (%)
Mud Acid	The solution turned turbid, and sediment formed at the bottom after standing.	The solution became more turbid, and the amount of sediment increased after standing.	The solution became more turbid, but no discernible change in sediment volume was observed after standing	Precipitate settled at the tube bottom, while the upper solution in the pH-adjusted tube became slightly turbid	0
Composite Acid 3	No observable change	No observable change	The solution turned slightly turbid	The solution turned slightly turbid	73

and

Table 5. Reaction phenomena between the composite acid and Na₂SiO₃ and inhibition rate of fluosilicate precipitation.

Acidic Fluid Types	Precipitation Behavior of Mixed Solutions Upon Addition of Sodium Silicate Solutions at Varying Volumes
	1 mL	2 mL	3 mL	4 mL	5 mL	6 mL	Inhibition Rate%
Mud Acid	Clear and Transparent	Clear and Transparent	Slightly Turbid	Precipitate Formation	Precipitate Formation	Precipitate Formation	0
Composite Acid 3	Clear and Transparent	Clear and Transparent	Clear and Transparent	Clear and Transparent	Slightly Turbid	Precipitate Formation	62.5

, the composite acid achieved inhibition rates of 73% for fluoride precipitation and 62.5% for fluosilicate precipitation, significantly reducing the risk of pore–throat blockage caused by CaF₂ and fluosilicate formation during acidizing.

Overall, these results confirm that the optimized composite acid system provides a balanced performance in terms of damage removal efficiency, reaction controllability, and reservoir protection, forming a reliable basis for subsequent core-flow experiments and field application.

3.5. Acid Flow and Deplugging Experiments

3.5.1. Overall Core-Scale Deplugging Performance

To directly evaluate the deplugging efficiency of the composite acid, flow-through acidizing experiments were conducted on drilling-mud-damaged cores. Gas permeability was measured for the initial cores, damaged cores, and post-treatment cores to quantify permeability recovery and assess whether acid treatment compromised the core framework.

Figure 7 and Figure 8 compare the core end faces and permeability evolution before and after acid treatment. Formation damage caused a pronounced permeability reduction, whereas acid treatment resulted in a rapid and sustained permeability increase. After treatment under moderate displacement pressure gradients, permeability recovery ranged from 92.76% to 106.91% relative to the initial cores, indicating the effective removal of mud-induced plugging without structural damage. No sand production or visible core degradation was observed, confirming that the composite acid achieved efficient deplugging while preserving framework integrity.

At a displacement pressure differential of 4 MPa (Figure 9), permeability increased further to 165.34–190.48% of the initial value. This enhancement reflects not only complete removal of external mud cake but also partial reopening and widening of internal pore–throat channels, demonstrating the strong flow-assisted deplugging capability of the composite acid under field-relevant pressure gradients.

3.5.2. Local Deplugging Behavior from Continuous Core Scanning

While bulk permeability measurements provide an overall assessment of deplugging efficiency, continuous core scanning was employed to resolve spatial variations in permeability along the core length. Figure 10 compares permeability distributions for the same cores in the initial, damaged, and post-treatment states.

Before treatment, permeability reduction was concentrated near the core inlet, indicating dominant near-face plugging by solids present in drilling-fluid. After acid treatment, permeability distribution became more uniform along the core axis, with local permeability values recovering to or slightly exceeding those of the initial cores. This result demonstrates that the composite acid effectively removes near-wellbore damage and restores connectivity across multiple flow units, rather than producing localized high-permeability zones.

3.5.3. Microscopic Deplugging Mechanism Revealed by NMR

NMR imaging and T₂ spectral analysis were used to elucidate pore-scale deplugging mechanisms. Figure 11 shows that formation damage primarily affected the near-face region of the cores, whereas the core interiors experienced limited penetration of the solids present in drilling-fluid. After acid treatment, the near-face blockage was effectively eliminated, and internal fluid signal intensity increased, indicating improved pore connectivity.

According to the T₂ spectra shown in Figure 12, the pore system of the initial cores was mainly dominated by mesopores (intermediate T₂ range), which contributed the majority of the effective pore volume and governed gas flow capacity. After formation damage, the T₂ distribution shifted markedly toward shorter relaxation times, indicating a significant reduction in mesopore volume fraction and a relative increase in micropore-dominated storage pores, resulting in a pronounced decline in permeability.

Following treatment with the composite acid, the T₂ spectra exhibited a clear rightward shift, accompanied by a substantial recovery of pore volume within the mesopore T₂ interval, while the contribution of micropores decreased correspondingly. Quantitative integration of T₂ signal amplitudes over different relaxation-time ranges indicates that the increase in mesopore-associated pore volume accounts for the dominant contribution to permeability recovery. Importantly, no distinct amplification or emergence of long T₂ signals corresponding to macropores was observed after acidizing.

This absence of macropore generation demonstrates that the composite acid system does not induce excessive dissolution or framework over-etching. Instead, permeability enhancement is primarily achieved through selective widening and reconnection of pre-existing pore–throat channels at the mesopore scale, thereby improving seepage capacity while preserving the structural integrity of the core framework.

4. Field Application Feedback

The targeted acidizing system optimized through laboratory-scale experiments—comprising 10% HCl + 10% HBF₄ + 0.8% HF + 4% polyprotic acid combined with corrosion, iron-control, clay-stabilization, and diversion additives—was subsequently applied in field acid-fracturing operations. The treatment was implemented in five representative wells within the K gas storage reservoir, and field performance was continuously monitored over a six-month period. Basic information on the treated wells and operational parameters is summarized in

Table 6. Summary of field application results before and after composite acid treatment.

Well ID	Monitoring Period	Injection Rate (Before) (105 m3/d)	Injection Rate (After) (105 m3/d)	Production Rate (Before) (105 m3/d)	Production Rate (After) (105 m3/d)
W-1	Six months	3.11	4.38	2.28	4.12
W-2		5.2	8.4	4.16	6.3
W-3		4.46	5.78	3.94	4.88
W-4		6.33	7.12	3.8	7.3
W-5		5.08	6.77	4.17	6.03

Notes: “Before” values represent the average operational performance of the treated wells prior to acid treatment, while “After” values correspond to stabilized performance measured during the six-month post-treatment monitoring period. All five wells were treated using the same composite acid formulation and operational procedures.

. The observed field performance can be directly interpreted in light of the laboratory findings on pore–throat restoration and permeability enhancement.

Core-scale flow-through experiments and NMR T₂ analyses demonstrated that the composite acid selectively restores mesopore-scale pore–throat connectivity while avoiding macropore generation and framework over-etching. This mechanism provides a physical basis for the substantial improvement in injectivity and deliverability observed in the field. Following treatment, daily gas injection increased from 5.2 × 10⁵ m³/d to a stable 8.4 × 10⁵ m³/d (61.5% increase), while daily gas production rose from 3.8 × 10⁵ m³/d to 7.3 × 10⁵ m³/d (92.1% increase). Under emergency peak-demand conditions, the maximum daily production exceeded 1.25 × 10⁶ m³/d, fully meeting operational requirements.

The smooth decline in formation pressure during production further corroborates the laboratory observation that permeability enhancement was achieved through controlled pore–throat widening rather than excessive matrix dissolution. By preserving the reservoir framework and improving effective flow pathways, the acid system maintained the reservoir energy retention and operational stability throughout the monitoring period.

At the reservoir scale, the enhancement effects observed in laboratory cores are amplified by the treatment of multiple flow units within the near-wellbore region. Although reservoir heterogeneity and local mineralogical variability may influence the magnitude of response among different wells, the composite acid’s controlled reactivity and strong clay- and precipitation-control capabilities contributed to robust and reproducible field performance. As is summarized in Table 6, all treated wells exhibited consistent improvements in the injection capacity, production rate, and recovery factor over the six-month monitoring period. As a result, the reservoir recovery factor increased from 60% before treatment to 78% after treatment, indicating the effective activation of previously underutilized pore volumes and improved reservoir utilization.

Overall, the field application confirms that the laboratory-identified damage-removal mechanisms are scalable under realistic operational conditions, providing reliable technical support for long-term stable operation and peak-shaving supply assurance in gas storage reservoirs.

5. Conclusions

(1)

Optimized Composite Acid Design: An optimized high-compatibility composite acid system was developed by integrating HCl, fluorine-containing acids, and polyprotic acid with corrosion inhibition, iron control, clay stabilization, and diversion additives. The formulation is specifically designed for damage removal in sandstone gas storage reservoirs.

(2)

Balanced Reactivity and Compatibility: Laboratory evaluations demonstrate that the composite acid achieves a favorable balance between effective dissolution and reservoir protection. The system shows strong corrosion control, iron stabilization, clay swelling inhibition, and precipitation suppression, fully satisfying industry requirements for sandstone acidizing operations.

(3)

Effective Damage Removal and Permeability Restoration: Core-scale flow-through experiments confirm that the composite acid efficiently removes drilling-fluid-induced formation damage without causing core-face erosion or framework degradation. Permeability is effectively restored and locally enhanced, indicating reconnection of blocked pore–throat pathways rather than excessive matrix dissolution.

(4)

Reservoir Protection and Long-Term Stability: The acid system not only restores flow capacity but also preserves reservoir integrity by suppressing secondary precipitation and minimizing structural damage. This controlled reaction behavior is critical for maintaining long-term injectivity and deliverability in gas storage reservoirs.

(5)

Field Verification and Engineering Implications: Field applications validate that the laboratory-identified damage-removal mechanisms are scalable under operational conditions, resulting in sustained improvements in injection and production performance. For field engineers, the proposed composite acid provides a practical and reliable option for designing sandstone acidizing treatments that balance injectivity enhancement with reservoir protection, thereby reducing operational risk and improving long-term storage performance.