Influence of Clay Content on the Compaction and Permeability Characteristics of Sandstone Reservoirs

Abstract

Clay content is a critical geological parameter influencing the pore structure, compaction sensitivity, and flow capacity of sandstone reservoirs. In this study, representative Tertiary sandstones from a major sedimentary basin in western China were selected, covering natural and synthetic core samples with clay contents ranging from 20% to 70%. Utilizing a self-developed apparatus capable of both static and dynamic compaction experiments, we systematically performed staged static loading and gas–water two-phase displacement tests. This enabled us to obtain comprehensive datasets on porosity, permeability, pressure response, and two-phase flow characteristics under various clay content, confining pressure, and gas drive rate conditions. Results demonstrate that high clay content leads to pronounced pore structure compaction and substantially greater permeability reductions compared to low-clay reservoirs, indicating heightened stress sensitivity. The synergy between gas drive rate and confining pressure regulates intralayer water production efficiency: initially, increased gas drive enhances mobile water production, but efficiency drops sharply at late stages due to pore contraction and increased bound water. As confining pressure increases, the mixed-flow region for two-phase flow shrinks, with water permeability decreasing sharply and gas permeability increasing, revealing the dynamic fluid transport and productivity decline mechanisms controlled by effective stress. The research deepens understanding of compaction–flow mechanisms in clay-rich sandstones, offering bases for evaluating reservoir stress sensitivity and supporting efficient, sustainable gas reservoir development, which increasingly helps offset global energy shortages.

1. Introduction

With the continuous growth of global energy demand, unconventional oil and gas resources have received increasing attention, with high clay content sandstone reservoirs serving as important sources of hydrocarbons that face numerous development challenges [1,2]. The physical properties of sandstone reservoirs, particularly porosity and permeability, play decisive roles in oil and gas exploration and development [3]. However, these key parameters are influenced by various geological factors, among which clay content is considered one of the most significant factors affecting reservoir quality [4,5].

During reservoir development, as formation fluids are extracted, increased effective stress leads to compaction deformation of the reservoir rock framework, resulting in decreased porosity and permeability [6,7]. This phenomenon is particularly prominent in high clay content sandstone reservoirs because clay minerals have lower stiffness and higher compressibility [8]. Numerous studies have demonstrated that increased clay content significantly enhances reservoir sensitivity to pressure changes, thereby affecting oil and gas productivity and recovery efficiency [9,10].

Current research on the influence of clay content on sandstone reservoir compaction characteristics primarily focuses on theoretical model construction and limited experimental verification. Athy [11] first proposed an exponential relationship model between porosity and depth (or effective stress), laying the foundation for subsequent research. Dong et al. [12] discovered through experimental research that the type and content of clay minerals significantly affect the compaction characteristics of sandstone. Bjørlykke and Høeg [13] pointed out that the rearrangement and deformation of clay minerals during compaction are the main causes of dramatic decreases in reservoir permeability. Wang et al. [14] proposed a permeability pressure sensitivity prediction model considering clay content, but its applicability remains limited. In addition, some researchers have employed machine learning methods to explore reservoir characteristics [15].

In recent years, with the advancement of experimental techniques, more research has begun to focus on compaction–flow coupling mechanisms. Zhang et al. [16] studied the stress sensitivity of sandstones with different clay contents through laboratory experiments and found a positive correlation between clay content and permeability damage degree. Pang et al. [17] analyzed the microscopic mechanisms of clay minerals on sandstone reservoir compaction deformation, revealing the plastic deformation and rearrangement processes of clay minerals. Liu et al. [18] investigated the influence of temperature on the compaction behavior of clay minerals, indicating that the hydration expansion effect of clay minerals is more significant under high-temperature conditions. Additionally, compaction characteristics under multiphase flow conditions have received increasing attention, with Khilar and Fogler [19] studying the effect of clay particle migration on permeability, while Civan [20] proposed a comprehensive reservoir damage model considering clay mineral expansion and migration.

Despite these advances, several significant gaps remain in existing research. First, there is a lack of systematic experimental data, particularly regarding compaction and flow characteristics of sandstone reservoirs across a broad range of clay contents (20–70%) [21]. Second, understanding of multi-variable coupling effects remains incomplete, such as the interaction mechanisms between clay content, confining pressure, and flow rate [22]. Furthermore, considerable divergence exists between quantitative evaluation models and engineering applications, limiting the practical value of research findings [23,24].

To address these limitations, this study selects typical Tertiary sandstone reservoirs from a large sedimentary basin in western China and prepares both natural and synthetic core samples covering a wide range of clay contents (20–70%). By employing a self-developed compaction apparatus capable of both static and dynamic loading and two-phase displacement, we systematically acquire data on porosity, permeability, pressure response, and two-phase flow characteristics across various clay contents, confining pressures, and gas injection rates. These results provide a robust foundation for establishing coupled mechanical-flow control models and developing optimal production strategies for high-clay reservoirs [25,26].

The main objectives of this study include the following: (1) quantitatively characterizing the influence patterns of clay content on sandstone reservoir compaction sensitivity; (2) revealing the interaction mechanisms between clay content and factors such as confining pressure and flow rate; (3) establishing a compaction–flow coupling model applicable to high clay content sandstone reservoirs; and (4) providing theoretical basis and technical support for the development optimization of high clay content reservoirs. This research not only enriches the fundamental understanding of compaction and flow characteristics but also offers new insights and methods for the efficient development of unconventional reservoirs [27].

2. Geological Background and Sample Description

2.1. Geological Background

The study area is located in a large sedimentary basin in western China. As illustrated in the comprehensive stratigraphic column (Figure 1), the target reservoir is characterized by typical fluvial–deltaic depositional systems of the Tertiary period, exhibiting distinct sand-shale interbedding. The primary producing intervals occur at depths between 1280 and 1350 m, comprising predominantly fine- to medium-grained sandstones and siltstones with individual bed thicknesses ranging from 2 to 15 m. Extensive argillaceous interlayers and silty mudstone barriers are distributed throughout the reservoir interval, with thicknesses varying from 0.5 to 3 m, which compartmentalize the gas-bearing zones into multiple isolated or semi-connected flow units.

The lithological assemblage exhibits characteristic “sand-in-mud” and “mud-in-sand” composite architectures. Gas-bearing intervals are primarily hosted within medium- to coarse-grained sandstone sections (1310–1315 m and 1320–1325 m in Figure 1), displaying typical gas reservoir log responses. Water-bearing and gas–water transition zones are predominantly associated with siltstones and argillaceous siltstones, reflecting lithological control on fluid distribution. Dry layers occur mainly in clay-rich silty mudstone intervals with poor reservoir quality and negligible commercial productivity.

The natural core photographs (right side of Figure 1) directly illustrate the lithological characteristics: Core from Well S4-15 (1310.6–1312.3 m) exhibits a grayish-brown coloration with visible clay laminae and patchy distribution, reflecting rapid facies changes typical of channel deposits. The core from 1320.9 to 1323.3 m displays lighter coloration and coarser grain size with relatively lower clay content, representing depositional characteristics of the main channel axis. Overall, the reservoirs demonstrate medium to high porosity (18–32%) and low to medium permeability (10–120 mD), with spatial variations in clay content (20–70%) resulting in pronounced reservoir heterogeneity. During production, as formation pressure declines and effective stress increases, this lithologically controlled heterogeneity directly impacts compaction deformation, flow capacity, and production performance.

2.2. Core Selection and Sample Description

This study employed six groups of sandstone samples with clay contents ranging from 20% to 70%, comprising two natural cores and four synthetic cores, to systematically investigate their petrophysical properties and compaction response characteristics.

(1)

Natural Core Samples

Natural core selection followed rigorous criteria for representativeness, integrity, and experimental feasibility. Cores were required to originate from the main producing intervals of the target reservoir to ensure that their mineral composition, pore structure, and clay content accurately represent reservoir characteristics. Priority was given to well-preserved, full-diameter cores (≥25 mm) without visible fractures or mechanical damage, with minimum lengths of 5 cm to meet experimental holding requirements. Core scanning and CT imaging techniques were employed for preliminary screening to eliminate samples containing large dissolution vugs or fractures, ensuring that experimental results reflect matrix flow properties. Additionally, at least three parallel samples were selected from each depth interval for comparative validation. Clay content was quantitatively determined through X-ray diffraction (XRD) analysis with deviation controlled within ±2%. For cores with hydrocarbon shows, Soxhlet extraction using toluene–ethanol mixture was performed to ensure initial oil saturation < 1%, preventing interference from residual hydrocarbons on flow experiments. Based on these criteria, the selected cores were as follows:

Sample 1 (Well S4-15, 1310.6–1312.3 m): Clay content: 41.3%, porosity: 30.6%, permeability: 7.07 mD (Figure 1).

Sample 2 (Well S4-15, 1320.9–1323.3 m): Clay content: 23.3%, Porosity: 30.9%, Permeability: 34.05 mD (Figure 1).

(2)

Synthetic Core Samples

Synthetic core preparation employed quantitative compositional control and standardized manufacturing processes to achieve precise clay content regulation and reproducible petrophysical properties. The framework material consisted of 100–300 mesh quartz sand (>98% purity), while the clay component utilized industrial-grade kaolinite and illite powder (<2 μm particle size). Materials were precisely weighed according to designed clay contents and mixing homogeneity was verified using laser particle size analysis. The wet-forming technique was employed: mixed materials were thoroughly blended with 5% polyvinyl alcohol (PVA) solution to form a homogeneous slurry, which was then molded under 10 MPa pressure into cylindrical specimens (φ25 mm × 50 mm). Samples underwent sequential drying at 110 °C for 24 h and sintering at 550 °C for 2 h to achieve consolidation. Post-formation synthetic cores required porosity-permeability calibration to ensure batch consistency with porosity deviation < 3% and permeability deviation < 10%. Mercury intrusion porosimetry was used to verify pore-throat distribution similarity with natural cores, ensuring that synthetic samples effectively simulate stress–flow response characteristics of reservoirs with varying clay contents.

The artificial cores were designed with four gradients of clay content (20%, 50%, 55%, and 70%). Among these, the 20% sample simulates high-porosity and high-permeability reservoirs, while the 70% sample characterizes shale barrier layers. In addition, two natural cores were included. The selected clay content levels cover a range from relatively low (20%) to relatively high (70%), enabling a comprehensive reflection of the changes in reservoir physical properties under different clay content conditions.

When the clay content exceeds 50%, the trend of permeability reduction becomes more pronounced, indicating that the reservoir becomes more sensitive to changes in clay content. By selecting the two key points of 50% and 55%, this change trend can be observed more clearly, thereby facilitating a deeper understanding of the influence mechanism of clay content on reservoir characteristics.

2.3. Core Physical Properties

Comprehensive petrophysical measurements (X-ray diffraction (XRD) analysis, nuclear magnetic resonance (NMR), and the method for determining permeability by unsteady-state methods) were performed on all core samples with varied clay contents, including porosity, permeability, gas saturation, and bound water saturation. These key parameters (summarized in

Table 1. Basic Physical Properties of Cores with Different Clay Contents.

Core No.	Clay Content (%)	Porosity (%)	Permeability (mD)	Gas Saturation (%)	Bound Water Saturation (%)
1	41.3	30.6	7.07	51.5	48.5
2	23.25	30.9	34.05	76.8	23.2
3 *	20	31.0	24.17	—	—
4 *	50	26.5	14.32	—	—
5 *	55	25.0	13.01	—	—
6 *	70	20.0	6.48	—	—

Note: Parameters marked with “*” are determined through artificial core experiments; due to experimental limitations, data on gas saturation and irreducible water saturation for some rock samples were not obtained.

) provide a robust data foundation for subsequent investigations of compaction and flow characteristics under stress.

3. Experimental Methods

3.1. Experimental Apparatus and Design

In this study, a self-developed dual-system compaction experiment apparatus was employed to systematically analyze the mechanical response and permeability characteristics of sandstone samples with varying clay contents. The experimental system integrates high-precision modules for the measurement of pressure, flow, and volume, thereby enabling coordinated control of multiple parameters and ensuring data reliability and reproducibility.

3.1.1. Experimental Setup

The experiments utilized a custom-built uniaxial-static and dynamic-flow compaction system. The static compaction unit comprises an axial-radial loading mechanism, confining pressure control module, and a core holder with precise effluent collection capability. Stepwise loading (0–15 MPa) was applied to simulate stratigraphic pressure variations, while simultaneously monitoring core deformation and fluid production dynamics in real time.

The dynamic-flow compaction unit (Figure 2), based on the static system, incorporates a constant-flow gas injection module and a multi-parameter data acquisition system. Gas–water two-phase displacement was implemented by regulating confining pressure (2–15 MPa) and gas drive velocity (2.5–5.7 mL/min), thereby enabling precise simulation of reservoir stress–flow coupling processes. Both systems are equipped with high-accuracy sensors and automated data acquisition, enabling synchronous measurement of porosity, permeability, and pressure profiles.

3.1.2. Experimental Variables

Following an orthogonal design principle, this study selected clay content (20–70%), confining pressure (2–15 MPa), and gas drive velocity (2.5–5.7 mL/min) as the main controlled variables (

Table 2. Experimental Design Parameters.

Parameter	Value/Range	Notes
Clay content	20%, 23.25%, 41.3%, 50%, 55%, 70%	Grouping by natural and artificial core types
Confining pressure	2–15 MPa	Stepwise loading to represent burial depth effects
Gas drive rate	2.5, 3.1, 4.1, 5.7 mL/min	Flow control simulates various production intensities
Temperature	Ambient (higher temperatures are optional)	Environmental parameter control
Measured Parameters	Effluent volume, porosity, permeability, pressure profile	Automatic full-process data logging

). Through multi-factorial experiments, the influence of each parameter on the compaction–permeability characteristics of the reservoir was systematically analyzed. All experiments were conducted under ambient conditions (20 °C, 0.101 MPa). The water sample used in the displacement experiments was formation water from the study area, with a salinity of 97,517 mg/L, density of 1.066 g/cm³, and viscosity of 1.225 mPa·s. An automated data acquisition system was employed to record key parameters such as porosity, permeability, and pressure curves.

3.2. Experimental Procedure

3.2.1. Sample Preparation and Pretreatment

Both natural (samples 1 and 2) and artificial core samples were selected. Each sample underwent physical cleaning and drying, followed by vacuum saturation to ensure complete water saturation and baseline measurement of initial porosity. For data reliability, triplicate experiments were conducted for every group.

3.2.2. Experimental Workflow

Static Compaction Tests:

(1)

Place the saturated core into the high-pressure chamber and connect the confining pressure system;

(2)

Apply stepwise loading from 0 MPa, incrementally increasing confining pressure (2, 5, 8, 10, 12, 15 MPa), maintaining each stage until equilibrium is reached;

(3)

Record core deformation and effluent variation in real time;

(4)

Use a constant pressure gradient method to determine permeability at each pressure stage;

(5)

After completion, unload pressure stepwise and measure final parameters.

Dynamic Flow Compaction Tests:

(1)

Install the saturated sample in the flow compaction apparatus, connect the gas–water system;

(2)

Set initial confining pressure (2–5 MPa) and gas drive velocity (2.5–5.7 mL/min);

(3)

Employ two schemes: (i) constant confining pressure with stepwise increase in gas drive rate; (ii) constant drive rate with stepwise increase in confining pressure (ΔP = 1 MPa);

(4)

Continuously monitor effluent volume, pressure gradient, and gas–liquid ratio;

(5)

At test end, measure residual water saturation and calculate porosity and permeability reduction rates.

Through these protocols, comprehensive coupled hydromechanical data were obtained under various operating conditions, forming the experimental basis for reservoir stress sensitivity evaluation models. All results were verified by triplicate measurements to ensure reliability.

4. Results and Discussion

To ensure data reliability, all experimental results presented below are averages obtained from three repeated experiments, with error margins all less than 5%.

4.1. Pressure Sensitivity of Porosity and Permeability

4.1.1. Experimental Results

To investigate the pressure sensitivity of sandstone reservoirs with varying clay contents, two representative core samples were selected: Sample 1 with a clay content of 41.3%, and Sample 2 with a clay content of 23.25%. Stepwise confining pressure loading (0–15 MPa) was applied to assess the response of porosity and permeability in these cores. The characteristic variation curves of porosity and permeability as functions of confining pressure are illustrated in Figure 3 and

Table 3. Porosity and permeability measurements versus confining pressure.

Confining Pressure MPa	41.3% Clay Content		23.25% Clay Content
	Permeability mD	Porosity f	Permeability mD	Porosity f
0	7.07	0.306	34.05	0.309
2	6.36	0.292	31.13	0.302
5	5.44	0.275	26.73	0.293
8	4.64	0.267	24.29	0.285
10	4.30	0.262	21.08	0.280
12	3.77	0.260	18.37	0.276
15	3.21	0.256	16.71	0.270

.

The results indicate that both porosity and permeability exhibit significant decreases with increasing confining pressure, demonstrating pronounced pressure sensitivity in both samples. Specifically, under confining pressures ranging from 0 to 15 MPa, Sample A (high-clay, 41.3%) experienced a porosity reduction of 16.34%, while Sample B (low-clay, 23.25%) showed a decrease of 12.62%. The greater porosity loss in the high-clay sample is attributed to the plastic deformation of clay minerals under stress, where enhanced particle rearrangement and increased pore throat blockage intensify pore compaction.

A similar trend was observed in permeability. For Sample A, permeability declined from 7.07 mD to 3.21 mD (a reduction of 54.60%), while that of Sample B decreased from 34.05 mD to 16.71 mD (a reduction of 50.93%). The pressure sensitivity of permeability is more pronounced in the high-clay content sample, primarily due to the augmented compressive effect of clay minerals on pore throats, as well as the more severe pore plugging resulting from fine particle migration in clay-rich sandstones.

Additionally, the pressure sensitivity displays a stage-dependent behavior. During the low-pressure loading stage (2–5 MPa), both porosity and permeability drop rapidly, reflecting the initially loose microstructure. At higher confining pressures, the rate of decline in both parameters slows, suggesting the occurrence of irreversible compaction, especially where closure of micropores and throats is more evident in high-clay samples.

4.1.2. Data Analysis and Discussion

Mechanistically, differences in pressure sensitivity among various samples can be attributed to clay content. High-clay sandstones are enriched in plastic minerals, making them more susceptible to particle rearrangement and framework deformation under stress, while low-clay sandstones, dominated by rigid minerals such as quartz, retain greater structural stability. The heterogeneous distribution of clay cementation further magnifies permeability loss in high-clay samples.

In terms of reservoir development, the presence of high-pressure sensitive clay-rich interlayers may enhance vertical sealing capacity, thereby suppressing interlayer fluid crossflow. However, for the main reservoir intervals, the permeability loss induced by pressure depletion during production necessitates careful monitoring. It is recommended that optimized drawdown management be employed to maintain formation pressure and mitigate the adverse impact of pressure sensitivity on reservoir deliverability.

4.2. Effect of Clay Content on Compaction Performance

4.2.1. Experimental Results

To assess the impact of clay content on the compaction-induced decline and pressure sensitivity of permeability in sandstone reservoirs, a series of permeability measurements were conducted on synthetic core samples with varying clay contents (20%, 50%, 55%, and 70%) under progressively increasing confining pressures (0–15 MPa). The experimental results (Figure 4) demonstrate a systematic decrease in the permeability of cores with different clay contents as confining pressure increases.

As shown in Figure 4, the magnitude of permeability reduction under equivalent confining pressure conditions increases substantially with rising clay content. Notably, when the clay content exceeds 50%, the trend of permeability decline becomes markedly more pronounced. Specifically, at a confining pressure of 15 MPa, the cores with clay contents of 20% and 55% exhibit permeability reductions of 40.86% and 57.53%, respectively, while the core with 70% clay content shows a dramatic reduction of up to 87.19%. This trend clearly indicates that clay content exerts a significant influence on the pressure sensitivity of permeability in sandstone reservoirs, with cores of higher clay content suffering far more severe deterioration of permeability.

4.2.2. Discussion

This study elucidates the mechanisms behind the influence of clay content on reservoir pressure sensitivity through systematic experiments on synthetic cores. The results reveal that, with increasing clay content, the rock framework gradually transitions to one dominated by fine-grained clay components and plastic cement, thereby substantially reducing its structural stability. Under external confining pressure, the low stiffness and high expansibility of clay minerals facilitate particle slippage and rearrangement, rendering the pore structure more sensitive to pressure changes and ultimately causing substantial permeability reduction.

The unique physical properties of clay minerals are key determinants of compaction sensitivity. Clay minerals such as illite and kaolinite possess pronounced plasticity and adsorption characteristics, leading to irreversible deformation under stress. As confining pressure increases, rocks with high clay content rapidly experience structural densification, with appreciable decreases in both porosity and pore-throat radius (Figure 5). Experimental data demonstrate that, at a confining pressure of 15 MPa, the permeability reduction in the core with 70% clay content reaches 87.19%, far exceeding that of low-clay-content cores, thereby confirming a strong positive correlation between clay proportion and compaction sensitivity.

Mechanistic analysis of stress sensitivity indicates that clay infilling exerts a dual controlling effect on reservoir response to stress. First, an increased clay fraction amplifies the stress concentration effect within the pore-framework system, promoting the closure of micropore throats. Second, the expansion and plastic deformation of clay further constrict fluid pathways, significantly increasing secondary capillary pressure and further impairing permeability. It is noteworthy that in high-clay-content intervals, these characteristics may enhance interlayer sealing during reservoir development but could simultaneously cause substantial reductions in gas reservoir productivity.

From an engineering perspective, field practices in the Sebei Gas Field and similar medium to high-clay-content reservoirs indicate that reductions in formation pressure, resulting in increased effective stress, will markedly exacerbate permeability degradation. The permeability of reservoir sections may decline by 30–50%, directly impacting well productivity, while that of clay-rich interlayers may decrease by over 70%, possibly reinforcing the sealing effectiveness between layers. Accordingly, development strategies should give full consideration to the spatial distribution characteristics of clay content, and an optimized pressure management protocol should be employed to balance productivity maintenance and control of interlayer fluid communication.

4.3. Mechanism of Intra-Reservoir Water Production Under Static and Dynamic Compaction

4.3.1. Results and Analysis of Static Compaction Experiments

Static compaction experiments, designed to simulate the restoration of formation pressure, were conducted to investigate the pore compression and intra-reservoir water release mechanisms in reservoir rocks under stress conditions. Fully water-saturated core samples were subjected to incremental confining pressures, with systematic monitoring of expelled water and variations in pore volume throughout the compaction process. Results indicate that as confining pressure increased from 2 MPa to 5 MPa, the total core volume contracted, leading to a rapid decrease in pore volume and a substantial reduction in porosity. Specifically, the compression ratio of pore volume in saturated cores increased from 14.4% to 24.3% (Figure 6).

Quantitative analysis of water expelled per unit pressure difference revealed a declining trend with increasing confining pressure (Figure 7). Within the 2–5 MPa range, the expelled water ratio per unit pressure differential was 9.61% and 6.23%, respectively, indicating high sensitivity of the initial pore structure to pressure changes. In the later stages, intensified throat compression and capillary plugging effects diminished the marginal benefit of increasing pressure for water displacement. This nonlinear response highlights the densification of the core under high-pressure conditions, where additional stress fails to effectively mobilize residual bound water.

These experimental findings demonstrate that water production due to compaction-induced effective stress enhancement occurs mainly during the early stages of reservoir development, while the contribution of subsequent pressure increments to water recovery is significantly reduced. This phenomenon is closely associated with the irreversible compression of pore throats and capillary-force-governed water trapping mechanisms. The results provide experimental evidence for understanding fluid production rules in stress-sensitive reservoirs, particularly illustrating how pore structure evolution under high-stress conditions constrains flow capacity.

These insights are of direct relevance for the water production control in high-water-content layers or clay-rich interbeds. By quantifying the pressure sensitivity of compaction-driven water release, formation pressure maintenance strategies can be optimized to avoid unnecessary pressurization and associated energy consumption. Furthermore, the study confirms that, under static loading conditions, reservoir water production is primarily governed by stress-induced pore volume loss rather than by pressure-driven seepage, providing an important reference for refining productivity prediction models in tight reservoirs.

4.3.2. Results and Analysis of Dynamic Compaction Experiments

In dynamic compaction experiments, variable gas displacement rates were introduced to systematically study intra-reservoir water migration and production characteristics under different gas drive velocities and confining pressures. Two approaches were adopted: increasing gas drive velocity under constant confining pressure, and raising confining pressure under constant gas drive velocity, in order to identify key control factors for intra-reservoir water production. Results showed that, at a given confining pressure, higher gas drive velocities yielded greater water production per unit time and significantly higher cumulative water output. For example, under 2 MPa confining pressure, cumulative expelled water increased sequentially as gas drive rates were raised from 2.5 to 4.1 and 5.7 mL/min, illustrating that an initial increase in pressure differential effectively accelerates water release. However, as the gas drive velocity continued to increase, the water-producing efficiency per unit time declined, reflecting the dual effects of reduced movable water and increased displacement resistance (Figure 8).

Analysis of the effect of confining pressure on water-producing ratio per unit time demonstrated that, under identical gas drive rates, cumulative water output increased with confining pressure, yet the portion displaced per unit time continually decreased. Specifically, as confining pressure rose from 2 MPa to 8 MPa, the water production ratio per unit time dropped from 3.43% to 0.21%, exhibiting a marked downward trend. This indicates that augmented effective stress can efficiently mobilize pore water at early stages; however, with ongoing pore compression, channel narrowing, and rising bound-water fraction, the reservoir’s water-output capacity gradually weakens. This trend parallels the patterns observed in static compaction experiments, further corroborating the regulatory effect of stress on pore structure evolution (Figure 9).

The experimental data also indicate that the principal stage of intra-reservoir water output occurs within low-to-medium confining pressure intervals. At higher confining pressures, despite some maintenance of displacement efficacy via increased gas drive rates, compression and narrowing of main flow channels and intensified capillary forces markedly reduce water production rates. At this stage, a larger proportion of residual water transitions into immobile bound water, reflecting marked core densification under high stress. This dynamic response demonstrates that gas drive velocity and confining pressure jointly regulate the migration and production efficiency of intra-reservoir water, with their mechanisms exhibiting distinct evolutionary stages during the experimental process.

Overall, results suggest that under dynamic compaction, intra-reservoir water production is governed by the synergistic effect of gas drive velocity and confining pressure. In the early production stage, an increased displacement pressure differential promotes water release; subsequently, compaction of pore structure and enhanced capillary effects lead to substantially reduced water-removal efficiency. These findings provide valuable guidance for optimizing gas drive strategies in practical field development, particularly for high-water-content or tight reservoirs, where the dynamic evolution of stress sensitivity and flow capacity must be considered to enhance water control efficacy.

4.3.3. Discussion of Compaction Mechanisms

Experimental results reveal that under static compaction, intra-reservoir water release is primarily controlled by pore volume compressibility: rapid initial compaction of the pore structure leads to significant water discharge, while subsequent increases in stress yield diminished water production potential. In contrast, dynamic compaction experiments highlight that gas drive velocity controls the initial water breakthrough efficiency, while elevations in confining pressure compress pore throats and intensify capillary forces, incrementally increasing the proportion of bound water and shifting the water production mechanism from a stress-driven to a capillary-constrained regime.

This evolving pattern provides clear engineering guidance: in the development of stress-sensitive or clay-rich gas reservoirs, early optimization of production pressure differential and gas extraction intensity is essential to fully exploit initial movable water productivity. Simultaneously, implementation of segmented pressure management strategies can delay the onset of capillary constraints, ultimately achieving the development goal of “high-efficiency initial drainage, followed by controlled water production and stable output” throughout the reservoir lifecycle.

4.4. Variation in Relative Permeability and Two-Phase Flow Behavior

4.4.1. Experimental Results

In this study, full-diameter core samples were utilized to systematically investigate gas–water two-phase flow under varying confining pressures, aiming to elucidate the influence of effective stress on multiphase flow characteristics within sandstone reservoirs. The experimental results indicate that, as confining pressure increases from 5 MPa to 15 MPa, both the morphology of gas–water relative permeability curves and the extent of the two-phase co-permeation interval are significantly altered (Figure 10). The key observations are as follows:

Dynamic Shrinkage of Two-Phase Co-Permeation Zone: As confining pressure is progressively elevated from 5 MPa to 8, 10, and 15 MPa, the saturation window for simultaneous gas–water flow (Sw) correspondingly narrows from 0.299 to 0.285, 0.235, and 0.223. The effective stress increment leads to a 25.4% reduction in the cooperative flow saturation window, underscoring the pronounced stress sensitivity of the reservoir.

Inverse Evolution of Relative Permeability Parameters: The water-phase relative permeability (Krw) is globally suppressed across the examined range. For example, at Sw = 0.92, Krw sharply decreases from 0.466 to 0.118, reflecting a reduction of 74.7%. Conversely, the gas-phase relative permeability (Krg) exhibits a marked increase in the medium-to-low water saturation region, rising from 0.203 to 0.649 (an increase of 219.7%) at Sw = 0.72, suggesting that enhanced effective stress significantly improves the connectivity of gas flow pathways.

Shift in Curve Family Characteristics: As shown in Figure 9, under high confining pressure (15 MPa), the Krw curves display a systematic downward shift, while the Krg curves exhibit prominent convexity in the Sw < 0.8 interval. The intersection point of the two curves migrates towards higher Sw by 0.12, indicating that pressure sensitivity promotes the expansion of gas-flow-dominated zones within the reservoir.

4.4.2. Mechanism Discussion

To further elucidate the mechanisms underlying these experimental results, the analysis is conducted from the perspective of coupling between microscopic pore-throat structure and macroscopic flow characteristics:

Pore Throat Compression and Capillary Effects Narrow Two-Phase Flow Regions: Increased effective stress compacts the rock’s pore-throat structure, leading to a reduction in the average flow channel radius and diminished network connectivity. This contraction substantially increases capillary pressure within the pore system; in ultrafine throats, capillary pressure may exceed the gas driving pressure, resulting in liquid water being trapped by capillary forces and the occurrence of a “water sealing” phenomenon. Under high confining pressure, some pore-throat channels may close completely, further restricting the Sw interval for two-phase flow and markedly narrowing the window for simultaneous gas and water flow.

Physicochemical Disparities Between Gas and Water Govern Flow Regime Evolution: Natural gas, as a non-wetting phase, is characterized by significantly lower viscosity and smaller molecular size relative to water. Under conditions of throat contraction, gas molecules preferentially permeate narrow channels and occupy central pore positions, whereas the wetting phase (water) is mainly adsorbed along pore walls owing to its strong wettability, thereby further limiting its mobility. The combined influence of capillary pressure and high water viscosity exacerbates water retention, leading to a pronounced reduction in water-phase relative permeability (Krw) and enhanced dominance of gas-phase relative permeability (Krg) at intermediate-to-low Sw.

Competition Between Gas-Preferential Flow and Water Sealing Effects: Throat contraction and elevated capillary pressure enable gas to sustain effective flow even at relatively high water saturations, exhibiting a “gas-preferential flow” characteristic. However, in high Sw regions, substantial quantities of water may become immobilized due to capillary constraints, resulting in a water sealing effect. This mechanism not only causes the boundary of the two-phase co-flow region to shift towards lower Sw but also increases the difficulty of water removal and gas production in the late stage of development, significantly influencing gas recovery and production stability.

4.5. The Coupling Effect Among Various Factors

4.5.1. The Coupling Effect of Clay Content and Confining Pressure

Pore Structure and Permeability: High-clay-content reservoirs are more prone to pore structure compression under confining pressure, leading to a significant decline in permeability. This is because clay minerals have relatively low stiffness and high compressibility, which can lead to particle rearrangement and pore throat plugging under confining pressure. This coupling effect makes the permeability of high-mud-content reservoirs more sensitive to changes in confining pressure.

Stress Sensitivity: High-clay-content reservoirs exhibit stronger pressure sensitivity as confining pressure increases. This is due to the more pronounced plastic deformation and rearrangement of clay minerals under high pressure, resulting in greater reductions in permeability and porosity. This coupling effect requires special attention during reservoir development, as increased confining pressure can significantly affect reservoir productivity.

4.5.2. The Coupling Effect of Clay Content and Gas Flooding Rate

Water-phase displacement efficiency: In high-clay-content reservoirs, initially increasing the gas injection rate can promote the production of movable water. However, as the gas injection rate continues to rise, the compression of the pore structure and the increase in bound water will sharply reduce water displacement efficiency. This is because clay minerals are more prone to particle migration and pore plugging under high gas injection rates, leading to a decline in water-phase permeability.

Gas-phase permeability: In high-clay-content reservoirs, the variation in gas-phase permeability during gas injection is also influenced by clay content. Initially, increasing the gas injection rate can enhance the flow capacity of the gas phase. However, as the pore structure compresses and capillary forces increase, the improvement effect on gas-phase permeability gradually diminishes.

4.5.3. The Coupling Effect of Confining Pressure and Gas Injection Rate

Two-phase flow characteristics: The synergistic effect of confining pressure and gas injection rate has a significant impact on the two-phase flow characteristics of the reservoir. Under low confining pressure conditions, increasing the gas injection rate can effectively promote the displacement of the water phase. However, as the confining pressure increases, the compression of the pore structure and the enhancement of capillary forces significantly reduce the permeability of the water phase, leading to a decline in water displacement efficiency. Meanwhile, the gas phase permeability may increase within the intermediate-to-low water saturation range, but its flow is also suppressed at high water saturation levels.

Production decline mechanism: The coupling effect of confining pressure and gas injection rate also influences the production decline mechanism of the reservoir. Under high confining pressure conditions, even if the gas injection rate is increased, the production decline rate of the reservoir accelerates. This is because the compression of the pore structure and the enhancement of capillary forces significantly reduce the reservoir’s permeability and porosity, leading to a decline in the flow capacity of both the gas and water phases.

4.5.4. The Combined Coupling Effect of the Three Factors

Reservoir Heterogeneity: The combined coupling effects of clay content, confining pressure, and gas injection rate can significantly influence reservoir heterogeneity. In high-clay-content reservoirs, the changes in pore structure and permeability become more complex under conditions of increasing confining pressure and varying gas injection rates, thereby exacerbating reservoir heterogeneity. This heterogeneity affects the distribution and flow paths of fluids, which in turn impacts the development efficiency of the reservoir.

4.6. Comparative Validation of Actual Production Data

To enhance the engineering credibility of the proposed compaction–flow coupling model, we compared the model predictions with actual production data from the Sebei Gas Field. The field data included production rates, pressure profiles, and water cut measurements from multiple wells over a period of five years. The model was calibrated using early production data and then used to predict the subsequent production behavior. The results showed that the model predictions closely matched the actual field observations, with an average deviation of less than 10% in gas production rates and pressure trends. This validation confirms the applicability and reliability of the model in predicting reservoir performance under varying operational conditions.

4.7. The Limitations of Scale and Their Impact on Numerical Modeling

The main limitation of upscaling from the core scale to the reservoir scale lies in the potential loss of detail and variability. Core samples provide high-resolution data but may fail to capture the spatial distribution of properties over larger distances. Numerical models must account for this variability to accurately simulate reservoir behavior. Advanced numerical techniques such as upscaling and stochastic modeling can help bridge the gap between core-scale and reservoir-scale behavior. Upscaling represents larger volumes by averaging core-scale properties, while stochastic modeling incorporates variability and uncertainty to simulate a range of possible reservoir behaviors. Geostatistical methods can be used to integrate core data with larger-scale geological information (such as seismic data) to create more representative reservoir models. This integration helps capture the spatial variability and heterogeneity of the reservoir.

Future research should focus on developing more sophisticated numerical models that better account for large-scale heterogeneity. Additionally, integrating multi-scale data (such as core, well logging, and seismic data) can enhance the understanding and prediction of reservoir behavior under compaction and fluid production conditions.

5. Enlightenment for Oil and Gas Field Development

5.1. Stress Sensitivity of High-Mud-Content Reservoirs and Early Warning Mechanism for Production Decline

Indoor experiments have confirmed that gas reservoirs in high-mud-content sandstones exhibit significant stress sensitivity characteristics during the mid-to-late development stages. When the confining pressure increases from 0 MPa to 15 MPa (simulating the increase in formation effective stress), the permeability reduction rate of high-mud-content reservoirs (with a mud content of 41.3%) reaches 50.2%, while the permeability reduction rate of mud interbeds (with a mud content of 70%) reaches 87.4%. This phenomenon reveals the following laws:

(1)

Stress sensitivity effect of the main producing layer: An increase in effective stress by 10 MPa can lead to a permeability reduction of ≥30% in the main producing layer, directly causing a sharp decline in gas well productivity, manifested as a drastic decrease in daily gas production (decline rate > 15%/a) and insufficient development of recoverable reserves.

(2)

Plugging enhancement effect of interbeds: The permeability reduction range of mud interbeds (70–87%) is significantly higher than that of the main producing layer, resulting in an expanded permeability contrast (ΔK > 2 orders of magnitude). Although this can effectively suppress interlayer crossflow (the crossflow coefficient is reduced by 60–80%), it will exacerbate reservoir heterogeneity (the variation coefficient increases to 0.65–0.82).

The following measures are recommended: Establish a dynamic productivity early warning model based on rock mechanics parameters (initiate early warning when the stress sensitivity coefficient is >0.05 MPa⁻¹). Implement zonal differentiated development. For high-stress-sensitivity areas, adopt controlled pressure and reduced-rate exploitation, with a pressure drop rate of <0.3 MPa/d. Equip with a real-time productivity monitoring system (the sampling frequency of downhole pressure gauges is ≥1 time/h).

5.2. Mechanism and Prevention Countermeasures of Water Channeling and Interlayer Seepage

Experimental and field data indicate that during the reservoir compaction process, the increase in effective stress not only reduces the permeability of the main producing layer but also significantly affects the seepage behavior of water within and between layers. In high-water-cut intervals and shale interbeds, bound water migrates across layers under the driving force of pressure difference, invades the main producing layer, and triggers water channeling and water lock effects. The following conclusions are drawn from the study:

(1)

Characteristics of interlayer seepage: Shale interbeds still maintain partial seepage capacity in the early stage of development. However, as the effective stress increases, their permeability drops sharply (with a reduction of >70%). Although this characteristic is beneficial for later plugging, it is prone to inducing interlayer crossflow in the early stage.

(2)

Water invasion law in the main producing layer: In areas with a large pressure difference between shale interlayers and gas-bearing main layers, water invasion is significant, showing a continuous “seepage leakage” mode, resulting in an increase in the water saturation of the main producing layer.

(3)

Hazards of water channeling: The diffusion of water invasion and the formation of water cones will sharply reduce the relative permeability of gas. In some well areas, the gas production decreases by more than 40%, and even the gas flow channels are completely blocked.

The following measures are recommended: Combine stratified well logging to quantitatively analyze the source of produced water and identify water channeling paths in real time. Adopt stratified isolation (such as packers + chemical water shutoff) and selective gas production (intelligent completion regulation) to control the interlayer pressure difference. For high-mud-content reservoirs, implement low-speed production to suppress water channeling and maintain the synergistic flow of gas and water.

5.3. Problems of Water Production Within Gas Reservoir Layers and Development Optimization Countermeasures

Intra-layer water production is a major technical challenge faced in the mid-to-late development stages of high-muddy-sandstone gas reservoirs (such as the Sebei Gas Field). Experimental studies have shown that with the increase in the recovery degree and the rise in effective stress, the compression of reservoir pores and throats and the capillary plugging effect lead to an increase in the proportion of intra-layer retained water and the contraction of water-phase seepage channels. The specific manifestations are as follows:

(1)

In the pressure-driven stage at the initial stage of development, the water production is relatively high, but the unit-time water production rate shows a decreasing trend. In the later stage of development, it is mainly manifested as the difficulty in effectively producing bound water.

(2)

Increasing the gas flow velocity can enhance the intra-layer kinetic energy transfer and improve the water production efficiency in the short term. However, as the displacement pressure attenuates and the seepage channels narrow, the production-increasing effect gradually weakens.

(3)

When the confining pressure continues to increase, the intra-layer retained water is difficult to be discharged through the main seepage channels, resulting in a high water production rate of high-water-cut gas wells and a significant decrease in drainage efficiency.

In response to the above problems, the following development optimization countermeasures are proposed. Differentiated pressure control and productivity regulation—implement differentiated pressure control strategies for high-muddy layers and main producing layers, maintain reasonable inter-layer and intra-layer pressure gradients to avoid water channeling caused by pressure disturbances in interbeds, and ensure the smooth flow of the main gas flow. Coordinated optimization of production and pressure difference—avoid using an excessively high production pressure difference at the initial stage of single-well development, implement the development mode of “stable production with pressure control-balanced drainage”, dynamically adjust the gas production and production pressure difference, slow down the reservoir compaction process, and continuously improve the gas-driving-water effect. Fine water invasion control and layer-segment treatment—adopt a combination of mechanical isolation and chemical profile control measures for water control, improve the drainage efficiency of the main producing layer, and reduce the interference of muddy interbeds and high-water-cut layer segments on gas reservoir development. Application of new mining technologies—for wells with severe water lock, intermittent production, plugging removal and injection enhancement, and staged fracturing technologies can be adopted to improve the micro-scale seepage environment and enhance the mobility of retained water.

6. Conclusions

With the increase in effective stress, the porosity and permeability of sandstone reservoirs decrease significantly, and this pressure sensitivity becomes stronger with higher clay content. During the mid-to-late development stage, the effective stress typically rises by about 10 MPa, leading to a permeability reduction of over 30% in conventional reservoirs and 70–87% in high-clay interbeds.

As confining pressure increases, the continuous compression of pore volume due to compaction reduces water production. Initially, under the driving force of pressure difference, a large amount of water is expelled from the reservoir. However, subsequently, capillary plugging and throat narrowing cause the remaining water to gradually become bound water, making it increasingly difficult to effectively extract, thereby reducing the efficiency of gas well dewatering.

Effective stress also significantly narrows the gas-water two-phase co-flow interval (Sw), markedly reducing the relative permeability of the water phase and increasing that of the gas phase within the low-to-moderate water saturation range. The underlying mechanisms include pore throat contraction, increased capillary pressure, and preferential flow of the non-wetting phase (gas), resulting in a stress response characterized by promoting gas flow while hindering water phase flow.