The static evaluation method is primarily based on geological, logging, and core data, aiming to conduct a preliminary assessment of aquifer energy during the early stages of oil and gas field development. This approach does not rely on production dynamic data, making it particularly suitable for undeveloped or early-stage reservoirs. The core of static evaluation lies in estimating the aquifer volume to preliminarily determine the magnitude of the aquifer energy. The volumetric method serves as the most fundamental static evaluation technique, wherein the size of the aquifer is estimated by calculating the geometric volume of the aquifer and incorporating key petrophysical parameters, as shown in Equation 1. W = π R 1 2 − R 2 2 × h × φ × 1 − S w i (1)

In this equation, R ₁ denotes the outer radius of the aquifer, m; R ₂ represents the radius of the gas reservoir, m; h is the effective thickness of the aquifer, m; φ is the average porosity of the aquifer, fraction; S _wi is the irreducible water saturation of the aquifer, fraction.

In contrast to static methods, dynamic evaluation techniques utilize production dynamic data—such as pressure, gas production rate, and water cut—to quantitatively assess aquifer energy. These methods are more accurate than static approaches and can reflect the actual flow characteristics and energy intensity of the aquifer. Dynamic evaluation is particularly applicable to developed reservoirs and comprises production performance analysis, material balance methods (both linear and nonlinear), and numerical simulation techniques.

Previous studies have evaluated water invasion intensity in gas reservoirs using the Water Drive Index (DI). This index is derived from actual gas production, water injection, and reservoir pressure data collected during the water-drive process and provides a quantitative measure of water invasion (Feng et al., 2015). The DI represents the fraction of driving energy contributed by aquifer support (edge or bottom water) relative to the total driving energy, as shown in Equation 23. D I e = W e / G p B g + W p B w (23)

Accordingly, elastic water-drive gas reservoirs are classified based on the DI value as follows: strong water drive (DI > 0.3), moderate water drive (0.1 ≤ DI ≤ 0.3), and weak water drive (DI < 0.1).

The petrophysical characteristics of the E_1-2Z2 ¹ and E_1-2Z2 ² gas layers of the Ziniquanzi Formation exhibit notable differences, specifically reflected in similar porosity but significant variation in permeability (Figure 2). The porosity of the E_1-2Z2 ¹ gas layer ranges from 9.0% to 26.0%, with an average of 16.4%, and its permeability ranges from 0.2 to 1,300 mD, averaging 39.3 mD. In comparison, the porosity of the E_1-2Z2 ² gas layer ranges from 9.5% to 25.2%, with an average of 18.1%, while the permeability varies from 0.56 to 604 mD, with an average of 31.7 mD. According to the classification standards for continental clastic reservoir rocks in China, the Ziniquanzi Formation (Second Member) reservoir of the Hutubi Gas Field is categorized as a medium-porosity and permeability reservoir.

Thin-section analysis reveals pronounced regional contrasts in reservoir characteristics. In the central zone, the reservoir is dominated by fine sandstone with relatively good sorting. Pores are mainly intergranular, accompanied by minor dissolution pores and microfractures, resulting in overall higher porosity and connectivity (Figure 3a). In contrast, the western zone is primarily composed of coarse siltstone with moderate sorting, where pore space consists of both intergranular pores and clay-related intercrystalline pores, yielding lower porosity and connectivity (Figure 3b). The eastern zone is dominated by fine siltstone with poor sorting and pervasive basal cementation; pores are mainly intergranular and intercrystalline, but overall porosity and connectivity are the lowest (Figure 3c). Overall, pore structure is most favorable in the central zone, intermediate in the west, and poorest in the east, underscoring distinct spatial heterogeneity across the reservoir.

The lithology of the Second Member is dominated by fine-grained sandstone and siltstone. The mineral composition is primarily quartz (ranging from 38.00% to 59.67%, with an average of 48.00%), followed by feldspar (21.50%–30.60%, averaging 28.00%) and volcanic rock fragments (3.57%–18.14%, averaging 15.00%). The pore-filling materials mainly consist of ferruginous clay and sericitized clay, while calcite is the dominant cementing mineral. Based on the ratio of stable minerals (quartz) to unstable minerals (feldspar plus lithic fragments), the compositional maturity of the Second Member reservoir ranges from 0.61 to 1.48, indicating a moderate to high compositional maturity (Table 2).

High-pressure mercury intrusion (HPMI) results for samples from the Second Member of the Ziniquanzi Formation exhibit significant regional variations:

1. Samples from the central part of the study area (HUK18-3,556.4 m, KUKJ3-3,058.67 m) show pore structures characterized by high mercury intrusion saturation (92.19%–88.55%), low displacement pressures (0.09–0.11 MPa), and a pronounced “plateau segment” in the mercury intrusion curves. The lower limit of the main flow pore radius is relatively large (1.28–3.013 μm), indicating high pore utilization efficiency, good pore connectivity, a concentrated pore size distribution (dominant peak radius at 2.147 μm), and strong effective flow capacity (Figure 4a).

Sand bodies of the second member of the Ziniquanzi Formation in the Hutubi gas reservoir are continuously distributed and well connected. The E_1-2Z2 ^1-1 sand body is relatively underdeveloped, with a thickness of 5.0–17.0 m, and is thickest in the west and thinnest in the east (Figure 5a). The E_1-2Z2 ^1-2 sand body has a thickness of 15.0–33.0 m and is distributed in a southwest-northeast elongated strip, mainly in the eastern and central parts of the study area, thinning toward the west and south (Figure 5b). The E_1-2Z2 ² sand body is relatively well developed, with a thickness of 25.0–30.0 m, and is primarily distributed in the east and central regions (Figure 5c).

The gas layers of the Ziniquanzi Formation are thick and contain stable mudstone interlayers between sublayers. Stable mudstone interlayers occur between the E_1-2Z2 ¹ and E_1-2Z2 ² layers, and between the E_1-2Z2 ^1-1 and E_1-2Z2 ^1-2 sublayers. Between E_1-2Z2 ¹ and E_1-2Z2 ², the interlayer thickness decreases toward the west (it is thicker in the east) (Figure 5d). Between E_1-2Z2 ^1-1 and E_1-2Z2 ^1-2, the interlayer thickens westward (Figure 5e). In the E_1-2Z2 ¹ layer, gas layers and interlayers alternate over 15 layers, mainly composed of mudstone and argillaceous siltstone, with individual layer thicknesses ranging from 13.0 to 36.3 m. In contrast, the E_1-2Z2 ² layer contains only three interlayers, primarily argillaceous siltstone, with thicknesses between 0.6 and 10.3 m.

Based on core analyses, core data were used to calibrate logging curves and establish mathematical models relating logging data to porosity and permeability, enabling mapping of these properties across the study area. The porosity distribution in the second member of the Ziniquanzi Formation is stable; high-porosity zones form northeast–southwest–trending elongate strips with good connectivity. The average porosity in the western region (13.0%) is slightly lower than in the central and eastern regions. The average porosity of the E_1-2Z2 ^1-1, E_1-2Z2 ^1-2, and E_1-2Z2 ² layers increases gradually from top to bottom (Figures 6a–c). Overall, the reservoir exhibits good permeability, with most areas having permeability values greater than 25.0 mD. In plan view, the reservoir shows strong heterogeneity. High-permeability zones occur in northeast-southwest strips, with significant variations by layer: in the E_1-2Z2 ^1-1 layer, these zones are mainly in the western and central parts (Figure 6d); in the E_1-2Z2 ^1-2 layer, they are in the central part (Figure 6e); and in the E_1-2Z2 ² layer, they are distributed in the central and eastern parts (Figure 6f). All these high-permeability zones have permeability values exceeding 60 mD. The formation coefficient reflects the productivity of injection and production wells in the gas storage reservoir; larger values indicate higher productivity. For the effective reservoirs in the E_1-2Z2 ^1-1, E_1-2Z2 ^1-2, and E_1-2Z2 ² layers, the formation coefficients range from 1 to 571.0 mD·m (mean 66.0 mD·m), 3.7 to 2,659.0 mD·m (mean 370.0 mD·m), and 8.0 to 3,914.2 mD·m (mean 521.0 mD·m), respectively, indicating an increasing trend from top to bottom (Figures 6g–i). High values of the formation coefficient are distributed in strip-like zones. In the E_1-2Z2 ^1-1 layer, formation coefficients form blocky high-value zones along the east-west direction, with good connectivity along the north-south direction, consistent with sedimentary trends. The E_1-2Z2 ^1-2 layer shows blocky high values in uplifted areas with good lateral connectivity, whereas the western region has lower values. The E_1-2Z2 ² layer exhibits a north-south zonation in formation coefficients (Figure 6c).

Prior to the construction of the USG, seven wells were put into production, of which only two wells (Well Hu2 and Well HU 2006) produced formation water, and the produced water volume was limited. Well Hu2 had a cumulative water production of 0.53 × 10⁴ m³ and a maximum water-gas ratio of 0.9 m³/10⁴ m³. After 2 years of water production, the bottom water-producing interval of the E_1-2Z2 ^1-2 formation was plugged; Well HU2006 encountered water and was quickly flooded, producing a cumulative 0.66 × 10⁴ m³ of water with a water-gas ratio of 2.46 m³/10⁴ m³ before shut-in. After Well Hu2 began producing water, gas production from the western structural low of the E_1-2Z2 ¹ reservoir decreased significantly, exhibiting clear water-invasion characteristics (Figure 8a). Material balance calculations indicate a unit pressure-drop water invasion volume of 6.7 × 10⁴ m³ (Figure 8b), with an estimated connected aquifer volume of 9,054 × 10⁴ m³. Although Well HU2006 in the E^1-2z₂ ² formation was quickly flooded after encountering water, the pressure decline curve did not show an upward kink (Figure 8c), indicating that only a local bottom-water cone developed and it did not affect the entire reservoir.

Three-dimensional numerical simulation reveals significant selective layer and directional characteristics of reservoir water invasion. In the E_1-2Z2 ¹ reservoir, water invasion mainly occurred in the lower main layers 7-11 (from small layer E_1-2Z2 ^1-2-2 to E_1-2Z2 ^1-2-4), showing regional differences (taking small layer 7 as an example, Figures 9a,b). In the western zone, the distance from the gas-water contact to Well HU2002 decreased from 1,652.0 m originally to 674.0 m by the end of the production stage, with the water invasion front advancing 978 m and a pore volume reduction of 356 × 10⁴ m³. In the eastern zone, the distance from the gas-water contact to Well HU2004 changed from 278.0 m to 238.0 m, with the water invasion front advancing only 40 m. Although water invasion occurred in E_1-2Z2 ¹, the gas saturation at the reservoir edges decreased, but the internal gas saturation basically remained unchanged. In addition, the upper main layers 1–6 (E_1-2Z2 ^1-1-1 to E_1-2Z2 ^1-2-2) were essentially unaffected by water invasion. In the E_1-2Z2 ² reservoir, bottom water intrusion occurred only locally in the eastern part (taking small layer 12 as an example), with the gas-water contact advancing 40 m (Figures 9c,d) and an average vertical rise of about 10.0 m (Figures 9e,f), indicating a limited affected range.

Seven-cycle injection-production numerical simulation was conducted to obtain the advancement of the gas-water front and changes in gas saturation for two sets of injection layer systems. A comprehensive analysis of the displacement characteristics of multiple injection-production cycles for the two injection systems is as follows:

1. In the E_1-2Z2 ¹ reservoir, water invasion mainly occurred in the lower main layers 7–11 (E_1-2Z2 ^1-2-2 to E_1-2Z2 ^1-2-4, Figures 10a,b), showing regional differences (taking small layer 7 as an example): In the western area, gas breakthrough at the water-front led to an increase in gas saturation, and the gas-drive expansion was significant but uneven (Figures 10c,d); in the eastern area, during high-rate injection-production, influenced by formation heterogeneity and differences in gas-water flow capacity, local gas fingering occurred, and gas saturation increased southeast of Well HUK1 (Figures 10e,f).

The aquifer energy of the Hutubi USG imposes a dual constraint on the scale of water invasion: 1) the aquifer size directly limits the total water influx (Fang et al., 2019). The static volumetric method estimated the affected volume of water invasion to be 7.93 × 10⁸ m³. However, numerical simulation indicates that the actual cumulative invaded water volume is only 50.2 × 10⁴ m³, accounting for merely 7.9% of the gas-filled pore volume. Moreover, the aquifer multiple (5 times) is significantly lower than that of strong water-drive reservoirs (typically >20 times), suggesting a small peripheral aquifer with strong sealing capacity. 2) The low activity of aquifer energy leads to discontinuous water invasion (Fang et al., 2024). After 2006, the pressure drawdown curve returned to a constant volume behavior, and the driving mechanism shifted from elastic water drive (B = 1.85) to constant volume depletion B → ∞ . The water drive index is only 0.025, indicating an interruption of aquifer recharge and weak driving force, resulting in selective regional water invasion and localized bottom-water coning rather than large-scale areal expansion.

The water invasion characteristics of the Hutubi UGS are governed by a dynamic coupling of “structure–deposition–reservoir properties–heterogeneity”. A regional reverse fault on the southern side (fault displacement >100 m, SGR >0.65) forms a rigid boundary that seals the southern aquifer, resulting in edge water being mainly distributed on the eastern, western, and northern flanks of the E_1-2Z2 ¹ reservoir. The main body of the E_1-2Z2 ¹ reservoir develops underwater distributary channels and mouth bars, while the low-lying areas to the east, west, and north are dominated by sheet sands deposited between distributary channels and mud-rich siltstones, forming medium-to low-permeability layers with poorer continuity than the main reservoir. This results in three-sided low-permeability sealing, with a permeability gradient difference of 3.2 times along the NE-SW direction, effectively limiting the extent of edge water (cumulative invaded water volume of 50.2 × 10⁴ m³). As the production degree increases, the formation pressure drops, and the western structural low (−3,051.0 m) coupled with high-permeability zones (>60 mD) drives orderly inward advancement of the aquifer, while the eastern uplifted structure (no water breakthrough at Well Hu001) forms a natural barrier to water invasion. Strong intra- and interlayer heterogeneity (permeability contrast >1,000) causes vertical differentiation of water invasion, with only the lower part of the E_1-2Z2 ^1-2 sublayer and local zones of the E_1-2Z2 ² reservoir affected (Figures 10a,b). In terms of planar distribution, a 24-fold difference in water invasion advancement is observed (978 m westward vs. 40 m eastward), controlled by spatial property variations (high-permeability zones concentrated in the west). Gas expansion response is evident in high-permeability areas under injection-production disturbances. The coupling of reservoir properties and structural features results in contrasting behaviors: although the bottom-water of the E_1-2Z2 ² reservoir exhibits high permeability (>60 mD), water invasion is constrained by structural closure (only −10 m interface uplift), whereas the combination of the structural depression and high-permeability channels in the western E_1-2Z2 ¹ reservoir forms preferential water invasion pathways (from Well Hu2 to Well Hu 2002, with the water-gas ratio increasing westward and decreasing eastward). The interaction of these four-dimensional elements forms a dynamic coupling mechanism of “structural sealing–depositional control on flow–heterogeneity-induced differentiation–property selection” (Li et al., 2022; Guo et al., 2024)resulting in westward-directed water invasion (E_1-2Z2 ¹), localized bottom-water coning (E_1-2Z2 ²), and heterogeneous planar expansion, with the cumulative water invasion volume accounting for only 7.9% of the gas-filled pore volume.

The dynamic behavior of water invasion under strong injection–production conditions in the UGS fundamentally differs from that of conventional gas reservoirs (Tang et al., 2021). During the injection phase, high-pressure gas displaces edge water outward at high velocities, rapidly increasing formation pressure. Although gas storage capacity expands, the water invasion volume is suppressed due to the reduced pressure differential. Conversely, during the production phase, the gas withdrawal rate is ten times that of conventional reservoirs, causing a sharp pressure drop that triggers reverse water influx, leading to a rapid decrease in gas storage capacity and an exponential increase in water invasion volume (Zhu et al., 2021). This cyclical pressure fluctuation causes repeated reversals in the direction of gas–water two-phase migration within the reservoir, significantly amplifying the effects of heterogeneity (Liu et al., 2022). Given that permeability contrasts can reach 10-100 times, high-permeability zones under strong injection–production form high-velocity flow channels, with flow rates exceeding Darcy flow limits (Reynolds number >1), inducing inertial effects and turbulent flow. Meanwhile, low-permeability layers remain poorly mobilized, with most pore space becoming “ineffective storage,” further widening the utilization gap between high- and low-permeability zones.

Additionally, differences in microscopic pore structures directly govern the heterogeneity of water invasion (Peng et al., 2024). In the central zone, large pore throats dominate flow, resulting in good pore connectivity, high mobilization efficiency, and continuous alternating gas–water flow, thereby maintaining stable internal gas saturation. In contrast, the western and eastern zones exhibit fine pore throats, which cause significant capillary resistance, intensifying gas–water locking and reducing gas recoverability. When gas and water phases migrate through fine pore structures, the gas phase tends to become trapped, forming three types of trapped gas: bypassed gas, snap-off gas, and water-locked gas (Singh et al., 2017). Under low displacement pressure differentials dominated by capillary forces, the water phase preferentially invades small throats and rapidly breaks through, while gas is bypassed and trapped in larger throats due to lower capillary forces and slower flow (Figure 11a). Under high displacement pressure differentials dominated by hydrodynamic forces, the water phase preferentially occupies larger throats, leaving gas stranded in smaller throats due to higher flow resistance (Figure 11b) (Hu et al., 2021; Chu et al., 2024). Pore–throat scale effects further exacerbate gas entrapment. Narrow throats induce additional resistance due to the Jamin effect, and continuous water films form along hydrophilic pore walls (He et al., 2021). As gas passes through, it undergoes deformation, contraction, and expansion cycles leading to snap-off events (Figure 11c). Although accumulated energy from bubble collisions may temporarily restore flow, gas ultimately becomes dispersed into isolated bubbles (Xiong et al., 2024). Water-locking gas arises from capillary suction compressing gas flow paths, forming localized closures (Figure 11d) (Jiang et al., 2024).

The spatial distribution of different gas-locking types exhibits clear heterogeneity. Bypassed gas commonly develops in peripheral low-permeability zones, where fine pore throats and strong capillary forces allow water to preferentially invade narrow channels and rapidly break through, while gas in larger pores with weaker capillary control and slower displacement becomes isolated. These peripheral zones often align with the direction of aquifer advance, leading to continuous accumulation of bypassed gas along invasion pathways and forming banded stratigraphic patterns. Snap-off and residual trapping mainly occur within wellbores and adjacent injection–production disturbance zones. Under high displacement pressures, water preferentially enters large pores, generating high-velocity flow, while gas in fine throats undergoes deformation, contraction, and expansion under the combined influence of the Jamin effect and water-film formation, ultimately resulting in snap-off or retention. Consequently, trapped gas in these near-well zones tends to cluster in point–band composites. Water-blocked gas is typically associated with mudstone interbeds or fine-grained intervals, where hydrophilic pore walls promote capillary imbibition that compresses gas flow channels, producing locally confined clusters with a vertically stratified distribution. Overall, the structural high in the central anticline, with coarser throats and better connectivity, allows more continuous gas flow and weaker locking effects during water invasion. In contrast, reservoir margins and fine-pore-throat domains, characterized by higher capillary pressures and restricted flow channels, are more prone to multiple gas-locking mechanisms and thus represent the primary zones of trapped-gas accumulation.