The FM fault-fractured-vuggy volatile oil reservoir exhibits significant heterogeneity and rapid production decline. Furthermore, there are notable differences in the effects of depletion development, and the impact of volatile oil degassing on water injection parameters remains unclear. This paper established artificial cores that replicate both single-fractured-vuggy and multi-fractured-vuggy full-diameter systems, reflecting a typical reserves ratio of pores, fractures, and caves in the FM oilfield. Concurrently, water injection experiments were conducted for both single-well and multi-well units after natural energy depletion had occurred. The results indicated favorable development when single-well units opened the lower part of the fracture-vuggy zone, allowing for depletion below bubble pressure at an early stage. Due to dissolved gas flooding at the top of reservoirs, crude oil depletion recovery reached over 67%. The filling of fractures and caves led to delayed degassing: single-phase seepage before degassing was influenced by reservoir physical properties. In contrast, multiphase seepage after degassing was affected by fluid viscosity. The single-well units employed large-volume water injection huff-n-puff techniques, resulting in a pronounced gravity oil displacement effect. This method improved cumulative crude oil recovery by more than 5%. Additionally, it was recommended that multi-well units adopt a deep injection and shallow production development strategy, with continuous water flooding enhancing oil recovery by over 40%. However, during the asynchronous injection-production stage, the recovery improvement was limited to only 1%.

The DX gas reservoir is characterized by ultra-high pressure, extremely low porosity and permeability, well-developed fractures, and a strong bottom-water drive. During depletion, the decline in formation pressure intrudes rapid bottom-water invasion through fracture networks, resulting in early water breakthrough and significant trapping of natural gas within micro-fractures and pore spaces, thereby reducing overall recovery. To investigate the bottom-water invasion behavior in fractured tight gas reservoirs, physical simulation experiments were conducted under high-temperature and ultra-high-pressure conditions (136 ℃ and 106 MPa) using full-diameter fractured core samples. The effects of depletion rate and aquifer sizes on key indicators, including recovery factor, water-gas ratio, water-free production period, and gas production per unit pressure drop, were systematically analyzed. Results indicate that both increasing aquifer size and accelerating depletion rate lead to higher water production, increased water-gas ratio, shortened water-free period, and reduced gas recovery. Aquifer size exerts a significantly stronger influence than the depletion rate. Specifically, increasing the aquifer size from 4.5 to 20.0 times the hydrocarbon pore volume results in a nearly tenfold increase in cumulative water production, an rise in water breakthrough pressure by 18 MPa, and a value of 21.61% reduction in gas recovery. In contrast, doubling the depletion rate results in approximately a twofold increase in cumulative water production, a 6 MPa increase in breakthrough pressure, and a 10.97% reduction in recovery. These findings indicate that appropriate control of rational depletion rate and effective water management strategies are critical for improving economic performance of fractured tight gas reservoirs. This research provides a crucial theoretical and experimental basis for understanding and managing bottom-water invasion and offers significant practical guidance for optimizing development strategies in fractured gas reservoirs.

In gas-condensate reservoirs, the phase behavior of reservoir fluids is inherently dynamic during pressure depletion. When the rate of external pressure decline exceeds the intrinsic relaxation rate governing phase equilibrium, the system deviates from thermodynamic equilibrium and exhibits pronounced non-equilibrium effects. These transient behaviors significantly influence fluid properties; meanwhile, conventional equilibrium models neglect phase transition lag, resulting in inaccurate phase behavior and biased production predictions. In this study, a non-equilibrium dynamic phase transition model is developed to quantitatively couple the pressure depletion rate with the relaxation kinetics of the system. This model, established based on controlled non-equilibrium phase transition experiments performed on the condensate-gas fluid investigated in this work, provides an analytical framework for describing the temporal evolution of phase behavior under dynamic conditions. Model validation through integrated experimental measurements and numerical simulations shows good agreement between calculated and measured results for the studied condensate-gas system, with average relative errors below 5%. Results reveal that accelerated pressure depletion strengthens non-equilibrium effects. At a rate of 15 MPa/h, the relative volume and retrograde condensate saturation decrease by 9.09% and 5.38%, respectively, while condensate recovery improves by 13.85%. Moreover, the characteristic relaxation time toward equilibrium exhibits a strong dependence on the depletion rate, increasing as the depletion rate rises. This work provides an experimentally constrained analytical framework for describing rate-dependent non-equilibrium phase behavior during pressure depletion and for interpreting its impact on condensate recovery in the specific condensate-gas system studied. Although the governing framework may be transferable to other rate-sensitive hydrocarbon systems after fluid-specific recalibration, the parameterized analytical model and validation presented in this study are limited to the investigated condensate-gas fluid, and its applicability to other hydrocarbon fluid types remains to be evaluated in future studies.

Carbonate bottom-water gas reservoirs commonly exhibit complex gas-water distributions, and the limited understanding of the factors controlling water invasion has hindered their efficient development. In this study, full-diameter physical models representing different gas-water distribution patterns were constructed using field cores, and a high-temperature, high-pressure physical simulation method was developed to investigate interlayer-controlled water-invasion behavior. Two representative configurations—the barrier-bed-reservoir type and the reservoir-interlayer-reservoir type—were examined. The effects of aquifer-to-reservoir volume ratio, pressure-depletion rate, barrier-bed sealing area, interlayer thickness, and interlayer permeability on water invasion were systematically evaluated. The results show that barrier beds and interlayers act as flow barriers that retard bottom-water encroachment, delay water breakthrough, prolong the water-free gas-production stage, and help maintain gas deliverability and recovery after breakthrough. Increasing interlayer thickness or decreasing interlayer permeability prolongs the gas-expansion-dominated depletion stage and improves gas recovery, whereas a larger barrier-bed sealing area suppresses bottom-water encroachment and preserves gas-flow capacity. A smaller aquifer-to-reservoir volume ratio slows bottom-water advance, extends the water-free production period, and mitigates water-induced gas-flow impairment, thereby supporting sustained gas productivity. In addition, reducing the pressure-depletion rate delays water invasion and alleviates the decline in gas production per unit pressure decline (GPPD), which improves gas recovery during the gas-water co-production stage and increases the ultimate recovery factor. The proposed method and findings provide experimental support for performance prediction and production-strategy optimization in carbonate bottom-water gas reservoirs influenced by barrier beds and interlayers.

Conventional material balance methods, typically based on single- or dual-porosity models solvable via single-step linearization, are inadequate for hydraulically fractured shale oil reservoirs due to their pronounced heterogeneity and contrasting interzonal connectivity. Specifically, dual-zone models fail to represent the realistic characteristics of shale oil reservoirs because they treat artificially created hydraulic fractures and natural fractures as equivalent, despite their substantially different properties. To address this gap, this paper proposes a novel three-zone conceptual model, segmenting the reservoir into the matrix zone (MZ), the Weakly Stimulated Zone (WSZ, low-conductivity zone), and the Strongly Stimulated Zone (SSZ, high-conductivity zone). A corresponding three-zone gas injection replenishment material balance model is developed. This model explicitly captures interactions between injected gas and formation fluids and incorporates dynamic variations in pore volume and fluid saturation induced by imbibition. To solve the complexities introduced by the triple-porosity system, a dedicated two-step linearization solution procedure is proposed. Utilizing conventional production performance and basic PVT data, the method enables simultaneous estimation of zone-specific developed reserves and prediction of the Estimated Ultimate Recovery (EUR) through a least squares algorithm. Validation against actual well cases and multi-well statistics confirms that the method provides stable and reliable zonal reserve characterization and EUR forecasting. The results indicate that the MZ contributes the majority of the geological reserves, accounting for >70%. The WSZ contributes approximately 29.5% of the reserves and serves as the primary source for energy replenishment in the shale oil reservoir. In contrast, the SSZ contributes less than 0.5% of the reserves but acts as the dominant channel for flow convergence, controlling the main fluid production pathways. The proposed framework not only offers a practical tool for refined reserve assessment in shale oil reservoirs but also provides a computational basis and decision support for the design and injection parameter optimization of pre-pad CO2 energy storage fracturing schemes.

BACKGROUND:Thallium, a highly toxic heavy metal, is widely distributed in the environment. The substance poses a grave threat to human health through contamination of the food chain, drinking water, and environmental exposure. Consequently, the monitoring of thallium levels, particularly in water, is of critical importance. In this study, a novel analytical method was developed for the direct quantification of thallium ions (Tl+) in aqueous samples. This method is based on the specific supramolecular interaction between cryptand[2.2.2] and Tl+, and it utilizes electrospray ionization tandem mass spectrometry (ESI-MS/MS). RESULTS:The method demonstrated remarkable analytical performance, exhibiting a linear range of 2.5 to 100 μg/L (R2 > 0.999), a limit of quantification (LOQ) of 2.5 μg/L, and a limit of detection (LOD) of 0.8 μg/L. The recovery rates exhibited a range from 88.65% to 118.09%, with relative standard deviations (RSD) falling below 10%, thereby affirming the attainment of satisfactory accuracy and precision. It is noteworthy that this method necessitated only 5 μL of sample and did not require any preliminary separation steps. Despite the inhibitory effects exhibited by complex sample matrices, these effects were effectively mitigated through a straightforward dilution strategy. The method was successfully applied to the analysis of 66 real-world environmental water samples. SIGNIFICANCE:This work presents a novel tool that enables rapid and reliable detection of Tl+ in water samples. Compared with traditional ESI methods for heavy metals, the application of cryptand[2.2.2] makes the developed method more selective and sensitive, since it has strong binding ability and selective to Tl+ ion. The study introduces a novel design concept and practical application for the development of supramolecular recognition-based ESI-MS methods for metal ion analysis. These methods hold significant potential for environmental monitoring and related fields.

Shale reservoirs are dominated by nanopores, where wall-fluid adsorption and anomalous fluid intermolecular interactions lead to substantial deviations from conventional equation of state (EOS) predictions. This study proposes a modified Peng-Robinson equation of state (m-PR EOS) that incorporates two innovative key corrections: (1) a refined molar volume term accounting for wall-fluid adsorption effects; and (2) introduction of the contact angle in the attractive term to rectify anomalous fluid intermolecular interactions. The m-PR EOS quantitatively captures the shifts in critical properties of confined hydrocarbons and pioneeringly integrates critical pore size determination, identifying confinement thresholds for pure hydrocarbons. The critical pore radii of methane were determined as 18.62 nm (based on temperature shift) and 51.33 nm (based on pressure shift). The analysis reveals that hydrocarbons with larger Lennard-Jones molecular sizes exhibit larger critical pore sizes and greater deviations in critical properties at the same confinement scale. The model validated with binary hydrocarbons was applied to simulate pore-size-dependent phase behavior in shale condensate systems and Constant Composition Expansion experiments. Results demonstrate that reducing pore size causes phase envelope to contract towards the lower-left quadrant in the P-T phase diagram, with accelerated contraction rates. Constant Composition Expansion simulations show that the retrograde condensation volume curve exhibits a similar contraction trend as the phase envelope. By incorporating wettability effects, the m-PR EOS model extends its applicability to a wide range of reservoirs. The m-PR EOS provides a thermodynamic foundation for accurately predicting nanoscale phase behavior and optimizing condensate recovery in unconventional reservoirs.

Gas condensate reservoirs constitute important natural gas resources; however, their development is frequently hindered by condensate banking and complex multiphase flow behavior. Naturally fractured gas condensate reservoirs present additional challenges because their dual-porosity and dual-permeability structure induces strong phase redistribution and nonuniform flow between matrix and fracture systems, thereby complicating reservoir characterization and compositional simulation. In this study, integrated laboratory experiments and numerical simulations were performed for a deep, rich, naturally fractured gas condensate reservoir. Depletion, diffusion, and core flooding experiments involving CO2, N2, and dry gas injection were conducted using fractured core samples. A dual-porosity and dual-permeability compositional model incorporating a five-spot well pattern was established to evaluate condensate liquid recovery and to quantify mass transfer between matrix and fracture networks. The effect of matrix-fracture permeability contrast on production performance was systematically analyzed. The results indicate that matrix permeability is a primary parameter controlling recovery in gas condensate reservoirs. The ratio of matrix-fracture permeability contrasts exerts a stronger influence on condensate liquid recovery than on natural gas recovery. Pressure maintenance through gas injection is critical for improving recovery performance. When reservoir pressure declines below the dew-point pressure, early gas injection is recommended to mitigate condensate accumulation in the near-well region. Among the injected gases evaluated, CO2 demonstrated superior pressure maintenance performance compared with N2 and dry gas.

The S reservoir is a typical Middle Eastern carbonate formation characterized by a formation temperature of 89 °C, salinity of 200,000 mg/L, and permeability below 1 mD. It exhibits low and continuously declining formation pressure and single-well productivity, making water flooding inefficient. Therefore, it is essential to evaluate the feasibility of gas injection to supplement reservoir energy and provide a theoretical basis for selecting suitable injection media and parameters for field development. To address these challenges, a high-temperature and high-pressure NMR online gas displacement and long-core flooding experimental system was established. Gas expansion, minimum miscibility pressure, and dynamic core displacement experiments were conducted and integrated with numerical simulations to examine the effects of gas type, injection timing, and injection rate on microscopic displacement behavior, recovery efficiency, and flow characteristics in ultra-low-permeability carbonate reservoirs. The results indicate that, in such tight formations, macroscopic flow follows non-Darcy behavior with a distinct threshold pressure gradient, while microscopically, gas diffusion from larger pores into smaller throats promotes oil displacement. The coupling between molecular diffusion and the threshold pressure gradient jointly governs ultimate recovery efficiency, providing new insights into gas injection mechanisms in ultra-low-permeability carbonate reservoirs. Experimental findings further demonstrate that crude oil in the S reservoir exhibits a large saturation pressure difference and low viscosity. Gas injection enhances the elastic expansion capacity of crude oil by 13.68%–19.54% and reduces its viscosity by 8.08%–12.23%. Under the current formation pressure (34.45 MPa), CO2 and hydrocarbon gas achieve miscible flooding, whereas N2 remains immiscible. Miscible flooding improves small-pore oil utilization by approximately 20%, and considering both miscibility and displacement efficiency, hydrocarbon gas is recommended as the preferred injection medium. Compared with N2 immiscible flooding, hydrocarbon gas—under pulse or continuous injection—achieves more than 50% recovery. The optimal conditions for miscible flooding include an injection rate of 0.0811–0.0908 m/d, injection pressure above the MMP, and an injection–production ratio of 1:1, resulting in a maximum recovery efficiency of up to 76%. This study establishes both a theoretical and experimental foundation for optimizing gas injection in ultra-low-permeability carbonate reservoirs and demonstrates practical relevance by improving gas–oil mobility control, reducing emulsion stability, and enhancing separation efficiency during surface fluid processing.

CO2 injection for enhanced oil recovery and carbon sequestration in low-permeability reservoirs has become a major research focus, driven by growing global energy demand and carbon-emission reduction targets. Among available development strategies, synchronous huff-and-puff and asynchronous injection–production show considerable field application potential; however, large-scale physical simulation experiments to validate these approaches remain lacking. In this study, large-scale high-temperature, high-pressure, two-dimensional physical simulation experiments were conducted under CO2 miscible flooding conditions to compare the displacement mechanisms of these two strategies in a low-permeability reservoir. Numerical simulation was employed to history-match the experimental results, confirming their accuracy and reliability. The results show that CO2 exhibited strong adaptability under the investigated reservoir conditions. It effectively replenished formation energy and, upon dissolution in crude oil, induced pronounced swelling and viscosity-reduction effects that enhanced oil mobility. Under miscible conditions, interfacial tension was significantly reduced, further improving displacement efficiency. Compared with synchronous huff-and-puff, asynchronous injection–production established a unidirectional pressure gradient by injecting CO2 into the low-permeability zone while producing from the high-permeability zone, substantially enlarging the swept volume and mobilizing residual oil. The final oil recovery under this mode reached 41.56%, an improvement of 21.78% over synchronous huff-and-puff. Reservoir heterogeneity was identified as the key factor controlling CO2 flooding effectiveness and residual oil distribution. The high-permeability zone served as the preferential CO2 migration pathway, while the low-permeability zone retained considerable residual oil. Therefore, rational optimization of the injection–production direction and pressure regime is essential for overcoming heterogeneity constraints and improving overall recovery performance.

The widespread development of unconventional oil and gas reservoirs has advanced reservoir research to the nanoscale level. Under the influence of nanoscale confinement effects, the phase behavior of condensate gas reservoirs deviates from the classical theories derived from traditional pressure/volume/ temperature (PVT) experiments. Therefore, studying the phase behavior of fluids in porous media at the nanoscale is significant. The experiment employs two-dimensional nuclear magnetic resonance T1-T2 (2D NMR T1-T2) spectrum method to study the phase behavior characteristics of condensate gas in three cores with varying degrees of tightness, then explores the effects of different cores and different CO2 contents on the phase behavior characteristics of condensate gas. As the core tight degrees of cores increases, the dew point pressure rises from 25.9 to 27.9 MPa while restricting fluid migration within the pores. The maximum condensate oil saturation increases from 10.35% to 17.35%. Compared with the bulk PVT phase experiment, the dew point pressure of condensate gas in porous media is lower than that of condensate gas in the PVT visualization cell. This is related to the formation of phase mixing and "liquid bridges" when oil and gas reach the dew point pressure in porous media. The retrograde condensation phenomenon in condensate gas systems in different porous media occurs first in the micropores. CO2 inhibits the retrograde condensation phenomenon in tight cores, and CO2 concentration is negatively correlated with the dew point pressure of the condensate gas. (c) 2025 The Authors. Publishing services by Elsevier B.V. on behalf of KeAi Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-ncnd/4.0/).

Water intrusion in gas reservoirs with strong aquifer drives and pronounced heterogeneity presents significant challenges for production efficiency and cost control, as conventional rate management and drainage strategies often fail to address preferential water flow paths and trapped gas issues. Existing water shut-off technologies are constrained by poor agent transportability, imprecise placement, and neglect of the gas-water interface equilibrium. This study presents an advanced chemical water shut-off strategy that constructs large-area, crosslinked polymer water-blocking barriers directly at the gas-water interface within porous media through interfacial spreading-polymerization. The approach employs specific surfactants to enhance the spreading of an oil-phase monomer solution, thereby enabling broad interfacial coverage, while simultaneous in situ interfacial polymerization generates robust, crosslinked polymer networks. Specifically, the plugging system comprises two components: an oil solution and an aqueous solution. The oil solution contains cyclohexane, 0.1 wt% trimesoyl chloride (TMC), and the spreading agent octylphenol polyoxyethylene-4 (OP-4), which imparts strong spreading capacity to facilitate broad distribution of the TMC monomer. The aqueous solution comprises water, 2 wt% mphenylenediamine (MPD), and sodium hydroxide. Fourier transform infrared spectroscopy (FTIR), X-ray photoelectron spectroscopy (XPS), Raman, and scanning electron microscopy (SEM) analyses confirm that the barrier is a highly cross-linked three-dimensional polyamide network with a highly dense internal structure and a thickness exceeding 300 mu m, capable of effectively blocking pores, throats, and most natural fractures. Core flooding experiments further demonstrate that the barrier has substantial water-blocking performance, especially in low-permeability porous media.

This paper proposes an approach to determing the optimal cluster spacing for volume fracturing in shale oil reservoirs based on three scales, i.e. microscopic capillary displacement, large-scale core imbibition, and macroscopic reservoir nuclear magnetic resonance (NMR) logging. Through flow experiments using capillary with different diameters and lengths, and large-scale core counter-current and dynamic imbibition tests, and combing with the NMR logging data of single wells, a graded optimization criterion for cluster spacing is established. The proposed approach was tested in the shale oil reservoir in the seventh member of the Triassic Yanchang Formation (Change 7 Member), the Ordos Basin. The following findings are obtained. First, in the Chang 7 reservoir, oil in pores smaller than 8 & micro;m requires a threshold pressure, and for 2-8 & micro;m pores, the movable drainage distance ranges from 0.7 m to 4.6 m under a pressure difference of 27 mPa. Second, the large-scale core imbibition tests show a counter-current imbibition distance of only 10 cm, but a dynamic imbibition distance up to 30 cm. Third, in-situ NMR logging results verified that the post-fracturing matrix drainage radius around fractures is 0-4 m, which is consistent with those of capillary flow experiments and large-scale core imbibition tests. The main pore-size range (2-8 & micro;m) of the Chang 7 reservoir corresponds to a permeability interval of (0.1-0.4)& times;10-3 & micro;m2. Accordingly, a graded optimization criterion for cluster spacing is proposed as follows: for reservoirs with permeability less than 0.20 & times;10-3 & micro;m2, the cluster spacing should be reduced to smaller than 4.2 m; for reservoirs with permeability of (0.2-0.4) & times;10-3 & micro;m2, the cluster spacing should be designed as 4.2-9.2 m. Field application on a pilot platform, where the cluster spacing was reduced to 4.0-6.0 m, yielded an increased initial oil production by approximately 36.6% over a 100-m horizontal reservoir section as compared with untested similar platforms.

Gas hydrate plugging is a common yet hazardous problem during oil and gas reservoir exploitation, compelling the petroleum industry to invest substantial resources annually in mitigation strategies. Two novel hydrate kinetic inhibitors (HKIs), a PVP derivative (PVP-DP) and a PVCap derivative (PVCap-DP), were synthesized and systematically evaluated. Structural characterization by FT-IR, NMR, and TG analyses confirmed increased molecular weights and the introduction of additional polar functional groups relative to the present polymers. In pure water at a subcooling temperature of 6.2 K and a concentration (Cp) of 1 wt%, the methane hydrate induction times (Ih) for PVP-DP and PVCap-DP were 358 min and 395 min, respectively. These values significantly exceed those observed in distilled water (23 min) and in systems containing commercial HKIs, such as PVP (138 min) and VC-713 (272 min). Increasing Cp to 3 wt% further prolonged Ih to 911 min and 964 min, respectively. Even at a higher subcooling of 8.4 K, Ih remained considerable at 126 min and 158 min, demonstrating sustained inhibition under more severe thermodynamic driving forces. Synergistic effects were observed when HKIs (3 wt%) were combined with glycol (1 wt%), resulting in Ih values of 230 min and 268 min. Increasing the glycol concentration to 3 wt% maintained a strong inhibition performance, with Ih values of 211 min and 238 min even at a subcooling of 9 K. In addition, both derivatives exhibited effective inhibition in water/diesel emulsion systems. At 6.2 K subcooling, the PVP-DP (3 wt%)–water/diesel emulsion system achieved an Ih of 404 min, which was markedly longer than that of the uninhibited water/diesel emulsion (51 min), although the emulsion phase moderately reduced the inhibitor efficiency. Overall, PVP-DP and PVCap-DP demonstrate strong kinetic inhibition performance against the formation of natural gas hydrate in both aqueous and emulsion systems, indicating promising application potential in complex production environments.

Abstract: Efficient shale gas extraction critically depends on a detailed understanding of CH4 behavior within nanoporous geological formations. In these formations, Kaolinite and kerogen serve as the respective mineral and organic proxies for these nanoporous media. This study employs grand canonical Monte Carlo and molecular dynamics simulations to investigate the influence of reservoir characteristics on CH4 phase equilibrium and diffusion behaviors, using kaolinite and Type-II kerogen as representative nanopores. The simulations systematically examined the effects of pore size and water saturation under controlled temperature and pressure conditions. The results show that pore size is the primary factor controlling phase transition, significantly depressing the critical conditions due to enhanced confinement. Different surface properties of kaolinite hydroxyl and siloxane surfaces, along with the heterogeneous nature of kerogen, dictate local molecular aggregation and condensation strength. In addition, increased water saturation severely restricts the effective storage volume and induces competitive adsorption, thereby reducing the CH4 diffusion coefficient. The diffusion mechanism is primarily governed by the CH4 phase transition, followed by pore size and temperature. By elucidating these coupled microscopic mechanisms, this study provides important theoretical insights and quantitative support for optimizing fluid-solid interactions, which are essential for efficient shale gas exploration and the development of enhanced gas recovery strategies in unconventional reservoirs.

To address the challenges of nonuniform water invasion fronts and complex interlayer interference during the development of vertically heterogeneous edge-water gas reservoirs, this study integrates laboratory experiments with numerical simulations. First, a depletion experiment under edge-water drive was conducted using a self-developed large-scale 2D physical model operating under high-temperature and high-pressure conditions, equipped with a nonintrusive acoustic-electrical monitoring system. Based on the experimentally obtained dynamic pressure and fluid production data, a quantitative characterization method for interlayer crossflow that accounts for dynamic water saturation was established. Subsequently, a numerical model, rigorously calibrated through history matching, was employed to systematically examine the effects of aquifer size, production rate, and reservoir sequence on water invasion behaviors and crossflow characteristics. The results indicate that (1) the large-scale physical experiment confirmed that the high-permeability layer serves as a preferential flow path for edge water invasion. After water breakthrough occurred in this layer, the gas production rate dropped sharply while water production surged, precipitating drastic variations in interlayer and intralayer pressure differentials. Interlayer crossflow persists throughout the development process, primarily characterized by gas recharging from the medium- and low-permeability layers into the high-permeability layer. Quantitative calculations normalized to the total reservoir hydrocarbon pore volume (HCPV) reveal that the high-permeability layer (K3) acted as a macroscopic gas sink, receiving a cumulative gas influx equivalent to 22.35% of the total HCPV. Concurrently, the low-permeability (K1) and medium-permeability (K2) layers supplied this crossflow, experiencing gas outflows representing 11.58% and 10.76% of the total HCPV, respectively. (2) Numerical studies show that a larger aquifer size results in a faster water invasion velocity, earlier water breakthrough, a shorter water-free production period, and a lower recovery degree, while the intensity of interlayer crossflow is relatively weakened due to the rapid pressure maintenance in the high-permeability layer. Conversely, a lower production rate extends the water-free production period, delays water breakthrough, intensifies interlayer crossflow, and leads to a higher recovery degree. Reservoir sequence significantly dictates the water invasion pattern and sweep efficiency. In Fining-upward Sequence reservoirs (characterized by high permeability at the bottom), edge water preferentially fingers through the bottom high-permeability layer, whereas Coarsening-upward Sequence reservoirs are prone to top-water fingering. This study quantifies the gas-water two-phase interlayer interference mechanism under heterogeneous conditions. Furthermore, based on the numerical model calibrated by history matching, the effects of aquifer size, production rate, and reservoir sequence on development performance are systematically investigated. The methodologies and findings of this work provide effective tools for predicting water invasion behaviors, thereby offering a theoretical basis for the efficient development of vertically heterogeneous edge-water gas reservoirs.

Wettability controls fluid distribution, saturation, and relative permeability in tight reservoirs, but conventional measurements cannot resolve mixed wetting behavior across pore sizes. This study develops a pore-size-dependent wettability evaluation method that combines the Amott index with nuclear magnetic resonance measurements using heavy water. Signal changes during spontaneous and pressurized imbibition were used to quantify wettability indices for discrete relaxation-time intervals, corresponding to pore-throat radii of 0.0037-101 μm. The results reveal strong pore-scale wettability heterogeneity. Tight sandstones are mainly oil-wet in small pores and water-wet in larger pores, whereas shales show the opposite trend. Mineral composition explains these differences, with clay-rich inorganic pores favoring water-wet behavior and organic matter favoring oil-wet behavior. Average pore-scale wettability indices agree well with gravimetric and macroscopic nuclear magnetic resonance results, demonstrating a reliable approach for evaluating tight reservoir wettability and improving recovery assessment.

Shale oil reservoirs exhibit ultralow permeability and complex pore structures, which result in non-Darcy low-velocity flow and cause permeability to be stress-sensitive. Moreover, two-phase flow of oil and gas frequently occurs during the depletion of shale oil reservoirs. Consequently, investigating the rate-transient behavior of shale oil wells necessitates comprehensive consideration of multiphase flow, threshold pressure gradients, and stress sensitivity. Although numerous analytical models exist for rate-transient analysis of multistage fractured horizontal wells, none of them simultaneously incorporate these critical factors. In this study, we extend the classical five-region model to incorporate multiphase flow, threshold pressure gradients, and stress sensitivity. The proposed model is solved using Pedrosa’s transformation, perturbation theory, the Laplace transform, and the Stehfest numerical inversion method. A systematic analysis of the influence of various parameters on the oil production rate and cumulative oil production is conducted, and a field case study is presented to validate the applicability and effectiveness of the model. It is found that the permeability modulus of the main fracture, the half-length of the main fracture, and the threshold pressure gradient of the unstimulated reservoir have a significant influence on cumulative oil production spanning 20 years. With a 100% relative input error, these parameters result in prediction errors of 23.77%, 16.65%, and 17.78%, respectively. In contrast, the threshold pressure gradient of the main fracture and the threshold pressure gradient of the stimulated reservoir have a negligible impact; under the same level of input error (100%), they cause only 0.36% and 0.48% prediction errors in the 20-year cumulative oil production period, respectively. This research provides an efficient and reliable framework for analyzing production data and forecasting shale oil well performance.