The development of water drive gas reservoirs (WDGRs) with fractures or strong heterogeneity is severely influenced by water invasion. Accurately simulating the rules of water invasion and drainage gas recovery countermeasures in fractured WDGRs, thereby revealing the mechanism of water invasion and an appropriate development strategy, is important for formulating water management measures and enhancing the recovery of gas reservoirs. In this work, physical simulation methods were proposed to gain a better understanding of water invasion and to optimize the water control of fractured WDGRs. Five groups of experiments were designed and conducted to probe the impacts of the distance between the fractures and the gas well, the drainage position, the drainage timing and the aquifer size on the water invasion and production performance of a gas reservoir. The gas and water production and the internal pressure drop were monitored in real time during the experiments. Based on the above experimental works, a theoretical analysis was conducted to quantitatively evaluate the performance of the gas reservoir recovery via the gas well production performance, water invasion, dynamic pressure drop and residual gas and water distribution analysis. The results show that when the fracture scale was appropriate, a gas well drilled close to a fracture (Experiment 1-3) or a high-permeability formation could also produce gas and achieve drainage efficiently. The recovery factor of Experiment 1-3 reached 62.5%, which was 24.6% and 21.1% higher than those of Experiments 1-1 and 1-2, respectively, which had wells drilled in low-permeability areas. Draining water near an aquifer can effectively inhibit water invasion during the early stage of gas recovery. The setup in Experiment 2-1 effectively inhibited water invasion and avoided the formation of water-sealed volumes of gas to recover 30% more gas than recovered with that of Experiment 1-1 without drainage wells. A shorter distance between the drainage well and the aquifer increased the drainage capacity and decreased the gas production capacity, respectively (Well 2 at Point A vs Point B). A larger aquifer had a lower gas recovery, which reduced the economic benefit. For example, due to an infinitely large aquifer, the reserves in Experiment 4-1 were developed by a single well, the gas recovery was only 33.4%. These research results are expected to be beneficial for the preparation of development plans and the optimization of water control measures for WDGRs.

In the development process for a fractured-porous gas reservoir with developed fracture and active water, edge water or bottom water easily bursts rapidly along the fracture to the production well, and the reservoir matrix will absorb water, reducing the gas percolation channel and increasing the gas phase percolation resistance of the reservoir matrix, therefor reducing the stable production capacity and recovery efficiency of the gas reservoir. For this reason, this paper investigates physical simulation experimental technology and mechanisms as reported by both domestic and foreign scholars regarding water invasion in fractured-porous gas reservoirs. In this paper, it is considered that the future trend and focus of water invasion experiments will be to establish a more realistic three-dimensional physical model on the basis of fine geological description, combined with gas reservoir well pattern deployment and production characteristics, and to fully consider the difference between horizontal and vertical water invasion along the reservoir side; at the same time, dynamic parameters such as model pressure field and water saturation field can be obtained in real time. Based on this understanding of the water invasion mechanism of fractured-porous gas reservoirs, we propose the next research direction and the development countermeasures such as water controls, drainage, and dissolved water seals and water locks to combat water invasion in reservoirs, along with the injection of gas to replenish formation energy, etc., so as to slow down and control the influence of water invasion.

The propagation pattern of pressure drawdown effectively reflects the recoverable reserves range around the gas well and serves as a crucial basis for development strategies. However, it is not easy to detect the pressure propagation boundary near the producing well, especially in low-permeability reservoirs where the drainage radius is small. Physical simulation experiments can serve as a crucial method as the whole pressure profile and gas rate can be obtained in real time. Using long core plugs with permeabilities of 2.300 mD, 0.486 mD, and 0.046 mD, physical simulation experiments were carried out under varying initial water saturation (Swi) conditions of 0%, 20%, 40%, and 55% to observe the dynamic variations in pressure profiles of the core plugs during pressure depletion. Based on the material balance equation and pressure profile characteristics of the core plugs, a method for evaluating recoverable reserves within a well-spacing radius through laboratory experiments was proposed and performed. Mechanism analysis was conducted based on mercury injection tests, and suggestions for enhancing gas recovery were presented. Research findings indicate that lower permeability, higher initial water saturation, and higher abandonment gas rates result in reduced reserve utilization range and degree. Under abandoned gas rate conditions, for type I and II rocks, the pore radius is primarily distributed between 0.1 and 1 μm, the pressure drawdown can reach the well-spacing radius of 600 m, and the ultimate recovery efficiencies are more than 70.6%. For type III rocks, the pore radius mainly falls below 0.1 μm, the drainage radius is smaller than 10 m with Swi greater than 40%, and the ultimate recovery is below 10%. This paper provides an experimental method for recoverable reserves evaluation while formulating gas reservoir development strategies before well testing.

The scientific evaluation of the damage caused by working fluid invasion in tight sandstone gas reservoirs is critical for optimizing drilling design, fracturing fluid systems, and construction design. This study focused on the tight sandstone core of the Qingshimao gas field in the Ordos Basin. A set of experimental methods and equipment were designed to facilitate the visual monitoring and quantitative evaluation of the reservoir damage caused by working fluids. Systematic evaluation experiments were conducted to analyze the extent of reservoir damage caused by working fluid invasion under varying pore pressure and permeability conditions. The results show the following: (1) As permeability increases, the real-time invasion flow rate rises, and the invasion rate accelerates. Meanwhile, as pore pressure increases, the real-time invasion flow rate decreases, and the invasion rate slows down. (2) The core’s fluid saturation after working fluid invasion exceeds 70%, with permeability damage reaching 95% or higher. (3) At the same reservoir pore pressure, cores with permeability ranges between 0.1 × 10⁻³ μm² and 1 × 10⁻³ μm² exhibit higher fluid-phase saturation and greater invasion damage. For cores with similar permeability, the higher the pore pressure, the higher the invasion-phase saturation, and the greater the extent of invasion damage. The research results provide certain guiding significance for evaluating the extent of the damage caused by working fluid invasion in tight sandstone gas reservoirs and achieving efficient gas reservoir development.

The late-stage development of gas reservoirs often encounters the paradox of significant remaining formation pressure coupled with low wellhead pressure, which indicates small drainage volume, low gas production rate, and low recovery efficiency, reducing gas supply and economic benefit. Owing to the lack of experimental research, the reasons behind this contradiction between gas production and producing pressure differential are unclear. The key factors affecting the development outcomes are reservoir permeability and initial water saturation, while the evaluation parameters include gas and water production rates, reservoir pressure, and recovery efficiency. Based on the characteristic properties of typical gas fields, physical simulation experiments of constant-rate gas production are conducted on spliced long cores with average permeabilities of 2.300, 0.486, and 0.046 millidarcy (mD). Furthermore, leveraging the multi-point embedded pressure measurement technique, the pressure drawdown propagations and the macroscopic and microscopic characteristics of connate water production at the initial water saturations of 0%, 20%, 40%, and 55% are investigated. By connate water, we mean water that occurs naturally within the pores of rock. Pre- and post-experiment core weighing and nuclear magnetic resonance testing are performed. In addition to the mercury injection tests, the results indicate that during gas reservoir depletion, connate water primarily stems from macropores and mesopores, with micropores and nanopores capturing water through capillary imbibition. Moreover, lower permeability and higher initial water saturation lead to greater pressure gradients, increased connate water production, and reduced recovery efficiency. Reservoirs with permeabilities below 0.1 mD are significantly affected by connate water, exhibiting steep pressure profiles. Owing to connate water, the near-wellbore pressure quickly decreases, while distant reservoir pressure barely decreases, implying a limited drainage area. To enhance the recovery efficiency, measures like infill drilling and reservoir stimulation are recommended for low-permeability gas reservoirs.

Addressing the problem of limited methane (CH₄) recovery degree under different production conditions in a target low-permeability carbonate gas reservoir, this study intends to further investigate the effect of carbon dioxide (CO₂) injection on enhanced gas recovery (EGR). A group of long-core physical simulation experiments of CO₂ injection for EGR was adopted. Field injection–production parameters were converted to laboratory conditions through similarity criteria to simulate the actual production process of gas wells. Systematic experiments on CH₄ depletion and CO₂ displacement were carried out under different irreducible water saturation, gas injection timing pressure and injection rates. The influence laws of each key parameter on the CO₂ breakthrough time and CH₄ recovery degree were analyzed emphatically, and the optimal injection–production scheme was obtained. For the target low-permeability carbonate gas reservoir (permeability < 1 mD), the optimal CO₂ injection scheme is as follows: for layers with medium to high irreducible water saturation (≥40%), CO₂ injection at a rate of 36,000 m³/d per well after the end of stable production (formation pressure > 7.38 MPa) can increase the CH₄ recovery degree by 3–5%. This study provides experimental support for the optimization of CO₂ injection schemes for enhanced recovery in gas reservoirs and the adjustment of gas reservoir development strategies under different irreducible water saturation conditions.