Development Of Gas Reservoirs Research Articles

Large-Scale Physical Simulation Experiment of Water Invasion Law for Multi-Well Development in Sandstone Gas Reservoirs with Strong Water Drive

In order to clarify the water invasion law and residual gas distribution characteristics in edge and bottom water gas reservoirs with multi-well development, a large-scale three-dimensional physical simulation model was developed and a physical simulation experiment method for the water invasion law of multi-well development in sandstone gas reservoirs with strong water drives was established. Water invasion physical simulation experiments of multi-well development under the conditions of different water body multiples and production systems were conducted. The results show the following: (1) Gas wells near fractures and high-permeability zones experience the earliest water breakthrough. The larger the water body multiple, the faster the rate of water invasion, the earlier the water breakthrough time of gas wells, the more severe the degree of water invasion in gas reservoirs, and the lower the ultimate recovery rate. (2) Shutting in low-position gas wells immediately after water breakthrough reduces the overall water production of the gas reservoir and extends the overall water-free gas production period. However, the ultimate recovery rate is lower than when the wells are not shut in. (3) The residual gas in the fracture model is mainly distributed around the fracture and the edge of the gas reservoir, with the ultimate recovery rate ranging from 38.5% to 58.2%. The residual gas in the fracture–high-permeability zone model is mainly distributed around the fracture–high-permeability zone and the edge of the gas reservoir, with the ultimate recovery rate ranging from 28.32% to 41.8%. The experimental results have important guiding significance for the economical and efficient development of similar gas reservoirs.

Modified guanidine gel fracturing fluid system and performance optimization for ultra-deep and ultra-high temperature oil and gas reservoirs

The development of deep high-temperature oil and gas reservoirs gives rise to a rise in reservoir temperature along with the depth of the oil reservoir, thereby imposing higher requirements on the heat resistance of fracturing fluid. Guar gum fracturing fluid has difficulty tolerating temperatures exceeding 160 °C, thereby demanding the development of corresponding cross-linking agents, temperature stabilizers, and other additives to enhance the thermal stability of the fracturing system. Considering the distinctive characteristics of deep and ultra-deep reservoirs, such as extreme burial depth (exceeding 6000 m), ultra-high temperature (higher than 160 °C), and high fracturing pressure, an experimental modification of a guar gum fracturing fluid system was carried out, specifically tailored for ultra-high temperatures. The experiment identified and selected individual agents for ultra-high temperature fracturing fluids, including crosslinking agents, thermal stabilizers, flowback aids, and clay inhibitors. Through rigorous experimentation, these key agents for an ultra-high temperature fracturing fluid system have been successfully developed, including the optimal thickener GBA1-2, crosslinking agent BA1-1, anti-swelling agent FB-1, and gel breaker TS-1. The evaluation of diverse additive dosages has facilitated the development of an optimal guar fracturing fluid system, which exhibits outstanding high-temperature resistance while minimizing damage and friction. The outcomes of our experiments indicate that even after subjecting our ultra-high temperature fracturing fluid to 2 h of shearing at 170 s−1 at 180 °C, its viscosity remained above 200 mPa s—a distinct proof of its superior performance in withstanding high temperatures. This achievement represents a substantial progress in providing a suitable fracturing fluid system for the transformation and stimulation of ultra-deep and ultra-high temperature reservoirs, and also lays a solid foundation for further exploration and application in related fields in the future.

SELECTION OF A MRP SYSTEM FOR OIL AND GAS DEPOSITS

A number of serious problems arise in the development of sub-gas zones of oil and gas deposits due to the joint occurrence of oil and gas. The key problem is gas breakthrough from the gas cap to oil wells. This entails an increase in the gas factor (GOR), a rapid and intense decrease in pressure in the gas cap. If there is a reservoir pressure maintenance system or an active aquifer as a result of a decrease in reservoir pressure in the gas cap, oil may be pushed back into it, which leads to a rise in gas-oil contact, jamming of mobile oil in the «dry sandstones» of the gas cap, which in turn leads to a decrease in reserves of mobile oil and a decrease in the oil recovery factor (ORF). All this together allows us to consider oil in the sub-gas zones as hard-to-recover reserves.Preventing and combating the negative consequences of gas breakthrough from the gas cap to oil wells is a complex task and consists of several areas, such as selection of rational drilling of production and injection wells, selection of optimal operating modes for them, use of inflow control devices or performance of repair and isolation work to limit inflow from intervals with gas breakthrough, periodic shutdown of wells to disband gas cones. The ultimate goal of solving these problems is to increase the oil recovery factor and economic efficiency indicators for the development of sub-gas zones.Due to the variety of ways to optimize the development of oil and gas reservoirs, it is not possible to cover them all in one work, therefore, the tasks associated with optimizing the reservoir pressure maintenance system are considered. It is worth noting that in comparison with the development of oil reservoirs, the presence of a gas cap significantly complicates this task due to the lack of analytical solutions for three-phase filtration. For this reason, the selection of the optimal parameters of the reservoir pressure maintenance system is usually carried out either by multivariate calculations in the hydrodynamic model (HDM), or by the method of analogies or the implementation of pilot tests of various approaches.In this study, an approach based on multivariate numerical calculations using the sector model of the development element of the gas zone was used. As a result of calculations, it was shown that when choosing the optimal parameters of the reservoir pressure maintenance system, it is advisable to use a differentiated approach, which consists in the fact that these parameters must be set individually for zones with different ratios of oil-saturated and gas-saturated thicknesses.

Characterization of fault-karst reservoirs based on deep learning and attribute fusion

AbstractThe identification of fault-karst reservoir is crucial for the exploration and development of fault-controlled oil and gas reservoirs. Traditional methods primarily rely on well logging and seismic attribute analysis for karst cave identification. However, these methods often lack the resolution needed to meet practical demands. Deep learning methods offer promising solutions by effectively overcoming the complex response characteristics of seismic wave fields, owing to their high learning capabilities. Therefore, this research proposes a method for fault-karst reservoir identification. Initially, a comparative analysis between the improved U-Net++ network and traditional deep convolutional networks is conducted to select appropriate training parameters for separate training of karst caves and faults. Subsequently, the trained models are applied to actual seismic data to predict karst caves and faults within the research area, followed by attribute fusion to acquire data on fault-karst reservoirs. The results indicate that: (1) The proposed method effectively identifies karst caves and faults, outperforming traditional seismic attribute and coherence methods in terms of identification accuracy, and slightly surpassing U-Net and FCN; (2) The fusion of predicted karst caves and faults yields clear delineation of the relationship between top karst caves and bottom fractures within the research area. In summary, the proposed method for fault-karst reservoirs identification and characterization provides valuable insights for the exploration and development of fault-controlled oil and gas reservoirs in the region.

Analysis of Factors Influencing Tight Sandstone Gas Production and Identification of Favorable Gas Layers in the Shan 23 Sub-Member of the Daning-Jixian Block, Eastern Ordos Basin

The Daning-Jixian Block harbors abundant tight sandstone gas resources. However, significant variations in gas production exist among the different wells within the block. A comprehensive study was conducted on key factors such as sedimentary strata and petrophysical characteristics to elucidate their impact on gas reservoir productivity. Linear regression equations were employed to classify the favorable reservoirs within the study area. The analysis revealed that within the first 6 months of production from the Shan 23 gas layer, daily gas production ranged from 2576.19 to 156,078.17 m3/d, averaging 24,037.9 m3/d. Over the first year, average daily production varied from 2185.05 to 136,806.99 m3/d, averaging 23,469.23 m3/d, indicating relatively stable production from the Shan 23 layer alone. In the dominant central area of the underwater distributary channel delta front in Shan23, the sand body exhibits a superimposed cutting type, resulting in high production rates. Conversely, the sand bodies on the periphery gradually transition to superimposed and isolated types, leading to decreased production. Through a correlation analysis of gas layer thickness, porosity, permeability, and initial gas well production, it was determined that gas production from the wells within the same layer is primarily influenced by gas layer thickness, porosity, and permeability. Gas saturation demonstrates a minimal impact on production according to single-factor analysis. The evaluated factors such as the gas productivity coefficient, energy storage coefficient, and enrichment coefficient exhibited similar distribution patterns across the study area. The high-value areas for the gas productivity coefficient, energy storage coefficient, and enrichment coefficient are concentrated in distributary channel zones and delta lobes. In contrast, regions with underdeveloped skeletal sand bodies generally display lower values for these parameters. The linear relationships between these parameters and the average gas production were calculated to further classify the favorable reservoirs in the study area. This study aimed to establish a scientific basis for the efficient development of the tight sandstone gas reservoirs within the Daning-Jixian Block.

Efficient development technology of Upper Paleozoic Lower Shihezi tight sandstone gas reservoir in northeastern Ordos Basin

Abstract The Lower Shihezi Formation of the Upper Paleozoic at the northeastern margin of the Ordos Basin develops widely distributed thick massive and multilayer gas reservoirs. How to formulate an effective development policy is a difficult and hot spot. In this article, reservoir characteristics and production capacity influencing factors of the tight gas sandstone in Lower Shihezi Formation in this area are systematically studied, and optimization schemes of development measures for massive and multilayer gas reservoirs are proposed. The results show that the petrophysical characteristics of the small pore–mesopore type gas reservoir in the target layer are the best, with the average porosity, permeability, and coordination number of 7.6%, 0.74 mD, and 3.3, respectively. Thick sand body, high structural position, good petrophysical properties, and high drilling rate of sandstone are all conducive to drilling high production gas wells. Development policies for massive and multilayer gas reservoirs have been formulated: (1) the preferred well type for massive gas reservoir is vertical well + horizontal well, while the preferred well type for multilayer gas reservoir is horizontal well + stepped horizontal well; (2) the reasonable horizontal segment length of massive gas reservoir is 1,000 m, and the reasonable horizontal segment length of multilayer gas reservoir is 1,250 m; (3) similar to massive and multilayer gas reservoirs, the more the fracture stages, the higher the cumulative gas production, and the optimal fracture stage number of both gas reservoirs is 8; (4) the optimal fracture half-length and the angle between the fracture and the horizontal section are 140 m and 90°, respectively; and (5) the reasonable well spacing of vertical wells is 600 m and that of horizontal wells is 750 m. The development policy proposed in this study is suitable for the efficient development of complex tight sandstone gas reservoirs in similar areas.

Pore-Scale Numerical Simulation of Acid-Rock Reaction Processes in Carbonate Reservoirs.

In the process of acidizing carbonate reservoirs, dissolution is employed for reservoir modification to enhance recovery rates. This study establishes a numerical model at the pore scale for acid-rock reaction flow based on a microscopic continuum medium model, integrating phase-field theory and component transport models. Subsequently, the results of the Darcy-Brinkman-Stokes model are compared to those of the arbitrary Lagrange-Euler method to validate the accuracy of the model. Finally, the flow behavior of the acid solution at the pore scale and the complex dissolution mechanisms in carbonate reservoirs are analyzed. The research indicates that the microscopic pore-scale dissolution in carbonate reservoirs mainly manifests as five dissolution modes: uniform dissolution, compact dissolution, conical wormholes, dominant wormhole, and ramified wormholes. Different distributions of microfractures will alter the flow state of the acid solution and the rock-acid reaction process within the pores. Once the wormhole breakthrough occurs, there is an increased probability of acid flow through the wormhole to the outlet, leading to a decrease in the effectiveness of the acidizing carbonate reservoirs. A proper understanding of pore-scale acid-rock reaction laws is of great significance for the development of carbonate oil and gas reservoirs.

Accurate identification of low-resistivity gas layer in tight sandstone gas reservoirs based on optimizable neural networks

In tight sandstone reservoirs, low resistivity gas reservoirs have a certain gas production capacity, but their reservoir resistivity value is less than 20 Ω m, or their ratio to water layer resistivity is less than 2. Therefore, the identification of low resistivity gas reservoirs is a prominent problem that needs to be resolved. In this paper, on the basis of traditional experimental analysis, NMR experiments and wettability experiments were conducted. The high bound water saturation and pore fractal dimension have a significant impact on reservoir resistivity. After various experimental analysis results were preprocessed by the image pool and data pool, an optimized neural network (ONN) classification model was established based on deep learning theory. The confusion matrix result (training datasets) was 87.13%, and the ROC area of low resistivity gas layers was close to 1, indicating good recognition performance for low resistivity gas layers. The model was used to identify the properties of the J4 well reservoir section. The identification result was consistent with the actual logging resistivity values (low resistivity) and testing conclusions (gas layer). This model can accurately identify low resistivity gas reservoirs in the research area, and has important guiding significance for identifying the reservoir properties of tight sandstone gas reservoirs in the Sichuan Basin. It can provide reference value for the exploration and development of similar gas reservoirs in other regions.

A novel approach to understanding the genesis and distribution of widespread reservoirs at the basin edge: A case study of gas-bearing sandstone in the Sangonghe Formation, Junggar Basin, Western China

A 20 m thick sandstone drilled in the second member of the Sangonghe Formation in the Qianshao area of the Junggar Basin has been identified to be a high-quality gas-bearing reservoir. However, recent missions reveal an uncertainty in reservoir distribution and bring high risk to the subsequent gas development, although the gas-bearing reservoir has been encountered by several drillings and proved to be widespread. To investigate the accurate distribution and reveal the evolution of the reservoir, we reconstruct the stratigraphic framework and depositional stages by a high-revolution sequence stratigraphic method, effectively identify the gas-bearing reservoir by seismic attributes refusion and seismic stratigraphic slices, and finally map the distribution strata distribution at different stages. The results indicate that the landward onlap phenomenon in the seismic data indicates a retrogradational stratigraphic structure during the water level rise rather than the equal-thickness stratigraphic pattern under stable water conditions. According to the retrogradational stratigraphic structure, the real driver for the widespread characteristic of a gas-bearing reservoir is the backward staggered movement of multistage sand bodies during the transgressive process rather than single-stage deposition. The fusion of seismic acoustic impedance and main frequency attributes provides an effective survey to identify the accurate distribution of the reservoir, by which interpretation of a stratigraphic slice along the vertical centerline of the reservoir extracted from the multiattribute fusion survey can present the distribution and evolution of the three stages on only one map. Achieved by an appropriate interpretation on the map, two sandy debris flow bodies are identified as being deposited at the bottom successively during the first two transgressive stages. They are completely staggered in the source direction with a clear boundary between well Qs9 and Qs7. Subsequently, the subsequent rise of the water level led to the deposition of a large-scale multibranch shallow-water delta, which exhibits the characteristics of multistage, multisource, and multibranch. The results not only advance our comprehension of widespread sand bodies but also furnish fundamental insights for the development of lithologic condensate gas reservoirs in the Qianshao area.

Experimental Study on Proppant Migration in Fractures Following Hydraulic Fracturing

Complex fracture technology is key to the successful development of unconventional oil and gas reservoirs, such as shale. Most current studies focus on how to improve the complexity of the fracture network. It is still unclear whether proppant can enter the branch fractures at all levels after the formation of complex fractures. The effects of construction displacement, proppant particle size, proppant density, fracturing fluid viscosity, sand ratio, and other factors on proppant migration in single fractures and complex fractures were studied using an experimental device independently developed by the laboratory. The results show that the lowest point height of the sandbank and the equilibrium height of the sandbank are directly proportional to the particle concentration and density, respectively, and inversely proportional to the displacement and fracturing fluid viscosity. The equilibrium time of the sandbank is inversely proportional to the displacement, particle concentration, and density, respectively, and proportional to the viscosity of the fracturing fluid. Under the same experimental conditions, the larger the branch angle, the smaller the height of the main/secondary fracture sandbank. In the design of the fracturing process, fracturing fluid with varying viscosities and proppant with different densities should be selected according to the formation conditions and fracturing targets. In the face of long fracture lengths, the combination of low-viscosity fracturing fluid with an appropriate viscosity and low-density proppant can meet the goal of placing proppant over long distances and effectively supporting fractures over extended lengths. Subsequently, high-density proppant or reduced construction displacement are adopted to usefully support fractures in the near-wellbore area. The results of this paper can provide theoretical support for proppant selection and fracturing program design.

Research on Gas Injection Limits and Development Methods of CH4/CO2 Synergistic Displacement in Offshore Fractured Condensate Gas Reservoirs

Gas injection for enhanced oil and gas reservoir recovery is a crucial method in offshore Carbon Capture, Utilization, and Storage (CCUS). The B6 buried hill condensate gas reservoir, characterized by high CO2 content, a deficit in natural energy, developed fractures and low-pressure differentials between formation and saturation pressures, requires supplementary formation energy to mitigate retrograde condensation near the wellbore area through gas injection. However, due to the connected fractures, the B6 gas reservoir exhibits strong horizontal and vertical heterogeneity, resulting in severe gas channeling and a futile cycle, which affects the gas injection efficiency at various levels of fracture development. Based on these findings, we conducted gas injection experiments and numerical simulations on fractured cores. A characterization method for oil and gas relative permeability considering dissolution was established. Additionally, the gas injection development boundary for this type of condensate gas reservoir was quantified according to the degree of fracture development, and the gas injection mode of the B6 reservoir was optimized. Research indicates that the presence of fractures leads to the formation of a dominant gas channel; the greater the permeability difference, the poorer the gas injection effect. The permeability gradation (fracture permeability divided by matrix permeability) in the gas injection area should be no higher than 15; gas injection in wells A1 and A2 is likely to achieve a better development effect under the existing well pattern. Moreover, early gas injection timing and pulse gas injection prove beneficial in enhancing the recovery rate of condensate oil. The study offers significant guidance for the development of similar gas reservoirs and for reservoirs with weakly connected fractures; advancing the timing of gas injection can mitigate the retrograde condensation phenomenon, whereas initiating gas injection after depletion may reduce the impact of gas channeling for reservoirs with strongly connected fractures.

Synthesis and performance evaluation of low‐damage variable viscosity integrated drag reducer

AbstractTo solve problems such as inadequate proppant carrying capacity, a complex viscosity changing process, and limited environmental friendliness associated with traditional slick water fracturing fluids, a variable viscosity friction reducer called Jianghan friction reducer (JHFR) with low damage, high drag reduction, and strong proppant‐carrying capacity is prepared by inverse emulsion polymerization. The properties of JHFR are investigated by viscometer, JHFR‐II high‐temperature and high‐pressure slick water drag reduction rate tester, surface tension meter, and JHCQ Core dynamic damage evaluation device. The result shows that the dissolution time of JHFR is less than 120 s. The drag reduction of 0.08 wt% JHFR (4.83 mPa s) is 80.3%. When the concentration of JHFR increases from 0.08 to 0.8 wt %, the viscosity of the JHFR increases from 4.83to 97.41 mPa s. After sheared at 90°C and 170 s−1 for 60 min, the viscosity of 0.8 wt% JHFR still maintains 51 mPa s. The damage rate of JHFR to core matrix permeability is lower than 30%. JHFR also shows the advantages of easy breakage and low residue. It provides guidance for the design and selection of fracturing fluid for unconventional oil and gas reservoir development.

In-situ CT study on the effect of cyclic gas injection and depletion exploitation on the phase behavior of fractured condensate gas reservoirs

Using subterranean rock cores as samples, the impact of depletion exploitation and cyclic gas injection on the occurrence and dynamic utilization of condensate oil and the damage to reservoirs were studied. Initially, the internal pore structure of the rock core was analysed using computer tomography (CT), followed by depletion and cyclic gas injection experiments, with in-situ CT scanning of the samples. The results indicate that under different fracture apertures, condensate oil exhibits wave flow and slug flow states. The production effectiveness of cyclic gas injection is significantly superior to depletion exploitation production, with condensate oil saturation decreasing by over 30%. During cyclic gas injection, fractures serve as the main flow channels, with condensate oil being extracted first. In cyclic gas injection, the most significant effect is seen during the first injection, with a decrease in oil saturation of around 3%. Subsequent injections show decreases of approximately 1% and 0.5% in oil saturation respectively. As the gas injection volume increases, the extent of cumulative production rate improvement also gradually increases; however, once the injection volume reaches the reservoir pressure, the rate of cumulative production rate improvement will gradually decrease. These findings provide technical support for optimizing the development mode of condensate gas reservoirs, clarifying the seepage law of condensate oil and gas, and providing technical support for the efficient development of fractured condensate gas reservoirs.

Pressure Transient and Production Analysis of Fractured Vertical Wells in Tight Sand Gas Reservoirs Considering Threshold Pressure Gradient, Phase-Change Phenomenon, and Stress Sensitivity

The productivity and pressure response of the tight sand gas wells are influenced by multiple flow mechanisms, such as threshold pressure gradient, phase-change phenomena, and stress sensitivity. Understanding the sensitivity of these factors is crucial for the effective development of tight sand gas reservoirs. This study aims to clarify the sensitivity of various factors affecting the productivity and pressure response of tight sand gas wells. Based on the percolation theory of tight sand gas reservoirs, we considered stress sensitivity, threshold pressure gradient, and phase-change phenomena to derive an unsteady mathematical model of a fractured well with an infinite boundary, and a point source solution was obtained. The proposed model was solved using series function properties, variable substitution, perturbation technique, Poisson superposition formula, Laplace transform, and numerical inversion. The influence of several important parameters on pressure response and productivity is discussed in detail. The results show that the threshold pressure gradient, stress sensitivity, and skin factor significantly impact gas well production and pressure response, while the wellbore storage effect and phase-change effect primarily affect the initial production and pressure response, having little effect on the cumulative gas production. The proposed model can estimate the influence of the threshold pressure gradient and stress sensitivity on productivity and pressure, providing a guide for the development of technical measures for fractured wells in tight sand gas reservoirs.

Microscopic Mechanism and Percolation Model of Dynamic Deposition of Elemental Sulfur Particles in Acidic Gas Reservoirs.

The dissolution of elemental sulfur in acidic gas leads to its precipitation as gas pressure decreases, thereby causing potential damage to the formation due to the deposition of sulfur particles. Previous sulfur deposition prediction models often relied on the solubility of sulfur in acidic gas and the stress state of sulfur particles to determine the occurrence of deposition, thus establishing predictive models. However, in the presence of complex geological conditions, the multiphase flow through porous media and the adsorption of particles on pore throat walls can also influence sulfur particle deposition to some degree. It is well known that sulfur particle deposition during gas reservoir development exhibits instability, with multiple factors influencing the deposited sulfur particles. Particularly noteworthy is the influence of airflow velocity, which can resuspend sulfur particles that are physically adsorbed on pore throat surfaces, thereby reintegrating them into the gas phase. Additionally, the dynamic deposition of larger sulfur particles involves a dynamic process. This study elucidates the dynamic process of sulfur deposition by considering the diverse transport dynamics of sulfur particles. Physical adsorption and desorption behaviors of sulfur particles are determined based on variations in reservoir conditions. The desorption status of sulfur particles with different particle sizes within the formation is established by evaluating the equilibrium between the force exerted on the pore throat wall and the suspension force generated by gas flow. The critical conditions for sulfur deposition in Yuanba gas reservoir were obtained by substituting on-site parameters into calculations. Moreover, a mathematical model is proposed to describe the dynamic deposition and migration of sulfur particles, adopting principles from continuous porous media porous flow theory, fluid flow mass conservation, as well as sulfur particle desorption and migration. The formulated model is solved, and its resulting solution process and outcomes hold significant implications for numerical simulation and predictive assessment of the development impact on gas reservoirs, particularly in later stages.

Sedimentary Evolution Laws and Main Controlling Factors of the Nenjiang Formation in the Songnan Da’anbei Area, China

Shallow-water deltas serve as a critical area for the exploration and development of terrestrial lacustrine oil and gas reservoirs. Current research on oil and gas exploration and development in China’s terrestrial lacustrine basins primarily focuses on their delta front facies zones. Despite extensive discussions on the sedimentary characteristics of shallow-water deltas by predecessors, there is a lack of comprehensive analysis on the combined effects of dynamic factors such as climate change, lake level fluctuations, and sediment supply. This paper, through a detailed examination of 12 core samples and integrating data from 493 exploratory, appraisal, and development wells in the study area, establishes a stratigraphic correlation framework using well–seismic integration techniques. It identifies two main sedimentary facies types in the southern Da’anbei area of the Songliao Basin: shallow-water deltas and lake facies, which can be further subdivided into four sub-facies and nine microfacies. Two depositional models for the shallow-water deltas of the Southern Songliao Nenjiang Formation are established: a deeper water background with channel-river mouth bar sequences forming the delta front framework and a shallower water background with channel-sheet sand sequences forming the delta front framework. This paper also discusses the controlling effects of paleoclimate, sediment supply, and lake level changes on sedimentary evolution, providing a scientific basis for the exploration of lithologic oil and gas reservoirs in the Nenjiang Formation of the study area and the deployment of horizontal wells.

A Review of Supercritical CO2 Fracturing Technology in Shale Gas Reservoirs

Shale gas reservoirs generally exhibit characteristics such as low porosity, permeability, and pore throat radius, with high airflow resistance. Currently, hydraulic fracturing is a commonly used method for commercial shale gas extraction; however, the hydraulic fracturing method has exhibited a series of issues, including water sensitivity and reservoir pollution in shale reservoirs. Therefore, the development of anhydrous fracturing technology suitable for shale gas reservoirs has become an urgent requirement. The supercritical carbon dioxide fracturing technique has the merits of reducing reservoir damage, improving recovery and backflow rates, and saving water resources. Moreover, this technique has broad application prospects and can achieve the effective extraction of shale gas. To enhance the understanding of the supercritical carbon dioxide fracturing technique, this review summarizes the progress of current research on this technique. Furthermore, this study analyzes the stage control technology of supercritical carbon dioxide during the fracturing process, the interaction characteristics between supercritical carbon dioxide and rocks, and the laws of rock initiation and crack growth in supercritical carbon dioxide fracturing. The outcomes indicate that after SC-CO2 enters the reservoir, CO2 water–rock interaction occurs, which alters the mineral composition and pore throat framework, weakens the mechanical characteristics of shale, reduces the rock fracturing pressure, and increases the complexity of the fracturing network. This article provides a reference for research related to supercritical carbon dioxide fracturing technology and is greatly significant for the development of shale gas reservoirs.

Solubility of H2S-CH4 mixtures in calcium chloride solution: Insight from molecular dynamics simulations

This study uses equilibrium molecular dynamics (EMD) simulations to gain microstructural insight into and predict crucial properties of gas-brine mixtures affecting sour gas reservoir development. The effects of pressure, temperature, gas composition and salinity on the solubility and density of H2S-CH4 mixtures in pure water and CaCl2 brine were investigated at industrially relevant conditions (temperature range of 280 − 340 K, pressures up to 20 MPa, and a salinity range of 4.78 − 17.32 wt%). The force fields used in the MD simulations were validated using experimental data for pure H2S and CH4. The results showed that the solubility of pure H2S and CH4 in pure water increases with pressure, with the latter having a higher solubility. For H2S-CH4 mixtures, the solubility of H2S increased while that of CH4 fell with increasing H2S mole fraction, with the solubilities of the two gases intersecting at an H2S mole fraction of 0.28. Further, the solubility of H2S shows a greater pressure dependence than that of CH4, and H2S gas tends to reach saturation in pure water. In calcium chloride solution, the gas solubility decreases as the ions reduce the interaction between water and gas molecules. The solubility of H2S gas is a stronger function of the ion concentration compared with CH4, and increases 6-fold as the H2S mole fraction increases from 0.5 to 0.8. The overall solubility ranges were 0.45 to 3.48 mol/kg for H2S and 0.15 to 0.25 mol/kg for CH4.

Review about evaluation methods of recoverable reserves of deep water drive gas reservoirs in China

It has been widely accepted that China is one of the biggest natural gas consumers. Related to the imports of LNG, China stands in a very uncomfortable situation. Most domestic gas reservoirs fall within deep water drive gas reservoirs inordinately, which has entered the production depletion stage. Accurate estimation of SEC recoverable reserves of deep water drive gas reservoirs is of great significance for gas consumption planning and peak shaving. The existing calculation methods of recoverable reserves mainly consist of static methods and dynamic methods. In the early stage of exploration and development, the volumetric method has often been utilized to calculate the recoverable reserves. With the continuous development of gas reservoirs, the main methods for evaluation are dynamic methods, including the successive subtraction of production method, water drive curve method, prediction model method, attenuation curve method, improved virtual curve method, and material balance method for deep gas reservoirs.

CO2 injection-based enhanced methane recovery from carbonate gas reservoirs via deep learning

CO2 injection is a promising technology for enhancing gas recovery (CO2-EGR) that concomitantly reduces carbon emissions and aids the energy transition, although it has not yet been applied commercially at the field scale. We develop an innovative workflow using raw data to provide an effective approach in evaluating CH4 recovery during CO2-EGR. A well-calibrated three-dimensional geological model is generated and validated using actual field data—achieving a robust alignment between history and simulation. We visualize the spread of the CO2 plume and quantitatively evaluate the dynamic productivity to the single gas well. We use three deep learning algorithms to predict the time histories of CO2 rate and CH4 recovery and provide feedback on production wells across various injection systems. The results indicate that CO2 injection can enhance CH4 recovery in water-bearing gas reservoirs—CH4 recovery increases with injection rate escalating. Specifically, the increased injection rate diminishes CO2 breakthrough time while concurrently expanding the swept area. The increased injection rate reduces CO2 breakthrough time and increases the swept area. Deep learning algorithms exhibit superior predictive performance, with the gated recurrent unit model being the most reliable and fastest among the three algorithms, particularly when accommodating injection and production time series, as evidenced by its smallest values for evaluation metrics. This study provides an efficient method for predicting the dynamic productivity before and after CO2 injection, which exhibits a speedup that is 3–4 orders of magnitudes higher than traditional numerical simulation. Such models show promise in advancing the practical application of CO2-EGR technology in gas reservoir development.