Development Of Gas Reservoirs Research Articles

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.

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.

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.

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.

Pore-scale investigations of permeability of saturated porous media: Pore structure efficiency

Accurate estimation of permeability and the establishment of correlations with pore space properties have garnered attention due to the increasing demand for oil and gas reservoir development as well as geological carbon sequestration. However, prevailing theoretical and empirical models often rely on porosity and pore sizes as key pore space properties to predict permeability, overlooking the variability of pore structure. To delineate the intrinsic associations between permeability and pore space properties, a self-developed visualized experimental system with controllable pore space properties is used to measure permeability of porous media with varying porosity and particle arrangements. Various parameters, encompassing porosity, pore sizes (maximum pore diameter and pore throat diameter) and fractal parameters (pore fractal dimension, succolarity, and lacunarity) are extracted to quantify pore space properties, and further utilized to develop permeability models. Results demonstrate a positive correlation between permeability and porosity, maximum pore diameter, and average pore throat diameter. Additionally, particle arrangements yield pronounced anisotropy in permeability. Relying solely on porosity and pore sizes to portray pore space properties falls short of comprehensively characterizing permeability. Incorporating fractal characterization through metrics like succolarity and lacunarity emerges as a potent avenue for delineating heterogeneity and pore connectivity. This approach proves useful in characterizing the effect of pore structure variability on permeability. The established permeability model rooted in flow direction succolarity and normalized lacunarity aligns effectively with experimental data, capturing the essential physics of permeability variation.

Experimental study on critical sand production pressure gradient at different production stages of high temperature and high pressure tight sandstone gas reservoir

AbstractSand production is a common issue in sandstone gas reservoir development, severely impacting the productivity of sandstone gas wells. In order to thoroughly investigate the sand production characteristics of high‐temperature and high‐pressure tight sandstone gas reservoirs, this study focuses on six core samples from tight sandstone gas reservoirs(three samples with fractures), under reservoir conditions (185 MPa, 160°C), sand production experiments were conducted to thoroughly investigate the sand production patterns in sandstone reservoirs under the combined influence of different effective stresses and production pressure differentials. The results indicate: (1) under the simultaneous increase of effective pressure and production pressure differential, sand production near the wellbore (r = 0.1 m) becomes more likely in the reservoir; (2) in actual reservoirs without fractures near the wellbore (r = 0.1 m), sand production phenomena do not occur; (3) reservoirs with fractures near the wellbore (r = 0.1 m) are more prone to sand production, under an effective stress of 90 MPa, with specimens containing fractures exhibiting a 76.48% lower critical sand production pressure gradient compared to those without fractures; (4) when the pore fluid pressure is 95 MPa, the maximum gas production rate for Well X without sand production is 12.4 × 104 m3/d. The experimental results have guiding significance for the rational production of gas wells in this type of reservoir.

Study on the Interaction Propagation Mechanism of Inter-Cluster Fractures under Different Fracturing Sequences

Horizontal-well multi-cluster fracturing is one of the most important techniques for increasing the recovery rate in unconventional oil and gas reservoir development. However, under the influence of complex induced stress fields, the mechanism of interaction and propagation of fractures within each segment remains unclear. In this study, based on rock fracture criteria, combined with the boundary element displacement discontinuity method, a two-dimensional numerical simulation model of hydraulic fracturing crack propagation in a planar plane was established. Using this model, the interaction and propagation process of inter-cluster fractures under different fracturing sequences within horizontal well segments and the mechanism of induced stress field effects were analyzed. The influence mechanism of cluster spacing, fracture design length, and fracture internal pressure on the propagation morphology of inter-cluster fractures was also investigated. The research results indicate that, when using the alternating fracturing method, it is advisable to appropriately increase the cluster spacing to weaken the inhibitory effect of induced stress around the fractures created by prior fracturing on subsequent fracturing. Compared to the alternating fracturing method, the propagation morphology of fractures under the symmetrical fracturing method is more complex. At smaller cluster spacing, fractures created by prior fracturing are more susceptible to being captured by fractures from subsequent fracturing. The findings of this study provide reliable theoretical support for the optimization design of fracturing sequences and fracturing processes in horizontal well segments.

Segmentation Study of Deep Shale Gas Horizontal Wells of the South Sichuan Shale Gas

Summary The low porosity and low permeability of shale gas reservoirs make fracturing technology an indispensable part of shale gas reservoir development. The initial stage of shale gas development is characterized by shallow direct wells, but with the advancement of drilling and completion technology in the development of unconventional oil and gas reservoirs, horizontal wells and fracturing technology have gradually become the key methods for the effective development of oil and gas reservoirs. “Geology-engineering integration” has gradually become a hot spot in the research of horizontal well fracturing. The factors affecting the development of shale gas reservoirs are subdivided into “geological sweet spot” and “engineering sweet spot” influencing factors. Geological sweet spot refers to the area where the reservoir is rich in hydrocarbons or organic matter; engineering sweet spot refers to the area with good fracturability in the later fracturing and reforming of the reservoir. The shale gas sweet spot area should have the characteristics of high gas content, high fracturable, and high efficiency. Comprehensively evaluating the physical properties and brittleness characteristics can provide certain guidance for shale gas horizontal well segmentation.

Tight carbonate reservoir evaluation case study based on neural network assisted fracture identification and analytic hierarchy process

Comprehensive evaluation of reservoirs is an important link in gas reservoir exploration and development. The evaluation of tight carbonate reservoirs often focuses on the characteristics of porosity and permeability, ignoring the important factor of fractures, also the quantitative evaluation of reservoirs is relatively few. It is difficult to identify fractures and evaluate the reservoir factors qualitatively and quantitatively. Herein, the sedimentary microfacies and microporosity of the tight carbonate reservoir of the Ma55 submember in the eastern Sulige area are comprehensively studied by casting thin section, rock physical property, and capillary pressure test data. The backpropagation (BP) neural network algorithm is used to identify and predict fractures. Finally, through the analytic hierarchy process, the above reservoir influencing factors are modeled and quantitatively analyzed for reservoir evaluation. The results show that the highest probability of fracture development in the central and northwest areas of the study area can reach 0.92. The accuracy of the BP neural network model in identifying cracks can reach 80%, which is reliable and effective compared with the conventional logging identification method. Reservoirs can be classified into four types according to their quality. The synthetic weights of porosity, permeability and fracture development probability are 0.2, 0.2 and 0.216 respectively, which are the three most important evaluation parameters. This study improves the accuracy of fracture identification and prediction of tight reservoirs in comprehensive reservoir evaluation, which provides guidance and scheme for more detailed exploration and development of tight carbonate reservoirs.

Study on the Phase Behavior Simulation Method of High-Salinity Reservoirs.

The presence of salinity affects the accuracy of existing correlations used in the equation of state. Moreover, the variation of salinity is often ignored in the systematic analysis of the phase diagram, resulting in a large error in the final calculation result. It is obvious that the conventional phase equilibrium calculation is not applicable in a high-salinity reservoir. By introducing the hydrocarbon-brine binary interaction coefficient and α-function, combined with the definition of salinity, and considering the variation of salinity under different pressure and temperature conditions, a more perfect phase equilibrium calculation model was established. The complete phase diagram was drawn, and the calculation results of salinity distribution are obtained. The effect of the mole percentage of water and salt content on the phase behavior was simulated. Finally, the phase distribution simulation is carried out based on the measured data. The phase state and salinity variation law of a high-salinity reservoir are obtained. According to the fluid composition of different periods, the real phase state of the high-salinity reservoir can be monitored in real time. It can provide a theoretical basis for the gas reservoir development and the dynamic evaluation of gas storage injection and production with a hydrocarbon-brine two-phase system.

Gas mass transfer characteristics in shales: Insights from multiple flow mechanisms, effective viscosity, and poromechanics

Accurate characterization of gas transport behavior is indispensable for successful shale gas reservoir development. In this study, a fractal-theory-based apparent permeability (AP) model is developed to better characterize real gas mass transfer in shales. The proposed model involves multi-scale organic matter (OM) and inorganic matter (IOM) flow channels and incorporates poromechanics-related dynamic pore size, multiple gas transport mechanisms, and dynamic viscosity. The discrete integration method (DIM) is employed to address viscosity changes during fractal scaling up. Experimental data, molecular dynamics simulations, and published theoretical models were used to verify the proposed model and reasonable agreements have been achieved. Results indicate that as the pore pressure and size increase, dominant mechanisms for gas transport change from surface diffusion at low pressure (lower than switch pressure) to viscous flow at higher pressure and larger pore sizes. Furthermore, higher organic matter content makes the permeability curve more similar to OM type. Ignoring effective viscosity results in underestimation of permeability, which is more noticeable when pressure rises and pore shrinks. Poromechanical properties primarily affect pore size, larger elastic modulus and smaller Poisson's ratio leads to significantly lower permeability. The real gas effect on AP reduction cannot be ignored, especially at high pressure. This work provides insights into the gas transport characteristics in shales, which have practical implications for shale gas reservoir simulation and development.

A three-dimensional numerical well-test model for pressure transient analysis in fractured horizontal wells with secondary fractures

During oil and gas reservoir development, multi-stage horizontal wells (MFHWs) and hydraulic fracturing techniques can effectively increase estimated ultimate recovery. However, there still lacks an understanding of the three-dimensional (3D) pressure transient behaviors of multi-stage fractured horizontal wells with secondary fractures. To narrow this gap, a three-dimensional numerical well-test model based on a discrete fracture model and unstructured tetrahedral grids is developed to study the pressure transient behaviors of MFHWs with secondary fractures. The pressure transient solutions of MFHWs with secondary fractures have been demonstrated by model verifications. The results show that the proposed model can accurately capture the complex transient flow around fractures, including early radial flow that is not easily captured by two-dimensional numerical well test models. The proposed model classifies the flow regimes of a MFHW as: wellbore storage and skin effects, early radial flow, bilinear flow, linear flow, elliptical flow, pseudo radial flow, and pseudo-boundary dominated flow. It is found that the fracture geometry has a relatively large effect on the shape of the pressure derivative curve in this work. The hydraulic fracture half-length has the greatest impact on the pressure transient behaviors of the MFHW, followed by fracture height and secondary fracture half-length, as found in this study. Additionally, fracture parameters are evaluated, and actual well testing data are interpreted, taking into account the fracture height. This work is meaningful to understand the three-dimensional pressure transient behaviors of MFHWs with secondary fractures.

Study on Key Technologies of Geosteering for Shale Gas Horizontal Wells in the Complex Structural Area of Block H in Western Hubei-Eastern Chongqing.

Block H, located in western Hubei-eastern Chongqing, remains at a low exploration degree. Characterized by its complex structural attributes, the area presents adverse conditions such as a thin thickness of high-quality shale reservoir, rapid lateral formation occurrence, and poor stratigraphic correlation, challenging conventional geosteering methods. The primary shale gas reservoir in Block H corresponds to the Upper Permian Wujiaping Formation. To ensure that the shale gas horizontal wells in this block effectively penetrate high-quality gas reservoirs, this study delves into the geological characteristics of this stratigraphic unit, identifies principal challenges faced by current geosteering techniques, and introduces a tailored technical solution. This solution encompasses the application of real-time 3D geological modeling to track while drilling, identification of steering marker layers, optimization of steerable tools, and optimization of the steering trajectory while drilling. In the technology of optimization of the steering trajectory while drilling, a trajectory control calculation model based on the average angle technique was established for the first time. Additionally, a sectional control chart for marker layers and well inclination under different deflecting constraints was established. These methods have solved the problems of large error in target prediction and poor trajectory control effects by using the equal thickness method alone. The findings from this study can significantly enhance target prediction and trajectory control accuracy in complex structural areas, offering pivotal insights for the proficient development of analogous shale gas reservoirs in the future.

Single-Well Simulation for Horizontal Wells in Fractured Gas Condensate Reservoirs.

Fractured gas condensate reservoirs (FGCR) are a complex, special, and highly valuable type of gas reservoir, accounting for a significant proportion of gas reservoir development. In recent years, with the continuous advancement of horizontal well technology, it has become the main approach for the development of FGCR. The current model is unable to accurately represent the fluid distribution in the near-well area of horizontal wells due to the unique retrograde condensation phenomenon in GCR. Additionally, the presence of fractures complicates the solution of traditional analytical models. In response to this issue, this paper proposes a novel semianalytical model for horizontal wells in FGCR, which incorporates natural fractures, multiphase flow, and the influence of stress sensitivity on pressure response. A dual-porosity model is employed to simulate fractured reservoirs, and a four-region radial composite model is developed to characterize multiphase flow resulting from retrograde condensation in GCR. The pseudopressure transform, Pedrosa transform, Laplace transform, and Finite Cosine transform are utilized to address the nonlinear partial differential equation. A systematic verification of the semianalytical solution is confirmed through a comparison with the numerical solution from computer modeling group (CMG). We thoroughly explain the physical significance of the various features by identifying the 12 flow regimes of the typical curve. Furthermore, we offer a method for assessing the extent of retrograde condensation and the size of the retrograde condensate region based on the curve's characteristics. Finally, the pressure measurements recorded from the Bohai field are carried out to validate the accuracy of the proposed model. The results show that the predictions of the new model are in good agreement with the actual production data, demonstrating the proposed solution's applicability.

Seismic geological characteristics and gas reservoir distribution of Changxing Formation biological bio-reef reservoir in the Longhuichang-Tieshan area, northeastern Sichuan Basin, China

This research aims to address the ambiguity surrounding the extent of development of Changxing Formation bio-reef reservoirs in the Longhuichang-Tieshan area of the northeastern Sichuan Basin, China, and to elucidate the relationship between these reservoirs and gas distribution. Utilizing drilling and logging data, this study provides a comprehensive summary of the seismic geological characteristics of bio-reef reservoirs. Furthermore, it investigates the effects of reservoir parameters, structural location, and strike-slip faults on the development of bio-reef gas reservoirs. The research shows that bio-reef reservoirs in the area predominantly manifest vertical development in the middle and upper parts of the Changxing Formation, with horizontal expansion occurring along the platform margin and local highland areas. Notably, potential exploration areas are identified, particularly the western wing of the Longhuichang structure and the southwestern side of the Tieshannan structure. By comparing and analyzing the relationship between bio-reef gas reservoirs in the study area, the study aims to clarify the controlling effects of reservoir parameters, structural location, strike-slip faults, and other pertinent factors on the development of bio-reef gas reservoirs. It is observed that while these factors do not exhibit a clear strong linear relationship, they have a comprehensive effect on the development of gas reservoirs. The enrichment mode and failure mode of favorable gas reservoirs in the study area have been analyzed and established, providing crucial technical support to facilitate further exploration of Changxing Formation bio-reef gas reservoirs in the northeastern Sichuan Basin.