Geological and Engineering Problems in the Development of Unconventional Oil and Gas Reservoirs

In order to avoid potential personnel and financial losses, the evaluation of pre-drilling safety is of great importance in oil and gas exploration and development. This paper presents a method of evaluating pre-drilling safety through combining the Analytic Hierarchy Process (AHP) with the Alternating Condition Expectation (ACE) method. An indicator system with a 9-3-1 structure was established, incorporating various unrestricted variables to describe the technical factor. Additionally, nine membership functions and weights were determined in order to build the AHP model by connecting the independent variables in the basic layer to dependent variables in the middle layer. Four transformed functions were also formulated to construct the ACE model by linking the middle variables to the pre-drilling safety value in the final layer. A total of 28 sets of on-site drilling data from three oilfields were collected for the establishment and verification of the AHP-ACE model. Average absolute error (AAE) and average absolute relative error (AARE) of the model to predict the training data are 0.03 and 4.29%, respectively, whereas the AAE and AARE for verification samples are 0.03 and 4.51%, respectively. The sensitivity ranking of the three potential variables is as follows: human factor exhibits the highest degree of sensitivity, followed by natural factor and technical factor, in descending order. The AHP-ACE model for pre-drilling safety assessment faces limitations in universal applicability and scope, particularly in real-time drilling activities. However, its potential for improvement lies in integrating insights from past operations and expanding the dataset to enhance accuracy and broaden safety assessment coverage. This method is not limited by blocks, which is of great significance to ensure drilling safety. Full article

The gas–water relative permeability curve plays a crucial role in reservoir simulation and development for condensate gas reservoirs. This paper conducted a series of high-temperature and high-pressure analysis experiments on real gas cores from Wells A and B in Block L of the Yinggehai Basin to investigate the effects of temperature, pressure, and different types of gas media on gas–water seepage. The gas–water relative permeability was simulated in this experiment through variations in temperature, pressure, and gas composition. Temperature has a significant impact on both gas and water relative permeability, particularly on gas relative permeability. As temperature increases, gas relative permeability shows a substantial increase, while water relative permeability remains relatively unchanged. Under the same effective stress, increasing pressure causes downward shifts in both the gas and water relative permeability curves; however, there is a more pronounced decrease in gas relative permeability. Gas composition has minimal influence on the gas–water relative permeability except at higher water saturation where differences become apparent. When water saturation ranges from 80% to 50%, there is no significant variation observed in the measured relative permeability of different displacement gases. However, as water saturation exceeds 80%, distinctions gradually emerge. The relative permeability of nitrogen is approximately 92% lower than that of mixed gas when the bound water saturation reaches 80%. This investigation provides valuable insights into the characteristics of gas–water relative permeability in high-temperature and high-pressure condensate reservoirs within Yinggehai Basin, thereby offering significant contributions to development strategies for similar reservoirs. Full article

During the development of condensate gas reservoirs, the phenomenon of retrograde condensation seriously affects the production of gas wells. The skin factor caused by retrograde condensation pollution is the key to measuring the consequent decrease in production. In this study, a multiphase flow model and a calculation model of retrograde condensate damage are first constructed through a dynamic simulation of the phase behavior characteristics in condensate gas reservoirs using the skin coefficient, and these models are then creatively coupled to quantitatively evaluate retrograde condensation pollution. The coupled model is solved using a numerical method, which is followed by an analysis of the effects of the selected formation and engineering parameters on the condensate saturation distribution and pollution skin coefficient. The model is verified using actual test data. The results of the curves show that gas–liquid two-phase permeability has an obvious effect on well production. When the phase permeability curve changes from the first to the third type, the skin coefficient increases from 3.36 to 26.6, and the condensate precipitation range also increases significantly. The distribution of the pollution skin coefficient also changes significantly as a result of variations in the formation and dew point pressures, well production, and formation permeability. The average error between the calculated skin of the model and the actual test skin is 3.87%, which meets the requirements for engineering calculations. These results have certain significance for guiding well test designs and the evaluation of condensate gas well productivity. Full article

Nano-elastic microspheres are particle-absorbent polymers that can be applied in plugging water. They plug pores and throats, reducing the damage from water invasion. The plug effect and flow mechanism of nano-elastic microspheres during water invasion were investigated in this paper through laboratory experiments. The results of the plugging experiments show that the nano-elastic microspheres had a higher plugging rate and formed physical plugs in the aquiferous region, thus preventing water invasion. Online nuclear magnetic resonance experiments indicated that the nano-elastic microspheres migrated from large pores to smaller ones during the flow process, forming elastic plugs in the porous media. The nano-elastic microspheres expanded in the aquiferous layer, increasing the flow resistance through both physical and elastic plugging, thereby reducing the water cut. Nano-elastic microspheres employed physical plugging to prevent water invasion and exhibited elastic flow in the porous media during the invasion. Full article

Global tight-oil reserves are abundant, but the depletion development of numerous tight-oil reservoirs remains unsatisfactory. CO₂ injection development represents a significant method of reservoir production, potentially facilitating enhanced oil recovery (EOR) alongside CO₂ storage. Currently, limited research exists on advanced CO₂ injection and well pattern adjustment aimed at improving the oil recovery and CO₂ storage within tight-oil reservoirs. This paper focuses on the examination of tight oil within the Ordos Basin. Through the employment of slim-tube experiments, long-core displacement experiments, and reservoir numerical simulations, the near-miscible pressure range and minimum miscible pressure (MMP) for the target block were ascertained. The viability of EOR and CO₂ sequestration via advanced CO₂ injection was elucidated, establishing well pattern adjustment methodologies to ameliorate CO₂ storage and enhance oil recovery. Simultaneously, the impacts of the injection volume and bottom-hole pressure on the development of advanced CO₂ injection were explored in further detail. The experimental results indicate that the near-miscible pressure range of the CO₂–crude oil in the study area is from 15.33 to 18.47 MPa, with an MMP of 18.47 MPa, achievable under reservoir pressure conditions. Compared to continuous CO₂ injection, advanced CO₂ injection can more effectively facilitate EOR and achieve CO₂ sequestration, with the recovery and CO₂ sequestration rates increasing by 4.83% and 2.29%, respectively. Through numerical simulation, the optimal injection volume for advanced CO₂ injection was determined to be 0.04 PV, and the most favorable bottom-hole flowing pressure was identified as 10 MPa. By transitioning from a square well pattern to either a five-point well pattern or a row well pattern, the CO₂ storage ratio significantly improved, and the gas–oil ratio of the production wells also decreased. Well pattern adjustment effectively supplements the formation energy, extends the stable production lives of production wells, and increases both the sweep efficiency and oil recovery. This study provides theoretical support and serves as a reference for CO₂ injection development in tight-oil reservoirs. Full article

In recent years, oil and gas field surface engineering construction projects tend to be large in scale, large in quantity, and short in cycle. The task of surface construction management has increased significantly. In the process of project construction, corresponding standards and specifications are required to provide sufficient technical guidance and support for design, construction, and management personnel to ensure project management and control towards compliance, safety, and quality. However, the oil and gas field engineering standards are numerous and specialized, involving different levels of national standards, enterprise standards, and industry standards, which leads to the inefficiency of the actual use of standards and specifications. To solve them, this paper uses knowledge graph technology, OCR recognition, and natural language processing technology to conduct systematic research on the knowledge classification mechanism, data extraction, database construction mechanism, data structuring, and intelligent retrieval matching of oil-gas field surface engineering construction standards. In this study, the structured identification, storage, and information warehousing of standards are realized, and a highly sharable library of standards and specifications is formed, which realizes the intelligent retrieval and pushing of technical standards for surface engineering construction. This paper creates conditions for the realization of intelligent push and benchmarking management of standards and specifications, providing support for digital transformation and intelligent development of oil–gas fields. Full article

High-temperature treatment significantly impacts the permeability of mudstone. The permeability of mudstone after exposure to high temperatures is closely influenced by the temperature it experiences and the stress state it is subjected to. This study examines the change in macroscopic physico-mechanical properties of mudstone with temperature following high-temperature treatment. Additionally, we conducted experimental research on the gas and water seepage behavior of mudstone specimens from the top of the coal seam of Taiyuan Group–Shanxi Group in the Ordos Basin. The coal-rock mechanics-permeability test system TAWD-2000 was employed for this purpose. Subsequently, we analyzed the evolution of mudstone permeability after high-temperature treatment with consideration to temperature, axial pressure, and other influencing factors. The findings reveal that gas permeability of mudstone gradually increases with increasing temperature, while water permeability initially decreases and subsequently increases. Furthermore, both gas and water permeability of mudstone exhibit a trend of decreasing and then increasing with rising stress levels after undergoing the same high-temperature treatment. We constructed a quadratic mathematical model with a goodness of fit of 99.4% and 89.2% to describe the relationship between temperature–stress coupling and mudstone gas and water permeability. This model underscores the significance of temperature–stress coupling on mudstone permeability and provides valuable guidance for numerically calculating the gas–water transport law of peripheral rock in the underground coal gasification process and its practical application in engineering. Full article

The oil and gas phase behavior of high temperature is complex and changeable, which is usually obtained by PVT experiments. The accuracy of the experiment data plays a crucial role in the reserve evaluation and development plan of oil and gas reservoirs. However, the current PVT experiment consistency checks are not suitable for high-temperature reservoir conditions. This paper proposes a systematic check method for the PVT experiment data consistency at high temperature. These checks revise the material balance method, Hoffman method, and equilibrium constant method by using the equilibrium constant calculation method at high temperature. The consistency check of component data and constant volume depletion experiment data is carried out by combining the three improved methods with the component check method, so as to judge the experiment data accurately. In this paper, two high-temperature reservoir fluids—gas condensate sample fluid X and volatile oil sample fluid Y—are selected to carry out consistency checks with component data and constant volume depletion data. This check method is of great significance to study the phase behavior of formation oil and gas at high temperature, especially for volatile oil and gas condensate fluid. Full article

Transport and retention of multi-sized suspended granules are common phenomena in fracture media of oil, gas and geothermal reservoirs. It can lead to severe permeability damage and productivity decline, which has a significant impact on the efficient development of underground resources. However, the granule transport and retention behaviors remain not well understood and quantified. The novel stochastic model is proposed for the multi-sized suspended granule transport in naturally fractured reservoirs accounting for granule retention and fracture clogging kinetics. A percolation fracture network is proposed considering fracture connectivity evolution during suspended granule transport. Granule retention and fracture clogging dynamics equations are proposed to account for incomplete fracture clogging by retained granules. The microscale stochastic model is allowed for upscaling to predict the multi-sized granule transport behavior in naturally fractured reservoirs. The model solution exhibits preferential plugging of fractures with sizes equal to or below the granule size. Multi-sized suspended granule shows great advantages over mono-sized suspended granule in the control of permeability damage induced by granule retention and fracture clogging. The retained granule concentration and permeability damage rate decrease with fracture network connectivity improvement. The experimental investigation on size-exclusion suspended granule flow has been performed. The model-based prediction of the retained granule concentration and permeability variation history shows good agreement with the experimental data, which verifies the developed model. Full article

Production measurement plays a vital role in the daily management of unconventional oil wells. It enables reservoir managers to gain a comprehensive understanding of reservoir changes and facilitates dynamic analysis and scientific development plans for the unconventional oil field. This paper focuses on accurately measuring well production by tracking over 300 sucker rod pumps (SRPs) in an experimental area of an oil field. The study utilizes easily obtainable continuous electrical parameters and real-time well production as training parameters. Accurate identification of the top and bottom dead points of the power curve is crucial in converting the power curve into the SRP’s dynamometer card. To achieve this, FFT is employed to extract single-period data from multi-period data. Subsequently, the top and bottom dead points are identified. The SRP electric power curve and corresponding real-time production data are segregated into samples based on the stroke cycle time, resulting in 200,000 valid samples. Deep learning techniques are then applied to classify the production state of pumping wells. FFT and statistical feature extraction are performed on the electric curve, and deep learning is utilized with the production parameters as input vectors and the well fluid production as output results. Through extensive training, a big-data-based SRP production calculation model is established, and subsequently used to calculate the production of SRPs in the experimental area of northeastern China’s oil field. The model is validated against actual production data. For low-yield wells with a daily production less than 6 m${}^3$/d, the model error remains below 0.5 m${}^3$/d. Additionally, the relative error for high-yield wells surpassing 6 m${}^3$/d stays under 10%, meeting the expectations of managers. This big data production measurement model serves as a valuable tool for operators to optimize the production system and detect oil well faults. Particularly in a low oil price environment, this method helps managers reduce costs and improve efficiency. Full article

Focusing on the problem of drilling fluid loss circulation due to fractured granite formation in ultra-deepwater drilling in the research area, a novel self-degrading loss-circulation material is developed with polymer resin as the core material, according to the principles of loss-circulation prevention and reservoir and environmental protection. The relevant properties of the novel self-degrading loss-circulation material are evaluated by using tests or experiments. The pressure-bearing properties are evaluated by using a sealing capability test; the self-degrading properties are evaluated by using a self-degrading performance test; the pressure-bearing capability and reservoir protection properties are tested by measuring pressure sealing and gas permeability. The results of the tests and experiments show that the grinding rate of the loss-circulation material is less than 6% under 25 MPa, indicating that the novel loss-circulation material is of high compressive strength. The degradation process of the novel self-degrading loss-circulation material can be accelerated by increasing temperature and pH, and the degradation of the self-degradable polymer composite can be accomplished within 5 days under 95 °C and pH = 14. After self-degrading, the permeability recovery values of the highly permeable reservoir and the fractured reservoir are more than 96.9% and 99.15%, respectively, which indicates outstanding reservoir protection capability. Therefore, the novel self-degrading loss-circulation material has excellent temporary plugging and reservoir protection performance and can be used for plugging while drilling in ultra-deepwater drilling. Full article

The fractured granite reservoir is well developed in Yongle block, which leads to severe drilling fluid loss-circulation. To solve the technical problem of both plugging and reservoir protection, on the basis of comprehensive literature research and laboratory tests at home and abroad, a polymer with an appropriate molecular weight, an organic crosslinking agent and other auxiliary materials were screened. In addition, a kind of high-temperature resistant loss-circulation plugging gel, which could be formed by timing and self-degradation, was developed. The high-strength gel loss-circulation system can be established by the development of a dynamic covalent borate ester bond crosslinking agent, which can crosslink with polyvinyl alcohol and xanthan gum. This system is of formidable strength and can be used for loss-circulation control in a fractured formation. The dynamic covalent borate ester bond tends to break due to the peroxide glue breaker under low pH levels, which can accelerate the degradation of the plugging gel into small molecules. The degradable temporary plugging material can ensure high-performance sealing and self-degradation capabilities of the fractured granite reservoir. The laboratory results showed that the high-performance degradable gel system was of adjustable gelling time, high gelling strength and high sealing capability. Its pressure-bearing could reach 5.8 MPa under 110 °C with 3.5 mm width of fractured granite core. Before crosslinking, the system also boasted promising thixotropy and rheology. The gel breaking time of the system was short, which could be completely broken with 6.1 h in 6% peroxide solution with pH of 4. The gelation time was related to the type of crosslinking agent, the amount of crosslinking agent and temperature. With the increase of temperature, the gelation time of gel system decreased. With the increase of the amount of the agent, the gelation time of gel system decreased. The gelation time was 105 min when using a 1% dynamic covalent borate ester bond crosslinking agent at 80 °C; the gelation time was 72 min when using a 1% dynamic covalent borate ester bond crosslinking agent at 110 °C; the gelation time was 71 min when using a 2% dynamic covalent borate ester bond crosslinking agent at 80 °C; the gelation time was 65 min when using a 2% dynamic covalent borate ester bond crosslinking agent at 110 °C; the gelation time was 72 min when using a 1% chromium crosslinking agent at 80 °C; the gelation time was 63 min when using a 2% chromium crosslinking agent at 80 °C; and the gel system had good reservoir protection performance. The permeability recovery rate was introduced to evaluate reservoir protection performance. The permeability recovery rate of using the dynamic covalent borate ester bond crosslinking agent was superior to that of using the chromium crosslinking agent. Using the dynamic covalent borate ester bond crosslinking agent, when the fracture width was 1.6 mm, the temperature was 80 °C and the soaking time was 8 h, the permeability recovery rate was 90.32%; when the fracture width was 0.75 mm, the temperature was 80 °C and the soaking time was 8 h, the permeability recovery rate was 84.53%. Using the chromium crosslinking agent, when the fracture width was 1.6 mm, the temperature was 80 °C and the soaking time was 12 h, the permeability recovery rate was 59.58%; when the fracture width was 0.75 mm, the temperature was 80 °C and the soaking time was 12 h, the permeability recovery rate was 45.65%. The viscosity of the residual solution was low and was helpful for reservoir protection during loss-circulation control under the fractured granite reservoir condition. The novel degradable temporary plugging material can solve the loss-circulation problem of the ultra-deepwater fractured granite reservoir. In addition, the material can pave the way for the exploration and development of a vast amount of hydrocarbon resources in the South China Sea. Full article

Natural gas hydrate (NGH) is a kind of clean energy with great potential because of its huge reserves. There are several effective methods for exploiting hydrate sediments such as depressurization, thermal excitation, inhibitor injection and displacement, etc. Among these methods, the combined depressurization and heat injection method is considered a very promising method, which solves the problem of insufficient heat supply during the depressurization process. In this paper, the mechanism of combined depressurization and heat injection exploitation of NGH is analyzed, and the multiphase flow models of the injection well and production well are established, respectively, for the parallel horizontal NGH well production system with this combined method. The multiphase flow laws of fluids in a wellbore were obtained, and the factors affecting the temperature and pressure distributions in the wellbore were analyzed. The results of this study show that gas and water are produced simultaneously in the process of exploitation with this combined depressurization and heat injection method. The electric submersible pump has a great influence on the flow of the fluids in the wellbore, and there are sudden skips of the temperature and pressure at the pump position. Increasing the depth and working frequency of the pump will reduce the risk of continuous discharge of water from the annulus. Increasing the injection rate and injection temperature can both improve the effect of heat injection. This study provides theoretical guidance for the combined extraction with depressurization and heat injection method and production optimization of NGH. Full article

To study the microscopic pore characteristics of marine–continental transitional shale, we studied the Daning–Jixian block of the Shanxi Formation using low-pressure CO₂ adsorption (LP-CO₂A) and low-temperature N₂ adsorption (LT-N₂A) methods in conjunction with field emission scanning electron microscopy (FE-SEM), geochemistry, and mineral composition analysis in order to obtain pore structure characteristic parameters. The fractal dimension of the pores was calculated using the Frankel–Halsey–Hill (FHH) model, and the study also discusses the factors that influence the pore structure. The study found that the marine–continental transitional phase shale of the Shanxi Formation has clay mineral contents ranging from 36.24% to 65.21%. The total organic carbon (TOC) contents range from 0.64% to 9.70%. Additionally, the organic matter maturity is high. The FE-SEM and gas adsorption experiments revealed that the transitional shale of the Shanxi Formation possesses a diverse range of pore types with relatively large pore sizes. The dominant pore types are organic and intragranular pores, with pore morphologies predominantly appearing as slit and parallel plate structures. According to the experimental data on gas adsorption, the total SSA values range from 11.126 to 47.220 m²/g. The total PV values range from 0.014 to 0.056 cm³/g. Micropores make up a greater proportion of the total SSA, whereas mesoporous pores make up a greater proportion of the total PV. The distribution of shale pore fractal dimensions D₁ and D₂ (D₁ is 2.470 to 2.557; D₂ is 2.531 to 2.755), obtained through LT-N₂A data, is relatively concentrated. D1 and D2 have a positive correlation with the TOC content, clay mineral content, and BET-SSA, and D₁ and D₂ have a negative correlation with the quartz content. D₂ is positively correlated with the Langmuir volume, showing that D₂ can be used to evaluate the methane adsorption capacity. Full article

In the Ordos Basin, Chang 81, a Member of the Yanchang Formation, features the development of braided river thin-bedded tight sandstones. These sandstones constitute one of the main production layers of tight oil and gas in the Yanchang Formation within the basin. This study integrates data from core samples, drilling, and seismic information to identify braided river thin-bedded sandstones in the Chang 81 Member at Daijiaping, Ordos Basin, using a method of constrained correlation between seismic waveform and seismic facies. This approach aids in determining the sedimentary microfacies types and reservoir characteristics of thin-bedded tight sandstones. We establish a quantitative fitting formula for the width-to-thickness ratio of braided channel sand bodies to finely characterize sand body stacking patterns and spatial distribution of thin-bedded tight sandstones in braided channels. Braided delta plain deposits in the Chang 81 Member at Daijiaping mainly comprise four types of sedimentary microfacies: braided channels, crevasse channels, floodplains, and swamps. The thickness of the reservoir sand body of Chang 81 member is mainly concentrated between 5–25 m, with low porosity and permeability, making it a typical thin-bedded tight sandstone reservoir. A method of constrained correlation between seismic waveforms and seismic facies was employed to identify sand bodies of braided river thin-bedded sandstones in the Chang 81 Member, summarizing four sand body stacking patterns: longitudinal incision type, longitudinal separation type, lateral shifting type, and single channel type. Furthermore, a quantitative forecasting formula of width-to-thickness ratio was established for the river channel scale, providing accurate guidance for well deployment. Horizontal wells deployed from the sand body’s side towards its center in a river channel yield a production 1.8 times higher than that of horizontal wells deployed in the opposite direction. Thin-bedded tight sandstones in braided channels, characterized by flat-top and convex-bottom lenticular seismic facies, hold practical significance in guiding the deployment of horizontal well patterns for tight oil and enhancing oil and gas recovery. Full article

In order to explore the rules between gravity anomalies and oil-gas distribution characteristics in central and western Sichuan Basin, we divided the tectonic unit in central and western Sichuan basin on the base of the analysis of gravity anomaly characteristics, and studied the correlation between the oil–gas distribution and the local gravity anomaly in the study area. The results show that the variation in the range of the Bouguer gravity field in the interior of the basin is relatively small, and the southern part shows a clear gravity high zone, with gradual gravity gradient zones all around the basin periphery. The abnormal value of the residual gravity field in the basin is an obvious high–value gravity belt in the north and west, and the interior is arranged alternately with local high gravity and low gravity in the north–east direction. The tectonic units of the central and western Sichuan Basin can be divided into five regions, based on the characteristics of the Bouguer gravity field, namely, the Central Sichuan uplift zone, the West Sichuan depressional zone, the East Sichuan high steep zone, the South Sichuan low steep zone, and the North Sichuan low slow zone. Combined with geological data and Bouguer gravity anomaly processing results, the distribution of oil and gas fields in the central and western Sichuan Basin is certain correlated with the local gravity high zone and the transition zone between the local gravity high zone and the local gravity low zone. They are the major areas of oil and gas. Full article

The fracture-cavity combination structure between wells in fracture-cavity reservoirs is complex and changeable. Reliably identifying and quantitatively characterizing the fracture-cavity combination structure between wells has become an important prerequisite for flow channel adjustment in fracture-cavity reservoirs after water channeling and flooding. Aiming at the problems that it is difficult for the existing carving technology to characterize the flow characteristics of the injected fluid in the interwell fracture-cavity composite structure during the production process, and it is difficult for the existing interwell tracer proxy model to consider the specific fracture-cavity composite structure, this paper proposes a quantitative interpretation model for interwell tracers in fracture-cavity reservoirs with different architectures. Taking the Tahe fracture-cavity reservoir as the object, the matching relationship between the interwell fracture-cavity structure and the tracer curve was analyzed, and the tracer curve characteristics of five types of fracture-cavity structures were clarified. Considering the basic idea of tracing, a unified quantitative interpretation model of tracers under different fracture-cavity configurations based on branched flow channels and karst caves was deduced and established, and the input parameters required to apply the model, the parameters obtained directly by fitting, and further expandable calculated parameters were clarified. The interpretation model was used to fit, quantitatively interpret, and verify the reliability of the tracer curves of three wells in group TK411 of fracture-cavity unit S48 in the fourth area of Tahe Oilfield. The results show that the tracer curve fitting effect of each well was good, and the average relative error between the total flow rate explained by the tracer and the daily water production during the tracer monitoring period in the mine was only 3.02%, which effectively shows that the applicability and reliability of the quantitative interpretation model are established. The research results provide an effective way to apply tracer data in deep mining while improving the quantitative characterization ability of interwell tracer monitoring in fracture-cavity reservoirs. Full article

Oil and gas reservoirs in volcanic rocks are a particular type of unconventional reservoir and present unique challenges for exploration and production engineers. To help the oil industry understand volcanic reservoirs and solutions to complex development problems, we reviewed their key engineering technologies as well as their geological characteristics. The distinctive geological characteristics of volcanic hydrocarbon reservoirs are strong heterogeneity, low porosity and permeability, complex fracture systems, etc. The volcanic reservoir rock types in order of hydrocarbon abundance are basalt (38.5%), andesite (15.9%), volcaniclastic (12.1%), and rhyolite (11.5%). The porosity ranges from 0.1 to 70%, and permeability ranges from 0.0007 to 762 md. In some commercially developed volcanic reservoirs of China, the average porosity is 7.7–13%; the average permeability is 0.41–3.4 md. Engineers have applied a variety of adapted technologies to produce volcanic reservoir economically. Horizontal wells can increase production and reserves by 4–6 times those of vertical wells, and longer wells are preferred. Specialized hydraulic fracturing techniques are suggested, including small or mixed proppant size, second HF treatment after proppant slugging, high-viscosity frac fluid with high-temperature resistance, special fluid loss reducer, high pump pressure, Extreme Overbalance Perforating, limited-entry fracturing, matrix acidizing, etc. Water control measures include producing below critical rates, partial perforation or penetration, controlling hydraulic fracture height, using horizontal wells, implementing complete cementing job, etc. Well productivity evaluation should be conducted to understand well performance and appropriately allocate production rates among wells, using the modified AOF method and other productivity prediction models considering breakdown fracture gradient, gas slippage effect, non-Darcy effect, etc. Well sites need to be selected based on recognizing profitable lithologies, lithofacies, high porosity and permeability, relatively developed fracture systems, thick net pay zones, etc. The critical questions for the industry are how to enhance volcanic reservoir recovery with more efficient and economic hydraulic fracturing and water control techniques. This is one of the first papers systematically summarizing the engineering technologies and unique solutions to develop volcanic reservoirs. Further and more complete reviews can be carried out in the future, and more novel and effective techniques can be explored and tested in the field. Full article

Petroleum engineers need real-time understanding of the dynamic information of reservoirs and production in the development process, which is essential for the fine description of oil and gas reservoirs. Due to the non-invasive feature of electromagnetic waves, more and more oil and gas reservoirs have received attention to capture the development dynamics with electrical resistance tomography (ERT). By measuring the distribution of resistivity on the surface, the ERT can offer information on the subsurface media. The theory and foundation of the ERT technology are presented in this study in the context of monitoring oil and gas reservoir growth dynamics. The characteristics of ERT technology are analyzed, and the progress of ERT application in the development of monitoring dynamics in terms of residual oil distribution, detection of water-driven leading edge, and monitoring of fractures during hydraulic fracturing is reviewed, as well as the progress of ERT technology optimization, including forward and inverse algorithms. This review aims to promote further application of ERT in the field of reservoir dynamics monitoring because of its important engineering significance as well as its academic value in terms of improving production efficiency and reducing risk. Full article

The boost of shale gas production in the last decade has reformed worldwide energy structure. The macroscale modeling of shale gas production becomes particularly important as the economic development of such resources relies on the deployment of expensive hydraulic fracturing and the reasonable planning of well schedules. A flood of literature was therefore published focused on accurately and efficiently simulating the production performance of shale gas and better accounting for the various geological features or flow mechanisms that control shale gas transport. In this regard, this paper presents a holistic review of the macroscopic modeling of gas transport in shale. The review is carried out from three important points of view, which are the modeling of the gas flow mechanisms, the representation of multiscale transport, and solution techniques for the mathematical models. Firstly, the importance of gas storage and flow mechanisms in shale is discussed, and the various theoretical models used to characterize these effects in the continuum scale are introduced. Then, based on the intricate pore structure and various pore types of shale gas reservoirs, this review summarizes the multiple-porosity models in the literature to represent multiscale gas transport, and discusses the applicability of each model. Finally, the numerical and analytical/semi-analytical approaches used to solve the macroscopic mathematical model governing shale gas production are reviewed, with a focus on the treatment of the complex fracture network formed after multistage hydraulic fracturing. Full article