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To improve water solubility and salt tolerance of viscoelstic surfactants (VESs), modifying the spacer of Gemini VES was adopted and a novel Gemini VES nominated TC‐2OH, with tri‐cationic groups and double hydroxyls on the spacer, was developed. The basic surface activity properties of TC‐2OH and the molecular aggregate behavior stimulated by NaCl or NaSal were measured and analyzed to investigate the mechanism of viscoelastic fluid forming by TC‐2OH solution, and it proved that TC‐2OH is more sensitive to NaSal, compared with NaCl, due to the embedded structure of salicylate. The molecular structure of TC‐2OH imparts excellent solubility to itself, and with the assistance of ethanol, the dissolution time in water can be shortened to within 45 seconds. In addition, oscillation experiments, heat and shear resistant experiments, and drag reduction tests were conducted to study the advantage of NaSal for stimulating the formation of the slickwater compared with NaCl. The slickwater stimulated by NaSal indeed exhibit superior drag reduction and proppant carrying capacity. To effectively disassemble the wormlike micelles for gel breaking, ethylene glycol butyl ether performs better than the hydrocarbons because of its high polarity and water solubility. The gel breaking fluids of slickwater caused extremely low damage to the tight sandstone cores. The successful development of TC‐2OH enables instant preparation of slickwater and variable‐viscosity for fracturing in unconventional reservoirs, which also realizes convenient switching between the slickwater with different viscosity. [ABSTRACT FROM AUTHOR]

The work is devoted to solving the problem of correctly determining capillary pressure functions during mathematical modeling of oil displacement processes during flooding of productive formations. It is shown that the use of these functions, determined in laboratory conditions using traditional methods using capillarimeters and high-speed centrifuges, when modeling processes of oil displacement from low-permeability productive reservoirs can lead to significant errors. The work notes that when conducting laboratory studies in rock samples, there is no formation of residual oil in a stationary form, while in real conditions of displacement of oil by water from productive formations, residual oil is formed in the rock, and in low-permeability formations the residual oil saturation can reach 50% or more of the pore volume. To obtain capillary pressure curves that more reliably reflect the real processes in productive formations during their flooding, it is proposed that when preparing rock samples for laboratory research, it is proposed to provide for the process of preliminary formation of residual oil saturation in these samples. This will make it possible to more reliably simulate the processes of oil displacement during waterflooding of productive formations in real conditions, especially when developing low-permeability oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

Natural fractures play a significant role in oil and gas reservoirs. Accurate predictions of fracture parameters are vital in reservoir prediction and oil and gas development. The birefringent phenomenon of shear waves in fractured media makes shear wave splitting (SWS) analysis an important tool in formulating fracture predictions. The traditional SWS analysis method is based on an orthogonal assumption of fast and slow shear waves. However, in an orthotropic medium composed of a background vertical transversely isotropic medium and a set of vertical fractures, fast and slow shear waves are not necessarily orthogonal. This causes the traditional SWS analysis method to fail. To solve this problem, we proposed an SWS analysis algorithm with a non-orthogonal assumption of fast and slow shear waves in this study. First, we introduced a parameter (difference angle) to characterize the angle between slow shear waves and the normal polarization directions of the fast shear waves. Subsequently, based on the traditional two-parameter scanning algorithm, a parameter was added to facilitate three-parameter scanning. In addition, we derived an expression for the two-parameter scanning objective function using the non-orthogonal assumption. Two-parameter scanning can accurately extract fast and slow wave time delay data, but it cannot determine an accurate fast shear wave polarization direction. Therefore, we optimized the three-parameter scanning algorithm as follows: first, we used two-parameter scanning to obtain the fast and slow wave time delays and then performed further scanning to determine the polarization direction of the fast shear wave and difference angle. The optimization algorithm significantly improved the computational efficiency. Subsequently, we tested the accuracy of this method using synthetic single-trace and three-component vertical seismic profile data. We demonstrated the implementation process of the three-parameter scanning method using actual data, separated fast and slow shear waves, and predicted fracture parameters. The final fracture parameters were verified. [ABSTRACT FROM AUTHOR]

The lateral sealing of a fault plays a pivotal role in the efficacy of a fault trap and its degree of hydrocarbon filling. Nevertheless, the evaluation of this phenomenon remains a challenging task, with evaluation methods either unable to accurately reflect subsurface reality or obtaining the necessary parameters difficult. In light of these considerations, a porosity-based fault laterality evaluation method was proposed, with the F1 Fault of the Nanpu No. 5 structure in the Nanpu Sag serving as the research object. First, the relationship between porosity and the product of burial depth and shale content was established using measured porosity, burial depth, and shale content data of the surrounding rocks in the study area. Subsequently, the reservoir rock porosity was obtained by employing logging data or core samples or by calculating the reservoir rock shale content from natural gamma logging data. Concurrently, the shale content of fault rock was calculated using three-dimensional (3D) seismic data, mud logging data, and natural gamma logging data, thereby enabling its porosity to be determined. Finally, the porosity difference between the two was employed to assess the lateral closure of faults. The results indicate that the porosity difference is less than 0 at lines L1~L3 of the F1 Fault, which suggests that the fault is not laterally closed at this site. Conversely, the F1 Fault is laterally sealed at this location, as indicated by the porosity difference being greater than 0 at lines L4~L10. The findings of this evaluation were found to be in close alignment with the actual distribution of oil and water, indicating that the proposed method can accurately evaluate the lateral closure of faults with developed fault rocks and provide valuable guidance for the exploration of faulted oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

In this paper, firstly, the tectonic features, sedimentary features, reservoir formation features and oil and gas drainage system of the P5-QS2 well are systematically analyzed. Then, the main controlling factors of reservoir aggregation in this area with seismic data is studied to achieve the purpose of optimizing favorable targets. Finally, a new model of dense, thin sandstone reservoir aggregation with dual control of lithology and tectonics is proposed, and the potential zone of P5-QS2 well area is clarified. Results show that: (a) Tectonics and lithology are the main controlling factors for the formation of oil and gas reservoirs. (b) The QS 2 and QS 4 wells deployed at the high point of the P5-QS2 well zone are currently producing a cumulative total of more than 15 million cubic meters of gas. (c) The deployment of the MZ 15 well is expected to achieve an industrial oil flow rate of 100,000 tons per day, further realizing a new breakthrough in the exploration of the Jurassic Badawan Formation in the hinterland of the P5-QS2 well zone. [ABSTRACT FROM AUTHOR]

The development of oil and gas resources in low-permeability reservoirs is being paid more and more attention. Moreover, oil and gas resources in low-permeability reservoirs are affluent, and the water cut of the medium permeability layer is so high that the injection capacity has decreased significantly. Therefore, it is of great importance to address the issues of injectability and enhance oil recovery in low-permeability reservoirs. Given the existing conditions of low permeability and high water cut in Daqing Oilfield, the synthesis of an in situ emulsified associative polymer (ISEPAM) is the focus of the research. The polymer was prepared by micellar polymerization, ensuring a molecular weight of 5 × 106 Dalton. A series of experiments were conducted to investigate its dissolution filtration property, viscosifying, emulsification, anti-adsorption, conductivity, and oil displacement capacity. The experimental results show that ISEPAM has more significant properties than the polymeric surfactant (HB) used in Daqing Oilfield. The ISEPAM solution has significant filterability (filter factor is 1.1), viscosifying (38.66 mPa·s), emulsification (the water evolution rate of ISEPAM was only 4.4% for 60 min at 90% water cut), and good anti-adsorption property (after five adsorptions, still has a viscosity retention rate of 65%) in a specific concentration (1000 mg/L) and the field water in Daqing Oilfield (salinity is 4996.3 mg/L). The reason for this is due to the presence of dynamic reversible networks in the ISEPAM solution, and there are no cationic functional groups on the polymer chain. The conductivity of ISEPAM was tested using a homogeneous square core with 48.1 mD permeability, and the results show that the viscosity retention rate of the effluent can reach 90% and excellent injection property can be achieved. In the oil displacement test, ISEPAM presents excellent sweep efficiency and enhanced oil recovery by about 25% under 50 mD permeability. Under low permeability conditions, the ISEPAM exhibits better injectability and excellent oil displacement capacity. The related findings can provide an important idea and reference for the design and development of EOR polymers in the reservoirs with low permeability or high water cut. [ABSTRACT FROM AUTHOR]

Nowadays, there has been a recognition of the remarkable potential of nanofluids and microorganisms as eco-friendly agents for enhanced oil recovery. on the other hand, one of the unique strategies for boosting hydrocarbon recovery is altering the wettability of the rock surface of oil and gas reservoirs. Herein, a nanohybrid that combines graphene oxide (GO) and silica (SiO2) was synthesized using a low-temperature, facile, and eco-friendly approach (sol-gel). GO-SiO2 nanocomposite was characterized with the aid of XRD, SEM, and FTIR analyses. Afterward, Nanofluids with different concentrations (0.005, 0.01, 0.015, and 0.02 wt%) of GO-SiO2 nanocomposite at various ratios (1:1, 1:2, and 2:1) were prepared using a surfactant-free and pH-neutral approach with a salinity of 30,000 ppm. The results of the Zeta potential measurement reveal that the manufactured nanofluids have great stability and the ratio of 1:1 was the most effective ratio for improving the reservoir wettability change from oil-wet to water-wet. At a higher temperature of 80 °C compared to the ambient condition of 25 °C, a more significant change in wettability was observed (23° to 161°). At the optimal concentration of nanofluid (0.015 wt%), the contact angle increased from 23° (on a non-treated surface) to 161°. These findings suggest that GO-SiO2 has great potential as an affordable, flexible, and environmentally friendly natural nanofluid, particularly under harsh conditions for the EOR process. [ABSTRACT FROM AUTHOR]

Radial borehole fracturing is a production method that combines ultrashort radius radial boreholes with hydraulic fracturing, which is expected to effectively improve the drainage and transformation effect of tight oil and gas reservoirs. In view of the problem that radial boreholes cannot be fully fractured when high-pressure liquids are injected into them simultaneously, this paper proposes a new method of fracturing the radial boreholes step by step, and this method is verified by the laboratory fracturing experiments. It designed and processed wellbores with both internal and external pipes, conducted 24 sets of radial boreholes step-by-step experiments of double-layer radial boreholes, analyzed the reproducibility of the experimental results, and compared the results of fracturing radial boreholes simultaneously and fracturing radial boreholes step-by-step experiments. The results show that this method can fracture two sets of radial boreholes distributed in different vertical planes. The results demonstrate that this method is feasible and can solve the problem that not all the radial boreholes are fractured when fracturing fluids are simultaneously injected into them. Besides, the azimuth is the key factor affecting fracture geometries. When the azimuths are 0° and 30°, the fractures can cut through radial boreholes in different layers within the rock samples. If the radial boreholes with larger azimuths are fractured, it will generate higher breakdown pressures. Fracturing radial boreholes with smaller azimuths first and then radial boreholes with larger azimuths should be selected. This study provides a theoretical basis for the field application of radial borehole fracturing technology. Highlights: A new method of fracturing the radial boreholes step by step is proposed. The azimuth is the key factor affecting fracture geometries. If the radial boreholes with larger azimuths are fractured, it will generate higher breakdown pressures. [ABSTRACT FROM AUTHOR]

Fault-block gas reservoirs are dominated in the K Gas Field, Xihu Sag, East China Sea Shelf Basin. Research on the effectiveness of fault-block traps is lacking. A quantitative method for the evaluation on the effectiveness of fault-block traps has been developed in the study. Based on the core test, logging and geophysical data, detailed depiction and trap effectiveness research were conducted on the pools of the gas field. Anticline traps, lithological traps and mudstone-correspondent traps are effective traps with high probability of reservoir formation, while sandstone-correspondent traps are the least effective with 35% probability of effective traps. Twenty-one drilling wells in the K Gas Field show that when the fault displacement pressure is less than the reservoir displacement pressure, the trap is non-effective, which matches the result 92% of traps without oil and gas. On the contrary, the trap is effective, which matches the result 100% of gas reservoirs. The discrimination diagram of fault-block trap effectiveness can quickly identify trap effectiveness and contribute to fault-block oil and gas exploration in K Gas Field. The method has a wide application potential for the exploration of fault-block reservoirs in other areas. [ABSTRACT FROM AUTHOR]

Multi-stage fractured horizontal well technology is an effective development method for unconventional reservoirs; however, shale oil reservoirs with ultra-low permeability and micro/nanopore sizes are still not ideal for production and development. Injecting CO2 into the reservoir, after hydraulic fracturing, gas injection flooding often produces a gas channeling phenomenon, which affects the production of shale oil. In comparison, CO2 huff-n-puff development has become a superior method in the development of multi-stage fractured horizontal wells in shale reservoirs. CO2 huff and injection can not only improve shale oil recovery but also store the CO2 generated in industrial production in shale reservoirs, which can reduce greenhouse gas emissions to a certain extent and achieve carbon capture, utilization, and storage (CCUS). In this paper, the critical temperature and critical parameters of fluid in shale reservoirs are corrected by the critical point correction method in this paper, and the influence of reservoir pore radius on fluid phase behavior and shale oil production is analyzed. According to the shale reservoir applied in isolation to the actual state of the reservoir and under the condition of a complex network structure, we described the seepage characteristics of shale oil and gas and CO2 in the reservoir by embedding a discrete fracture technology structure and fracture network, and we established the numerical model of the CO2 huff-n-huff development of multi-stage fractured horizontal wells for shale oil. We used the actual production data of the field for historical fitting to verify the validity of the model. On this basis, CO2 huff-n-puff development under different gas injection rates, huff-n-puff cycles, soaking times, and other factors was simulated; cumulative oil production and CO2 storage were compared; and the influence of each factor on development and storage was analyzed, which provided theoretical basis and specific ideas for the optimization of oilfield development modes and the study of CO2 storage. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

The most crucial task of petroleum geology is to explore oil and gas reservoirs in the deep underground. As one of the analysis techniques in petroleum geological research, rock thin section identification method includes particle segmentation, which is one of the key steps. A conventional sandstone thin section image typically contains hundreds of mineral particles with blurred boundaries and complex microstructures inside the particles. Moreover, the complex lithology and low porosity of tight sandstone make traditional image segmentation methods unsuitable for solving the complex thin section segmentation problems. This paper combines petrology and image processing technologies. First, polarised sequence images are aligned, and then the images are transformed to the HSV colour space to extract pores. Second, particles are extracted according to their extinction characteristics. Last, a concavity and corner detection matching method is used to process the extracted particles, thereby completing the segmentation of sandstone thin section images. The experimental results show that our proposed method can more accurately fit the boundaries of mineral particles in sandstone images than existing image segmentation methods. Additionally, when applied in actual production scenarios, our method exhibits excellent performance, greatly improving thin section identification efficiency and significantly assisting experts in identification. [ABSTRACT FROM AUTHOR]

Fault-block gas reservoirs are dominated in the K Gas Field, Xihu Sag, East China Sea Shelf Basin. Research on the effectiveness of fault-block traps is lacking. A quantitative method for the evaluation on the effectiveness of fault-block traps has been developed in the study. Based on the core test, logging and geophysical data, detailed depiction and trap effectiveness research were conducted on the pools of the gas field. Anticline traps, lithological traps and mudstone-correspondent traps are effective traps with high probability of reservoir formation, while sandstone-correspondent traps are the least effective with 35% probability of effective traps. Twenty-one drilling wells in the K Gas Field show that when the fault displacement pressure is less than the reservoir displacement pressure, the trap is non-effective, which matches the result 92% of traps without oil and gas. On the contrary, the trap is effective, which matches the result 100% of gas reservoirs. The discrimination diagram of fault-block trap effectiveness can quickly identify trap effectiveness and contribute to fault-block oil and gas exploration in K Gas Field. The method has a wide application potential for the exploration of fault-block reservoirs in other areas. [ABSTRACT FROM AUTHOR]

Addressing the poor performance of existing logging saturation models in low-permeability tight sandstone reservoirs and the challenges in determining model parameters, this study investigates the pore structure and fluid occurrence state of such reservoirs through petrophysical experiments and digital rock visualization simulations. The aim is to uncover new insights into fluid occurrence state and electrical conduction properties and subsequently develop a low-permeability tight sandstone reservoir saturation model with easily determinable parameters. This model is suitable for practical oilfield exploration and development applications with high evaluation accuracy. The research findings reveal that such reservoirs comprise three types of formation water: strongly bound water, weakly bound water, and free water. These types are found in non-connected micropores, poorly connected mesopores where fluid flow occurs when the pressure differential exceeds the critical value, and well-connected macropores. Furthermore, the three types of formation water demonstrate variations in their electrical conduction contributions. By inversely solving rock electrical experiment data, it was determined that for a single sample, the overall cementation index is the highest, followed by the cementation index of pore throats containing strongly bound water, and the lowest for the pore throats with free water. Building on the aforementioned insights, this study develops a parallel electrical pore cementation index term, ϕm′, to account for the differences among the three types of water and introduces a parallel electrical saturation model suitable for logging evaluation of low-permeability tight oil and gas reservoirs. This model demonstrated positive application effects in the logging evaluation of low-permeability tight gas reservoirs in a specific basin in the Chinese offshore area, thereby confirming the advantages of its application. [ABSTRACT FROM AUTHOR]

As an unconventional oil and gas reservoir, helium gas reservoirs have gradually become a focus of attention. In recent years, with the continuous increase in demand for helium gas, the uneven distribution of global helium resources has attracted China's attention to helium resources. In this study, a method for predicting favorable areas of helium gas was proposed based on the natural gas exploration theory and the idea of "finding gas in enrichment areas". We conducted an in-depth study and analysis of the types of helium gas formations in China by comprehensively using geochemical and isotope-testing data, identifying the distribution of helium source rocks in China. Based on this, we conducted directed analyses of the transport channels and caprock conditions for helium gas, and summarized the enrichment modes of helium gas. Using this method, we predicted five favorable areas for the enrichment of helium gas in China, providing an important basis for the future exploration and development of helium resources in China. [ABSTRACT FROM AUTHOR]

Tight reservoirs characterized by complex physical properties pose significant challenges for extraction. CO2 flooding, as an EOR technique, offers both economic and environmental advantages. Accurate prediction of recovery rate plays a crucial role in the development of tight oil and gas reservoirs. But the recovery rate is influenced by a complex array of factors. Traditional methods are time-consuming and costly and cannot predict the recovery rate quickly and accurately, necessitating advanced multi-factor analysis-based prediction models. This study uses machine learning models to rapidly predict the recovery of CO2 flooding for tight oil reservoir development, establishes a numerical model for CO2 flooding for low-permeability tight reservoir development based on actual blocks, studies the effects of reservoir parameters, horizontal well parameters, and injection-production parameters on CO2 flooding recovery rate, and constructs a prediction model based on machine learning for the recovery. Using simulated datasets, three models, random forest (RF), extreme gradient boosting (XGBoost), and light gradient boosting machine (LightGBM), were trained and tested for accuracy evaluation. Different levels of noise were added to the dataset and denoised, and the effects of data noise and denoising techniques on oil recovery factor prediction were studied. The results showed that the LightGBM model was superior to other models, with R2 values of 0.995, 0.961, 0.921, and 0.877 for predicting EOR for the original dataset, 5% noise dataset, 10% noise dataset, and 15% noise dataset, respectively. Finally, based on the optimized model, the key control factors for CO2 flooding for tight oil reservoirs to enhance oil recovery were analyzed. The novelty of this study is the development of a machine-learning-based method that can provide accurate and cost-effective ORF predictions for CO2 flooding for tight oil reservoir development, optimize the development process in a timely manner, significantly reduce the required costs, and make it a more feasible carbon utilization and EOR strategy. [ABSTRACT FROM AUTHOR]

This study conducted water-induced fracture experiments and full-diameter core displacement experiments on the cores of a certain oil reservoir in the Ordos Basin, aiming to investigate the impact of these induced fractures of different sizes on displacement efficiency and the distribution of remaining oil, and to perform quantitative analysis. The experimental results indicate that the oil displacement efficiency of the core is related to the depth, angle, and complexity of full-diameter core fractures. [ABSTRACT FROM AUTHOR]

Reservoir stimulation using hydraulic fracturing technology is one of the most common stimulation measures to develop tight oil and gas reservoirs, and the conductivity of fractures after fracturing is the key to the stimulation effect of oil fields. In this paper, the laboratory simulation system of fracture conductivity is used to study the long‐term fracture conductivity under the displacement of formation water and fracturing fluid. The experimental results show that the fracture conductivity decreases with the increase of displacement time under the displacement of formation water and fracturing fluid, and the decrease of fracture conductivity under the displacement of fracturing fluid with time is greater than that of formation water displacement because of the plugging effect of fracturing fluid residue on pore channels. The use of formation water and fracturing fluid circulation displacement can delay the decline rate of conductivity with time. The conductivity increases with the increase of sand concentration, proppant particle size, and elastic modulus, and decreases with the increase of closure pressure. In addition, by studying the influence of elastic modulus on fracture width, it is found that the smaller the elastic modulus is, the more serious the embedding phenomenon of proppant is, and the smaller the fracture width is. [ABSTRACT FROM AUTHOR]

Recently, there has been a growing interest in utilizing depleted gas and oil reservoirs for carbon capture and storage. This interest arises from the fact that numerous reservoirs have either been depleted or necessitate enhanced oil and gas recovery (EOR/EGR). The sequestration of CO2 in subsurface repositories emerges as a highly effective approach for achieving carbon neutrality. This process serves a dual purpose by facilitating EOR/EGR, thereby aiding in the retrieval of residual oil and gas, and concurrently ensuring the secure and permanent storage of CO2 without the risk of leakage. Injectivity is defined as the fluid's ability to be introduced into the reservoir without causing rock fracturing. This research aimed to fill the gap in carbon capture and storage (CCS) literature by examining the limited consideration of injectivity, specifically in depleted underground reservoirs. It reviewed critical factors that impact the injectivity of CO2 and also some field case data in such reservoirs. [ABSTRACT FROM AUTHOR]

Underground Hydrogen Storage (UHS), especially in depleted oil and gas reservoirs is becoming increasingly attractive as a solution to H 2 large-scale seasonal storage but there are several concerns regarding the repurposing of existing structures due to hydrogen detrimental effects on materials. This article aims to provide insight into the wellbore integrity challenges associated with UHS in depleted reservoirs. It briefly discusses past and current experiences of UHS. To identify knowledge gaps and technical barriers, an overview of wellbore integrity issues that could be encountered during UHS projects in depleted oil and gas reservoirs is presented. Since wellbore integrity issues lead to fluid migration, published work on leakage rate estimation and risk evaluation in storage projects are also discussed. Field wellbore integrity evaluation methods and analytical models are discussed as well as current potential site criteria for the UHS selection site. Based on the review, leakage through the injection and legacy wells are primary concerns on UHS projects. Wellbore integrity can be affected by hydrogen damage, microbial-induced corrosion and corrosion processes on metallic materials, cement degradation due to hydrogen and corrosive agents exposure, and the severe conditions to which the materials are exposed through the wellbore life. In addition, the existence of legacy wells in poor conditions represents a risk to the safety of UHS projects. Future works were recommended to better comprehend hydrogen damage processes, hydrogen interaction with casing, cement, and subsurface microbiological processes, and to establish multi-criteria selection methods for potential sites. • Field experiences with underground hydrogen storage in porous media are presented. • Hydrogen damage mechanisms in steel and the effect of corrosive agents are discussed. • Overview of cement and packer integrity issues in the UHS context. • The importance of legacy wells in UHS projects is discussed and highlighted. • Recommendations for future research work on wellbore integrity in UHS are specified. [ABSTRACT FROM AUTHOR]

In view of the short effective period of conventional foam for water shutoff during oil and gas reservoir development, a strong stability gel foam system is proposed in this work. By comparing the foam properties of different foaming systems, the optimized formulation of foam system is "0.3% SDS (sodium dodecyl sulfate) + 0.4% HPAM (partially hydrolyzed polyacrylamide) + 0.3% SD-107 (organic chromium)." At 50 °C and 10 000 mg/l salinities, the volume of foam is basically unchanged after a short time of defoaming and finally remains above 70%, and the drainage half-life can reach 16 days. The polymer and crosslinker form a stable three-dimensional network structure on the Plateau boundary after foaming, which has good viscosity and viscoelasticity. The foam system has excellent temperature and salt resistance. It is appropriate for medium and low temperature shallow reservoirs. The foam system has a good plugging efficiency. It can effectively plug the fracture and improve the sweep volume, which has a good application prospect. [ABSTRACT FROM AUTHOR]

The distribution characteristics and main controlling factors of hydrocarbon phases in deep strata from petroliferous basins are important for the evaluation of oil–gas resources and decision-making regarding exploration. The distribution characteristics and controlling factors of the Ordovician hydrocarbon phases are systematically analyzed in the Tazhong I block, Tarim Basin, NW China. The results show that the Ordovician reservoirs in the Tazhong I block are characterized as multi-phase reservoirs with a lateral co-existence of condensates, normal oil reservoirs, and heavy oil reservoirs. From east to west, gas-rich in the fault belt and oil-rich in the platform area are presented. Meanwhile, there are regular variations in the geochemical characteristics of the Ordovician hydrocarbon, showing decreasing trends in the gas/oil ratio (GOR), wax contents, dryness coefficients, methane contents, and methane carbonate isotope values (δ13C1) and an increasing trend in oil densities. Because the same Cambrian–Lower Ordovician source for the Ordovician hydrocarbon is observed in the Tazhong I block, the regular variations in the hydrocarbon phases and geochemical characteristics can be interpreted as records of gas invasion, biodegradation, multi-stage filling, thermal cracking, and thermochemical sulfate reduction (TSR) rather than controlled by the source rock organofacies. This indicated that different kinds of secondary processes for a diversity of the hydrocarbon phase can appear in one region. Our re-construction of the Ordovician hydrocarbon accumulation model in the Tazhong I block encourages future exploration to target gas reservoirs in the fault belt and oil reservoirs in the platform area. [ABSTRACT FROM AUTHOR]

Reservoir reconstruction, where parameter prediction plays a key role, constitutes an extremely important part in oil and gas reservoir exploration. With the mature development of artificial intelligence, parameter prediction methods are gradually shifting from previous petrophysical models to deep learning models, which bring about obvious improvements in terms of accuracy and efficiency. However, it is difficult to achieve large amount of data acquisition required for deep learning due to the cost of detection, technical difficulties, and the limitations of complex geological parameters. To address the data shortage problem, a transfer learning prediction model based on long short-term memory neural networks has been proposed, and the model structure has been determined by parameter search and optimization methods in this paper. The proposed approach transfers knowledge from historical data to enhance new well prediction by sharing some parameters in the neural network structure. Moreover, the practicality and effectiveness of this method was tested by comparison based on two block datasets. The results showed that this method could significantly improve the prediction accuracy of the reservoir parameters in the event of data shortage. [ABSTRACT FROM AUTHOR]

As unconventional oil and gas receive more and more attention, scholars pay more and more attention to waterless fracturing technology. Among them, carbon dioxide fracturing technology, as the main representative of waterless fracturing technology, has unique advantages and broad application prospects in the development of unconventional oil and gas reservoirs. However, when using carbon dioxide fracturing fluid for construction, carbon dioxide is greatly affected by temperature and pressure, so it is necessary to simulate the temperature and pressure in the wellbore during carbon dioxide fracturing construction. In this article, the basic physical properties of carbon dioxide under different temperatures and pressures are analyzed, and the changes of wellbore temperature and pressure during carbon dioxide fracturing are studied based on the generalized heat conduction theory. The results show that the faster the injection rate of CO2 fracturing fluid at the wellhead, the lower the bottom hole temperature and the higher the bottom hole pressure. However, the higher the wellhead injection temperature, the higher the bottom hole temperature, and the lower the bottom hole pressure. [ABSTRACT FROM AUTHOR]

The horizontal fractures in the strata will close in the compaction effect of overlying strata, while the vertical cracks are widely developed, which can be equivalent to HTI (transverse isotropy with a horizontal axis of symmetry) medium. When an S-wave propagates into HTI media, the shear wave will divide into two types of waves: a fast S-wave and slow S-wave. When the strata of HTI are thin and overlapping, called the thin interbeds model, the wave field exhibits complex primary reflections, converted waves, and multiples. We introduce a new second-order approximation of the total reflection coefficient, with the incidence angle lower than the critical angle in thin-interbed HTI media using a recursive algorithm. We verify the effectiveness of the second-order approximation by analyzing the energy of multiples. Comparing the second-order approximate solution that degenerates the HTI medium into isotropic and Kennett's exact solution, we find that our solution has an accuracy of over 99.9% in any azimuth, with the incidence angle lower than the critical angle under P-wave incidence. However, our solution of the SP wave field is suitable for incidence azimuth angles between 0–75° and 120–180°, with the lowest accuracy occurring at an incidence angle of 25° and a relative error of 6.4%. The approximate solution in the SS wave field has the same applicable range as the SP wave, with the maximum error of 6.3% occurring at the incident angle of 1°. This new second-order approximate formula for the total reflection coefficient of thin interbeds composed of HTI helps us to understand the reflection characteristics of complex thin interbeds. It also lays a theoretical foundation for the development of AVO (Amplitude Versus Offset) analysis and inversion techniques for lithological and stratigraphic oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

With the continuous growth in global energy demand, research and development of unconventional oil and gas reservoirs have become crucial in the field of energy. This study focuses on the Chang 3 reservoir of the Yanchang Formation in the Ordos Basin, Weibei Oilfield, China. This reservoir is a typical tight sandstone reservoir, and its microscopic pore structure and displacement mechanism are essential for the efficient development of tight oil. However, the reservoir faces challenges such as complex microscopic pore structures and unclear displacement mechanisms, which hinder the efficient development of tight oil. In light of these challenges, through various studies including core observation, high-pressure mercury injection tests, water flooding experiments, oil-water two-phase relative permeability measurements, and stress sensitivity experiments, it was found that the Chang 3 reservoir exhibits strong microscopic heterogeneity. The pore-throat distribution characteristics mainly present two types: single peak and double peak, with the double peak type being predominant. The reservoir was classified and evaluated based on these characteristics. The improved injection ratio and properties enhance oil displacement efficiency, but an increase in irreducible water saturation has a negative impact on efficiency. The stress sensitivity of the reservoir fluctuates between weak and strong, with permeability being sensitive to net confining pressure. It is recommended to pay particular attention to the stress-sensitivity characteristics during reservoir development. The research results provide a scientific basis for the optimized development of tight oil reservoirs in this region, promote the sustainable development of unconventional oil and gas resources, and have significant theoretical and practical implications. [ABSTRACT FROM AUTHOR]

The formation, storage and seepage characteristics of shale gas reservoirs are significantly different from those of conventional oil and gas reservoirs, and their in-depth study is extremely important for improving energy security and promoting sustainable development. In this paper, based on the nonlinear seepage theory of shale gas reservoirs and the capacity analysis of test wells, a steady state capacity model integrating the apparent permeability model and the multi-scale transport mechanism is constructed to investigate the influence of various factors on the apparent permeability and the capacity of shale gas fractured horizontal wells, as well as to predict the production of shale gas wells. It is found that: apparent permeability is significantly affected by pore radius, and the non-Darcy effect is particularly significant under low-pressure and small-scale pore conditions; when the reservoir pressure is lower than 15 MPa, the sensitivity of apparent permeability to temperature and Langmuir volume increases, but decreases with the increase of Langmuir pressure; and the production capacity analysis of shale gas reservoirs shows that the production rates of fractured wells that consider the multiscale transport mechanism are generally higher than those considering Darcy flow only, especially in the case of low wellbore pressure and large pore radius; the effects of Langmuir volume and pressure on the production capacity are relatively small, and mainly noticeable in the range of wellbore flow pressure from 1 MPa to 15 MPa. The number of fracture bars has a significant effect on production, but too many fractures can lead to gap interference, which slows down production growth. The results of this research provide theoretical support for the scientific development of shale gas reservoirs and have important research and application value for the efficient and rational development of actual well sites. [ABSTRACT FROM AUTHOR]

The study of fluid inclusions in petroliferous basins is an effective method to understand hydrocarbon migration and accumulation. In this paper, the fluid inclusions in the Ordovician carbonate rock samples taken from the TS3, TP18, YQ8 and YJ2-3 wells in Tahe Oilfield are analyzed by experiments, the purpose is to explore the accumulation period of the Ordovician oil and gas reservoirs in the Tahe area and the reasons for the differences between different blocks.The results show that the Ordovician Yingshan Formation and the Yifangfang Formation in the Tahe area are rich in fluid inclusions, and there are only a single phase of oil, gas and brine in the phase. There are also two phases of oil, gas and water mixed with each other. According to the fluorescence characteristics and homogenization temperature of hydrocarbon inclusions, combined with the burial history-thermal evolution history of the study area, it is determined that the Tahe oil and gas reservoir is filled in the fourth stage, in the middle of the Caledonian period (454-446 Ma), and in the late Hercynian-Indosinian period (255-217 Ma), late Yanshanian period(143-99 Ma), Himalayan period (25-5 Ma).Among them, the middle of Caledon is mainly filled with low-mature oil, with a small amount of mature oil; the late high-mature oil in the late Hercynian is filled with some mature oil; the late Yanshan is mainly filled with high mature oil; during the Himalayan period, as the depth of burial continues to increase, the cracking of the accumulated hydrocarbons has occurred, mainly the migration of gas hydrocarbons. The four wells selected in this study belong to different tectonic units, after analysis, the author believes that the difference between single wells is on the one hand the influence of hydrocarbon thermal evolution and the other is influenced by tectonic movement. [ABSTRACT FROM AUTHOR]

The transient electromagnetic method (TEM) is widely used in the exploration of mineral, petroleum, and geothermal resources due to its sensitivity to low-resistivity bodies, limited site constraints, and strong resistance to interference. In practical applications, the TEM often uses a long wire source instead of an idealized horizontal electric dipole (HED) source as the excitation source. This is due to the complex external conditions and the relatively large distance between the receiving zone and the transmitter source. Compared to the HED, the long wire source can provide a larger excitation current, generating stronger signals to meet the requirements of a higher signal-to-noise ratio or deeper exploration. It also produces longer-duration signals, thereby providing better resolution. Additionally, for the interpretation of TEM data, three-dimensional forward modeling plays a crucial role. However, the mature traditional TEM forward method is based on a simple, sometimes inappropriate model, as it is well established that the induced polarization (IP) effect is widely present in the deep earth, especially in oil and gas reservoirs. The presence of the IP effect results in negative responses in field data that do not conform to the traditional theoretical decay law of TEM, which can significantly impact data processing and inversion results. To address this issue, a TEM forward modeling method considering the IP effect based on the spectral element method (SEM) has been developed in this study. Firstly, starting from the Helmholtz equation satisfied by the time domain electric field, we introduce the Debye model with polarization information into the forward modeling by utilizing the differential form of Ohm's law. As a result, we derive the boundary value problem for the time domain electric field that considers the induced polarization effect. Using Gauss–Lobatto–Legendre (GLL) polynomials as the basis functions, the SEM is employed to discretize the governing equations at each time step and obtain spectral element discretization equations. Then, temporal discretization equations are derived using the second-order backward Euler formula, and the linear system of equations is solved using the Pardiso direct solver. Finally, the electromagnetic responses at any time channel are obtained via SEM interpolation and numerical integration, thereby achieving three-dimensional TEM forward modeling considering the IP effect. The results indicate that this method can effectively reflect the spatial distribution of polarizable subsurface media. It provides valuable references for studying the polarization parameters of subsurface media and performing a three-dimensional inversion of TEM data considering the induced polarization effect. [ABSTRACT FROM AUTHOR]

The goals of carbon neutrality and peak carbon have officially been proposed; consequently, carbon dioxide utilization and sequestration technology are now in the limelight. Injecting carbon dioxide into reservoirs and solidifying and sequestering it in the form of carbonates after a series of geochemical reactions not only reduces carbon emissions but also prevents carbon dioxide from leaking out of the formation. Carbon dioxide mineralization sequestration, which has good stability, has been considered the best choice for large-scale underground CO2 sequestration. To provide a comprehensive exploration of the research and prospective advancements in CO2 mineralization sequestration within Chinese oil and gas reservoirs, this paper undertakes a thorough review of the mechanisms involved in CO2 mineralization and sequestration. Special attention is given to the advancing front of carbon dioxide mineralization, which is driven by microbial metabolic activities and the presence of carbonic anhydrase within oil and gas reservoirs. The paper presents an in-depth analysis of the catalytic mechanisms, site locations, and structural attributes of carbonic anhydrase that are crucial to the mineralization processes of carbon dioxide. Particular emphasis is placed on delineating the pivotal role of this enzyme in the catalysis of carbon dioxide hydration and the promotion of carbonate mineralization and, ultimately, in the facilitation of efficient, stable sequestration. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is widely recognized as a potential stimulation technology for the development of challenging natural gas hydrate. However, the fracturing behavior of non-diagenetic hydrate reservoirs has peculiar characteristics that are different from those of conventional oil and gas reservoirs. Herein, a fully coupled fluid-mechanical model for simulating hydraulic fracturing in hydrate-bearing sediments (HBS) was established based on the discrete element method, and the influence of hydrate saturation, in situ stress, and injection rate on the meso-fracture evolution was investigated. The results indicate that with the increase in hydrate saturation, the fracture morphology transitions from bi-wing to multi-branch, thereby enhancing fracture complexity. Both tensile and shear failure modes exist, and the tensile failure between the weakly cemented sediment particles is dominant. The tensile strength of HBS is an exponential function of hydrate saturation, with the breakdown pressure being governed by hydrate saturation and in situ stress, with the form being consistent with the classical Kirsch equation. Additionally, lower in situ stress and higher injection rates are conducive to the generation of microcracks, whereas an excessive injection rate reduces the fracture length. These findings contribute to understanding the meso-evolution mechanism of hydraulic fractures and guide the design of on-site hydraulic fracturing plans of natural gas hydrate reservoirs. [ABSTRACT FROM AUTHOR]

The possibilities of using geothermal energy are slowly expanding to all areas of energy consumption, so the assessment of geothermal potential has become the backbone of energy policies in countries that have the potential. Countries and companies that have experience in the oil and gas industry are increasingly exploring the possibilities of first using the acquired knowledge, and then using the existing oil and gas infrastructure for the use of geothermal energy. For this reason, it is necessary to analyse the possibilities of using the existing infrastructure with all its limitations to maximise the energy potential of geothermal energy. The existing oil infrastructure, especially the wells, is in many cases not suitable for the production of brine and it is necessary to analyse the maximum impact of each well for the production of geothermal energy, with particular attention to the equipment installed in the well and the thickness of the geothermal reservoir in the oil and gas fields that would be suitable for the production of brine. [ABSTRACT FROM AUTHOR]

Wellbore stability problems increase with the exploration and development of oil and gas reservoirs. A new 3D non-linear failure criterion is proposed as a trigonometric function considering the intermediate principal stress (s2) on the triaxial compression test data. Mohr-Coulomb and Hoek-Brown are well-known failure criteria, but they do not consider the influence of (s2) on rock strength. This new criterion produces a concave surface on the principal stress space (s1,s2,s3) with the influence of intermediate principal stress. In this study, sensitivity analysis for the variable is also done to understand the significant influence of parameters on the accuracy of the proposed criterion. Further validation of this non-linear criterion on three principal stresses (s1,s2,s3) was done compared with linear regression and second-degree polynomial regression results. It has been observed that the new non-linear 3D criterion with five material parameters reveals a good fit compared to linear regression and second-degree polynomial regression, which have four and six material parameters, respectively. The new non-linear criterion was further validated by comparison with existing criteria like the Priest, Drucker-Prager, and Mogi-Coulomb. It has been observed that the new 3D non-linear criterion shows a more accurate result than these existing criteria as certain rock types exhibit coefficient of determination (DC) values near one, precisely 0.95 for inada granite, 0.94 for orikabe monzonite, and 0.91 for KTB amphibolite. In contrast, other rock types have DC values ranging from 0.7 to 0.9. The new 3D non-linear criterion also yields lower root means square error (RMSE) values than the Mogi-Coulomb criterion for seven rock types. Specifically, the RMSE values by the new criterion are as follows: KTB amphibolite - 40.03 MPa, Dunham dolomite - 15.16 MPa, Shirahama sandstone - 9.08 MPa, Manazuru andesite - 22.14 MPa, Inada granite - 35.47 MPa, and Coconino sandstone - 19.047 MPa. This new 3D criterion gave precise predictions of the failure of the formation under in-situ stresses and was further helpful for the simulation of the wellbore in the petroleum industry. The variable in the new 3D criterion should be calculated from triaxial compression test data for each formation rock before applying this criterion to the wellbore stability problem and the sand production problem. [ABSTRACT FROM AUTHOR]

Under the conditions of many faults, sandbodies, and hydrocarbon sources on the slopes of faulted basins where structural traps are scarce, only a few sandbodies are capable of forming hydrocarbon pools, while most sandbodies act as aquifers. This situation presents a challenge for predicting favorable hydrocarbon accumulation areas and understanding controlling factors. The Pinghu Formation reservoirs in the Baoyunting nose structure of the Xihu Sag in the East China Sea exemplify this characteristic. Among the 19 small-scale oil and gas reservoirs discovered in this area, 10 are faulted sandbody composite traps and 9 are lithological traps, while the majority of the remaining sand layers, especially the thick layers, act as aquifers, resulting in significantly lower accumulation probabilities compared to the adjacent northern and southern areas. We analyzed the relationship between the sandstone thickness and the amplitude through the 1-D forward modeling of wells and dissected the 3-D seismic event to obtain the planar distribution of a single sandbody. Further comprehensive research on fault sealing and kinetic reservoir formation processes suggests that the gas pool formation in this area is closely related to fault sealing and lateral oil and gas transport. A small fault-to-caprock ratio is beneficial for the sealing of mudstone caprocks, while a large fault-to-sand thickness ratio is beneficial for the lateral sealing of faults and the formation of fault–sand composite pools. The tidal microfacies sandbody has a small scale, poor lateral transport ability, and a low probability of gas reservoir formation. The barrier and delta front sandbodies have a large scale, good lateral transport, and a high probability of reservoir formation. Based on the above methods, favorable pool formation traps were identified in the area, and high-yield gas wells were drilled. [ABSTRACT FROM AUTHOR]

In today's race to find ways to produce cheap and green hydrogen, the natural hydrogen wells in Bourakebougou offer a promising solution and are a good example of how H2 can be produced in the natural environment. Not only has one well been successfully exploited to generate electricity for the local village, but twenty-four other exploratory boreholes have also demonstrated the presence of natural H2 in the surrounding area. The Bourakebougou H2 field offers a unique opportunity for geoscientists to determine the key characteristics of natural hydrogen reservoirs. This paper presents the coring, logging, and geochemistry studies that were performed to better characterize the nature of the Bourakebougou H2-bearing reservoirs. The shallowest main reservoir, in which there is the highest content of H2, is made of dolomitic carbonate (Neoproterozoic cap carbonate). These carbonates are largely karstified and show a high degree of heterogeneity in porosity (0.21–14.32%). Based on the analysis of the drilling imagery of the carbonated reservoirs, the accumulation of hydrogen occurs in the karst (void) representing a secondary porosity in the rock matrix. Other reservoirs, especially the deepest ones, are porous sandstone rocks with much more homogeneous porosities (4.52–6.37%) compared to the massive carbonates. For the wells analysed, the neutron tool reacted in a specific way when there is the presence of hydrogen. Hence, it stands out as being the primary tool to detect the presence of natural hydrogen beyond simple gas logging. When comparing a H2 reservoir system to classical oil and gas reservoir systems, the results show that the hydrogen reservoir is a dynamic system that is progressively recharged in H2-rich gas at the production timescale. [ABSTRACT FROM AUTHOR]

This paper investigates the relevant mechanisms of microbial propagation and oil displacement, summarizes the characteristics of different microbial enhanced oil recovery technologies, and on this basis, introduces the research progress of microbial enhanced oil recovery in complex oil and gas reservoir environments such as low permeability, high viscous oil, high temperature and pressure, high water content, and high salinity, and looks forward to the future development direction of microbial oil displacement in different oil and gas reservoirs. It provides the corresponding theoretical basis and research reference for the relevant researchers. [ABSTRACT FROM AUTHOR]

Most available artificial intelligence models for bubble-point pressure (Pb) and oil formation volume factor (Bob) are multiple-input single-output models that are not reproducible or with complex topology. In this study, a multiple-input multiple-output genetically optimized neural network to predict oil Pb and Bob was developed using solution gas–oil ratio, API-oil gravity, gas gravity and reservoir temperature from 781 published datasets. The overall performance of the developed neural network resulted in a correlation coefficient (R) of 0.99918 and a mean square error (MSE) of 5.9941 × 10–4. The developed Pb and Bob models predictions resulted in a coefficient of determination (R2) of 0.9985 and R-value of 0.99423 for Pb, then R2 of 0.9842 and R-value of 0.99207 for Bob. Also, the Pb model had MSE of 2.0 × 10–4, root mean square error (RMSE) of 4.45 × 10–3 and average absolute percent relative error (AAPRE) of 0.4447, while Bob had 1.0 × 10–4, 3.9 × 10–3 and 0.0391 for MSE, RMSE and AAPRE, respectively. Furthermore, the generalization capacity of the developed models with new datasets resulted in R2, R, MSE, RMSE and AAPRE of 0.9613, 0.98046, 0.03713, 0.1927 and 19.2698, respectively, for Pb, as the Bob model had R2 of 0.9499, R of 0.97463, MSE of 0.0218, RMSE of 0.14763 and AAPRE of 8.20211. Again, the developed Pb and Bob models' generality performance showed that they outperformed some published correlations: Standing [1], Glaso [2], Al-Marhoun [3], Dokla and Osman [4], Almehaideb [5], Al-Shammasi [6], etc. Thus, these developed explicit Pb and Bob models for oil reservoir PVT prediction can be applied. [ABSTRACT FROM AUTHOR]

The pattern of placement of the proppant in the fracture determines the stimulation and success of the surgery. Using a three‐dimensional visual parallel plate fracture model capable of simulating fracture height, length, and variable fracture width, we experimentally investigate the impact of fiber loading, fracture fluid viscosity, sand concentration, pulse time, perforation pattern, and injection rate on proppant transport, placement pattern, and access rate. Experimentally and visually, the migration process and the morphology of the proppant placement in the fracture were assessed. The formation laws of stable support columns and well‐shaped high conductivity fracture channels in fractures have been elucidated. Experimental results show that increasing the fiber concentration improves the channel rate and the proppant mass is large and stable. The channel rate increases with the viscosity of the fracturing fluid, and it is difficult to form a perfect channel when the viscosity is small. If the constructive displacement is too slight or too large, it will not favor the formation of a Hi‐way channel in the fracture. The optimal design displacement is 4.5 m3/min. When the proppant concentration is low, the passage rate is large, but the stability of proppant mass is poor under the scour of large displacement, the conductivity is low under the high closure pressure, the proppant concentration is too high, the suspension is difficult, the settlement rate is large, and it is difficult to form a large passage. The current column and the passage rate are larger for pulse times of 15–20 s. Cluster perforations are better than large continuous perforations. The higher the number of clusters in the same number of holes, the higher the channel rate. The formation laws of stable support pillars and well‐shaped high conductivity fracture channels in fractures have been elucidated, which can be useful for efficient stimulation of oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

The study evaluates the geothermal energy potential of two depleted oil and gas reservoirs representing two different lithostratigraphic formations—the carbonate formation of the Visean age from the basement of the Carpathian Flysch and the Rotliegend sandstone formation from the Eastern part of the Foresudetic Monocline, Poland. Advanced modeling techniques were employed to analyze the studied formations' heat, storage, and transport properties. The obtained results were then used to calculate the heat in place (HIP) and evaluate the recoverable heat (Hrec) for both water and CO2 as working fluids, considering a geothermal system lifetime of 50 years. The petrophysical parameters and Hrec were subsequently utilized in the generalized c-means (GFCM) clustering analysis, which helped to identify plays with the greatest geothermal potential within the studied formations. The central block emerged as the most promising area for the studied carbonate formation with Hrec values of ~1.12 and 0.26 MW when H2O and CO2 were used as working fluids, respectively. The central block has three wells that can be easily adapted for geothermal production. The area, however, may require permeability enhancement techniques to increase reservoir permeability. Two prospective zones were determined for the analyzed Rotliegend sandstone formation: one in the NW region and the other in the SE region. In the NW region, the estimated Hrec was 23.16 MW and 4.36 MW, while in the SE region, it was 19.76 MW and 3.51 MW, using H2O and CO2 as working fluids, respectively. Both areas have high porosity and permeability, providing good storage and transport properties for the working fluid, and abundant wells that can be configured for multiple injection-production systems. When comparing the efficiency of geothermal systems, the water-driven system in the Visean carbonate formation turned out to be over four times more efficient than the CO2-driven one. Furthermore, in the case of the Rotliegend sandstone formation, it was possible to access over five times more heat using water-driven system. [ABSTRACT FROM AUTHOR]

Dielectric logging is a critical method for exploring and developing complex oil and gas reservoirs, such as tight reservoirs, low-resistivity contrast reservoirs, and shale oil and gas reservoirs. The sensitivity function is extended to high-frequency dielectric logging in this paper. The detection characteristics of attenuation and phase shift of an array dielectric logging tool in different modes are investigated, along with the influencing factors such as resistivity and dielectric constant. The results show the following: (1) The symmetrical coil system structure makes the sensitivity distribution symmetrically distributed, and the detection range is more focused. In the same measurement mode, the depth of investigation (DOI) becomes deeper under high resistivity formation, and the sensitivity range oscillates outward when the dielectric constant becomes greater. (2) The DOIs of different frequencies and source spacings cover the radial zone between 1 cm and 15 cm. The detection range has been enlarged to include part of the invasion zones, improving the measurement data's dependability. (3) With the increase in the dielectric constant, the curve tends to oscillate, and this behavior makes the DOI slightly shallower. Additionally, this oscillation phenomenon is obvious when the frequency, resistivity, and dielectric constant increase, particularly in high-frequency detection mode (F2, F3). [ABSTRACT FROM AUTHOR]

The carbonate reservoir plays a pivotal role in conventional oil and gas reservoirs. However, due to limited knowledge of fluid flow characteristics in fractured-vuggy carbonate formations (vuggy means a small to medium-sized cavity inside rock), high efficiency reservoir development remains challenging. In this study, the similarity principle is utilized to design a two-dimensional visual model based on geological data and the injection-production characteristics of a fractured-vuggy reservoir in M Oilfield. To investigate the characteristics of oil–water flow, the oil–water interface, and residual oil distribution, flooding experiments are conducted at various injection-production positions, types, and injection rates. The results suggest that a low injection/high production strategy is optimal for achieving maximum oil recovery. As a consequence, this configuration is employed in the subsequent flooding experiments. The optimal oil recovery of 82.2% is attained via pore injection and vug production. The Jamin effect exerts an influence on the oil-water flow in structures connected by small channels at the bottom of large vugs, necessitating adjustment of the flow rate to achieve optimal injection conditions. The variation of the oil–water interface height in each vug due to structural flaws results in suboptimal overall oil recovery. The oil recovery is limited to approximately 30% at an injection rate below 8 ml/min but can be enhanced to over 70% with a higher injection rate exceeding 8 ml/min. The residual oil of the fractured-vuggy reservoir is typically found in the tops of structures and peripheral areas with poor connectivity. The findings of this study offer direction for optimal production in fractured-vuggy carbonate reservoirs and facilitate a more comprehensive comprehension of oil–water flows within the reservoir. [ABSTRACT FROM AUTHOR]

Overpressure is significant to the exploration and exploitation of petroleum due to its influence on hydrocarbon accumulation and drilling strategies. The deep-burial hydrocarbon reservoirs of Jurassic strata in the central Junggar Basin are characterized by intensive overpressure, whose origins are complex and still unclear. In this study, Bowers' method and sonic velocity-density crossplot method based on well logging data were used as a combination for overpressure judgements in geophysics. Furthermore, the corresponding geological processes were analysed in quality and quantity to provide a rational comprehension of the overpressure origins and the model of overpressure evolution and hydrocarbon accumulation processes. The results showed that hydrocarbon generation in the Jurassic source rocks led to overpressure in the mudstones, while hydrocarbon generation in Permian source rocks led to overpressure in the sandstone reservoirs in Jurassic strata by vertical pressure transfer. The burial and thermal history indicated that the aquathermal effect of pore fluids by temperature increase in deep strata is also an important origin of overpressure, while disequilibrium compaction may not be the dominant cause for the overpressure in deep-buried strata. Furthermore, the continuous tectonic compression in both the north--south and west-east trends from the Jurassic period to the present may also have enhanced the overpressure in deep strata. Meanwhile, the developed faults formed by intensive tectonic compression led to pressure transfer from source rocks to the Jurassic reservoirs. Overpressured geofluids with hydrocarbons migrated to sandstone reservoirs and aggravated the overpressure in the Jurassic strata. To conclude, the intensive overpressure in the central Junggar Basin is attributed to the combination of multiple mechanisms, including hydrocarbon generation, the aquathermal effect, tectonic compression and pressure transfer. Furthermore, the developed overpressure indicated hydrocarbon migration and accumulation processes and the potential of oil and gas reservoirs in deeply buried strata. We hope this study will provide a systematic research concept for overpressure origin analysis and provide guidance for petroleum exploration and exploitation in deep-buried strata. [ABSTRACT FROM AUTHOR]

The recycling or burial of carbon dioxide in depleted petroleum reservoirs and re-imagining exploration strategies that focus on hydrogen reservoirs (with any associated hydrocarbon gas as the upside potential) are a necessity in today's environmental and geopolitical climate. Given that geologic hydrogen and hydrocarbon gases may occur in the same or different reservoirs, there will be gains in efficiency when searching for both resources together since they share some commonalities, but there is no geophysical workflow available yet for this purpose. Three-dimensional (3D) marine controlled-source electromagnetic (CSEM) and magnetotelluric (MT) methods provide valuable information on rock-and-fluid variations in the subsurface and can be used to investigate hydrogen and hydrocarbon reservoirs, source rocks, and the migration pathways of contrasting resistivity relative to the host rock. In this paper, a process-oriented CSEM-MT workflow is proposed for the efficient combined investigation of reservoir hydrocarbon and hydrogen within a play-based exploration and production framework that emphasizes carbon footprint reduction. It has the following challenging elements: finding the right basin (and block), selecting the right prospect, drilling the right well, and exploiting the opportunities for sustainability and CO2 recycling or burial in the appropriate reservoirs. Recent methodological developments that integrate 3D CSEM-MT imaging into the appropriate structural constraints to derive the geologically robust models necessary for resolving these challenges and their extension to reservoir monitoring are described. Instructive case studies are revisited, showing how 3D CSEM-MT models facilitate the interpretation of resistivity information in terms of the key elements of geological prospect evaluation (presence of source rocks, migration and charge, reservoir rock, and trap and seal) and understanding how deep geological processes control the distribution and charging of potential hydrocarbon, geothermal, and hydrogen reservoirs. In particular, evidence is provided that deep crustal resistivity imaging can map serpentinized ultramafic rocks (possible source rocks for hydrogen) in offshore northwest Borneo and can be combined with seismic reflection data to map vertical fluid migration pathways and their barrier (or seal), as exemplified by the subhorizontal detachment zones in Eocene shale in the Mexican Ridges fold belt of the southwest of the Gulf of Mexico, raising the possibility of using integrated geophysical methods to map hydrogen kitchens in different terrains. The methodological advancements and new combined investigative workflow provide a way for improved resource mapping and monitoring and, hence, a technology that could play a critical role in helping the world reach net-zero emissions by 2050. [ABSTRACT FROM AUTHOR]

An intermediate product is obtained by polymerization between 1, 3, 5,7-tetramethylcyclotetrasiloxane () and octamethylcyclotetrasiloxane (D4) under the initiation of Purolite® CT175 ・ The intermediate is then reacted with 3-buten-l・ol under the catalysis of platinum(O) -1divinyl-1, 1, 3, 3-tetramethyldisiloxane to obtain a hydroxy-modified poly siloxane ・ The structure of the product was characterized, and the temperature tolerance and ability to modulate the wettability of the sandstone surface were evaluated・ The results show that the polymer has good temperature resistance and can adjust the wettability of the sandstone surface to an intermediate wettability state at a high temperature of 240 °C, which can effectively reduce the loss of water phase in the drilling fluid and protect oil and gas reservoir. [ABSTRACT FROM AUTHOR]

In this work, geochemical modelling using PhreeqC was carried out to evaluate the effects of geochemical reactions on the performance of underground hydrogen storage (UHS). Equilibrium, exchange, and mineral reactions were considered in the model. Moreover, reaction kinetics were considered to evaluate the geochemical effect on underground hydrogen storage over an extended period of 30 years. The developed model was first validated against experimental data adopted from the published literature by comparing the modelling and literature values of H2 and CO2 solubility in water at varying conditions. Furthermore, the effects of pressure, temperature, salinity, and CO2% on the H2 and CO2 inventory and rock properties in a typical sandstone reservoir were evaluated over 30 years. Results show that H2 loss over 30 years is negligible (maximum 2%) through the studied range of conditions. The relative loss of CO2 is much more pronounced compared to H2 gas, with losses of up to 72%. Therefore, the role of CO2 as a cushion gas will be affected by the CO2 gas losses as time passes. Hence, remedial CO2 gas injections should be considered to maintain the reservoir pressure throughout the injection and withdrawal processes. Moreover, the relative volume of CO2 increases with the increase in temperature and decrease in pressure. Furthermore, the reservoir rock properties, porosity, and permeability, are affected by the underground hydrogen storage process and, more specifically, by the presence of CO2 gas. CO2 dissolves carbonate minerals inside the reservoir rock, causing an increase in the rock's porosity and permeability. Consequently, the rock's gas storage capacity and flow properties are enhanced. [ABSTRACT FROM AUTHOR]

Based on literature research in combination with the practice of CO2 flooding and storage in Jilin Oilfield, this study assesses the key problems in CO2 flooding and storage, proposing the corresponding countermeasures from five aspects of CO2 gas source condition, namely geological condition evaluation, scheme design incoordination with other production methods, economic and effectiveness evaluation, together with dynamic monitoring and safety evaluation. The results show that CO2 flooding is the most economic and effective CO2 storage method. In eastern China, inorganic origin CO2 gas reservoirs are widely developed and are especially the most enriched in the Paleozoic carbonate rock strata and the Cenozoic Paleogene–Neogene system, which provide a rich resource base for CO2 flooding and storage. In the future, CO2 generated in the industrial field will become the main gas source of CO2 flooding and storage. The evaluation of geological conditions of oil and gas reservoirs is the basis for the potential evaluation, planning scheme design and implementation of CO2 flooding and storage. CO2 storage should be below the depth of 800 m, the CO2 flooding and storage effects in low‐permeability oil reservoirs being the best. CO2 geological storage mechanisms primarily consist of tectonic geological storage, bound gas storage, dissolution storage, mineralization storage, hydrodynamic storage and coalbed adsorption storage. The practice of CO2 flooding and storage in Jilin Oilfield demonstratesthat the oil increment by CO2 flooding is at least 24% higher than by conventional water flooding. The most critical factor determining the success or failure of CO2 flooding and storage is economic effectiveness, which needs to be explored from two aspects: the method and technology innovation along with the carbon peaking and carbon neutrality policy support. After CO2 is injected into the reservoir, it will react with the reservoir and fluid, the problem of CO2 recovery or overflow will occur, so the dynamic monitoring and safety evaluation of CO2 flooding and storage are very important. This study is of great significance to the expansion of the application scope of CO2 flooding and storage and future scientific planning and deployment. [ABSTRACT FROM AUTHOR]

Staged multi-cluster fracturing of horizontal wells is one of the most important tools to achieve efficient development of unconventional oil and gas reservoirs. The multi-stage fracturing technique forms complex fractures with multiple clusters and branches in the formation, causing competing diversions leading to more complex proppant transport patterns, and the proppant placement method determines the flow conductivity of complex fractures, so it is necessary to investigate the proppant transport patterns in complex fractures. To address this issue, a field-scale geometric model is established for numerical simulation, and the multiphase flow diversion pattern in the wellbore, the proppant distribution pattern under different network conditions, and the optimization of different construction parameters are investigated. The results are obtained as follows: the distribution of solid and liquid phases in each cluster of the well conforms to the trend of variable mass flow; the proppant is distributed at the heel end in multiple clusters of fractures, and the sand and liquid are unevenly distributed among clusters of fractures, and the number of branching affects the proppant transport; through sensitivity analysis of the influencing factors, the pumping displacement, fracturing fluid viscosity and proppant particle size are optimized, and the construction parameters of 14 m3/min, 5 mPa·s, 70/140 mesh, 12% sand ratio are determined. This study has a certain guiding significance for the optimization of fracturing parameters in this block. [ABSTRACT FROM AUTHOR]

Subsurface energy storage in depleted petroleum reservoirs is a promising technique to balance and optimize the utilization of energy resources. In this work, we numerically explore the possibility of storing excessive hydrogen gas in depleted unconventional gas reservoirs. Our study is a multiscale analysis. From the molecular (pore) scale, we investigate the thermodynamics and transport mechanism of the hydrogen gas in the nanopores of the unconventional reservoirs. Then based on the results of the pore scale, we conduct reservoir-scale simulations to quantitatively investigate the preferred cycling pressure, the effective fraction of cushion gas and the amount of storage capacity of unconventional reservoirs. We have discovered that, compared to conventional gas reservoirs, hydrogen stored in unconventional reservoirs maintains higher purity because of the differential adsorption effect of the nanopores. This feature makes depleted unconventional gas reservoirs appealing candidates for underground storage of the hydrogen gas. • Potentials of hydrogen storage in unconventional reservoirs are investigated. • Molecular dynamics simulation and reservoir simulation are performed. • The preferential adsorption of methane facilitates the storage of hydrogen. • The hydraulically fractured region is the main contributor for hydrogen storage. • The existence of nanopores improves the purity of produced hydrogen. [ABSTRACT FROM AUTHOR]

Wormhole propagation plays a very important role in the product enhancement of oil and gas reservoir. A new combined hybrid mixed finite element method is proposed to solve incompressible wormhole propagation problem with discontinuous Galerkin finite element procedure, in which, the new hybrid mixed finite element algorithm is established for pressure equation, while the discontinuous Galerkin finite element method is considered for concentration equation, and then the porosity function is computed straightly by the approximate value of the concentration. This new combined method can keep local mass balance, meantime it also keeps the boundedness of the porosity. The convergence of the proposed method is analyzed and the optimal error estimate in L 2 -norm is derived. Finally, by the first-order backward Euler scheme in time, numerical examples are presented to verify the validity of the algorithm and the correctness of the theoretical results. [ABSTRACT FROM AUTHOR]

Mahu sag is an important hydrocarbon-rich sag and a large stratigraphic lithologic reservoir exploration field in the northwestern Junggar Basin, forming a large stratigraphic lithologic reservoir with multiple layers. In order to find out the distribution law of oil and gas in this area and provide geological basis for the next exploration deployment, based on core observation and comprehensive analysis of seismic, logging and other data, the structural sequence analysis method was applied to study the main oil and gas reservoir series from Permian to Triassic. The results show that there are many large stratigraphic unconformity surfaces from Permian to Triassic in Mahu sag, which can be divided into Lower Permian, Middle Permian, Upper Permian-Triassic and other structural sequences. From Permian to Triassic, it experiences three major evolution stages of fault depression, depression and large depression slope, forming the superposition of three major structural sequences. The Lower Permian is a dustpan structural sequence formed under the extensional tectonic background; the northern stratum is thick, and the southern stratum is thin; it is deposited under the dustpan structure background of deep north and shallow south; the depression area is widely distributed fine-grained mixed rock, which is constructed of high-quality hydrocarbon source rock, and gradually becomes sandstone and conglomerate towards the slope area. The Middle Permian is a structural sequence with thick central and thin peripheral margins under the tectonic background of depression; the basin margin fan delta is developed, which is characterized by large basin, shallow water, limited basin margin fan body, and interbedded sediment of sand and mud in the basin. In Upper Permian-Triassic, Mahu area is located in the northwest slope area of Junggar large depression basin; under the background of shallow water, gentle slope and lacustrine transgression, the large retrogressive fan delta deposits are formed, and the sand bodies are vertically superimposed and horizontally distributed. The vertical superposition of the three major structural sequences forms the multi-layer distribution of stratum-lithologic or structure-lithological reservoirs in the area. [ABSTRACT FROM AUTHOR]