Fractured Reservoir Research Articles

A theoretical study on Krauklis wave characteristics

Abstract The Krauklis wave is a special seismic phenomenon in fluid saturated fracture medium. The wave can prompt a unique resonance effect and enhance the amplitude at special frequencies. These frequencies have a quantitative relationship with the fracture geometry parameters and can be used for quantitative interpretation of geometry parameters. Such frequency information can be transmitted to body waves by the transformation between the Krauklis wave and the body wave. Both P- and S-waves become frequency dependent. In this study, an original numerical method is brought out to solve the equation of the Krauklis wave dispersion relation. The method has fine computational performance, and the frequency band for numerical solution is extended to the megahertz level. The dispersion, resonance, and attenuation of the Krauklis wave can be analyzed within the entire frequency range for Krauklis wave existence. What is more, the formation mechanism, existence, and observability are illuminated. The analysis shows that there are upper limits of frequency and fracture aperture for Krauklis wave existence, but within the frequency band for artificial seismic and micro-seismic exploration, the Krauklis wave exists widely. For experimental research, the frequency and fracture aperture should be well designed to ensure the generation of the Krauklis wave. The attenuation of the Krauklis wave can suppress the resonance effect. The influence of the attenuation should be taken into account, when the wave is used for seismic characterization of fracture reservoirs or micro-seismic monitoring of hydraulic fracturing.

In-situ stress field simulation and fracture distribution prediction of middle lower Ordovician in Zone B of Tahe Oilfield, Tarim Basin

This study constructed a heterogeneous rock mechanics model through well seismic joint inversion, set up a dual cycle statement to optimize the application of boundary loads, and obtained the current stress field distribution in Zone B. At the same time, we preferred the rock fracture criterion, carried out the quantitative characterization of different natures of fractures, and used the integrated fracture development rate to portray the integrated fracture development situation. Finally, the horizontal stress difference, stress heterogeneity coefficient, and comprehensive fracture rate were proposed to define the development index of fractured reservoirs. The results show that (1) the maximum horizontal principal stress is 102–144 MPa, and the minimum horizontal principal stress is 85–125 MPa; (2) the development rate of tension fractures is 0.03–0.23, the development rate of shear fractures is 0.15–0.54, and the integrated fracture development rate is 0.28–0.79; (3) the development index of fracture-type reservoirs is >2.3, Class I; 1.8–2.3, Class II; When it is lower than 1.8, Grade III. This article attempts to apply the stress field simulation results to the quantitative prediction of reservoir fractures, adding new ideas for the practical application of stress field results.

Numerical Calculation and Application for Crushing Rate and Fracture Conductivity of Combined Proppants

Proppant is one of the key materials for hydraulic fracturing. For special situations, such as middle-deep reservoirs and closure pressures ranging from 40 MPa to 60 MPa, using a single proppant cannot solve the contradiction between performance, which means crushing rate and fracture conductivity, and cost. However, using combined proppants is an economically effective method for hydraulic fracturing of such special reservoirs. Firstly, for different types, particle sizes, and proportions of combined proppants, various contact relationships between proppant particles are considered. The random phenomenon of proppant particle arrangement is described using the Monte Carlo method, and the deterministic phenomenon of proppant particles is processed using an optimization model, achieving computer simulation of the microscopic arrangement of proppant particles. Secondly, a mathematical model for the force analysis of combined proppant particles is established, and an improved singular value decomposition method is used for numerical solution. A computational model for the crushing rate and fracture conductivity of combined proppants is proposed. Thirdly, the numerical calculation results are compared and discussed with the test values, verifying the accuracy of the computational model. Finally, the application of combined proppants is discussed, and a model for optimizing the proportion of combined proppants is proposed. The onsite construction technology is introduced, and the cost and economic benefits of combined proppants are compared with those of all ceramic particles and excessive all-quartz sand. It is proved that combined proppants can balance performance and price, and are an economically effective method for hydraulic fracturing of special reservoirs. The research results can select the optimal proppant material and optimize the combination of different proppant types, which can help achieve cost reduction and efficiency increase in oil and gas development.

Analysis of Fracturing Expansion Law of Shale Reservoir by Supercritical CO2 Fracturing and Mechanism Revealing

The rapid expansion of reservoir fractures and the enlargement of the area affected by working fluids can be accomplished solely through fracturing operations of oilfield working fluids in geological reservoirs. Supercritical CO2 is regarded as an ideal medium for shale reservoir fracturing owing to the inherent advantages of environmental friendliness, excellent capacity, and high stability. However, CO2 gas channeling and complex propagation of fractures in shale reservoirs hindered the commercialization of Supercritical CO2 fracturing technology. Herein, a simulation method for Supercritical CO2 fracturing based on cohesive force units is proposed to investigate the crack propagation behavior of CO2 fracturing technology under different construction parameters. Furthermore, the shale fracture propagation mechanism of Supercritical CO2 fracturing fluid is elucidated. The results indicated that the propagation ability of reservoir fractures and Mises stress are influenced by the fracturing fluid viscosity, fracturing azimuth angle, and reservoir conditions (temperature and pressure). An azimuth angle of 30° can achieve a maximum Mises stress of 3.213 × 107 Pa and a crack width of 1.669 × 10−2 m. However, an apparent viscosity of 14 × 10−6 Pa·s results in a crack width of only 2.227 × 10−2 m and a maximum Mises stress of 4.459 × 107 Pa. Additionally, a weaker fracture propagation ability and reduced Mises stress are exhibited at the fracturing fluid injection rate. As a straightforward model to synergistically investigate the fracture propagation behavior of shale reservoirs, this work provides new insights and strategies for the efficient extraction of shale reservoirs.

Analysis of Critical Instability Conditions for Solid-Phase Plugging of Natural Fractures during Temporary Plugging and Fracturing.

Hydraulic fracturing has become a key technology for the development of unconventional oil and gas resources, such as deep shale. Due to the development of natural fractures in deep shale reservoirs, the opening of natural fractures during the fracturing process can cause a significant loss of fracturing fluid, resulting in a reduction in the width of the main fracture and construction risks, such as sand plugging. It is important to improve the fracturing effect of deep shale reservoirs by plugging natural fractures with solid phases, reducing filtration, and improving the efficiency of the fracturing fluid. Ensuring the effectiveness of solid plugging is key to optimizing the fracturing design and improving the stimulation effect after fracturing. In this study, solid plugging technology is introduced into the filtration control process of natural fractures. By setting a plugging zone with a certain length and permeability inside the natural fracture, a stability prediction model for the plugging zone of natural fractures is established, and the instability conditions of the plugging zone are analyzed. The simulation results indicate that the instability of the plugging zone is related to permeability and there is a critical permeability. When the permeability of the plugging zone is greater than this value, expansion instability will occur, and when it is less than or equal to this value, shear slip instability may occur. The strength of shear slip instability is mainly determined by the length of the plugging zone, the friction angle of the natural fracture surface, the friction angle between the plugging particles, and the porosity of the plugging zone. The friction angle of natural fracture surfaces affects only the strength of slip instability, while the friction angle of plugging particles and porosity mainly affect the strength of shear instability. The research results provide a theoretical basis for the optimization of fracturing construction parameters in deep shale reservoirs.

Mechanism and application of gas phase trapping by spontaneous imbibition

For fractured gas reservoirs with strong water drive, gas phase trapping affects the gas recovery significantly. The recovery may be less than 50% for some reservoirs while it is only 12% for Beaver River gas field. The gas phase trapping mechanism has been revealed by the results of depletion experimental test. The residual pressure of the trapped gas is as high as 11.75 MPa with a 12.8 cm imbibition layer resulting in gas recovery deceased 49.5% compared with that without imbibition layer. A mathematical model is built to calculate the imbibition thickness based on capillary pressure and relative permeability of the matrix. The gas phase trapping are analyzed by two representative wells in Weiyuan gas field, the intermittent production reinforces the imbibition thickness and result in gas trapped in the matrix block with high residual pressure for the low performace gas wells, the extremely low gas recovery can be explained more rationally. That lays a foundation of improving the gas recovery for fractured reservoirs.

Development characteristics of natural fractures in tight sandstone reservoirs and their controlling factors: upper Triassic Xujiahe Formation, western Sichuan Basin

Development characteristics of natural fractures in tight sandstone reservoirs and their controlling factors: upper Triassic Xujiahe Formation, western Sichuan Basin

Productivity evaluation method of offshore fractured reservoir based on artificial intelligence ChatGPT

Abstract At present, the analogy method is usually used to determine the production capacity. Due to the strong heterogeneity of fractured reservoirs in the Bohai Sea, the prediction error is large and cannot meet the needs of scheme deployment. Therefore, based on the test productivity, the characteristic parameter λ was introduced to characterize fractured reservoir productivity, and the relevant data affecting productivity were preprocessed by the K-nearest algorithm and Z-Score standardization method. Then, the feature vector of parameter λ was selected by the average impurity reduction MDI feature selection method. Finally, in the GPT Building module of ChatGPT, the reservoir parameters and productivity test data are used to train GPT and the deep forest prediction model with parameter λ is built intelligently by GPT. This method is applied to the CFD oilfield productivity evaluation in the Bohai Sea, and the prediction error caused by the difference in reservoir physical properties is reduced. The coincidence rate between prediction and actual is more than 85%, which provides a new idea and method for the productivity evaluation of offshore fractured reservoirs.

The hydraulic fracture propagation pattern induced by multi-stage temporary plugging and diverting fracturing in reservoirs with various lithologies: An experimental investigation

Multi-stage temporary plugging and diverting fracturing (TPDF) is an effective method for generating hydraulic fracture (HF) networks. This study investigates various lithological reservoirs in the Xinjiang region, obtaining downhole full-diameter cores for experimental analysis using true triaxial TPDF. The characteristics of HF morphology are quantitatively assessed by employing computed tomography (CT) scanning. The findings are summarized as follows: (1) Initial hydraulic fracturing of specimens with different lithologies results in σH-direction double-wing HF, while the first TPDF generates a single-wing HF along the σh direction, and the second TPDF produces a single-wing HF along the σH direction. (2) The volume and area of HFs in the first TPDF of volcanic rock increased by over 30%. The first TPDF effect is more pronounced in conglomerate rock, with HF volume over 25% and surface area increasing by more than 35%. (3) During multi-stage TPDF, volcanic rock transitions from initial HF to the formation of new HF, sandstone diverts from the wellbore to create new HF, and conglomerate generates new HF through multi-point initiation in the wellbore and HF. Each TPDF process involves the propagation of existing HFs and the generation of new ones. (4) The breakdown pressure in multi-stage TPDF increased by 46.5% and 51.6% in volcanic rock, while in sandstone, the first TPDF increased by 90.6%. In conglomerate rock, multi-stage TPDF saw increases of 51.2% and 41.9%, respectively. These findings offer theoretical insights for optimizing TPDF design in diverse lithological reservoirs.

Integrated modelling of CO2 plume geothermal energy systems in carbonate reservoirs: Technology, operations, economics and sustainability

The rising CO2 content in the atmosphere calls for urgent decarbonization efforts. Carbon capture and storage (CCS) have proven effective in storing large volumes of CO2 in geological reservoirs. Nevertheless, challenges persist in identifying sustainable energy sources and efficient storage sites, especially in carbonate reservoirs. This study aims to characterize the Miocene carbonate reservoir in the Jintan Megaplatform, for CO2 storage and geothermal energy utilization. By integrating advanced technologies such as CO2 Plume Geothermal (CPG) with 3D seismic techniques, borehole analysis and numerical modelling, the study reveals the distribution of critical reservoir characteristics, including architecture, heterogeneity, karstification, fractures, porosity, permeability, temperature and pressure that are paramount for CO2 plume and energy production. The reservoir is estimated to store over 31 Gt of CO2, produce 3.824 × 1018 J of geothermal energy and ⁓44.3 GW of power. This power output can be utilized for electrification of the CCS operations, industrial and municipals, potentially generating over $1.4 billion in revenue. A flow-through model has been proposed to improve energy efficiency, reservoir management, and risk mitigation. This study advances to achieving net-zero targets and the United Nations Sustainable Development Goals on clean energy, climate action and sustainable communities.

Diagenesis including cataclastic band development in the Permian Penrith Sandstone, Vale of Eden Basin, England

Diagenesis in the Penrith Sandstone is characterized by early hematite and mixed illite/smectite cementation, followed by burial compaction, feldspar and two episodes of quartz cementation. The primary quartz overgrowths are characterized by heterogenous luminescence; however, the secondary quartz overgrowths are characterized by thinner and darker luminescence. Cataclasis post-dates primary quartz cementation, and significantly reduces grain and pore aperture size. The apex of mercury volume for a deformed sample was reduced up to three times in comparison with the undeformed rock. Dissolution occurred during cataclasis as authigenic hematite was removed in deformation zones, improving pore aperture size and consequently enhancing sandstone porosity and permeability. Recent fracturing created fractured-pores and improved porosity and permeability in tight cataclastic samples. Evidence for syn-cataclastic dissolution is observed in the samples studied. This is indicated by the dissolution of authigenic feldspars and the enhancement of poroperm parameters adjacent to cataclastic zones and the absence of hematite cement within them. Based on those the sequence of diagenetic evolution in the Penrith Sandstone can be reconstructed. Host samples were characterized by good to very good poroperm values, varying between 20 and 24% porosity and from 809÷1445 mD permeability. Cataclastic core plugs have 13÷21% porosity and 0.12÷39 mD permeability. The porosity reduction by cataclasis was estimated to be as much as 4.5% on average. Fracturing and dissolution improved poroperm parameters in studied samples. Recently fractured core plugs have about 292 mD permeability on average. Dissolution-cataclastic samples have 32% porosity and 18 mD permeability, whereas dissolution-host samples have 31% porosity and maximum permeability as much as 2469 mD on average. Cataclasis occurred in combination with in situ significant reservoir dissolution and fracturing may improve a sandstone reservoir in excellent quality.

An improved mathematical model of gas–water two-phase flows in fractured horizontal wells accounting for physical contact behaviors of fractures with total factor characteristics

In water-bearing gas reservoirs, water existence affects gas production performances due to two-phase flows occurring in matrix and fracture systems. Under the background of staged multi-cluster fractured horizontal wells, this work focuses on an improved gas–water two-phase flow model accounting for physical contact behaviors of fractures with total factor characteristics. Combining a point-convergence method with fractal theory and applying Laplace transform and Stehfest numerical inversion, analytical solutions of this proposed model are solved to validate against the field production data and numerical simulation results. Subsequently, the analytical nephograms of formation pressure and water saturation at different stages are given for the first time, throughout which formation pressure and water saturation distributions at different locations of the fractured reservoir embedded with segmented multi-cluster tree-shaped fracture networks are visually exhibited. The results demonstrate that draining area evolution is limited to each segment at early stage and mid-stage, whereas these multi-cluster segments are really integrated into the whole draining area at late stage. Thus, the moving boundary of fracture-controlled unit is also delineated based on water saturation nephograms and expands with continuous production from 65 to 180 m in the y axis direction, contributing to the effective fracturing area for a high productivity. Furthermore, the share of free gas and adsorbed gas are 83% and 17% at early stage, while free gas and adsorbed gas account for 57% and 43% of total gas at the late stage. Those findings contribute to high-efficient and sustainable development of unconventional gas resources.

Application of CO2-Soluble Polymer-Based Blowing Agent to Improve Supercritical CO2 Replacement in Low-Permeability Fractured Reservoirs.

Since reservoirs with permeability less than 10 mD are characterized by high injection difficulty, high-pressure drop loss, and low pore throat mobilization during the water drive process, CO2 is often used for development in actual production to reduce the injection difficulty and carbon emission simultaneously. However, microfractures are usually developed in low-permeability reservoirs, which further reduces the injection difficulty of the driving medium. At the same time, this makes the injected gas flow very fast, while the gas utilization rate is low, resulting in a low degree of recovery. This paper conducted a series of studies on the displacement effect of CO2-soluble foaming systems in low-permeability fractured reservoirs (the permeability of the core matrix is about 0.25 mD). For the two CO2-soluble blowing agents CG-1 and CG-2, the effects of the CO2 phase state, water content, and oil content on static foaming performance were first investigated; then, a more effective blowing agent was preferred for the replacement experiments according to the foaming results; and finally, the effects of the blowing agents on sealing and improving the recovery degree of a fully open fractured core were investigated at different injection rates and concentrations, and the injection parameters were optimized. The results show that CG-1 still has good foaming performance under low water volume and various oil contents and can be used in subsequent fractured core replacement experiments. After selecting the injection rate and concentration, the blowing agent can be used in subsequent fractured cores under injection conditions of 0.6 mL/min and 2.80%. In injection conditions, the foaming agent can achieve an 83.7% blocking rate and improve the extraction degree by 12.02%. The research content of this paper can provide data support for the application effect of a CO2-soluble blowing agent in a fractured core.

Geomechanics Modeling of Strain-Based Pressure Estimates: Insights from Distributed Fiber Optic Strain Measurements

Summary Rayleigh frequency shift distributed strain sensing (RFS-DSS) has been demonstrated as a potential technology for characterizing fracture geometries and optimizing the completion design in unconventional reservoirs. The combination of RFS-DSS strain and pressure gauge measurements has been reported recently in field applications (Dhuldhoya and Friehauf 2022; Haustveit and Haffener 2023) to characterize conductive fracture dimensions and production profiles. Haustveit and Haffener (2023) demonstrated a novel technique that uses RFS-DSS strain change during production, measured from a far-field observation well, to monitor the drain profile of a horizontal multistage well. The strain change and pressure change were strongly related during production, and this relationship was applied to continuously estimate pressure drawdown along the full length of the well. However, the sensitivity or influencing factors of the relationship between strain change and pressure change along the fiber are not yet fully understood. Therefore, the main objective of this study is to investigate the relationship between strain change and pressure change under various fractured reservoir conditions and provide guidelines for better utilizing this novel strain-pressure relationship to estimate conductive fractures and pressure profiles. We use a coupled geomechanics and fluid flow model to simulate the strain and pressure changes in the near-well and far-field regions during stable production and shut-in periods. A linear relationship is used to fit the strain change and pressure change data obtained from both producing and monitoring wells. We analyze the impact of various fracture properties [size and permeability of the stimulated reservoir volume (SRV) around fractures, fracture conductivity, fracture area, and skin factor] on the linear relationship based on the R2 value and fitting error. The relationship between the strain change and pressure change during the stable production obtained by our numerical study is consistent with the field measurements. The slope of strain change vs. pressure change during one day of production is significantly influenced by fracture properties. Overall, the monitoring well shows a stronger linear relationship than the producing well during both stable production and shut-in periods. A better linear relationship between the strain change and pressure change is associated with a larger fracture conductivity or larger fracture spacing scenario on both producing and monitoring wells during the stable production period. The cluster spacing affects the linear relationship between strain and pressure change during rock deformation. When cluster spacing is reduced, the nonlocal effect of deformation becomes more pronounced, resulting in a weaker linear relationship. During the shut-in period, the monitoring well exhibits a stronger linear relationship with a high R2 value and small fitting error compared to the producing well. The linear relationship obtained during the shut-in period is less reliable for the producing well. In cases of homogeneous fractures, where the fracture properties are uniform, the strain change and pressure change are similar, except for two outer fractures. This study provides a better understanding of the relationship between strain change and pressure change measured in the near-well and far-field regions during stable production and shut-in periods. The results of our study also demonstrate the potential for utilizing the RFS-DSS strain measurement to characterize the effective fracture and drainage dimensions.

Superposition Rate: A Developed Approach for Analyzing Production Data in Tight Gas Reservoirs

The paper examines the application of various methods to analyze production data in which the superposition principle being one of them. This principle is divided into two main methods: Superposition rate and Superposition time. Both are designed to deal with multiple flow rates within production data. The Superposition time converts the production time into constant values and uses the final flow rate value. On the other hand Superposition rate consolidates multiple rates into a single flow rate during production time. This study focuses on analysis of production data using a developed method based on superposition-rate approach. This method converts variables such as flow rate and pressure into constant values, where each flow regime has its own technique by which superposition-rate is utilized. In addition, comparison between conventional and unconventional reservoirs is involved, particularly emphasizing the benefits and drawbacks of tight gas reservoirs.Various types of superposition methods with their functions were discussed. Among them, a workflow part includes a case study of a dominated flow regime used for a hydraulic fractured single well. The workflow part of this study includes a case study of hydraulically fractured well under a dominant flow regime. Results comparing multiple rates method with super position-rate method indicate that the latter has better accuracy with (R) coefficient of (0.96). Case study on fracture reservoir also shows further validated of superposition-rate by accurately estimating drainage volume.

Propagation of interfered hydraulic fractures by alternated radial-circumferential extensions and its impact on proppant distribution

The fracture extension mechanisms and proppant transport characteristics play key roles for optimizing hydraulic fracturing in unconventional reservoirs. In this work, the visual physical simulation method was used to analyze the 3D dynamic extension processes of multi-stage hydraulic fractures and the subsequent impact on proppant distribution. The interfered fracture in multi-stage hydraulic fracturing exhibit alternated radial-circumferential extension behavior. More specifically, these behavior changes from unilaterally radial initiation, circumferential extension to radial extension. Unilaterally radial initiation results in the formation of both mirror and conchoidal features, while circumferential extension leads to stepped feature, and radial extension gives rise to feather feature. The four features of hydraulic fractures result in four types of non-uniform proppant distribution: uniform, scattered, cluster, and regional distribution. The proppant transport shifted from linear to radial mode, promoting further fracture extension. The effects of segment spacing and proppant injection sequence were studied. The results showed that the influence on the interfered fracture decreases as the segment spacing increases. In addition, the propped fracture area is larger when the small-size proppant is injected first, followed by large-size one. The research can improve understanding and optimization of multi-stage hydraulic fracturing in unconventional oil and gas reservoirs.

A Morphological Method for Predicting Permeability in Fractured Tight Sandstone Reservoirs Based on Electrical Imaging Logging Porosity Spectrum

Summary Permeability is a crucial parameter in formation evaluation, which reflects reservoir fluid mobility and directly influences subsequent development and production. In conventional to tight sandstone formations without fractures, numerous methods have been developed to predict permeability. However, permeability prediction accuracy based on the current method is low in fractured tight sandstone reservoirs due to the influence of heterogeneity, and little research is focused on permeability evaluation in such reservoirs. Conventional wireline and nuclear magnetic resonance (NMR) logging lose their role in fracture parameter evaluation, whereas electrical imaging logging is available for reflecting fracture information. Hence, we adopt electrical imaging logging, instead of conventional wireline and NMR logging, to predict permeability in fractured tight sandstone reservoirs. In this study, we propose a morphological method for permeability prediction using electrical imaging logging. Initially, we process the electrical imaging logging data to obtain the porosity spectra and determine the peak of the primary porosity spectrum. We then extract the mean and standard deviation of the primary porosity spectrum based on its distribution morphology. Meanwhile, we also use the normal distribution function to fit the primary porosity spectrum and accumulate the amplitudes of the original and fitted porosity spectra, respectively. When the cumulative amplitude of the fitted spectra stabilizes, the corresponding porosity indicates the boundary between primary and secondary pores. This boundary allows us to calculate the proportion of primary pores to total pores. Permeability in fractured tight sandstone formations is influenced by both primary and secondary pores, showing a strong correlation with the proportion of primary porosity. Finally, we establish a permeability prediction model based on total porosity and the proportion of matrix pores. The reliability of our established permeability evaluation model is confirmed by comparing the predicted permeabilities with core-derived results in the Triassic Chang 63 Member of the Jiyuan area in the Ordos Basin. In unfractured formations, the predicted permeability based on our raised model closely matches the results derived solely from total porosity. In fractured formations, however, the calculated permeability using our proposed model aligns more closely with the core-derived result, while predictions based on current and NMR models tend to underestimate permeability.

Dynamic prediction of fracture propagation in horizontal well hydraulic fracturing: A data-driven approach for geo-energy exploitation

Accurate and efficient prediction of hydraulic fracturing fracture propagation is of utmost importance for unconventional reservoir development. Traditional numerical simulation methods require specialized domain knowledge and technical expertise, and machine learning approach can be an alternative predictive tool for fracture propagation. Additionally, existing neural networks cannot be directly applied to hydraulic fracturing scenarios influenced by multiple coupled factors. Thus, this study presents an innovative approach, “AE-ATT-ConvLSTM”, that integrates an additional Convolutional Layer, Autoencoder, and an Attention Mechanism Feature Fusion Layer into the architecture of a Convolutional Long Short-Term Memory (ConvLSTM) sequential image prediction network. This approach aims to predict fracture propagations in different fracturing stages of horizontal wells. The proposed model is trained on a sample dataset consisting of 5000 instances of hydraulic fracturing in horizontal wells. The dataset includes crucial data such as fracture propagation images, wellbore perforation images, natural fracture images, pumping schedules, and reservoir properties. The model achieves remarkable results, with an MSE less than 15 × 10−5, a maximum SSIM of 0.93, and an average FMAE less than 48. The research findings demonstrate that this method significantly enhances prediction efficiency and provides new insights for predicting fracture morphology and optimizing fracturing design.

Life Cycle Optimization of CO2 Huff ’n’ Puff in Shale Oil Reservoir Coupling Carbon Tax and Embedded Discrete Fracture Model

Summary Amidst escalating environmental pressures, energy-intensive industries, particularly the oil and gas sector, are compelled to transition toward sustainable and low-carbon operations, adhering to the constraints of the environmental economy. While conventional reservoirs have been extensively developed, unconventional reservoirs, such as shale reservoirs, are poised to be the focal point in the future. Carbon dioxide enhanced oil recovery (CO2-EOR), a potent development tool proven effective in shale reservoirs, offers substantial carbon storage potential while significantly augmenting production. However, prior studies have solely optimized shale oil CO2-EOR production based on a singular optimization algorithm with net present value (NPV) as the objective function. In this study, we propose a novel NPV concept incorporating a carbon tax, which incorporates carbon taxes regulated by governments or organizations, thereby guiding carbon offsetting in oil reservoirs. We employ the embedded discrete fracture model (EDFM) approach to strike a balance between the accuracy of shale reservoir fracture simulation and computational efficiency, thereby enhancing timely technical guidance in the field. Subsequently, we compare the existing mainstream reservoir optimization algorithms and introduce a novel life cycle CO2 huff ’n’ puff (HnP) optimization workflow based on low-carbon NPV. The optimized NPV of the target reservoir witnessed an increase of 116.30%, while the optimization time was reduced by 89.47%, and the CO2 storage capacity was augmented by 12.58%. The workflow accelerates the simulation of the CO2 HnP in shale reservoirs, optimizing the production efficiency and CO2 storage capacity of shale reservoirs, and facilitating comprehensive and efficient production guidance for the production site.

Numerical simulation of CO2-ECBM for deep coal reservoir with strong stress sensitivity

CH4 production rate of coalbed methane (CBM) well decreases rapidly during primary recovery in the deeply buried coal seam, resulting in a lot of CH4 residues. CO2 pour into deep coal seam with high stress sensitivity is available for enhancing CH4 recovery by improving permeability for reservoir fracture and displacing CH4 adsorbed in matrix. A coupled adsorp-hydro-thermo-mechanical (AHTM) model for deep methane development is established by considering the coupling relationships of non-isothermal and non-constant pressure competitive adsorption between CO2 and CH4, multi-phase flow, unsteady diffusion, heat transmission and in-situ stress variety. The model is verified by historical production and then used for CO2 enhanced CBM (CO2-ECBM) of deep coal reservoir in a sedimentary basin in Northwest China. The simulation results show that: (1) For primary recovery, permeability in coal reservoir drops rapidly with the development of CBM, which seriously restricts the production of CH4. The permeability of the reservoir decreases from 7.89 × 10−16 m2 to less than 1.50 × 10−16 m2, CH4 production rate in CBM well reduces to below 2000 m3/d, and the average total CH4 content of coal reservoir is reduced by 5.49 m3/t with the decrease of only 1.12 m3/t of average adsorbed CH4 in a production duration of 2000 d (2) With 10 MPa CO2 continuous injection into coal seam after 700d of primary, the permeability for reservoir and CH4 production rate increase while the total CH4 content and adsorption CH4 content in reservoir decrease compared with the primary recovery. (3) CO2 pouring into coal reservoir increases the CH4 production time and rate, which improves CH4 recovery of coal reservoir. And it increases by 23.36 %, 23.07 % and 22.46 % with shut-in thresholds of CH4 production rate of 1000 m3/d, 800 m3/d and 600 m3/d, respectively. The investigation is of great significance for the development of deep coalbed methane.