Fractured Reservoir Research Articles

Exploring pore-scale production characteristics of oil shale after CO2 huff ‘n’ puff in fractured shale with varied permeability

Recent studies have indicated that the injection of carbon dioxide (CO2) can lead to increased oil recovery in fractured shale reservoirs following natural depletion. Despite advancements in understanding mass exchange processes in subsurface formations, there remains a knowledge gap concerning the disparities in these processes between the matrix and fractures at the pore scale in formations with varying permeability. This study aims to experimentally investigate the CO2 diffusion behaviors and in situ oil recovery through a CO2 huff ‘n’ puff process in the Jimsar shale oil reservoir. To achieve this, we designed three matrix-fracture models with different permeabilities (0.074 mD, 0.170 mD, and 0.466 mD) and experimented at 30 MPa and 91 °C. The oil concentration in both the matrix and fracture was monitored using a low-field nuclear magnetic resonance (LF-NMR) technique to quantify in situ oil recovery and elucidate mass-exchange behaviors. The results showed that after three cycles of CO2 huff ‘n’ puff, the total recovery degree increased from 30.28% to 34.95% as the matrix permeability of the core samples increased from 0.074 to 0.466 mD, indicating a positive correlation between CO2 extraction efficiency and matrix permeability. Under similar fracture conditions, the increase in matrix permeability further promoted CO2 extraction efficiency during CO2 huff ‘n’ puff. Specifically, the increase in matrix permeability of the core had the greatest effect on the extraction of the first-cycle injection in large pores, which increased from 16.42% to 36.64%. The findings from our research provide valuable insights into the CO2 huff ‘n’ puff effects in different pore sizes following fracturing under varying permeability conditions, shedding light on the mechanisms of CO2-enhanced oil recovery in fractured shale oil reservoirs.

Prediction of thermal front movement in geothermal reservoirs containing distributed natural fractures

When designing a reinjection scheme for geothermal development, one needs to predict the flow and thermal behavior between the recharge and discharge wells. Premature thermal front breakthrough is of great concern and is often observed in real fields. However, prediction methods based on homogeneous media are prone to overly optimistic estimates. In this study, geothermal reservoirs with vertical fractures which are discretely distributed in the permeable rock are considered, and the streamline simulation is developed and applied to evaluate the thermal front movement, represented by the characteristic times tD*. With 1000 simulation results for stochastically generated natural fracture systems, regression models are developed for the expected values of tD* with minimal information requirements on fracture parameters. In general, the fracture orientation θf has a stronger negative correlation with tD* than the total fracture length Σf. The intensity of natural fractures has opposing effects (delay or advance) on tD* depending on θf, and taking this effect into account improves the quality of the regression model. In addition, when the pressure difference between the doublet wells is available, the model accuracy is further improved by incorporating pressure data into the regression. The prediction models are of practical use for understanding the thermal behavior and designing a reinjection scheme in fractured geothermal reservoirs.

Enhancing Reservoir Zonation through Triple Porosity System: A Case Study

Summary The Asmari-Jahrom reservoirs, located in southwest Iran, are recognized as one of the major fractured reservoirs in the world. Understanding the role of fractures in enhancing hydrocarbon flow and permeability is of utmost importance. In this study, petrophysical conventional logs [neutron porosity (NPHI), density (RHOB), sonic (DT), and gamma ray (GR)] and advanced image logs [formation microresistivity imaging (FMI)] were used to investigate the reservoir properties. The novelty of this study lies in the implementation of triple porosity on reservoir quality and identification of flow units in Asmari-Jahrom reservoirs using petrophysical and borehole image logs. By quantifying fracture and vuggy porosity and correlating them with velocity deviation log and fracture parameters [fracture aperture (VAH) and fracture density (VDC)], it was demonstrated that fracture porosity is directly related to VAH. High peaks were observed in fracture parameters, particularly in VAH diagrams where the velocity deviation log was negative and low. Total porosity from density logs was found to match secondary porosity from petrophysical logs, validating FMI results. However, FMI log resolution was higher, enabling clearer identification of fracture porosity peaks. The velocity deviation log indicated that the predominant type of porosity in the reservoir was matrix (primary) porosity. However, fracture and vuggy porosity were also observed in certain zones. Based on indirect evidence such as drilling mud loss, porosity type (matrix, fracture, and vuggy), porosity amount, and oil saturation, 18 zones were identified to determine quality zones with appropriate reservoir quality. Asmari-Jahrum reservoirs were found to possess high storage and flow capacity. The presence of multiple fracture types, especially longitudinal fractures, contributed to the development of secondary porosity and enhanced flow unit quality. Despite their complexity, these fractured carbonate reservoirs were analyzed comprehensively through integrated petrophysical and FMI log interpretation, enabling optimized reservoir performance and facilitating hydrocarbon production.

Prediction of fractures by using the stress field in medium to deep shale gas reservoirs: A case study of Late Ordovician–early Silurian shale gas reservoirs in the Nanchuan region, South China

Containing representative shale gas reservoirs, the Wufeng–Longmaxi Formations in the Nanchuan region in South China have been modified by three compressional tectonic movements (in the Late Jurassic to Early Cretaceous, Late Cretaceous, and Cenozoic to present). These movements formed deeply buried reservoirs with complex in situ stresses and rapid directional changes, influencing the state of shale gas reservoirs fractures. Numerical modeling applied to model the stress field in the three periods showed that the maximum compressive horizontal principal stress (σHmax), strain rate, and fault slip rate regimes transformed from a thrust and strike-slip regime to a thrust and strike-slip regime to a thrust regime. The σHmax direction changed from NW–SE and WNW–ESE to WNW–ESE and nearly E–W and then to multiple directions. The magnitude of strain rate changed from -16 ∼ -15 to -17.7 ∼ -15.6 to -18.8 ∼ -15.8. The fault slip rate changed from 0 to 0.029 mm/a to 0–0.0026 mm/a to 0–0.0012 mm/a. These data strongly agree with data from drilled wells and outcrops and show that the present-day stress field is the superposed effect of multistage movements. Semiquantitative research was conducted on shale gas fracture openness and fracture development. Fracture openness is favorable when the angle between the σHmax direction and nearby faults is ≤45° and the distance from the fault is >2 km, and fracture development is favorable when the magnitude of the strain rate is <-17.6 and the fault slip rate is <0.00036 mm/a. Accordingly, we predicted fractured shale gas reservoirs.

Deep learning-based dynamic forecasting method and application for ultra-deep fractured reservoir production

Addressing the complex challenges in dynamic production forecasting for the deep-ultra-deep fractured carbonate reservoirs in the Tarim Basin’s Tahe Oilfield, characterized by numerous influencing factors, strong temporal variations, high non-linearity, and prediction difficulties, We proposes a prediction method based on Gated Recurrent Unit networks (GRU). Initially, the production data and influencing factors are subjected to dimensionality reduction using Pearson correlation coefficient and principal component analysis methods to obtain multi-attribute time series data. Subsequently, deep learning modeling of time series data is conducted using Gated Recurrent Unit networks. The model is then optimized using the Optuna algorithm and applied to the dynamic production forecasting of the deep-ultra-deep fractured carbonate reservoirs in the Tahe Oilfield. The results demonstrate that the Gated Recurrent Unit network model optimized by Optuna excels in the dynamic production forecasting of the Tahe fractured carbonate reservoirs. Compared with the traditional method, the mean absolute error (MAE), the root mean square error (MSE) and the mean absolute percentage error (MAPE) are reduced by 0.04, 0.1 and 1.1, respectively. This method proves to be more adaptable to the production forecasting challenges of deep fractured reservoirs, providing an effective means to enhance model performance. It holds significant practical value and importance in guiding the development of fractured reservoirs.

Numerical study of hydraulic fractures propagation in deep fracture-cavity reservoir based on continuous damage theory

Natural fractures and cavities are the primary spaces for oil and gas accumulation in fracture-cavity carbonate reservoirs. Establishing the connection between these spaces and the wellbore through hydraulic fracturing treatment is important for oil and gas extraction from such reservoirs. Due to the discontinuity and heterogeneity of the existing natural fracture-cavity system, anticipating the viability of hydraulic fracturing treatment is troublesome. A new method to simulate the hydraulic fracturing propagation in fracture-cavity reservoirs is proposed based on the continuous damage theory. The method considers the random spatial distribution of fractures and cavities and can simulate the arbitrary expansion of hydraulic fractures in the three-dimensional direction. Based on this method, the influence of different geological and engineering factors on the propagation patterns of hydraulic fractures in the fracture-cavity reservoirs is investigated. It is found that the increase of reservoir burial depth significantly limits the propagation ranges of hydraulic fractures. The propagation modes of hydraulic fractures encountering natural fractures change with increasing burial depth, undergoing a transition from “penetrate and deflect” to ”defect” and then to ”penetrate”. The reduction of horizontal stress difference increases the complexity of hydraulic fractures, but it is not conducive for hydraulic fractures to connect more natural fractures and cavities. The increase in fracturing pump rate is significantly beneficial for hydraulic fractures to connect more natural fractures and cavities. The viscosity of fracturing fluid has a significant impact on the morphology of hydraulic fracture propagation, which undergoes a transition from simple to complex, and then to simple with the change of the fracturing fluid viscosity from low to high. either too high or too low viscosity of the fracturing fluid is not conducive to the connection of more natural fractures and cavities by hydraulic fractures. The obtained conclusions can provide a reference for the design of hydraulic fracturing treatment for fracture-cavity carbonate reservoirs.

Experimental study on the oil recovery characteristics of CO2 energetic fracturing in ultralow-permeability sandstone reservoirs utilizing nuclear magnetic resonance

CO2 energetic fracturing is effective for ultralow-permeability sandstone reservoirs, but research on fractures and CO2 effects at the pore scale is lacking. This study examines their impacts on oil recovery, mobilization sites, residual distribution, and oil mobility limits across pore types. This paper analyzed mineral composition and pore structure of Changji Oilfield cores via scanning electron microscopy (SEM) and X-ray diffraction (XRD). Accurate pore size distribution was determined by fitting mercury intrusion porosimetry (MIP) and nuclear magnetic resonance (NMR) curves using power functions. Fracture and CO2 effects on oil recovery characteristics across pore types were investigated using four sets of NMR experiments: depletion, CO2 energetic depletion, fractured depletion, and CO2 energetic fracturing depletion. The results show that Changji Oilfield cores are mainly composed of quartz (approximately 70 %) and contain clay minerals (about 10.2 %). The cores exhibit intergranular pores and curved lamellar throats. Pore types are categorized into micropores, macropores, and fractures, with diameters ranging from 10 to 100 nm, 0.1–5 μm, and 5–50 μm, respectively. The presence of CO2 reduces the lower limit of oil mobility to 10 nm compared to 30 nm in its absence, mainly by promoting oil expansion. CO2 primarily enhances oil recovery in micropores, while fractures increases recovery in macropores, mobilizing nearby oil and leaving minimal residual oil. In contrast, CO2 mobilizes most of the crude oil across the entire core, resulting in high residual oil content in mobilized areas. CO2 energetic fracturing combines benefits of fractures and CO2, achieving a 24.93 % final oil recovery rate. These findings underscore the importance of this technique for effective development strategies in ultralow-permeability sandstone reservoirs.

Research on productivity of stimulated natural gas hydrate reservoir

Natural gas hydrate (NGH) is a prospective clean energy. Conventional development method of the NGH reservoir by pressure drop in vertical well faces the problems of limited stimulated reservoir volume, low production efficiency, and low conductivity. At present, pressure drop production in various well types and stimulation treatments such as hydraulic fracturing in fracable NGH reservoirs have become the focus. The effects of pressure drop production in vertical well, horizontal well, radial wells, and hydraulic fracturing in vertical and horizontal wells in NGH reservoirs were simulated with HydrateResSim. We simulated the productivity of NGH reservoir for 1000 days with several types of development mode. The productivity is highest in horizontal well staged fracturing (5 stages), followed by pressure drop production in horizontal well, fractured vertical well (single fracture), and radial well (16 holes). The worst effect is obtained through production by pressure drop in single vertical well. The optimal effects were obtained with the fracture spacing of 58 m, the fracture half-length of 100 m and the conductivity of 30 μm2 cm. The horizontal well multi-cluster fracturing significantly enlarges the stimulated area and provides channels for gas migration and enhances productivity.

The effects of fractures on porous flow and heat transfer in a reservoir of a U-shaped closed geothermal system

In geothermal reservoirs, fractures, serving as preferential channels for heat transfer fluid circulation, can cause complicated migration patterns and heat transfer characteristics of the fluids. However, the crucial issue of whether and how fractures within a hydrothermal reservoir of a closed geothermal system (CGS) affect reservoir heat transfer fluid migration and the system’s heat transfer is still poorly understood. In this study, we construct a thermo-hydraulic coupling finite-element model to investigate the effects of fractures on fluid flow and heat transfer enhanced by natural convection in a U-shaped closed geothermal system (UCGS) with a horizontal well. We systematically analyze the responses of fluid migration and heat extraction in the system to key factors, such as fracture aperture, fracture azimuth, fracture distribution, and reservoir permeability. The results show that, in a high permeability reservoir (such as 2 × 10−13 m2), the fracture with an aperture of a millimeter scale can greatly strengthen and control the natural convection induced by heat transfer around the horizontal well in a UCGS, achieving a heat recovery efficiency of six times higher than conduction alone within the reservoir. The fracture azimuth can control the heat production region by guiding the evolution of natural convection. Intersecting network-distributed fractures can effectively improve heat recovery area and performance (more than 15%) compared to a single fracture. Some specific fracture segments within a fracture network may exhibit synergy or inhibition in different heat extraction stages, while a fracture connecting in the deep reservoir and orienting to the horizontal well may lead to heat breakthrough. In addition, a low-permeability interlayer below the horizontal well can restrict the heat recovery (nearly 20% drop in our models), but a fracture penetrating the layer can compensate for this hindrance. The findings of this study can contribute to understanding the thermodynamic mechanisms of fluid flow and heat transfer in a fractured reservoir, and then utilizing them to maximize heat recovery rather than considering conduction only, thus providing scientific insights into engineering practices of the UCGS.

Geometric characteristics of diverting fractures for multi-stage dynamic temporary plugging and diverting fracturing in fractured reservoir

Temporary plugging and diverting fracturing (TPDF) technology constitutes a pivotal stimulation methodology in the advancement of unconventional resources, given its efficacy in establishing communication with natural fractures (NFs). Presently, the comprehension of TPDF is primarily confined to laboratory-scale experiments, with a notable dearth of accurate knowledge regarding the diverting law and geometric characteristics of diverting fractures at the field scale. This study introduces a hydro-mechanical-damage model for hydraulic fracture (HF) propagation, developed through the derivation and refinement of the phase field method. The model integrates the dynamic flow distribution process among multi-perforation clusters under stress interference, alongside the construction of a dynamic transportation and plugging model for the temporary plugging agent in TPDF. Subsequently, a coupled model encompassing multi-cluster and multi-stage dynamic TPDF is established using the finite element method. Utilizing this model, an exploration of the diverting fracture's opening and propagation mechanisms, as well as the impact of stimulation and reservoir factors on geometric characteristics, is conducted at the field scale. The results show that the TPDF model has high accuracy, and for the first time, it realistically simulates the gradual increase and decrease in fracturing pressure in the field after temporary plugging. The diverting fracture propagation is affected by the stress interference from the initial HF (ini HF), NF, and horizontal stress difference. The energy required to open NFs to form a diverting fracture is higher than that to cross NFs after temporary plugging, and there is a strong positive correlation between the energy rise and the approach angle and the horizontal stress difference. The use of multi-scale plugging agents can promote a more uniform distribution of diverting fractures. When the NF angle is near 60°, the diverting fracture has a larger fracture control volume. The NF distribution and the interaction between NF and HF are of great significance to the opening position of diverting fractures in TPDF. According to the propagation pattern of diverting fractures, they can be divided into five categories. The temporary plugging agent can alleviate the directional propagation of HFs caused by NF induction. The alleviating effect is not only controlled by the interaction mode between HF and NF but also related to the NF density. The propagation distance of the diverting fracture formed by the inferior fracture will be about 50% farther compared with the superior fracture. The diverting fractures are mainly interfered by the stress of the HFs in the same perforation cluster at the early stage and mainly interfered by the HFs of different perforation clusters at the middle and late stages.

New Model for Predicting Production Capacity of Horizontal Well Volume Fracturing in Tight Reservoirs.

Production prediction is the most important and comprehensive index to measure the effect of oilfield development, and it is also one of the most fundamental problems in oilfield dynamic analysis. However, the recovery prediction is often affected by many factors. Usually, the recovery is predicted by core experiments, numerical simulations, and mathematical models. The main problem is accurately predicting reservoir recovery based on existing data. This paper proposes a comprehensive prediction model for the problem of recovery. First, the correlation coefficients between 14 factors and recovery were calculated based on Pearson, Spearman, gray correlation, variance selection, univariate selection method, and tree model. Second, the weights of the factors were determined using entropy weighting, CRITIC, and hierarchical analysis to clarify the degree of contribution of different factors to the recovery. Finally, a comprehensive evaluation model was established based on the results of the weighting analysis. The results indicate that the correlation coefficient and weight of porosity, permeability, oil saturation, well spacing, cluster spacing, total fluid volume, and horizontal section length are the most relevant to the recovery. The error between the comprehensive evaluation model and the actual results is less than 3%. Therefore, the method can predict the production capacity of the tight reservoirs. The research results of this paper are of guiding significance for improving the recovery of tight reservoirs.

Imaging faults and fractures with the difference of fast and slow shear-wave splitting reflectivity, Δγ(S): 3D/9C survey in Midland Basin, West Texas, and 3D/3C survey in Washakie Basin, Wyoming

One of the most important applications of shear-wave (S-wave) seismic exploration has been in reservoir fracture characterization. While many advancements have been made over the past 30 years to compute and correct for the long-wavelength kinematics of S-wave splitting (SWS) (fast S-wave polarization directions and slow S-wave time delays), practically no progress has been made in imaging the short-wavelength reflectivity of fractures directly with Δγ(S). This property is the contrast in the SWS anisotropy parameter, γ(S), and represents the reflection amplitude at vertical incidence for changes in fracture density and orientation across an interface. In this article, we examine the Lupin nine-component survey in Midland Basin, Texas, for the technical reliability of imaging fractures in depth with converted P to S waves (PS waves) guided by pure-mode horizontal shear waves and vertical shear waves. Final Δγ(S) amplitude maps for each mode show sensitivity to fractures, faults, and the maximum horizontal stress direction. These maps are computed from the difference between fast and slow S-wave stacks (after SWS analysis and correction) and P-wave amplitude variation with offset gradient stacks. The S-wave difference maps identify an east–west lineament, possibly a strike-slip fault or fracture corridor, that is not observed by P-wave depth slices. Pure-mode S waves and PS waves are orders of magnitude more sensitive to Δγ(S) than P waves. We also review the development of Δγ(S) and find that it has been relatively unexploited by the exploration industry. In addition, we demonstrate that Δγ(S) can be obtained directly from the objective function of the transverse energy to correct for SWS, and show a four-component Alford rotation example from a previous PS-wave survey in the Washakie Basin, Wyoming.

The Effect of Fracturing Fluids Types on Reservoir Fracture Geometry, Production, and Net Present Value

The Effect of Fracturing Fluids Types on Reservoir Fracture Geometry, Production, and Net Present Value

Fracture behavior and fracture surface roughness of high-temperature granite subjected to liquid nitrogen and water cooling

The thermal damage mechanism of water and liquid nitrogen on granite is a key scientific concern in reservoir fracturing. This study conducted fracture tests on high-temperature granite specimens subjected to water and liquid nitrogen cooling. The fracturing process was monitored and the fracture surface roughness was evaluated. The results indicated that the P-wave velocity, peak load, and fracture toughness exhibited a decreasing trend with increasing heating temperature. Specifically, at 150 °C, liquid nitrogen cooling samples exhibited higher fracture toughness than untreated ones. Acoustic emission events at peak load were more prominent in liquid nitrogen cooling samples, indicating higher brittleness and concentrated energy release. Conversely, water cooling samples displayed prolonged post-peak stages, suggesting greater ductility. The size of fracture process zones (FPZ) generally increased with temperature, with water cooling samples consistently exhibiting larger FPZ dimensions compared to liquid nitrogen cooling samples. Despite this, liquid nitrogen cooling resulted in significantly rougher fracture surfaces and numerous small cracks, while water cooling formed more extended through-going fractures. This suggests that high-temperature granite reservoirs by liquid nitrogen fracturing can enhance heat exchange areas more effectively. Additionally, different types of granite exhibit varying responses to temperature changes and cooling treatments, contingent on their unique mineral composition and structure.

Numerical Simulation Study on the Effect of Preinjected CO2 on the Hydraulic Fracturing Behavior of Shale Oil Reservoirs.

Due to the low permeability and apparent mechanical anisotropy of shale reservoirs, shale oil production highly depends on the performance of hydraulic fracturing of the tight reservoir. Pre-injection of CO2 before hydraulic fracturing treatment has been proven beneficial to enhance shale oil production. A comprehensive understanding of the effect of changes in the properties of shale reservoirs after preinjected CO2 on the hydraulic fracturing behavior of shale reservoirs is essential to improve the stimulated reservoir volume (SRV) of shale oil reservoirs. In this study, comprehensive evaluating parameters were proposed to specify the variation of mechanical properties of shale rock at different soaking times of CO2 based on published testing parameters of shale. Accordingly, a three-dimensional (3D) numerical model was established and three groups of horizontal well fracturing cases with different cluster spacings were conducted based on the adaptive FE-DE method to simulate and compare the hydraulic fracturing behavior in the reservoirs with different mechanical properties. We established a quantitative relationship between the alterations in reservoir properties and the stimulated reservoir volume. The results indicate that both the brittleness and conductivity properties of shale rock are dramatically improved as the increment of soaking time of CO2. It is beneficial to improve the SRV, and the initiation pressure is reduced with the increment of soaking time of CO2. However, as the stress shadow effect is involved in the horizontal well fracturing, the complexity of the hydrofracturing crack is significantly enhanced to restrain the development of hydrofracturing crack. When the cluster spacing is larger, the stress shadow effect is weakened, and the weakening effect of CO2 soaking on reservoir is more obvious.

Research on fracture propagation of hydraulic fracturing in a fractured shale reservoir using a novel CDEM-based coupled HM model

Shale reservoirs are usually buried deep, and contain lots of complex natural fractures (NFs) under the influence of tectonic stress and faults. Previous studies usually focus on small-scale reservoir models and there is also a lack of research that completely focuses on NF characteristics. Using the continuous-discontinuous element method (CDEM), a Hydro-Mechanical (HM) coupling model was constructed to explore the propagation mechanism of hydraulic fracture (HF) and the effects of NF characteristics on HF propagation. The results show that as the HF approaches the NFs, the NFs preferentially tend to undergo shear failure, resulting in a decelerated HF propagation rate and an increased injection pressure. After water enters the NFs, the HF rapidly propagates, so the fracture area swiftly increases and the HF has a more tortuous fracture morphology. The NF orientation (α) and the internal friction angle (φ) exhibit a pronounced and distinct effect on HF propagation. Specifically, when α is 30°∼60°, the HF propagation is more tortuous and complex, so it is easier to form a larger transverse reconstruction range. When the NF density (η) is no less than 0.12, the HF tends to open the NFs and form a more tortuous morphology, but a higher η does not necessarily imply a higher fracture complexity. A longer NF (l > 12 m) benefits to improve the longitudinal reservoir reconstruction scope, but has little impact on the overall reconstruction effect. In the presence of stress shadow effect, it is improbable for the HF to completely open the intersecting NFs; instead, it typically opens only a segment or one of them. Consequently, it may be challenging to establish a fracture network with the simultaneous development of primary and branching fractures. Additionally, some water leakage into the inactive NFs gives rise to a decline in both the fracture length and fracture area. The findings can offer theoretical insights for refining the fracturing design in shale reservoirs with NFs.

Development and performance evaluation of re-crosslinkable preformed particle gel under high temperature and high salt conditions

Self-healable hydrogels have attracted significant interests in the fields of environmental protection, oil plugging and electronic sensors, etc. Benefiting from the synergistic contribution of hydrogen bonding and ligand chelation, in this work, we prepared a series of self-healable hydrogels via a simple and inexpensive approach, which overcame the limitations of the intrinsic nature of dynamic covalent bonds and non-covalent interactions under harsh conditions. Systematic study of the effect of temperature, salt concentration and particle size on the physicochemical performance of the re-crosslinking progress revealed that re-crosslinked gels using particles of 0.20–0.28 mm (in a solution with salt concentration of 10%) at 130 °C presented an elastic modulus of 62 Pa at a frequency of 10 Hz and remained elastic after 45 days of aging (elastic modulus: 18,170 Pa). Of particular interest, gel particles with a particle size of 0.125–0.28 mm can be reassembled at temperatures up to 150 °C or salt concentrations up to 20%, which is superior to a plethora of previous reports (self-healing temperature usually less than 130 °C, salt concentration <10%). Employment of the green inexpensive sodium D-gluconate instead of partial acrylamide makes the gel product a promising candidate material for oil plugging, targeting fractured reservoirs for consistent control.

Research on the data-driven inter-well fracture channeling identification method for shale gas reservoirs

The issue of inter-well fracture channeling in shale reservoirs is becoming increasingly prominent, significantly impacting the production of nearby wells. Therefore, it is crucial to accurately determine the location of fracture channeling in order to effectively design anti-channeling measures and optimize reservoir fracturing. In this paper, a data-driven fracture propagation model and fracture channeling identification method are established. In the model, the fracture morphology is fitted by the bottom-hole flowing pressure constraint. The bottom-hole flowing pressure (pwp) calculated by the construction pump pressure and the fluid wellbore flow is mainly considered as the real solution. The bottom-hole flowing pressure (pwf) calculated by the construction displacement and the fracture morphology is used as the constraint variable, and the fracture parameters are changed using the SPSA optimization algorithm to realize the dynamic fitting of the fracture morphology. In order to accurately describe the position of fracture channeling, the seepage radius of the fracture boundary is introduced to calculate the volume of fracture reconstruction. The volume coefficient of repeated reconstruction is used as the quantitative evaluation index of fracture channeling. This approach enables an accurate depiction of the position of fracture channeling. Finally, the model method is applied to the actual fracture channeling well. The study shows that the fracture length of the well inversion is greater than the well spacing, and there is a possibility of inter-well fracture channeling. The volume coefficient of repeated reconstruction is 8%, similar to the critical fracture channeling index. There are nine fracturing sections with fracture channeling, and the maximum fracture channeling coefficient is 14.2%. This paper successfully explains the reason for cross-well fracture channeling, and its conclusion aligns with the actual monitoring results. The proposed method in this paper effectively identifies the location of fracture channeling and offers guidance for optimizing channeling prevention in subsequent designs.

Study of stress field induced by natural fracture and its influence on hydraulic fracture propagation

The change of fracture propagation direction caused by stress interference between fractures is one of the main reasons that affect shale gas productivity. Natural fractures will be damaged by the induced stress, and the induced stress field produced by natural fracture damage will in turn affect the propagation of hydraulic fractures. Previous studies usually ignored the impact of stress field variation caused by natural fracture damage, leading to inaccurate fracture propagation simulation results. A new model for simulating hydraulic fracturing-induced stress field is established with consideration of the influence of natural fracture damage. Then, the natural fracture-induced stress is analyzed in open and closed fracture states. Through superposition of stress fields of natural fractures and hydraulic fractures, the interaction among open and closed natural fractures, reservoir and hydraulic fracture, and the corresponding fracture property evolution are studied. The results demonstrate that induced stress is not affected by elastic modulus and Poisson's ratio of the rock. The induced stress difference at the fracture tip is proportional to the net pressure and the length of hydraulic fractures. The results provide guidance for the optimal design of fracturing. When the deflection angle of hydraulic fracture is less than 90°, the maximum induced stress difference at the fracture tip decreases with the reduction in the deflection angle. When the deflection angle of hydraulic fracture is smaller than 90° or the deflection angle of natural fracture is smaller than 45°, the steering of hydraulic fracture is less hindered, which is beneficial to the formation of complex fracture network.

Simulation of Gas Fracturing in Reservoirs Based on a Coupled Thermo-Hydro-Mechanical-Damage Model

Gas fracturing technology for enhancing rock permeability is an area with considerable potential for development. However, the complexity and variability of underground conditions mean that a variety of rock physical parameters can affect the outcome of gas fracturing, with temperature being a critical factor that cannot be overlooked. The presence of a temperature field adds further complexity to the process of gas-induced rock fracturing. To explore the effects of temperature fields on gas fracturing technology, this paper employs numerical simulation software to model the extraction of shale gas under different temperature conditions using gas fracturing techniques. The computer simulations monitor variations in the mechanical characteristics of rocks during the process of gas fracturing. This analysis is performed both prior to and following the implementation of a temperature field. The results demonstrate that gas fracturing technology significantly improves rock permeability; temperature has an impact on the effectiveness of gas fracturing, with appropriately high temperatures capable of enhancing the fracturing effect. The temperature distribution plays a crucial role in influencing the results of gas fracturing. When the temperature is low, the fracturing effect is diminished, resulting in a lower efficiency of shale gas extraction. Conversely, when the temperature is high, the fracturing effect is more pronounced, leading to a higher shale gas production efficiency. Optimal temperatures can enhance the efficacy of gas fracturing and consequently boost the efficiency of shale gas extraction. Changes in the parameters of the rock have a substantial impact on the efficiency of gas extraction, and selecting suitable rock parameters can enhance the recovery rate of shale gas. This paper, through numerical simulation, investigates the influence of temperature on gas fracturing technology, with the aim of contributing to its improved application in engineering practices.