Fractured Reservoir Research Articles

Investigation into the Variation Law of Network Fracture Conductivity in Unconventional Oil and Gas Reservoirs

The network fracturing technique is a key technology for increasing effective reservoir volume and enhancing production in shale oil and gas. The fracture network’s conductivity is one of the crucial factors affecting the efficient development of shale gas. To evaluate the variation patterns and influencing factors of the conductivity of network fractures, this study employed a proppant conductivity evaluation system and an equivalent theory testing method. It investigated the conductivity of propped and self-propped fractures under different angles and numbers of fractures. Experimental results showed that fractures with proppant support had higher conductivity than unsupported fractures. Smaller angles between secondary and main fractures resulted in greater conductivity. The conductivity of multi-fracture structures increased with the number of fractures. Under low-closure pressure conditions, self-propped fractures exhibited significantly higher conductivity than propped fractures, but this trend reversed under high closure pressure. This experimental research provides guidance for constructing network fractures with high conductivity in unconventional oil and gas reservoir fracturing.

Study on the influence of rock vertical heterogeneity on the vertical extension law of hydraulic fractures

The vertical expansion of fractures during hydraulic fracturing in low-permeability bottom-water oil and gas reservoirs is a crucial factor that significantly influences stimulation effectiveness. Fractures propagate concurrently in three dimensions; however, as operation time for fracturing and fracture length increase, there is a gradual reduction in fracture height. In the absence of a barrier layer or with inadequate strength and thickness, fractures may extend vertically or oscillate through it leading to an “unyielding” fractured state that impedes successful operations. This study introduces a mathematical model delineating the vertical expansion of hydraulic fractures (HFs) while computing stress intensity factors at upper and lower tips of each individual fracture. We use numerical methods to examine how vertical heterogeneity within reservoir rocks impacts laws governing vertical fracture propagation while conducting sensitivity analysis for making informed decisions on design parameters for hydraulic fracturing operations. The research results indicate that an escalation in stress disparity and increased toughness results in diminished height for HFs. Hydraulic fracturing augments fracture lengths along their respective axes. Nevertheless, if gap stress disparity surpasses net fluid pressure, a reduction in fracture length is observed. With an increasing ratio between local stress gradient versus fluid gravity gradient, HFs persistently advance vertically across cap and bed formations.

Chemical-Assisted CO2 Water-Alternating-Gas Injection for Enhanced Sweep Efficiency in CO2-EOR.

CO2-enhanced oil recovery (CO2-EOR) is a crucial method for CO2 utilization and sequestration, representing an important zero-carbon or even negative-carbon emission reduction technology. However, the low viscosity of CO2 and reservoir heterogeneity often result in early gas breakthrough, significantly reducing CO2 utilization and sequestration efficiency. A water-alternating-gas (WAG) injection is a technique for mitigating gas breakthrough and viscous fingering in CO2-EOR. However, it encounters challenges related to insufficient mobility control in highly heterogeneous and fractured reservoirs, resulting in gas channeling and low sweep efficiency. Despite the extensive application and research of a WAG injection in oil and gas reservoirs, the most recent comprehensive review dates back to 2018, which focuses on the mechanisms of EOR using conventional WAG. Herein, we give an updated and comprehensive review to incorporate the latest advancements in CO2-WAG flooding techniques for enhanced sweep efficiency, which includes the theory, applications, fluid displacement mechanisms, and control strategies of a CO2-WAG injection. It addresses common challenges, operational issues, and remedial measures in WAG projects by covering studies from experiments, simulations, and pore-scale modeling. This review aims to provide guidance and serve as a reference for the application and research advancement of CO2-EOR techniques in heterogeneous and fractured reservoirs.

Insight into the dynamic tensile behavior of deep anisotropic shale reservoir after water-based working fluid cooling

During deep shale gas production, flowing water-based working fluid inevitably cools shale reservoirs around boreholes and some fractures, and possible extraction methods induce dynamic stresses. To understand the dynamic tensile behavior of deep anisotropic shale reservoir after water-based working fluid cooling, a split Hopkinson pressure bar was used for performing the dynamic Brazilian tests on shale samples with bedding angles of 0°, 30°, 45°, 60° and 90° after reservoir temperature realization (25–200 °C) and water cooling. The results illustrate that dynamic tensile strength of shale samples decreases gradually as reservoir temperature increases under the loading rates 100–1000 GPa/s. From room temperature to 200 °C the most strength deterioration appears on samples with the bedding angle of 90°. A dynamic tensile strength deterioration model for deep shale reservoirs after water-based working fluid cooling is proposed considering the influence of loading rate and bedding angle. Geometrical trajectories of the main failure cracks are separated into three types, i.e., fully central tensile failure, tensile-shear failure and fully shear failure (sliding of bedding planes). For samples with bedding angles of 30°, 45° and 60°, increasing reservoir temperature encourages tensile failure to change into shear failure. The roles that bedding planes play in interacting with failure crack growth are summarized as IP mode (intersecting propagation), TP mode (turning propagation) and PP mode (promoting propagation). Anisotropic dynamic tensile strength responses are systematically discussed by using thermal stress simulation in ABAQUS, microstructure analyses, crack interaction conditions and the one-dimensional stress wave propagation theory. Based on experimental observations, field implications in borehole stability and fracturing of deep shale reservoirs are proposed under medium and high loading rates. This work is instrumental in providing valuable information and technology assistance for real deep shale gas production projects.

Resurgent dome and super-hot enhanced geothermal system: The Sahinkalesi Massif within the Hasandag Stratovolcanic Province, Central Anatolia, Turkey

The Sahinkalesi, a volcanic dome located NNE of Hasandağ, Türkiye exhibits anomalous heat flow value, geothermal gradient and the Curie point depth is located at very shallow depth in this region. Our investigation indicates presence of super-critical thermal regime (378°C) at about 4 km depth and the MT analysis indicate shallow magma chamber at about 5 km depth. The crust is relatively thin below this region with the low-velocity region located at depth of about 36 km. Thermo-Hydro-mechanical model investigation has been carried out using finite element discretization technique. For faulted zone reservoir models, 30 years of geothermal energy exploitation does not cause thermal breakthrough for mass flow rates up to 500 kg/s, however, the mean stress developed in the reservoir becomes much larger and may be unsustainable for the reservoir stability. To ensure the success of a fractured reservoir model, the use of multiple wellbores is recommended. In the case of a closed-loop geothermal system, the primary concern is the control of thermoelastic stress. This can be achieved either by increasing the wellbore depth while reducing the injection mass flow rate, or by extending the wellbore's horizontal component. The outlet temperature in both the cases maintained at 275°C. This is the first time a superhot EGS site has been identified in Türkiye.

Numerical Simulation of Non-Darcy Flow in Naturally Fractured Tight Gas Reservoirs for Enhanced Gas Recovery

In this work, we analyze non-Darcy two-component single-phase isothermal flow in naturally fractured tight gas reservoirs. The model is applied in a scenario of enhanced gas recovery (EGR) with the possibility of carbon dioxide storage. The properties of the gases are obtained via the Peng–Robinson equation of state. The finite volume method is used to solve the governing partial differential equations. This process leads to two subsystems of algebraic equations, which, after linearization and use of an operator splitting method, are solved by the conjugate gradient (CG) and biconjugate gradient stabilized (BiCGSTAB) methods for determining the pressure and fraction molar, respectively. We include inertial effects using the Barree and Conway model and gas slippage via a more recent model than Klinkenberg’s, and we use a simplified model for the effects of effective stress. We also utilize a mesh refinement technique to represent the discrete fractures. Finally, several simulations show the influence of inertial, slippage and stress effects on production in fractured tight gas reservoirs.

Use digital rock physics to characterize velocity and attenuation signatures of deep cavity-fracture carbonate reservoirs

Abstract Conventional rock physics experiments and well logging analyses face challenges in deep carbonate formation containing meter-scale cavity-fracture system, since it is unfeasible to extract representative samples from targeted formation. In this study, differing from the conventional digital rock models at the core scale, we construct a digital rock model from realistic outcrop images with meter-scale heterogeneity of cavities and fractures. Using a dynamic stress–strain simulation, we investigate how reservoir type, fracture density and spacing, cavity porosity and size, fluid saturation, and connectivity influence wave dispersion and attenuation. By selecting the simulation frequency of 0.3 MHz approximately corresponding to the field seismic measuring frequency of 30 Hz, the simulation results can reflect the realistic seismic velocity and attenuation characteristics of deep carbonate reservoir rocks. We find that the P-wave velocity decreases linearly with increasing fracture and cavity porosity. The P-wave attenuation is sensitive to variations in fracture density but shows limited sensitivity to changes in cavity porosity and size. Fractures with narrower spacing result in higher attenuation when fracture density remains constant. Deep carbonate rocks with cavity-fracture systems saturated with two immiscible fluids display enhanced attenuation compared to fully saturated conditions. The velocity demonstrates an almost linear increase with water saturation, while attenuation initially increases before decreasing at a peak water saturation of 70%–80%. The connectivity between fractures and cavities significantly influences the attenuation behavior. Our simulation results provide valuable guidance for seismic data processing and interpretation of deep carbonate reservoir rocks with cavity-fracture systems.

Research on Horizontal Well Multi-Fracture Propagation Law under the Synergistic Effect of Complex Natural Fracture and Reservoir Heterogeneity

Conventional fracturing design generally only considers the propagation of a single fracture in homogeneous storage, but the heterogeneity characteristics of the reservoir and the development of complex natural fractures will affect the fracturing effect. In order to study the horizontal well fracture propagation law under the synergistic effect of complex natural fracture reservoir heterogeneity, the globally embedded cohesive element finite model is established, and the heterogeneous reservoirs are built by Python programming. The influencing factors of multi-fracture propagation with heterogeneous reservoirs are analyzed, including the in situ stress difference, the injection rate of fracturing fluid, the perforation spacing, and the perforating clusters number. The results show that the heterogeneity and the natural fracture of the reservoir will affect the in situ stress distribution and propagation direction. When the in situ stress difference is low, the reservoir heterogeneity and natural fractures have a great influence on the fracture morphology. With the increase in injection rate, the fracture length and fracture width increase. With the in situ stress difference increase, the fracture deflection angle decreases. With the increase in fracturing fluid injection rate, the fracture length increases. The number of hydraulic fractures communicating with natural fractures increases with the natural fracture number and the number of perforation clusters under the synergistic effect of complex natural fracture and reservoir heterogeneity.

Evaluation of Key Development Factors of a Buried Hill Reservoir in the Eastern South China Sea: Nonlinear Component Seepage Model Coupled with EDFM

The HZ 26-B buried hill reservoir is located in the eastern part of the South China Sea. This reservoir is characterized by the development of natural fractures, a high density, and a complex geological structure, featuring an upper condensate gas layer and a lower volatile oil layer. These characteristics present significant challenges for oilfield exploration. To address these challenges, this study employed advanced embedded discrete fracture methods to conduct comprehensive numerical simulations of the fractured buried hill reservoirs. By meticulously characterizing the flow mechanisms within these reservoirs, the study not only reveals their unique characteristics but also establishes an embedded discrete fracture numerical model at the oilfield scale. Furthermore, a combination of single-factor sensitivity analysis and the Pearson correlation coefficient method was used to identify the primary controlling factors affecting the development of complex condensate reservoirs in ancient buried hills. The results indicate that the main factors influencing the production capacity are the matrix permeability, geomechanical effects, and natural fracture length. In contrast, the impact of the threshold pressure gradient and bottomhole flow pressure is relatively weak. This study’s findings provide a scientific basis for the efficient development of the HZ 26-B oilfield and offer valuable references and insights for the exploration and development of similar fractured buried hill reservoirs.

Quantification of the effect of fracturing on heterogeneity and reservoir quality of deep-water carbonate reservoirs

The Shiranish Formation represents one of the most important fractured reservoirs in northern Iraq. In this work, the petrophysical properties of the formation have been fully characterised using microscopy, core analysis, and well log analysis using conventional methods as well as new quantitative diagenetic approaches. During this work we have developed methods to quantify a petrophysical heterogeneity index (χ), reservoir quality indicator (RQI), and fracture effect index (FEI) for each of the stratigraphic units of the formation. The FEI was calculated by dividing the difference between the mean permeability of the wireline log data and the mean permeability of the unfractured core plug samples by the difference between the mean porosity of the wireline log data and the mean porosity of the unfractured core plug samples. This study shows that the Shiranish Formation has a fracturing pore system in all the characterised units, but it is particularly well developed in U.4, which shows the best reservoir quality (A and B). The new methods developed in this study can be applied to any carbonate formation to provide a trustworthy way to obtain a reservoir quality indicator linked to the petrophysical heterogeneity of the studied formation.

Mitigation of Fracturing Fluid Leak-Off and Subsequent Formation Damage Caused by Coal Fine Invasion in Fractures: An Experimental Study

During the hydraulic fracturing process of coalbed methane (CBM) reservoirs, significant amounts of secondary coal fines are generated due to proppant grinding and crack propagation, which migrate with the fracturing fluid into surrounding fracture systems. To investigate whether coal fines can form plugs to reduce fluid leak-off during the hydraulic fracturing stage, we conducted physical simulation experiments on coal seam plugging and unplugging to demonstrate that coal fines indeed contribute to reducing fluid leak-off during hydraulic fracturing. We also explored the plugging mechanisms of coal fines under different concentrations and particle sizes in fracturing fluids, and revealed the damage law of coal fines of temporary plugging on reservoir permeability. Research results indicate the leak-off volume of fracturing fluids containing coal fines is lower than an order without coal fines, demonstrating a significant effect of coal fines in decreasing fluid leak-off. The temporary plugging rate of coal fines increases with higher concentrations and decreases with larger particle sizes, achieving rates exceeding 90%. The high temporary plugging effect of coal fines results from the superposition of internal and external filter cakes. Under conditions of small particle size and high concentration, the damage to fractures during the fine return process is minimized. Considering the potential damage of coal fines to propping fractures and wellbore, the concentration of coal fines in fracturing fluids should be kept relatively low while ensuring a high temporary plugging effect. Overall, these findings provide crucial insights into optimizing the temporary plugging performance of coal fines during the hydraulic fracturing stage and controlling their behavior during the fracturing fluid flow-back stage, thereby enhancing reservoir fracturing effectiveness and improving CBM production rates.

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.