Natural Fracture Permeability Research Articles

Predicting gas flow rate in fractured shale reservoirs using discrete fracture model and GA-BP neural network method

In the process of shale gas exploitation, the hydraulic fracturing technology is generally used to generate the stimulate reservoir volume (SRV). The network connectivity between natural fractures (NFs) and hydraulic fractures (HFs) significantly affects gas production rate in the hydraulic fracturing stage. To study the influence of natural fracture characteristics on gas flow behavior, a discrete fracture model considering matrix and fracture behaviors is developed. It is found that the increase of natural fracture permeability and distribution density leads to the increase of gas production rate, whereas large orientation angle may cause its decrease. To determine the nonlinear relationship between the natural fracture parameters and gas production rate, the method of back propagation (BP) neural network with genetic algorithm (GA) was applied to make intelligent prediction for the shale gas production. The gas flow rate values for different natural fracture parameters (e.g., permeability, density, orientation) were calculated by discrete fracture model, and used as input data for training and prediction in the GA-BP neural network. Results demonstrate the applicability of forecasting model, which is suitable for shale gas prediction during the operation of horizontal wells if more data profiles could be collected.

Numerical Modeling and Simulation of Fractured-Vuggy Reservoirs Based on Field Outcrops

We propose a novel workflow to investigate the complex flow behaviors and remaining oil distribution related to the oil–gas–water three-phase system based on information from typical outcrops of fractured-vuggy reservoirs. A refined geological model is built to represent the size, geometry, and spatial distribution of the karst caves and fractures extracted from the field outcrop photographs. The combination of the perpendicular bisector (PEBI) grid technique and the control-volume finite difference method is adopted for space discretization. We have validated the numerical model against experimental data. Numerical simulations were performed to explore the impacts of the permeability of karst cave and natural fractures and the position of natural water bodies upon oil production performance. Numerical results indicate that (1) the cave permeability has few impacts on the oil production, yet the fracture permeability plays a significant role in determining the oil recovery; (2) a higher permeability of the fractures will lead to a longer period of time for no-water oil production and, thus, a higher oil recovery; (3) the position of natural water body shows significant impacts on oil recovery, e.g., a short distance between the natural water body and the production well tends to form preferential passages, causing severe reduction of water flooding range; and (4) the distribution of remaining oil is controlled by spatial patterns of the fractured-vuggy system and reservoir development schemes. We found that the remaining oil is mainly distributed along the model boundaries and at the corner of the caves with single or multiple connection/s to fractures.

Physical Simulation Experiments of Hydraulic Fracture Initiation and Propagation under the Influence of Deep Shale Natural Fractures

Horizontal wells’ multi-section and multi-cluster hydraulic fracturing plays an important role in the efficient development of shale gas. However, the influence of the perforating hole and natural fracture dip angle on the process of hydraulic fracture initiation and propagation has been ignored in the current researches. This paper presents the results related to a tri-axial large-scale hydraulic fracturing experiment under different natural fracture parameters. We discuss the experimental results relating to the near-wellbore tortuosity propagation of hydraulic fractures. Experimental results showed that the triaxial principal stress of the experimental sample was deflected by the natural fracture, which caused significant near-wellbore tortuosity propagation of the hydraulic fractures. The fractures in most rock samples were not perpendicular to the minimum horizontal principal stress after the experiment. As well, the deflection degree of triaxial principal stress direction and the probability of hydraulic fractures near-wellbore tortuosity propagation decreased with the increase of the natural fracture dip angle. After hydraulic fractures’ tortuous propagation, the hydraulic fractures will propagate in the direction controlled by the triaxial stress in the far-wellbore area. For reservoirs with natural fractures, proppant in hydraulic fracturing should be added after the fractures are fully expanded to prevent sand plugging in tortuous fractures. When the permeability of natural fractures is low, the volume of fracturing fluid entering natural fractures is small, and hydraulic fractures are easy to pass through the natural fractures.

Investigation of coupled hydro-mechanical modelling of hydraulic fracture propagation and interaction with natural fractures

Various fracture patterns may develop through hydraulic fracture propagation and interaction with natural fractures which may substantially enhance connectivity and connected fracture surface area in low-permeability formations. Key factors controlling this behavior are analyzed using the continuum simulator TOUGHREACT-FLAC3D that couples the evolution of stress and deformation (FLAC3D) with reactive fluid flow (TOUGHREACT) in fractured rock. The three potential interaction scenarios are accommodated - for the hydraulic fracture to directly cross, stay arrested by, or reinitiate from the intersected natural fracture. The results show that the combined effects of approach-angle and differential stress affect the normal closure response acting on fractures. Also, larger approach-angles, greater stress differences, and higher fracture shear strength favor direct crossing, with tensile stresses more readily transferred to the far-side of the approached natural fracture. Higher injection rates accelerate buildup of wellbore and fracture pressures which lead to more rapid propagation of the hydraulic fracture. Higher injection rates also increase the wellbore pressure and pressure gradient when injection rate exceeds leak-off rate of fractures arrested by the natural fracture. The presence of only single natural fractures results in faster hydraulic fracture propagation and greater propagation length driven by higher developed wellbore pressures than where dual natural fractures are present. The presence of dual parallel natural fractures hinders the propagation of the hydraulic fracture along its preferred original path as a result of greater and redistributed leak-off and diminution of pressure through the natural fractures. Increased natural fracture permeability slows hydraulic fracture propagation by increasing fluid flow and resulting pressure dissipation by the natural fractures. Combined, these factors influence mechanisms of fracture propagation and interaction, and evolution of flow paths, which are essential in design of hydraulic fracturing treatments, hydro-mechanical characterization and prediction of the response of stimulated fracture networks.

Thermal-hydraulic-mechanical analysis of enhanced geothermal reservoirs with hybrid fracture patterns using a combined XFEM and EDFM-MINC model

The long-term fluid circulation of Enhanced Geothermal Systems (EGS) involves complex coupled Thermal-Hydrological-Mechanical (THM) processes dominated by both hydraulic and activated natural fractures. The simulation of such multiphysical processes is known to be a challenging problem. In this work, we have developed an integrated numerical approach to advance the multiphysical simulation of EGS. In our model, the hydraulic fractures of arbitrary shapes in response to pressure changes and thermal strains are handled by the three-dimensional (3D) eXtended Finite Element Method (XFEM). The induced/natural fractures are incorporated into the model and treated as one continuum of the Multiple INteracting Continua (MINC) for the investigation of their impacts. A TOUGH -based program, TOUGH2-EGS, is utilized to simulate the Thermal-Hydrological processes. The 3D Embedded Discrete Fracture Method (EDFM), compatible with the 3D XFEM, is adopted to model the hydraulic fractures. Sensitivity analyses are performed for this model in terms of injection temperature and thermal expansivity. The hybrid EDFM and MINC model is established and analyzed for an EGS with both hydraulic and induced/natural fractures. The convergence performance of the single-fracture model shows that an appropriate stiffness coefficient is essential for this model and different choices of the coefficient values result in distinct behaviors. Our numerical results illustrate that the fracture aperture is opened by the cold fluid injection and the reservoir performance is dominated by the thermal stress/strain, which highlights the necessity of multiphysical simulation. In the hybrid model, the enhancement of the natural fracture permeability notably delays the thermal breakthrough by allowing injected fluid to contact more hot reservoirs. The novelties of this work lie in three aspects. Firstly, the combined 3D XFEM and EDFM is capable of handling arbitrary fracture shapes in a 3D EGS model. Secondly, the hybrid hydraulic and induced/natural fracture model enables us to establish the stimulated reservoir volume of the EGS and investigate the operational and geological parameters. Thirdly, the introduction of fracture stiffness stabilizes the numerical solution.

Representative elementary surface for morphology and permeability of natural rock fractures

Representative elementary surface for morphology and permeability of natural rock fractures

Development and Application of New Fracturing Fluid System for Shale Oil Reservoir Displacement

Shale reservoir has tight reservoir, ultra-low permeability and poor development of natural fractures, which need to be completed by fracturing reconstruction. There are some problems in conventional fracturing fluid construction, such as serious reservoir damage, poor salt resistance, inability to reuse flowback fluid, poor dispersion and wetting change performance. According to the characteristics of reservoir and the problems existing in the construction, a hydraulic fracturing fluid system for shale oil reservoir with surfactant as its main component has been developed. There is no residue after the thickener is broken, and the damage to the reservoir is small. It's salt resistant is 100000mg/L, can realize the reuse of flowback liquid and reduce the oil water interfacial tension to 10-3mN/m level because of good dispersion. At present, the application effect is good at the 725 strata of 13 Wells in H100 platform.

Permeability evolution during pressure-controlled shear slip in saw-cut and natural granite fractures

Fluid injection into rock masses is involved during various subsurface engineering applications. However, elevated fluid pressure, induced by injection, can trigger shear slip(s) of pre-existing natural fractures, resulting in changes of the rock mass permeability and thus injectivity. However, the mechanism of slip-induced permeability variation, particularly when subjected to multiple slips, is still not fully understood. In this study, we performed laboratory experiments to investigate the fracture permeability evolution induced by shear slip in both saw-cut and natural fractures with rough surfaces. Our experiments show that compared to saw-cut fractures, natural fractures show much small effective stress when the slips induced by triggering fluid pressures, likely due to the much rougher surface of the natural fractures. For natural fractures, we observed that a critical shear displacement value in the relationship between permeability and accumulative shear displacement: the permeability of natural fractures initially increases, followed by a permeability decrease after the accumulative shear displacement reaches a critical shear displacement value. For the saw-cut fractures, there is no consistent change in the measured permeability versus the accumulative shear displacement, but the first slip event often induces the largest shear displacement and associated permeability changes. The produced gouge material suggests that rock surface damage occurs during multiple slips, although, unfortunately, our experiments did not allow quantitatively continuous monitoring of fracture surface property changes. Thus, we attribute the slip-induced permeability evolution to the interplay between permeability reductions, due to damages of fracture asperities, and permeability enhancements, caused by shear dilation, depending on the scale of the shear displacement.

A composite model based on semi-analytical method for multiwell horizontal pad with stimulated reservoir volume

The multiwell horizontal pad is an effective method to enhance oil recovery for unconventional reservoirs. Microseismic evidence indicates that the stimulated reservoir volume (SRV) may have originated in the overlap region created by multi-well fracturing. However, the majority of SRV modeling studies have concentrated on a single well, ignoring the interference from offsetting wells. In this study, a novel model for modeling the SRV and multiwell horizontal pad in unconventional reservoirs is developed using an effective semi-analytical method. The proposed semi-analytical model is capable of simulating the behaviors of a multiwell horizontal pad with an irregularly shaped SRV and an impermeable boundary. The transient pressure behaviors of the multiwell horizontal pad with SRV are significantly different than that of a single isolated well, as demonstrated by the results. The linear flow between wells, the pseudoradial flow (PRF) of the multiwell pad in SRV, the transitional flow, and the final pseudoradial flow (PRF) of the multiwell pad all correspond to an extremely unusual transient pressure response. Due to the high flow capability of SRV, pressure diffusion occurs at a faster rate, resulting in the appearance of these flow regions in advance. Sensitivity analysis confirms that as the scale of SRV increases, the duration of the flow influenced by the SRV increases. The SRV and compensating wells result in a negligible PRF, while the pressure behaviors exhibit a gradual rise. This phenomenon may serve as a demonstration of the extremely rare occurrence of radial flow or PRF in unconventional reservoirs. The horizontal line value for the PRF in SRV is proportional to the total production of the well pad. The horizontal line value for the final PRF is also related to the unstimulated region's mobility ratio, the well pad's production rate and 0.5. The case in Junggar Basin shows that the natural fracture permeability in the SRV is 2.5 mD, the matrix permeability is 0.044 mD, the rectangular SRV side lengths are 1600 m and 880 m, the mobility ratio and dispersion ratio are 15, and the wellbore storage coefficient is 0.5 m3/MPa.

Investigating the Impacts of Nonuniform Proppant Distribution and Fracture Closure on Well Performance in Shale Gas Reservoirs

The nonuniform distribution of proppant in hydraulic fractures is an essential factor determining the accuracy of well performance evaluation in shale gas reservoirs. In particular, unpropped and propped parts hold distinct closure behavior. To study the impacts of distinct closure behavior between unpropped and propped parts in fracture on gas production, we combine the proppant transport simulation and the 3D hydromechanical coupling simulation. This study quantitatively indicates the significant effects of nonuniform proppant distribution and fracture closure on well performance in shale gas reservoirs. By comparing the well performances with three kinds of typical proppant distribution at the same injection volume, the distribution accumulating near the wellbore is recommended as it can reduce the impact of unpropped fracture and exploit more gas. In addition, the cases with higher natural fracture permeability are found to have less difference in the well performance with different proppant coverages. Therefore, the impacts of nonuniform proppant distribution and fracture closure on well performance in shale gas reservoirs should be investigated comprehensively.

Modeling and Economic Analyses of Graded Particle Injections in Conjunction with Hydraulic Fracturing of Coal Seam Gas Reservoirs

Summary Hydraulic fractures can enhance well productivity from stress-sensitive naturally fractured reservoirs, such as coalbed methane or coal seam gas (CSG) reservoirs. Graded proppant injection (GPI) has been proposed to enhance long-term, far-field interconnectivity between the created hydraulic and short-term, enhanced natural fracture permeability, resulting from fracture fluid leakoff and lowered net effective stress. This novel study shows how applying GPI with hydraulic fracturing treatments resulting in an increased stimulated reservoir volume (SRV) can enhance well productivity and improve CSG well economics. A commercially available reservoir model and history-matched hydraulically fractured coal seam case are used to evaluate well performance differences between a hydraulic fractured reservoir and one including GPI application. A dual-porosity system and the Palmer and Mansoori model are used to simulate initial and long-term permeability accounting for reservoir depletion (i.e., increased net effective stress and matrix shrinkage). A previously validated case study is used to describe the post-embedment benefits of GPI based on the porosity model and history-matched reservoir properties. A net present value (NPV) can then be calculated for each scenario, based on the production differences and typical Australian CSG costs. Our results show that permeability enhancement is achieved beyond the hydraulically fractured region for all post-GPI stimulation cases. An optimal SRV can be found relative to permeability that maximizes the incremental NPV from GPI application. The next most significant parameters after permeability that influence the economic outcomes are fracture porosity and coal compressibility. A larger SRV yields higher cumulative gas production over 30 years with up to 7.2 times increase over gas production without GPI. This study substantially increases our understanding of how to model and understand the benefits of GPI application along with hydraulic fracturing to increase the SRV in CSG wells.

Lab-Scale Permeability Enhancement by Chemical Treatment in Fractured Granite (Cornubian Batholith) for the United Downs Deep Geothermal Power Project, Cornwall (UK)

A hydrothermal doublet system was drilled in a fault-related granitic reservoir in Cornwall. It targets the Porthtowan Fault Zone (PTF), which transects the Carnmenellis granite, one of the onshore plutons of the Cornubian Batholith in SW England. At 5058 m depth (TVD, 5275 m MD) up to 190 °C were reached in the dedicated production well. The injection well is aligned vertically above the production well and reaches a depth of 2393 m MD. As part of the design process for potential chemical stimulation of the open-hole sections of the hydrothermal doublet, lab-scale acidification experiments were performed on outcrop analogue samples from the Cornubian Batholith, which include mineralised veins. The experimental setup comprised autoclave experiments on sample powder and plugs, and core flooding tests on sample plugs to investigate to what degree the permeability of natural and artificial (saw-cut) fractures can be enhanced. All samples were petrologically and petrophysically analysed before and after the acidification experiments to track all changes resulting from the acidification. Based on the comparison of the mineralogical composition of the OAS samples with the drill cuttings from the production well, the results can be transferred to the hydrothermally altered zones around the faults and fractures of the PTF. Core Flooding Tests and Autoclave Experiments result in permeability enhancement factors of 4 to >20 and 0.1 to 40, respectively. Mineral reprecipitation can be avoided in the stimulated samples by sufficient post-flushing.

Controls of interlayers on the development and distribution of natural fractures in lacustrine shale reservoirs: A case study of the Da'anzhai member in the Fuling area in the eastern Sichuan Basin

Lacustrine shale reservoirs with interbedded organic-rich shales and thinly layered tight shell limestones are mainly developed in the Da'anzhai Member of the Lower Jurassic Ziliujing Formation in the Fuling area. These reservoirs generally have low porosities and permeabilities. Natural fractures provide effective spaces for these reservoirs and significantly improve fluid flow capability. However, little research has been conducted on the genesis and distribution of fractures in the Da'anzhai Shale Member. This study aims to understand the features, distribution, and factors that influence natural fractures of these shale reservoirs in the study area. Based on field outcrop observations, core descriptions, and thin section analysis, four types of natural fractures are developed in the study area: tensile fractures, shear fractures, interlayer bedding fractures, and diagenetic shrinkage fractures. Most low-angle and horizontal natural fractures have lengths of 5 cm–10 cm, and the effective fracture density is 0.90 pieces/m. The lithology ( Y ), thickness of the rock layer ( H ), regional tectonic stress ( F ), and fault scale ( S ) have a significant impact on the development of natural fractures. Most natural fractures develop when there is a large number of laminations in thin rock layers. The large regional tectonic stress in the Late Himalayan, which had a large fracture density index, leads to the formation of natural fractures in numerical simulations. Large faults would have co-developed with more fractures than small faults due to the high energy of large faults. The relationship between the effective permeability and the four parameters (i.e., Y , H , F , and S ) was established. Based on this relationship, it is concluded that H is the most critical factor influencing the effective permeability of natural fractures in the study area. As a result, the middle to upper section in the 2nd subsection of the Da'anzhai Member, in which the lithofacies is thinly laminated shales with shells, can be considered to contain favourable shale gas layers. • Genesis and distribution of natural fractures in Da'anzhai Shale reservoir. • The thickness and frequency of interlayers and lamination mainly control on natural fracture intensity and penetration. • The thickness of interlayers is the most critical factor influencing the effective permeability of natural fractures. • The lithofacies of thin-shell lamination shales can be considered as favor shale gas layers.

Long-term effect of desorption-induced matrix shrinkage on the evolution of coal permeability during coalbed methane production

In a coal reservoir, matrix shrinkage caused by gas desorption is regarded as a significant factor that can influence natural fracture permeability. It is considered to be a constant and lasting effect throughout coalbed methane (CBM) production based on previous investigations. However, experimental measurements of long-term permeability change have demonstrated that adsorption-induced strain has a time-dependent effect on permeability evolution. This study presents long-term investigations on permeability evolution of coal reservoir during CBM production. A fully coupled two-phase flow model for gas-water is specially proposed. Furthermore, the independent impacts of the matrix swelling during gas adsorption are characterized by a strain-rate-based permeability model. The competing effect between pressure depletion and desorption shrinkage on the permeability change is evaluated during the process of long-term production. The calculations of the proposed model are respectively consistent with experimental and field data and the findings show that matrix shrinkage is the most important factor in permeability evolution towards the wellbore. The effect of matrix shrinkage on permeability enhancement is significant in the primary stage and vanishes with uniform depressurization in the matrix. As a result, matrix shrinkage dominates permeability first, followed by effective stress. A sensitivity analysis of mechanical properties and flow properties on permeability evolution was performed and has demonstrated that the larger the matrix shrinkage-induced strain is, the higher the permeability enhancement is, which can be also enhanced with greater initial permeability and a lower diffusion coefficient of the matrix and the impact of the negative strain induced by decreasing pore pressure is solely related to the bulk modulus. The range of permeability variation is narrowed when porosity is high, which implies that the influence of matrix shrinkage and effective stress on permeability is suppressed. This research will advance the understanding of the permeability change during long-term CBM production.

Petroleum rock mechanics: An area worthy of focus in geo-energy research

Petroleum rock mechanics: An area worthy of focus in geo-energy research

Innovative solutions in construction of deep industrial brine, oil and gas wells in deformable fractured reservoirs

The paper deals with the methodological features of drilling and completion of wells in the fractured natural reservoirs containing oil and gas accumulations with different reservoir pressures of fluid-pressure systems from abnormally high to abnormally low. The authors had studied the fluid-pressure systems of industrial lithium-bromine brines, oil and gas fields and accumulations in the south of the Siberian platform for the period from 1983 to 2019. The article summarizes the main results, including new technical solutions protected by the Russian Federation patents. The authors proposed and patented a series of new technical solutions for the immediate consolidation of natural permeable fractures during the primary opening of the reservoir by drilling, as applied to a fractured reservoir. The main task of the study is to preserve the permeability of the fractured system in the bottomhole formation zone under the action of compressive stresses (rock mass) that increase with the formation of a drawdown cone, primarily in the bottomhole formation zone with the increase in the drawdown (ΔP) above critical values. Such an area is the bottomhole formation zone within a radius of the first meters around the well that penetrated the fractured reservoir. Practice has proved that the use of innovative solutions through the advanced consolidation of permeable fractures in the bottomhole formation zone (of fluid-producing oil- and gas-bearing, water-bearing reservoir) in the open (initial natural) state ensures the preservation of natural permeability of natural filtering fractures of the reservoir with the fluid system reservoir pressure from anomalously low to abnormally high. The solution ensures constant permeability of the fractured filtration system throughout the cleaning cycles of the bottomhole formation zone rocks from drilling mud, obtaining of the true calculated hydrodynamic parameters based on the results of well testing in the modes of the “steady-state production method” and well flow rate (productivity) stabilization under further well operation.

Novel Model for Rate Transient Analysis in Stress-Sensitive Shale Gas Reservoirs.

Technical advances in hydraulic fracturing and horizontal drilling technologies enable shale to be commercially exploited. Due to the technical and economic limitations of well testing in shale gas plays, rate transient analysis has become a more attractive option. After hydraulic fracturing, flow mechanisms in multiple scaled pores of shale become extraordinarily complicated: adsorption in nanopores, diffusion in micropores, and non-Darcy flow in macropores. Moreover, shale gas reservoirs are stress-sensitive because of ultralow permeability and diffusivity in a matrix. Furthermore, the porosity and permeability of natural fractures are stress-dependent as well. Accounting for all of these complex flow mechanisms, especially the aforementioned stress-sensitive parameters, a semianalytical production solution of a multiple fractured horizontal well (MFHW) can rapidly predict the entire production behavior. Scholars have done much work on the complex flow mechanisms of shale. Most models regarded permeability as a stress-sensitive parameter while diffusivity and porosity were considered to be a constant. However, diffusivity and porosity were proved to be stress-sensitive as experimental science developed. In this study, we present a novel semianalytical model for rate transient analysis of MFHW, which simultaneously incorporates multiple stress-sensitive parameters into flow mechanisms. Substituting stress-dependent parameters (diffusivity, porosity, and permeability) into governing equations resulted in strong nonlinearities, which was solved by employing the perturbation method. Production behaviors with only stress-sensitive permeability were compared with multiple stress-dependent parameters. The new model with multiple stress-sensitive parameters declined slower than the permeability-sensitive model, and the new model matched better with the field data. In addition, the effects of major stress-sensitive parameters on production decline curves were analyzed by the proposed model. The sensitivity analysis indicated that different parameters had their own degree of sensitivity intensity and influence on the production period. Finally, 1001 wells from the Marcellus shale play were divided into three well groups. Estimated inversion values of reservoir parameters from the three well groups and relevant single wells were consistent with the field data. The inverted values of single wells fluctuate within the inversion values of well groups, which indicates that the production behavior of well groups could be a guide for rate transient analysis of a single well in shale gas reservoirs.

Compositional Simulation of Geological and Engineering Controls on Gas Huff-n-Puff in Duvernay Shale Volatile Oil Reservoirs, Canada

Duvernay shale is a world class shale deposit with a total resource of 440 billion barrels oil equivalent in the Western Canada Sedimentary Basin (WCSB). The volatile oil recovery factors achieved from primary production are much lower than those from the gas-condensate window, typically 5–10% of original oil in place (OOIP). The previous study has indicated that huff-n-puff gas injection is one of the most promising enhanced oil recovery (EOR) methods in shale oil reservoirs. In this paper, we built a comprehensive numerical compositional model in combination with the embedded discrete fracture model (EDFM) method to evaluate geological and engineering controls on gas huff-n-puff in Duvernay shale volatile oil reservoirs. Multiple scenarios of compositional simulations of huff-n-puff gas injection for the proposed twelve parameters have been conducted and effects of reservoir, completion and depletion development parameters on huff-n-puff are evaluated. We concluded that fracture conductivity, natural fracture density, period of primary depletion, and natural fracture permeability are the most sensitive parameters for incremental oil recovery from gas huff-n-puff. Low fracture conductivity and a short period of primary depletion could significantly increase the gas usage ratio and result in poor economical efficiency of the gas huff-n-puff process. Sensitivity analysis indicates that due to the increase of the matrix-surface area during gas huff-n-puff process, natural fractures associated with hydraulic fractures are the key controlling factors for gas huff-n-puff in Duvernay shale oil reservoirs. The range for the oil recovery increase over the primary recovery for one gas huff-n-puff cycle (nearly 2300 days of production) in Duvernay shale volatile oil reservoir is between 0.23 and 0.87%. Finally, we proposed screening criteria for gas huff-n-puff potential areas in volatile oil reservoirs from Duvernay shale. This study is highly meaningful and can give valuable reference to practical works conducting the huff-n-puff gas injection in both Duvernay and other shale oil reservoirs.

Natural fractures in the Triassic tight sandstones of the Dongpu Depression, Bohai Bay Basin, eastern China: The key to production

Natural fractures are identified as high-quality storage space and seepage channels for the Triassic tight sandstone reservoirs in the Dongpu Depression, playing an important role in tight sandstone oil production. We have evaluated natural fracture growth at different scales using outcrops, cores, thin sections, and imaging logs and analyzed the correlation between fractures and crude oil production capacity with production data. Results show that natural fractures primarily are distributed in fine sandstones and siltstones, which mostly are shear fractures of near east–west and northeast–southwest strikes. The natural fractures of near east–west strikes generally are parallel to the present-day maximum horizontal principal stress with the biggest apertures and the highest permeability, which are the main seepage channels, next being the fractures of northeast–southwest strike. The natural fractures of near east–west strikes also are the most important contributors to the crude oil production in the Triassic tight sandstones of the Dongpu Depression. The intensity, permeability, and direction of natural fractures govern the crude oil productivity in the per-unit sandstone thickness.

Utah FORGE: Hydrogeothermal modeling of a granitic based discrete fracture network

Enhanced geothermal systems (EGS) are engineered reservoirs that have been stimulated to extract efficiently heat from low permeability hot rock. Generating efficient hydraulic pathways for heat exchange is crucial. A 3-dimensional Discrete Fracture Network (DFN) model was developed for simulating and determining the optimum hydraulic fracture network for the proposed Phase 3 injection and production wells at a Frontier Observatory for Research in Geothermal Energy (FORGE) site in Utah. Numerical simulations are used to study hydrogeothermal transport in the fractured media. The effect natural fractures contribute to hydraulic fracture growth were studied in regard to changes in natural fracture intensity, flow rate, hydraulic pathways, permeability, and perforation cluster spacing. Post hydraulic fracturing networks are incorporated into a hydrothermal modeling package where a possible range of heat extraction values are determined from the reservoir over a 30-year production period. Results suggest that DFN modeling in an EGS setting has exceptional value. The study serves as a benchmark for developing an improved understanding of the effects of the existing FORGE natural fracture systems. The simulations suggest an optimized pumping schedule that generates conductive post-stimulation fracture networks between hypothetical Phase 3 injection and production wells and establishes an effective hydrological thermal model under various fluid flow conditions. A more viscous fluid increases the fracture height and significantly effects fracture growth in the middle cluster. Injection temperature and flow rate are two of most important parameters that control the production temperature and heat recovery.