The Relationship between Fractures and Tectonic Stress Field in the Extra Low-Permeability Sandstone Reservoir at the South of Western Sichuan Depression

The formation and distribution of fractures are controlled by paleotectonic stress field, and their preservative status and effects on development are dominated by the modern stress field. Since Triassic, it has experienced four tectonic movements and developed four sets of tectonic fractures in the extra low-permeability sandstone reservoir at the south of western Sichuan depression. The strikes of fractures are in the S-N, NE-SW, E-W, and NW-SE directions respectively. At the end of Triassic, under the horizontal compression tectonic stress field, for which the maximum principal stress direction was NW.SE, the fractures were well developed near the S-N faults and at the end of NE-SW faults, because of their stress concentration. At the end of Cretaceous, in the horizontal compression stress fields of the NE-SW direction, the stress was obviously lower near the NE-SW faults, thus, fractures mainly developed near the S-N faults. At the end of Neogene-Early Pleistocene, under the horizontal compression tectonic stress fields of E-W direction, stress concentrated near the NE-SW faults and fractures developed at these places, especially at the end of the NE-SE faults, the cross positions of NE-SW, and S-N faults. Therefore, fractures developed mostly near S-N faults and NE-SW faults. At the cross positions of the above two sets of faults, the degree of development of the fractures was the highest. Under the modern stress field of the NW-SE direction, the NW-SE fractures were mainly the seepage ones with tensional state, the best connectivity, the widest aperture, the highest permeability, and the minimum opening pressure.

A review of reservoir damage during hydraulic fracturing of deep and ultra-deep reservoirs

Deep and ultra-deep reservoirs have gradually become the primary focus of hydrocarbon exploration as a result of a series of significant discoveries in deep hydrocarbon exploration worldwide.These reservoirs present unique challenges due to their deep burial depth(4500-8882 m),low matrix permeability,complex crustal stress conditions,high temperature and pressure(HTHP,150-200℃,105-155 MPa),coupled with high salinity of formation water.Consequently,the costs associated with their exploitation and development are exceptionally high.In deep and ultra-deep reservoirs,hydraulic fracturing is commonly used to achieve high and stable production.During hydraulic fracturing,a substantial volume of fluid is injected into the reservoir.However,statistical analysis reveals that the flowback rate is typically less than 30%,leaving the majority of the fluid trapped within the reservoir.Therefore,hydraulic fracturing in deep reservoirs not only enhances the reservoir permeability by creating artificial fractures but also damages reservoirs due to the fracturing fluids involved.The challenging“three-high”environment of a deep reservoir,characterized by high temperature,high pressure,and high salinity,exacerbates conventional forms of damage,including water sensitivity,retention of fracturing fluids,rock creep,and proppant breakage.In addition,specific damage mechanisms come into play,such as fracturing fluid decomposition at elevated temperatures and proppant diagenetic reactions at HTHP conditions.Presently,the foremost concern in deep oil and gas development lies in effectively assessing the damage inflicted on these reservoirs by hydraulic fracturing,comprehending the underlying mechanisms,and selecting appropriate solutions.It's noteworthy that the majority of existing studies on reservoir damage primarily focus on conventional reservoirs,with limited attention given to deep reservoirs and a lack of systematic summaries.In light of this,our approach entails initially summarizing the current knowledge pertaining to the types of fracturing fluids employed in deep and ultra-deep reservoirs.Subsequently,we delve into a systematic examination of the damage processes and mechanisms caused by fracturing fluids within the context of hydraulic fracturing in deep reservoirs,taking into account the unique reservoir characteristics of high temperature,high pressure,and high in-situ stress.In addition,we provide an overview of research progress related to high-temperature deep reservoir fracturing fluid and the damage of aqueous fracturing fluids to rock matrix,both artificial and natural fractures,and sand-packed fractures.We conclude by offering a summary of current research advancements and future directions,which hold significant potential for facilitating the efficient development of deep oil and gas reservoirs while effectively mitigating reservoir damage.

Characteristics of proppant transport and placement within rough hydraulic fractures

A three-dimensional reconstruction of rough fracture surfaces of hydraulically fractured rock outcrops is carried out by casting process,a large-scale experimental setup for visualizing rough fractures is built to perform proppant transport experiments.The typical characteristics of proppant transport and placement in rough fractures and its intrinsic mechanisms are investigated,and the influences of fracture inclination,fracture width and fracturing fluid viscosity on proppant transport and placement in rough fractures are analyzed.The results show that the rough fractures cause variations in the shape of the flow channel and the fluid flow pattern,resulting in the bridging buildup during proppant transport to form unfilled zone,the emergence of multiple complex flow patterns such as channeling,reverse flow and bypassing of sand-carrying fluid,and the influence on the stability of the sand dune.The proppant has a higher placement rate in inclined rough fractures,with a maximum increase of 22.16 percentage points in the experiments compared to vertical fractures,but exhibits poor stability of the sand dune.Reduced fracture width aggravates the bridging of proppant and induces higher pumping pressure.Increasing the viscosity of the fracturing fluid can weaken the proppant bridging phenomenon caused by the rough fractures.

Microscopic characteristics of tight sandstone reservoirs and their effects on the imbibition efficiency of fracturing fluids:A case study of the Linxing area,Ordos Basin

The Linxing area within the Ordos Basin exhibits pronounced reservoir heterogeneity and intricate micro-pore structures,rendering it susceptible to water-blocking damage during imbibition extraction.This study delved into the traits of tight sandstone reservoirs in the 8th member of the Shihezi Formation(also referred to as the He 8 Member)in the study area,as well as their effects on fracturing fluid imbibition.Utilizing experimental techniques such as nuclear magnetic resonance(NMR),high-pressure mercury intrusion(HPMI),and gas adsorption,this study elucidated the reservoir characteristics and examined the factors affecting the imbibition through imbibition experiments.The findings reveal that:①The reservoir,with average porosity of 8.40%and average permeability of 0.642×10^(-3)μm^(2),consists principally of quartz,feldspar,and lithic fragments,with feldspathic litharenite serving as the primary rock type and illite as the chief clay mineral;②Nano-scale micro-pores and throats dominate the reservoir,with dissolution pores and intercrystalline pores serving as predominant pore types,exhibiting relatively high pore connectivity;③Imbibition efficiency is influenced by petrophysical properties,clay mineral content,and microscopic pore structure.Due to the heterogeneity of the tight sandstone reservoir,microscopic factors have a more significant impact on the imbibition efficiency of fracturing fluids;④A comparative analysis shows that average pore size correlates most strongly with imbibition efficiency,followed by petrophysical properties and clay mineral content.In contrast,the pore type has minimal impact.Micropores are vital in the imbibition process,while meso-pores and macro-pores offer primary spaces for imbibition.This study offers theoretical insights and guidance for enhancing the post-fracturing production of tight sandstone reservoirs by examining the effects of these factors on the imbibition efficiency of fracturing fluids in tight sandstones.

Anisotropic characteristics of electrical responses of fractured reservoir with multiple sets of fractures

In fractured reservoirs, the fractures not but also form the main flow channels which connect productivity of reservoirs. However, because of the only provide the storage space for hydrocarbons, the pores of the matrix, so fractures dominate the heterogeneity and randomness of the distribution of fractures, exploration and evaluation of fractured reservoirs is still one of the most difficult problems in the oil industry. In recent years, seismic anisotropy has been applied to the assessment of fractured formations, whereas electrical anisotropy which is more intense in fractured formations than seismic anisotropy has not been studied or used so extensively. In this study, fractured reservoir models which considered multiple sets of fractures with smooth and partly closed, rough surfaces were established based on the fractures and pore network, and the vertical and horizontal electrical resistivities were derived as a function of the matrix and fracture porosities according to Ohm＇s law. By using the anisotropic resistivity equations, variations of the electrical anisotropy of three types of fractured models under the conditions of free pressure and confining pressure were analyzed through the variations of the exerted pressure, matrix porosity, fracture aperture and formation water resistivity. The differences of the vertical and horizontal resistivities and the anisotropy between the connected and non-connected fractures were also analyzed. It is known from the simulated results that an increase of the confining pressure causes a decrease of electrical anisotropy because of the elasticity of the closed fractures and the decrease of the fracture aperture. For a fixed fracture porosity, the higher the matrix porosity, the weaker the electrical anisotropy in the rock formation.

A FEM-DFN model for the interaction and propagation of multi-cluster fractures during variable fluid-viscosity injection in layered shale oil reservoir

To investigate the height growth of multi-cluster fractures during variable fluid-viscosity fracturing in a layered shale oil reservoir,a two-dimensional finite element method(FEM)-discrete fracture network(DFN)model coupled with flow,stress and damage is proposed.A traction-separation law is used to describe the mixed-mode response of the damaged adhesive fractures,and the cubic law is used to describe the fluid flow within the fractures.The rock deformation is controlled by the in-situ stress,fracture cohesion and fluid pressure on the hydraulic fracture surface.The coupled finite element equations are solved by the explicit time difference method.The effects of the fracturing treatment parameters including fluid viscosity,pumping rate and cluster spacing on the geometries of multifractures are investigated.The results show that variable fluid-viscosity injection can improve the complexity of the fracture network and height of the main fractures simultaneously.The pumping rate of15 m^(3)/min,variable fluid-viscosity of 3-9-21-36-45 mPa s with a cluster spacing of 7.5 m is the ideal treatment strategy.The field application shows that the peak daily production of the application well with the optimized injection procedu re of variable fluid-viscosity fracturing is 171 tons(about 2.85 times that of the adjacent well),which is the highest daily production record of a single shale oil well in China,marking a strategic breakthrough of commercial shale oil production in the Jiyang Depression,Shengli Oilfield.The variable fluid-viscosity fracturing technique is proved to be very effective for improving shale oil production.

Multiple damage zones around hydraulic fractures generated by high-frequency pulsating hydraulic fracturing

Pulsating hydraulic fracturing(PHF)is a promising fracturing method and can generate a dynamic periodic pressure.The periodic pressure can induce fatigue failure of rocks and decrease initiation pressure of fracture.If the frequency of periodic pressure exceeds 10 Hz,the distribution of pressure along the main fracture will be heterogeneous,which is much different from the one induced by the common fracturing method.In this study,the impact of this special spatial feature of pressure on hydraulic fracture is mainly investigated.A coupled numerical simulation model is first proposed and verified through experimental and theoretical solutions.The mechanism of secondary fracture initiation around the main fracture is then discovered.In addition,sensitivity studies are conducted to find out the application potential of this new method.The results show that(1)this coupled numerical simulation model is accurate.Through comparison with experimental and theoretical data,the average error of this coupled model is less than 1.01%.(2)Even if a reservoir has no natural fracture,this heterogeneous distribution pressure can also cause many secondary fractures around the main fracture.(3)The mechanism of secondary fracture initiation is that this heterogeneous distribution pressure causes tensile stress at many locations along the main fracture.(4)Through adjusting the stimulation parameters,the stimulation efficiency can be improved.The average and amplitude of pressure can increase possibility of secondary fracture initiation.The frequency of this periodic pressure can increase number of secondary fractures.Even 6 secondary fractures along a 100 m-length main fracture can be generated.(5)The influence magnitudes of stimulation parameters are larger than ones of geomechanical properties,therefore,this new fracturing method has a wide application potential.

Application of fracturing technology to increase gas production in low-permeability hydrate reservoir:A numerical study

Low temperature and low permeability are the challenges for the development of hydrate reservoirs in permafrost.The ice produced around the production well caused by high depressurization driving force reduces the gas production,and it is necessary to reduce the effect of ice production on gas production.In this work,a new combination of fracturing technology and depressurization method was proposed to evaluate the gas production potential at the site DK-2 in Qinghai-Tibet Plateau Permafrost.A relatively higher intrinsic permeability of the fracture zone surround the horizontal production well was created by the fracturing technology.The simulation results showed that the fracture zone reduced the blocking of production ice to production wells and promoted the propagation of production pressure.And the gas production increased by 2.1 times as the radius of the fracture zone increased from 0 to 4 m in 30 years.Nearly half of the hydrate reservoirs were dissociated in 30 years,and greater than 51.7%of the gas production was produced during the first 10 years.Moreover,production behaviours were sensitive to the depressurization driving force but not to the thermal conductivity.The growth of gas production was not obvious with the intrinsic permeability of the fracture zone higher than 100 m D.The effect of ice production on gas production by fracturing technology and depressurization method was limited.

Fractal model of spontaneous imbibition in low-permeability reservoirs coupled with heterogeneity of pore seepage channels and threshold pressure

Spontaneous imbibition(SI)is an important mechanism for enhancing oil recovery in low-permeability reservoirs.Due to the strong heterogeneity,and the non-Darcy flow,the construction of SI model for lowpermeability reservoirs is extremely challenging.Commonly,traditional SI models based on single or averaged capillary tortuosity ignore the influence of heterogeneity of pore seepage channels and the threshold pressure(TP)on imbibition.Therefore,in this work,based on capillary model and fractal theory,a mathematical model of characterizing SI considering heterogeneity of pore seepage channels is established.On this basis,the threshold pressure was introduced to determine the pore radius at which the wetted phase can displace oil.The proposed new SI model was verified by imbibition experimental data.The study shows that for weakly heterogeneous cores with permeability of 0-1 m D,the traditional SI model can characterize the imbibition process relatively accurately,and the new imbibition model can increase the coefficient of determination by 1.05 times.However,traditional model has serious deviations in predicting the imbibition recovery for cores with permeability of 10-50 m D.The new SI model coupling with heterogeneity of pore seepage channels and threshold pressure effectively solves this problem,and the determination coefficient is increased from 0.344 to 0.922,which is increased by2.68 times.For low-permeability reservoirs,the production of the oil in transitional pores(0.01-0.1μm)and mesopores(0.1-1μm)significantly affects the imbibition recovery,as the research shows that when the heterogeneity of pore seepage channels is ignored,the oil recovery in transitional pores and mesopores decreases by 7.54%and 4.26%,respectively.Sensitivity analysis shows that increasing interfacial tension,decreasing contact angle,oil-water viscosity ratio and threshold pressure will increase imbibition recovery.In addition,there are critical values for the influence of these factors on the imbibition recovery,which provides theoretical support for surfactant optimization.

Experimental investigation and correlations for proppant distribution in narrow fractures of deep shale gas reservoirs

Hydraulic fracturing is a crucial stimulation for the development of deep shale gas reservoirs.A key challenge to the effectiveness of hydraulic fracturing is to place small proppants in complex narrow fractures reasonably.The experiments with varied particle and fluid parameters are carried out in a narrow planar channel to understand particle transport and distribution.The four dimensionless parameters,including the Reynold number,Shields number,density ratio,and particle volume fraction,are introduced to describe the particle transport in narrow fractures.The results indicate that the narrow channel probably induces fluid fingers and small particle aggregation in a highly viscous fluid,leading to particle settlement near the entrance.The low viscous fluid is beneficial to disperse particles further into the fracture,especially in the high-speed fluid velocity.The linear and natural logarithmic laws have relationships with dimensionless parameters accurately.The multiple linear regression method developed two correlation models with four dimensionless parameters to predict the bed equilibrium height and covered area of small particles in narrow fractures.The study provides fundamental insight into understanding small size proppant distribution in deep reservoirs.

Visualization and characterization of experimental hydraulic fractures interacting with karst fracture-cavity distributions

Karst fracture-cavity carbonate reservoirs,in which natural cavities are connected by natural fractures to form cavity clusters in many circumstances,have become significant fields of oil and gas exploration and exploitation.Proppant fracturing is considered as the best method for exploiting carbonate reservoirs;however,previous studies primarily focused on the effects of individual types of geological formations,such as natural fractures or cavities,on fracture propagation.In this study,true-triaxial physical simulation experiments were systematically performed under four types of stress difference conditions after the accurate prefabrication of four types of different fracture-cavity distributions in artificial samples.Subsequently,the interaction mechanism between the hydraulic fractures and fracture-cavity structures was systematically analyzed in combination with the stress distribution,cross-sectional morphology of the main propagation path,and three-dimensional visualization of the overall fracture network.It was found that the propagation of hydraulic fractures near the cavity was inhibited by the stress concentration surrounding the cavity.In contrast,a natural fracture with a smaller approach angle(0°and 30°)around the cavity can alleviate the stress concentration and significantly facilitate the connection with the cavity.In addition,the hydraulic fracture crossed the natural fracture at the 45°approach angle and bypassed the cavity under higher stress difference conditions.A new stimulation effectiveness evaluation index was established based on the stimulated reservoir area(SRA),tortuosity of the hydraulic fractures(T),and connectivity index(CI)of the cavities.These findings provide new insights into the fracturing design of carbonate reservoirs.

In-situ laboratory study on influencing factors of pre-SC-CO_(2) hybrid fracturing effect in shale oil reservoirs

Supercritical CO_(2)(SC-CO_(2)) fracturing, being a waterless fracturing technology, has garnered increasing attention in the shale oil reservoir exploitation industry. Recently, a novel pre-SC-CO_(2) hybrid fracturing method has been proposed, which combines the advantages of SC-CO_(2) fracturing and hydraulic fracturing. However, the specific impacts of different pre-SC-CO_(2) injection conditions on the physical parameters, mechanical properties, and crack propagation behavior of shale reservoirs remain unclear. In this study, we utilize a newly developed “pre-SC-CO_(2) injection → water-based fracturing” integrated experimental device. Through experimentation under in-situ conditions, the impact of pre-SC-CO_(2) injection displacement and volume on the shale mineral composition, mechanical parameters, and fracture propagation behavior are investigated. The findings of the study demonstrate that the pre-injection SC-CO_(2) leads to a reduction in clay and carbonate mineral content, while increasing the quartz content. The correlation between quartz content and SC-CO_(2) injection volume is positive, while a negative correlation is observed with injection displacement. The elastic modulus and compressive strength exhibit a declining trend, while Poisson's ratio shows an increasing trend. The weakening of shale mechanics caused by pre-injection of SC-CO_(2) is positively correlated with the injection displacement and volume.Additionally, pre-injection of SC-CO_(2) enhances the plastic deformation behavior of shale, and its breakdown pressure is 16.6% lower than that of hydraulic fracturing. The breakdown pressure demonstrates a non-linear downward trend with the gradual increase of pre-SC-CO_(2) injection parameters.Unlike hydraulic fracturing, which typically generates primary fractures along the direction of the maximum principal stress, pre-SC-CO_(2) hybrid fracturing leads to a more complex fracture network. With increasing pre-SC-CO_(2) injection displacement, intersecting double Y-shaped complex fractures are formed along the vertical axis. On the other hand, increasing the injection rate generates secondary fractures along the direction of non-principal stress. The insights gained from this study are valuable for guiding the design of pre SC-CO_(2) hybrid fracturing in shale oil reservoirs.

A novel dandelion-based bionic proppant and its transportation mechanism in different types of fractures

Low-permeability reservoirs are generally characterized by low porosity and low permeability.Obtaining high production using the traditional method is technologically challenging because it yields a low reservoir recovery factor.In recent years,hydraulic fracturing technology is widely applied for efficiently exploiting and developing low-permeability reservoirs using a low-viscosity fluid as a fracturing fluid.However,the transportation of the proppant is inefficient in the low-viscosity fluid,and the proppant has a low piling-up height in fracture channels.These key challenges restrict the fluid(natural gas or oil)flow in fracture channels and their functional flow areas,reducing the profits of hydrocarbon exploitation.This study aimed to explore and develop a novel dandelion-bionic proppant by modifying the surface of the proppant and the fiber.Its structure was similar to that of dandelion seeds,and it had high transport and stacking efficiency in low-viscosity liquids compared with the traditional proppant.Moreover,the transportation efficiency of this newly developed proppant was investigated experimentally using six different types of fracture models(tortuous fracture model,rough fracture model,narrow fracture model,complex fracture model,large-scale single fracture model,and small-scale single fracture model).Experimental results indicated that,compared with the traditional proppant,the transportation efficiency and the packing area of the dandelion-based bionic proppant significantly improved in tap water or low-viscosity fluid.Compared with the traditional proppant,the dandelionbased bionic proppant had 0.1-4 times longer transportation length,0.3-5 times higher piling-up height,and 2-10 times larger placement area.The newly developed proppant also had some other extraordinary features.The tortuosity of the fracture did not influence the transportation of the novel proppant.This proppant could easily enter the branch fracture and narrow fracture with a high packing area in rough surface fractures.Based on the aforementioned characteristics,this novel proppant technique could improve the proppant transportation efficiency in the low-viscosity fracturing fluid and increase the ability of the proppant to enter the secondary fracture.This study might provide a new solution for effectively exploiting low-permeability hydrocarbon reservoirs.

Performance and enhanced oil recovery efficiency of an acid-resistant polymer microspheres of anti-CO_(2) channeling in low-permeability reservoirs

CO_(2) flooding is a vital development method for enhanced oil recovery in low-permeability reservoirs,However,micro-fractures are developed in low-permeability reservoirs,which are essential oil flow channels but can also cause severe CO_(2) gas channeling problems.Therefore,anti-gas channeling is a necessary measure to improve the effect of CO_(2) flooding.The kind of anti-gas channeling refers to the plugging of fractures in the deep formation to prevent CO_(2) gas channeling,which is different from the wellbore leakage.Polymer microspheres have the characteristics of controllable deep plugging,which can achieve the profile control of low-permeability fractured reservoirs.In acidic environments with supercritical CO_(2),traditional polymer microspheres have poor expandability and plugging properties.Based on previous work,a systematic evaluation of the expansion performance,dispersion rheological properties,stability,deep migration,anti-CO_(2) channeling and enhanced oil recovery ability of a novel acid-resistant polymer microsphere(DCNPM-A)was carried out under CQ oilifield conditions(salinity of85,000 mg/L,80℃,pH=3).The results show that the DCNPM-A microsphere had a better expansion performance than the traditional microsphere,with a swelling rate of 13.5.The microsphere dispersion with a concentration of 0.1%-0.5%had the advantages of low viscosity,high dispersion and good injectability in the low permeability fractured core.In the acidic environment of supercritical CO_(2),DCNPM-A microspheres showed excellent stability and could maintain strength for over 60 d with less loss.In core experiments,DCNPM-A microspheres exhibited delayed swelling characteristics and could effectively plug deep formations.With a plugging rate of 95%,the subsequent enhanced oil recovery of CO_(2) flooding could reach 21.03%.The experimental results can provide a theoretical basis for anti-CO_(2)channeling and enhanced oil recovery in low-permeability fractured reservoirs.

Experimental Investigation on Condensate Revaporization During Gas Injection Development in Fractured Gas Condensate Reservoirs

The gas field in the Bohai Bay Basin is a fractured metamorphic buried-hill reservoir with dual-media characteristics. The retrograde vaporization mechanism observed in this type of gas condensate reservoir differs significantly from that observed in sand gas condensate reservoirs. However, studies on improving the recovery of fractured gas condensate reservoirs are limited;thus, the impact of retrograde vaporization on condensate within fractured metamorphic buried-hill reservoirs remains unclear. To address this gap, a series of gas injection experiments are conducted in pressure-volume-temperature(PVT) cells and long-cores to investigate the retrograde vaporization effect of condensate using different gas injection media in fractured gas condensate reservoirs. We analyze the variation in condensate volume, gas-to-oil ratio, and condensate recovery during gas injection and examine the influence of various gas injection media(CO_(2), N_(2), and dry gas) under different reservoir properties and varying gas injection times. The results demonstrate that the exchange of components between injected gas and condensate significantly influences condensate retrograde vaporization in the formation. Compared with dry gas injection and N_(2) injection,CO_(2) injection exhibits a superior retrograde vaporization effect. At a CO_(2) injection volume of 1 PV, the percentage shrinkage volume of condensate is 13.82%. Additionally, at the maximum retrograde condensation pressure, CO_(2) injection can increase the recovery of condensate by 22.4%. However, the condensate recovery is notably lower in fractured gas condensate reservoirs than in homogeneous reservoirs, owing to the creation of dominant gas channeling by fractures, which leads to decreased condensate recovery. Regarding gas injection timing, the effect of gas injection at reservoir pressure on improving condensate recovery is superior to that of gas injection at the maximum retrograde condensation pressure. This research provides valuable guidance for designing gas injection development plans and dynamic tracking adjustments for fractured gas condensate reservoirs.

Microseismic Imaging of Hydraulically Induced-Fractures in Gas Reservoirs: A Case Study in Barnett Shale Gas Reservoir, Texas, USA

Microseismic technology has been proven to be a practical approach for in-situ monitoring of fracture growth during hydraulic fracture stimulations. Microseismic monitoring has rapidly evolved in acquisition methodology, data processing, and in this paper, we evaluate the progression of this technology with emphasis on their applications in Barnett shale gas reservoir. Microseismic data analysis indicates a direct proportion between microseismic moment magnitude and depth, yet no relation between microseismic activity and either injection rate or injection volume has been observed. However, large microseismic magnitudes have been recorded where hydraulic fracturing stimulation approaches a fault and therefore the geologic framework should be integrated in such programs. In addition, the geometry of fracture growth resulted by proppant interactions with naturally fractured formations follows unpredictable fashion due to redirecting the injection fluids along flow paths associated with the pre-existing fault network in the reservoir. While microseismic imaging is incredibly useful in revealing the fracture geometry and the way the fracture evolves, recently several concerns have been raised regarding the capability of microseismic data to provide the fracture dimensional parameters and the fracture mechanism that could provide detailed information for reservoir characterization.

Hydrocarbon gas huff-n-puff optimization of multiple horizontal wells with complex fracture networks in the M unconventional reservoir

The oil production of the multi-fractured horizontal wells(MFHWs) declines quickly in unconventional oil reservoirs due to the fast depletion of natural energy. Gas injection has been acknowledged as an effective method to improve oil recovery factor from unconventional oil reservoirs. Hydrocarbon gas huff-n-puff becomes preferable when the CO_(2) source is limited. However, the impact of complex fracture networks and well interference on the EOR performance of multiple MFHWs is still unclear. The optimal gas huff-n-puff parameters are significant for enhancing oil recovery. This work aims to optimize the hydrocarbon gas injection and production parameters for multiple MFHWs with complex fracture networks in unconventional oil reservoirs. Firstly, the numerical model based on unstructured grids is developed to characterize the complex fracture networks and capture the dynamic fracture features.Secondly, the PVT phase behavior simulation was carried out to provide the fluid model for numerical simulation. Thirdly, the optimal parameters for hydrocarbon gas huff-n-puff were obtained. Finally, the dominant factors of hydrocarbon gas huff-n-puff under complex fracture networks are obtained by fuzzy mathematical method. Results reveal that the current pressure of hydrocarbon gas injection can achieve miscible displacement. The optimal injection and production parameters are obtained by single-factor analysis to analyze the effect of individual parameter. Gas injection time is the dominant factor of hydrocarbon gas huff-n-puff in unconventional oil reservoirs with complex fracture networks. This work can offer engineers guidance for hydrocarbon gas huff-n-puff of multiple MFHWs considering the complex fracture networks.

Study on the Impact of Massive Refracturing on the Fracture Network in Tight Oil Reservoir Horizontal Wells

Class III tight oil reservoirs have low porosity and permeability,which are often responsible for low production rates and limited recovery.Extensive repeated fracturing is a well-known technique to fix some of these issues.With such methods,existing fractures are refractured,and/or new fractures are created to facilitate communication with natural fractures.This study explored how different refracturing methods affect horizontal well fracture networks,with a special focus on morphology and related fluid flow changes.In particular,the study relied on the unconventional fracture model(UFM).The evolution of fracture morphology and flow field after the initial fracturing were analyzed accordingly.The simulation results indicated that increased formation energy and reduced reservoir stress differences can promote fracture expansion.It was shown that the length of the fracture network,the width of the fracture network,and the complexity of the fracture can be improved,the oil drainage area can be increased,the distance of oil and gas seepage can be reduced,and the production of a single well can be significantly increased.

Extended finite element-based cohesive zone method for modeling simultaneous hydraulic fracture height growth in layered reservoirs

In this study,a fully coupled hydromechanical model within the extended finite element method(XFEM)-based cohesive zone method(CZM)is employed to investigate the simultaneous height growth behavior of multi-cluster hydraulic fractures in layered porous reservoirs with modulus contrast.The coupled hydromechanical model is first verified against an analytical solution and a laboratory experiment.Then,the fracture geometry(e.g.height,aperture,and area)and fluid pressure evolutions of multiple hydraulic fractures placed in a porous reservoir interbedded with alternating stiff and soft layers are investigated using the model.The stress and pore pressure distributions within the layered reservoir during fluid injection are also presented.The simulation results reveal that stress umbrellas are easily to form among multiple hydraulic fractures’tips when propagating in soft layers,which impedes the simultaneous height growth.It is also observed that the impediment effect of soft layer is much more significant in the fractures suppressed by the preferential growth of adjoining fractures.After that,the combined effect of in situ stress ratio and fracturing spacing on the multi-fracture height growth is presented,and the results elucidate the influence of in situ stress ratio on the height growth behavior depending on the fracture spacing.Finally,it is found that the inclusion of soft layers changes the aperture distribution of outmost and interior hydraulic fractures.The results obtained from this study may provide some insights on the understanding of hydraulic fracture height containment observed in filed.

A Novel Fracturing Fluid with High-Temperature Resistance for Ultra-Deep Reservoirs

Ultra-deep reservoirs play an important role at present in fossil energy exploitation.Due to the related high temperature,high pressure,and high formation fracture pressure,however,methods for oil well stimulation do not produce satisfactory results when conventional fracturing fluids with a low pumping rate are used.In response to the above problem,a fracturing fluid with a density of 1.2~1.4 g/cm^(3)was developed by using Potassium formatted,hydroxypropyl guanidine gum and zirconium crosslinking agents.The fracturing fluid was tested and its ability to maintain a viscosity of 100 mPa.s over more than 60 min was verified under a shear rate of 1701/s and at a temperature of 175℃.This fluid has good sand-carrying performances,a low viscosity after breaking the rubber,and the residue content is less than 200 mg/L.Compared with ordinary reconstruction fluid,it can increase the density by 30%~40%and reduce the wellhead pressure of 8000 m level reconstruction wells.Moreover,the new fracturing fluid can significantly mitigate safety risks.