CO_(2)flooding in shale oil reservoir with radial borehole fracturing for CO_(2)storage and enhanced oil recovery

This study introduces a novel method integrating CO_(2)flooding with radial borehole fracturing for enhanced oil recovery and CO_(2)underground storage,a solution to the limited vertical stimulation reservoir volume in horizontal well fracturing.A numerical model is established to investigate the production rate,reservoir pressure field,and CO_(2)saturation distribution corresponding to changing time of CO_(2)flooding with radial borehole fracturing.A sensitivity analysis on the influence of CO_(2)injection location,layer spacing,pressure difference,borehole number,and hydraulic fractures on oil production and CO_(2)storage is conducted.The CO_(2)flooding process is divided into four stages.Reductions in layer spacing will significantly improve oil production rate and gas storage capacity.However,serious gas channeling can occur when the spacing is lower than 20 m.Increasing the pressure difference between the producer and injector,the borehole number,the hydraulic fracture height,and the fracture width can also increase the oil production rate and gas storage rate.Sensitivity analysis shows that layer spacing and fracture height greatly influence gas storage and oil production.Research outcomes are expected to provide a theoretical basis for the efficient development of shale oil reservoirs in the vertical direction.

Numerical simulation of fracturing and imbibition in shale oil horizontal wells

The shale oil reservoir is characterized by tight lithology and ultra-low permeability,and its efficient exploitation requires the technology of multi-stage and multi-cluster hydraulic fracturing in horizontal wells and shut-in imbibition.After multi-stage and multi-cluster hydraulic fracturing,a complex fracture network is formed,and a large volume of frac fluid is stored within the fracture network.During shut-in,imbibition and exchange between oil and water occurs under the action of the capillary force and osmotic pressure,and the formation pressure builds up in the shale reservoir.On basis of the characteristics of shale oil reservoir,we establish a model of imbibition during fracturing injection and shut-in by coupling oilewater two-phase flow and saline ion diffusion in the hydraulic fractures(HFs)network,natural fractures(NFs)and matrix system under the action of capillary force and osmotic pressure.The DFN method and the multiple continuum method are introduced to characterize fluid flow between the HF and the NF and that between the NF and the matrix respectively,which avoids the problem of a large amount of computation of seepage within the complex fracture.Then,the discrete fracture network(DFN)model and the multiple continuum model are solved with the finite element method,and it is verified in flow field,saturation field and concentration field that the models are accurate and reliable.We propose the imbibition exchange volume for quantitative evaluation of the imbibition degree and a method of calculating the imbibition exchange volume.Simulation of oil and water flow in the fracturing and shut-in stages is performed based on these models.It is found that imbibition in the shale reservoir is driven by mechanisms of pressure difference,capillary force and osmotic pressure.The osmotic pressure and capillary force only cause an increase in the imbibition rate and a reduction in the imbibition equilibrium time and do not lead to variation in the peak of imbibition exchange volume.The imbibition equilibrium time under the action of the capillary force and osmotic pressure is reduced from 150 to 45 d compared with that under the action of the pressure difference.If imbibition equilibrium is reached,low initial water saturation,strong rock compressibility,high formation water salinity and high matrix permeability enhance imbibition and exchange of oil and water in the reservoir.The leakoff volume of frac fluid is generally larger than the imbibition exchanged volume.Leakoff equilibrium occurs slightly earlier than imbibition equilibrium.The imbibition equilibrium time is mainly affected by reservoir permeability and NF density.The number of interconnected fractures mainly affects the frac fluid volume within the hydraulic fracture in the fracturing process.The stimulated reservoir volume(SRV)mainly affects frac fluid imbibition exchange in the shut-in process.

Laboratory study of the factors affecting hydraulic fracturing effect for inter-salt oil shale layers,Qianjiang Depression,China

This study aims to investigate the potential factors affecting hydraulic fracturing of inter-salt oil shale reservoirs in the Qianjiang Depression,China.Using the inter-salt shale samples,the re-crystallization seepage tests,rock mechanical tests under high temperature and pressure,salt rock creep tests,and direct shear tests were conducted.The testing results suggest several major factors that affect hydraulic fracturing effects in the end.First,the seepage of reservoir and fracturing fluid through hydraulic frac-tures leads to salt dissolution and crystallization,reducing the effective seepage area of fractures.Second,the salt crystal may block the pore throats or micro fractures after brine invades the shale,decreasing the overall permeability.Third,the low strength and obvious plasticity of inter-salt shale and the strong creep characteristics of salt rock raise difficulties for proppant to effectively support fracture walls,thereby sharply narrowing the hydraulic fracture width.Lastly,the weak interfaces(bedding planes and lithology interfaces)in inter-salt oil shale reservoirs restrict the height of hydraulic fractures,resulting in the disconnection of seepage channels between multiple inter-salt shale reservoirs.Thus,several factors together reduce reservoir permeability,weaken the fluid flow capacity in the fracture,narrow the fracture width,and limit the effective stimulation volume,resulting in weaken the effect hydraulic fracturing.

Practice and development suggestions of hydraulic fracturing technology in the Gulong shale oil reservoirs of Songliao Basin, NE China

This paper reviews the multiple rounds of upgrades of the hydraulic fracturing technology used in the Gulong shale oil reservoirs and gives suggestions about stimulation technology development in relation to the production performance of Gulong shale oil wells.Under the control of high-density bedding fractures,fracturing in the Gulong shale results in a complex fracture morphology,yet with highly suppressed fracture height and length.Hydraulic fracturing fails to generate artificial fractures with sufficient lengths and heights,which is a main restraint on the effective stimulation in the Gulong shale oil reservoirs.In this regard,the fracturing design shall follow the strategy of"controlling near-wellbore complex fractures and maximizing the extension of main fractures"Increasing the proportions of guar gum fracturing fluids,reducing perforation clusters within one fracturing stage,raising pump rates and appropriately exploiting stress interference are conducive to fracture propagation and lead to a considerably expanded stimulated reservoir volume(SRV).The upgraded main hydraulic fracturing technology is much more applicable to the Gulong shale oil reservoirs.It accelerates the oil production with a low flowback rate and lifts oil cut during the initial production of well groups,which both help to improve well production.It is suggested to optimize the hydraulic fracturing technology in six aspects,namely,suppressing propagation of near-wellbore microfractures,improving the pumping scheme of CO_(2),managing the perforating density,enhancing multi-proppant combination,reviewing well pattern/spacing,and discreetly applying fiber-assisted injection,so as to improve the SRv,the distal fracture complexity and the long-term fracture conductivity.

Evaluation of hydraulic fracturing of horizontal wells in tight reservoirs based on the deep neural network with physical constraints

Accurate diagnosis of fracture geometry and conductivity is of great challenge due to the complex morphology of volumetric fracture network. In this study, a DNN (deep neural network) model was proposed to predict fracture parameters for the evaluation of the fracturing effects. Field experience and the law of fracture volume conservation were incorporated as physical constraints to improve the prediction accuracy due to small amount of data. A combined neural network was adopted to input both static geological and dynamic fracturing data. The structure of the DNN was optimized and the model was validated through k-fold cross-validation. Results indicate that this DNN model is capable of predicting the fracture parameters accurately with a low relative error of under 10% and good generalization ability. The adoptions of the combined neural network, physical constraints, and k-fold cross-validation improve the model performance. Specifically, the root-mean-square error (RMSE) of the model decreases by 71.9% and 56% respectively with the combined neural network as the input model and the consideration of physical constraints. The mean square error (MRE) of fracture parameters reduces by 75% because the k-fold cross-validation improves the rationality of data set dividing. The model based on the DNN with physical constraints proposed in this study provides foundations for the optimization of fracturing design and improves the efficiency of fracture diagnosis in tight oil and gas reservoirs.

A novel triple responsive smart fluid for tight oil fracturing-oil expulsion integration

The traditional multi-process to enhance tight oil recovery based on fracturing and huff-n-puff has obvious deficiencies,such as low recovery efficiency,rapid production decline,high cost,and complexity,etc.Therefore,a new technology,the so-called fracturing-oil expulsion integration,which does not need flowback after fracturing while making full use of the fracturing energy and gel breaking fluids,are needed to enable efficient exploitation of tight oil.A novel triple-responsive smart fluid based on“pseudo-Gemini”zwitterionic viscoelastic surfactant(VES)consisting of N-erucylamidopropyl-N,N-dimethyl-3-ammonio-2-hydroxy-1-propane-sulfonate(EHSB),N,N,N′,N′-tetramethyl-1,3-propanediamine(TMEDA)and sodium p-toluenesulfonate(NaPts),is developed.Then,the rheology of smart fluid is systematically studied at varying conditions(CO_(2),temperature and pressure).Moreover,the mechanism of triple-response is discussed in detail.Finally,a series of fracturing and spontaneous imbibition performances are systematically investigated.The smart fluid shows excellent CO_(2)-,thermal-,and pressure-triple responsive behavior.It can meet the technical requirement of tight oil fracturing construction at 140°C in the presence of 3.5 MPa CO_(2).The gel breaking fluid shows excellent spontaneous imbibition oil expulsion(∼40%),salt resistance(1.2×104 mg/L Na+),temperature resistance(140°C)and aging stability(30 days).

Temporal variations in geochemistry of hydraulic fracturing fluid and flowback water in a tight oil reservoir

Hydraulic fracturing facilitates the development and exploitation of unconventional reservoirs.In this study,the injected hydraulic fracturing fluid(HFF)and flowback and produced water(FPW)in tight oil reservoirs of the Lucaogou Formation in the Junggar Basin are temporally sampled from day 1 to day 64.Freshwater is used for fracturing,and HFF is obtained.The chemical and isotopic parameters(including the water type,total salinity,total dissolved solids(TDS),pH,concentrations of Na^(+),Cl^(-),Ba^(+),K^(+),Fe^(2+)+Fe^(3+),and CO_(3)^(2-),dD,and δ^(18)O)are experimentally obtained,and their variations with time are systematically analyzed based on the flowback water.The results show that the water type,Na/Cl ratio,total salinity,and TDS of the FPW change periodically primarily due to the HFF mixing with formation water,thus causing δD and δ^(18)O to deviate from the meteoric water line of Xinjiang.Because of watererock interaction(WRI),the concentrations of Fe^(2+)+Fe^(3+)and CO_(3)^(2-)of the FPW increase over time,with the solution pH becoming more alkaline.Furthermore,based on the significant changes observed in the geochemistry of the FPW,three separate time intervals of flowback time are identified:Stage Ⅰ(<10 days),where the FPW is dominated by the HFF and the changes in ions and isotopes are mainly caused by the WRI;Stage Ⅱ(10-37 days),where the FPW is dominated by the addition of formation water to the HFF and the WRI is weakened;and finally,Stage Ⅲ(>37 days),where the FPW is dominated by the chemistry of the formation water.The methodology implemented in this study can provide critical support for the source identification of formation water.

Optimization of the Algorithm for Increasing Injection Rate in Water Injection Wells for Pressure Optimization in P Oilfield

In today’s society, with the continuous growth of energy demand, Bohai Oilfield, as an important offshore oil resource base in China, is facing increasingly severe challenges while contributing to national energy security. In order to improve the quality of water injection in the oilfield and gradually achieve efficient and stable production, Bohai Oilfield has launched a water injection well pressure optimization project, focusing on improving the efficiency and quality of water injection in the water injection wells, in order to achieve the optimal water injection plan. In practical work, P Oilfield continues to promote the development of water injection well pressure optimization projects, emphasizing practical exploration and continuous optimization of work plans. However, during the project implementation process, there were some problems, one of which was that the statistics of cumulative injection volume were not scientific enough, resulting in a more comprehensive and accurate presentation of the actual results of pressure optimization work. In the context of continuous improvement work, after careful analysis and research, P Oilfield has decided to optimize the cumulative injection rate algorithm to guide the oilfield’s water injection work in a more refined way, ensuring sufficient and good water injection, and enhancing the oilfield’s production efficiency and comprehensive competitiveness.

A technique for enhancing tight oil recovery by multi-field reconstruction and combined displacement and imbibition

A seepage-geomechanical coupled embedded fracture flow model has been established for multi-field coupled simulation in tight oil reservoirs,revealing the patterns of change in pressure field,seepage field,and stress field after long-term water injection in tight oil reservoirs.Based on this,a technique for enhanced oil recovery(EOR)combining multi-field reconstruction and combination of displacement and imbibition in tight oil reservoirs has been proposed.The study shows that after long-term water flooding for tight oil development,the pressure diffusion range is limited,making it difficult to establish an effective displacement system.The variation in geostress exhibits diversity,with the change in horizontal minimum principal stress being greater than that in horizontal maximum principal stress,and the variation around the injection wells being more significant than that around the production wells.The deflection of geostress direction around injection wells is also large.The technology for EOR through multi-field reconstruction and combination of displacement and imbibition employs water injection wells converted to production and large-scale fracturing techniques to restructure the artificial fracture network system.Through a full lifecycle energy replenishment method of pre-fracturing energy supplementation,energy increase during fracturing,well soaking for energy storage,and combination of displacement and imbibition,it effectively addresses the issue of easy channeling of the injection medium and difficult energy replenishment after large-scale fracturing.By intensifying the imbibition effect through the coordination of multiple wells,it reconstructs the combined system of displacement and imbibition under a complex fracture network,transitioning from avoiding fractures to utilizing them,thereby improving microscopic sweep and oil displacement efficiencies.Field application in Block Yuan 284 of the Huaqing Oilfield in the Ordos Basin has demonstrated that this technology increases the recovery factor by 12 percentage points,enabling large scale and efficient development of tight oil.

Impacts of proppant distribution on development of tight oil reservoirs with threshold pressure gradient

Field evidence indicates that proppant distribution and threshold pressure gradient have great impacts on well productivity.Aiming at the development of unconventional oil reservoirs in Triassic Chang-7 Unit,Ordos Basin of China,we presented an integrated workflow to investigate how(1)proppant placement in induced fracture and(2)non-linear flow in reservoir matrix would affect well productivity and fluid flow in the reservoir.Compared with our research before(Yue et al.,2020),here we extended this study into the development of multi-stage fractured horizontal wells(MFHWs)with large-scale complicated fracture geometry.The integrated workflow is based on the finite element method and consists of simulation models for proppant-laden fluid flow,fracture flow,and non-linear seepage flow,respectively.Simulation results indicate that the distribution of proppant inside the induced cracks significantly affects the productivity of the MFHW.When we assign an idealized proppant distribution instead of the real distribution,there will be an overestimation of 44.98%in daily oil rate and 30.63%in cumulative oil production after continuous development of 1000 days.Besides,threshold pressure gradient(TPG)also significantly affects the well performance in tight oil reservoirs.If we simply apply linear Darcy’s law to the reservoir matrix,the overall cumulative oil production can be overrated by 77%after 1000 days of development.In general,this research provides new insights into the development of tight oil reservoirs with TPG and meanwhile reveals the significance of proppant distribution and non-linear fluid flow in the production scenario design.

The effects of various factors on spontaneous imbibition in tight oil reservoirs

Slickwater fracturing fluids have gained widespread application in the development of tight oil reservoirs. After the fracturing process, the active components present in slickwater can directly induce spontaneous imbibition within the reservoir. Several variables influence the eventual recovery rate within this procedure, including slickwater composition, formation temperature, degree of reservoir fracture development, and the reservoir characteristics. Nonetheless, the underlying mechanisms governing these influences remain relatively understudied. In this investigation, using the Chang-7 block of the Changqing Oilfield as the study site, we employ EM-30 slickwater fracturing fluid to explore the effects of the drag-reducing agent concentration, imbibition temperature, core permeability, and core fracture development on spontaneous imbibition. An elevated drag-reducing agent concentration is observed to diminish the degree of medium and small pore utilization. Furthermore, higher temperatures and an augmented permeability enhance the fluid flow properties, thereby contributing to an increased utilization rate across all pore sizes. Reduced fracture development results in a lower fluid utilization across diverse pore types. This study deepens our understanding of the pivotal factors affecting spontaneous imbibition in tight reservoirs following fracturing. The findings act as theoretical, technical, and scientific foundations for optimizing fracturing strategies in tight oil reservoir transformations.

Optimization of refracturing timing for horizontal wells in tight oil reservoirs: A case study of Cretaceous Qingshankou Formation, Songliao Basin, NE China

Tight oil reservoirs in Songliao Basin were taken as subjects and a novel idealized refracturing well concept was proposed by considering the special parameters of volume fracturing horizontal wells, the refracturing potential of candidate wells were graded and prioritized, and a production prediction model of refracturing considering the stress sensitivity was established using numerical simulation method to sort out the optimal refracturing method and timing. The simulations show that: with the same perforation clusters, the order of fracturing technologies with contribution to productivity from big to small is refracturing between existent fractured sections, orientation diversion inside fractures, extended refracturing, refracturing of existent fractures; and the later the refracturing timing, the shorter the effective time. Based on this, the prediction model of breakdown pressure considering the variation of formation pressure was used to find out the variation pattern of breakdown pressure of different positions at different production time. Through the classification of the breakdown pressure, the times of temporary plugging and diverting and the amount of temporary plugging agent were determined under the optimal refracturing timing. Daily oil production per well increased from 2.3 t/d to 16.5 t/d in the field test. The research results provide important reference for refracturing optimization design of similar tight oil reservoirs.

Variability in Quantity and Salinity of Produced Water from an Oil Production in South Kuwait

Produced water (PW) is the largest waste stream in the oil and gas industry. Water remains trapped for millions of years in the reservoir with oil and gas. When a hydrocarbon reservoir is infiltrated by a production well, the produced fluids commonly contain water. The understanding of this water’s constituents and volumes is vital for the sustainable continuity of production operations, as PW has a number of negative impacts on the infrastructure integrity of the operation. On the other hand, PW can be an alternative source of irrigation water as well as of industrial salt. Interestingly, both the quantity as well as the quality of PW do not remain constant but can vary, both progressively and erratically, even over short periods of time. This paper discusses such a situation of variable PW in an oil and gas operation in the State of Kuwait.

微小RNA物质、血栓标志物、Wells评分系统联合预测高龄髋部骨折DVT风险价值

目的探究微小RNA物质、血栓标志物、下肢深静脉栓塞评分(Wells评分)系统联合对高龄髋部骨折深静脉血栓形成(DVT)风险的预测价值,为减少DVT发生提供诊断依据。方法选取2020年10月—2022年10月我院收治的105例高龄髋部骨折患者,根据术后1周是否发生DVT分为DVT组(34例)、未DVT组(71例)。比较两组临床资料,于入院后术前进行Wells评分评估,并检测两组微小RNA物质[微小RNA-374b-5p(miR-374b-5p)、微小RNA-664b-3p(miR-664b-3p)]、血栓标志物[凝血酶-抗凝血酶复合物(TAT)、可溶性血栓调节蛋白(sTM)、纤溶酶α2抗纤溶酶复合物(PIC)、组织型纤溶酶原激活物-抑制剂复合物(t-PAIC)],分析DVT发生的影响因素,通过受试者工作特征曲线(ROC)、决策曲线分析(DCA)Wells评分、miR-374b-5p、miR-664b-3p、sTM、PIc、TAT、t-PAIC联合对高龄髋部骨折DVT风险的预测价值及临床效用。结果DVT组术前血浆FDP水平及Wells评分高度可能占比高于未DVT组(P<0.05);DVT组miR-374b-5p相对表达量高于未DVT组,miR-664b-3p相对表达量低于未DVT组(P<0.05);DVT组血浆sTM、PIC、TAT、t-PAIC水平均高于未DVT组(P<0.05);FDP、Wells评分、miR-374b-5p、miR-664b-3p、sTM、PIC、TAT、t-PAIC均为高龄髋部骨折患者发生DVT的影响因素(P<0.05);Wells评分、miR-374b-5p、miR-664b-3p、sTM、PIC、TAT、t-PAIC预测高龄髋部骨折DVT风险的AUC值分别为0.666、0.734、0.750、0.730、0.764、0.761、0.800,各指标联合预测高龄髋部骨折患者发生DVT的AUC最大,为0.921,且具有良好临床效用(P<0.05)。结论miR-374b-5p、miR-664b-3p、sTM、PIC、TAT、t-PAIC、Wells评分系统联合预测高龄髋部骨折DVT风险的预测效能较高,临床效用良好。

Multistring analysis of wellhead movement and uncemented casing strength in offshore oil and gas wells

This paper presents a theoretical method and a finite element method to describe wellhead movement and uncemented casing strength in offshore oil and gas wells.Parameters considered in the theoretical method include operating load during drilling and completion and the temperature field,pressure field and the end effect of pressure during gas production.The finite element method for multistring analysis is developed to simulate random contact between casings.The relevant finite element analysis scheme is also presented according to the actual procedures of drilling,completion and gas production.Finally,field cases are presented and analyzed using the proposed methods.These are four offshore wells in the South China Sea.The calculated wellhead growths during gas production are compared with measured values.The results show that the wellhead subsides during drilling and completion and grows up during gas production.The theoretical and finite element solutions for wellhead growth are in good agreement with measured values and the deviations of calculation are within 10％.The maximum von Mises stress on the uncemented intermediate casing occurs during the running of the oil tube.The maximum von Mises stress on the uncemented production casing,calculated with the theoretical method occurs at removing the blow-out-preventer （BOP） while that calculated with the finite element method occurs at gas production.Finite element solutions for von Mises stress are recommended and the uncemented casings of four wells satisfy strength requirements.

Progress and prospects of horizontal well fracturing technology for shale oil and gas reservoirs

By systematically summarizing horizontal well fracturing technology abroad for shale oil and gas reservoirs since the “13th Five-Year Plan”, this article elaborates new horizontal well fracturing features in 3D development of stacked shale reservoirs, small well spacing and dense well pattern, horizontal well re-fracturing, fracturing parameters optimization and cost control. In light of requirements on horizontal well fracturing technology in China, we have summarized the technological progress in simulation of multi-fracture propagation, horizontal well frac-design, electric-drive fracturing equipment, soluble tools and low-cost downhole materials and factory-like operation. On this basis, combined with the demand analysis of horizontal well fracturing technology in the “14th Five-Year Plan” for unconventional shale oil and gas, we suggest strengthening the research and development in the following 7 aspects:(1) geology-engineering integration;(2) basic theory and design optimization of fracturing for shale oil and gas reservoirs;(3) development of high-power electric-drive fracturing equipment;(4) fracturing tool and supporting equipment for long horizontal section;(5) horizontal well flexible-sidetracking drilling technology for tapping remaining oil;(6) post-frac workover technology for long horizontal well;(7) intelligent fracturing technology.

Development Strategies for Achieving High Production with Fewer Wells in Conventional Offshore Heavy Oil Fields in Bohai Bay,China

Development strategy for heavy-oil reservoirs is one of the important research interests in China National Offshore Oil Corp. （CNOOC） that plans a highly effective development for heavy oil fields in multilayered fluvial reservoirs because of their significant influence on marine oil and even on China＇s petroleum production. The characteristics analysis of multilayered fluvial reservoirs in the heavy oil fields in Bohai Bay indicates that large amounts ofoil were trapped in the channel, point bar and channel bar sands. The reserves distribution of 8 oilfields illustrates that the reserves trapped in the main sands, which is 20%-40% of all of the sand bodies, account for 70%-90% of total reserves of the heavy oil fields. The cumulative production from high productivity wells （50% of the total wells） was 75%-90% of the production of the overall oilfield, while only 3%-10% of the total production was from the low productivity wells （30% of the total wells）. And the high productivity wells were drilled in the sands with high reserves abundance. Based on the above information the development strategy was proposed, which includes reserves production planning, selection of well configuration, productivity design, and development modification at different stages.

Integrated hydraulic fracturing techniques to enhance oil recovery from tight rocks

Two main challenges exist in enhancing oil recovery rate from tight oil reservoirs,namely how to create an effective complicated fracture network and how to enhance the imbibition effect of fracturing fluid.In response to the challenges,through modeling experiment in laboratory and evaluation of field application results,a set of integrated efficient fracturing and enhanced oil recovery(EOR)techniques suitable for tight oil development in China has been proposed.(1)Fracturing with temporary plugging agents to realize stimulation in multiple clusters,to form dense fracture network,and thus maximizing the drainage area;(2)Supporting induced fractures with micro-sized proppants during the prepad fluid fracture-making stage,to generate dense fracture network with high conductivity;(3)Using the liquid nanofluid as a fracturing fluid additive to increase oil-water displacement ratio and take advantage of the massive injected fracturing fluid and maximize the oil production after hydraulic fracturing.

Shut-in time optimization after fracturing in shale oil reservoirs

A multi-process(fracturing,shut-in and production)multi-phase flow model was derived considering the osmotic pressure,membrane effect,elastic energy and capillary force,to determine the optimal shut-in time after multi-cluster staged hydraulic fracturing in shale reservoirs for the maximum production.The accuracy of the model was verified by using production data and commercial software.Based on this model and method,a physical model was made based on the inversion of fracture parameters from fracturing pressure data,to simulate the dynamic changes of pore pressure and oil saturation during fracturing,soaking and production,examine effects of 7 factors on the optimal shut-in time,and find out the main factors affecting the optimal shut-in time through orthogonal experiments.With the increase of shut-in time,the increment of cumulative production increases rapidly first and then tended to a stable value,and the shut-in time corresponding to the inflection point of the change was the optimal shut-in time.The optimal shut-in time has a nonlinear negative correlation with matrix permeability,porosity,capillary pressure multiple and fracture length,a nonlinear positive correlation with the membrane efficiency and total volume of injected fluid,and a nearly linear positive correlation with displacement.The seven factors in descending order of influence degree on optimal shut-in time are total volume of injected fluid,capillary force multiple,matrix permeability,porosity,membrane efficiency,salinity of fracturing fluid,fracturing fluid displacement.

Stress redistribution in multi-stage hydraulic fracturing of horizontal wells in shales

Multi-stage hydraulic fracturing of horizontal wells is the main stimulation method in recovering gas from tight shale gas reservoirs, and stage spacing deter- mination is one of the key issues in fracturing design. The initiation and propagation of hydraulic fractures will cause stress redistribution and may activate natural fractures in the reservoir. Due to the limitation of the analytical method in calculation of induced stresses, we propose a numerical method, which incorporates the interaction of hydraulic fractures and the wellbore, and analyzes the stress distri- bution in the reservoir under different stage spacing. Simulation results indicate the following： （1） The induced stress was overestimated from the analytical method because it did not take into account the interaction between hydraulic fractures and the horizontal wellbore. （2） The hydraulic fracture had a considerable effect on the redis- tribution of stresses in the direction of the horizontal wellbore in the reservoir. The stress in the direction per- pendicular to the horizontal wellbore after hydraulic frac- turing had a minor change compared with the original in situ stress. （3） Stress interferences among fractures were greatly connected with the stage spacing and the distance from the wellbore. When the fracture length was 200 m, and the stage spacing was 50 m, the stress redistribution due to stage fracturing may divert the original stress pat- tern, which might activate natural fractures so as to generate a complex fracture network.