Fracture network types revealed by well test curves for shale reservoirs in the Sichuan Basin,China

Pressure buildup testing can be used to analyze fracture network characteristics and conduct quantitative interpretation of relevant parameters for shale gas wells,thus providing bases for assessing the well productivity and formulating proper development strategies.This study establishes a new well test interpretation model for fractured horizontal wells based on seepage mechanisms of shale reservoirs and proposes a method for identifying fracturing patterns based on the characteristic slopes of pressure buildup curves and curve combination patterns.The pressure buildup curve patterns are identified to represent three types of shale reservoirs in the Sichuan Basin,namely the moderately deep shale reservoirs with high pressure,deep shale reservoirs with ultra-high pressure,and moderately deep shale reservoirs with normal pressure.Based on this,the relationship between the typical pressure buildup curve patterns and the fracture network types are put forward.Fracturing effects of three types of shale gas reservoir are compared and analyzed.The results show that typical flow patterns of shale reservoirs include bilinear flow in primary and secondary fractures,linear flow in secondary fractures,bilinear flow in secondary fractures and matrix,and linear flow in matrix.The fracture network characteristics can be determined using the characteristic slopes of pressure buildup curves and curve combinations.The linear flow in early secondary fractures is increasingly distinct with an increase in primary fracture conductivity.Moreover,the bilinear flow in secondary fractures and matrix and the subsequent linear flow in the matrix occur as the propping and density of secondary fractures increase.The increase in the burial depth,in-situ stress,and stress difference corresponds to a decrease in the propping of primary fractures that expand along different directions in the shale gas wells in the Sichuan Basin.Four pressure buildup curve patterns exist in the Sichuan Basin and its periphery.The pattern of pressure buildup curves of shale reservoirs in the Yongchuan area can be described as 1/2/→1/4,indicating limited stimulated reservoir volume,poorly propped secondary fractures,and the forming of primary fractures that extend only to certain directions.The pressure buildup curves of shale reservoirs in the main block of the Fuling area show a pattern of 1/4/→1/2 or 1/2,indicating greater stimulated reservoir volume,well propped secondary fractures,and the forming of complex fracture networks.The pattern of pressure buildup curves of shale reservoirs in the Pingqiao area is 1/2/→1/4→/1/2,indicating a fracturing effect somewhere between that of the Fuling and Yongchuan areas.For reservoirs with normal pressure,it is difficult to determine fracture network characteristics from pressure buildup curves due to insufficient formation energy and limited liquid drainage.

A smart productivity evaluation method for shale gas wells based on 3D fractal fracture network model

The generation method of three-dimensional fractal discrete fracture network(FDFN)based on multiplicative cascade process was developed.The complex multi-scale fracture system in shale after fracturing was characterized by coupling the artificial fracture model and the natural fracture model.Based on an assisted history matching(AHM)using multiple-proxy-based Markov chain Monte Carlo algorithm(MCMC),an embedded discrete fracture modeling(EDFM)incorporated with reservoir simulator was used to predict productivity of shale gas well.When using the natural fracture generation method,the distribution of natural fracture network can be controlled by fractal parameters,and the natural fracture network generated coupling with artificial fractures can characterize the complex system of different-scale fractures in shale after fracturing.The EDFM,with fewer grids and less computation time consumption,can characterize the attributes of natural fractures and artificial fractures flexibly,and simulate the details of mass transfer between matrix cells and fractures while reducing computation significantly.The combination of AMH and EDFM can lower the uncertainty of reservoir and fracture parameters,and realize effective inversion of key reservoir and fracture parameters and the productivity forecast of shale gas wells.Application demonstrates the results from the proposed productivity prediction model integrating FDFN,EDFM and AHM have high credibility.

An optimization model for conductivity of hydraulic fracture networks in the Longmaxi shale,Sichuan basin,Southwest China

Shale gas is an important unconventional resource.The economic recovery of shale gas is only possible when a fracture network with sufficient conductivity is created by hydraulic fracturing,that,if effectively propped,connects fracturing fractures and natural fractures.Focusing on the Longmaxi shale in the Sichuan Basin,Southwest China,we built an optimization model for conductivity of multi-grade fractures based on equivalent seepage theory.We then experimentally analyzed the conductivity of self-propped and sand-propped fractures,and optimized the propping patterns of multi-grade hydraulic fractures in shale gas reservoirs.We concluded that the propping effectiveness of fracture networks could be improved by using low concentrations of small-sized sands and by focusing on creating a large number of self-propped fractures.By applying this understanding to the optimization of fracturing designs for the Longmaxi shale,we successfully created networks of well-propped fractures.

Analysis of fracture propagation and shale gas production by intensive volume fracturing

This paper presents an integrated study from fracture propagation modeling to gas flow modeling and a correlation analysis to explore the key controlling factors of intensive volume fracturing.The fracture propagation model takes into account the interaction between hydraulic fracture and natural fracture by means of the displacement discontinuity method(DDM)and the Picard iterative method.The shale gas flow considers multiple transport mechanisms,and the flow in the fracture network is handled by the embedded discrete fracture model(EDFM).A series of numerical simulations are conducted to analyze the effects of the cluster number,stage spacing,stress difference coefficient,and natural fracture distribution on the stimulated fracture area,fractal dimension,and cumulative gas production,and their correlation coefficients are obtained.The results show that the most influential factors to the stimulated fracture area are the stress difference ratio,stage spacing,and natural fracture density,while those to the cumulative gas production are the stress difference ratio,natural fracture density,and cluster number.This indicates that the stress condition dominates the gas production,and employing intensive volume fracturing(by properly increasing the cluster number)is beneficial for improving the final cumulative gas production.

Simulation of the Production Performances of Horizontal Wells with a Fractured Shale Gas Reservoir

The production performances of a well with a shale gas reservoir displaying a complex fracture network are simulated.In particular,a micro-seismic cloud diagram is used to describe the fracture network,and accordingly,a production model is introduced based on a multi-scale flow mechanism.A finite volume method is then exploited for the integration of the model equations.The effects of apparent permeability,conductivity,Langmuir volume,and bottom hole pressure on gas well production are studied accordingly.The simulation results show that ignoring the micro-scale flow mechanism of the shale gas leads to underestimating the well gas production.It is shown that after ten years of production,the cumulative gas production difference between the two scenarios with and without considering the micro-scale flow mechanisms is 19.5%.The greater the fracture conductivity,the higher the initial gas production of the gas well and the cumulative gas production.The larger the Langmuir volume,the higher the gas production rate and the cumulative gas production.With the reduction of the bottom hole pressure,the cumulative gas production increases,but the growth rate gradually decreases.

Complex fracture propagation model and plugging timing optimization for temporary plugging fracturing in naturally fractured shale

In this paper,a viscoelasticity-plastic damage constitutive equation for naturally fractured shale is deduced,coupling nonlinear tensile-shear mixed fracture mode.Dynamic perforation-erosion on fluid re-distribution among multi-clusters are considered as well.DFN-FEM(discrete fracture network combined with finite element method)was developed to simulate the multi-cluster complex fractures propagation within temporary plugging fracturing(TPF).Numerical results are matched with field injection and micro-seismic monitoring data.Based on geomechanical characteristics of Weiyuan deep shale gas reservoir in Sichuan Basin,SW China,a multi-cluster complex fractures propagation model is built for TPF.To study complex fractures propagation and the permeability-enhanced region evolution,intersecting and competition mechanisms between the fractures before and after TPF treatment are revealed.Simulation results show that:fracture from middle cluster is restricted by the fractures from side-clusters,and side-clusters plugging is benefit for multi fractures propagation in uniformity;optimized TPF timing should be delayed within a higher density or strike of natural fractures;Within a reservoir-featured natural fractures distribution,optimized TPF timing for most clustered method is 2/3 of total fluid injection time as the optimal plugging time under different clustering modes.

A New Fracability Evaluation Approach for Shale Reservoirs Based on Multivariate Analysis: A Case Study in Zhaotong Shale Gas Demonstration Zone in Sichuan, China

Fracability characterizes the effectiveness of hydraulic fracturing.The existing assessment methods cannot reflect the actual value of the effectiveness due to a lack of comprehensive consideration and neglect of the influences of engineering factors.This study aims to solve this problem by implementing geological static data and production dynamic data in multivariate analysis in Zhaotong shale gas demonstration zone.First,the reservoir quality index(RQI)was introduced to evaluate the exploration potential by integrating the geological parameters with gray relational analysis.Moreover,the differences in fracturing fluid types and proppant sizes were considered,and the operating parameters were normalized on the basis of the equivalence principle.Finally,the general reservoir fracability index(GRFI)was proposed based on a dimensioned processing of the various parameters.A case study was conducted to verify the accuracy and feasibility of this new approach.The results demonstrate that(1)the organic carbon and gas content are adjusted to contribute the most to the calculation of the RQI,while the effective porosity contributes the least;(2)the fracturing scale is the main operating parameter determining the fracability,which has the strongest correlation with the effectiveness of fracking;and(3)the GRFI has a positive correlation with shale gas production,and the lower limit of the GRFI of 2,000 corresponds to a daily production of 50,000 m3/d;this value is defined as the threshold value of a stripper well.The GRFI is consistent with the productivity trend of shale gas wells in the research block,which suggests that the new model is accurate and practical for well candidate selection.

A numerical investigation on deep shale gas recovery

In recent years,exploration and development of deep shale gas(at a burial depth of 3,500-4,500 m)has become a hotspot in the industry.However,the state of gas storage and transporting mechanism for deep shale gas under high pressure and temperature have not been thoroughly explored,compared with its shallower counterpart.A numerical model for deep shale gas recovery considering multi-site nonisothermal excess adsorption has been established and applied using Finite Element Method.Results from the simulation reveal the following.(1)Excess desorption significantly impacts early-stage performance of deep shale gas well;the conventional way for shallower shale gas development,in which the density of adsorbed gas is not distinguished from that of free gas,overestimates the gas in place(GIP).(2)Although thermal stimulation can speed up the desorption and transporting of deep shale gas,the incremental volume of produced gas,which is impacted not only by seepage velocity but also density of gas,is insignificant,far from expectation.Only an additional 2.03%of cumulative gas would be produced under treatment temperature of 190C and initial reservoir temperature of 90C in a period of 5 years.(3)Matrix porosity,which can be measured on cores in laboratory and/or estimated by using well logging and geophysical data,is the most favorable parameter for deep shale gas recovery.With 60%increase in matrix porosity,an extra 67.25%shale gas on a daily base would be recovered even after 5-year depletion production;(4)Production rate for gas wells in shale reservoirs at 3,500 m and 4,500 m deep would be raised by 5.4%in a 5-year period if the depth of target interval would increase by 340 m without thermal treatment according to the numerical model proposed in the study.

Productivity analysis of a fractured horizontal well in a shale gas reservoir based on discrete fracture network model

The treatment of horizontal wells with massive hydraulic fracturing technology is important for the economical development of shale gas reservoirs, but sometimes is complex because of the induced fractures during the fracturing process. The studies of the fluid flow characteristics in such formations are rare. In this study, a numerical method based on a finite element method (FEM) is developed for the productivity analysis of a horizontal well in a shale gas reservoir with complex fractures. The proposed method takes into account the adsorbed gas and the complex hydraulic fracture branches. To make the problem more tractable, the dimension of the fracture system is reduced from 2-D to 1-D based on the discrete fracture network (DFN) model. The accuracy of the new method is verified by comparing its results with those obtained by the Saphir commercial software. Finally, the productivity of the fractured horizontal wells in shale gas reservoirs with complex fractures systems is evaluated and analyzed. Results show that if a well is produced with a constant bottomhole pressure, the well productivity is much increased due to the existence of fracture branches that can increase the stimulated reservoir volume (SRV). In addition, the number of hydraulic fractures (Nf) and the fracture halMengths (Lf) have an important influence on the well's productivity. The larger the values of Nf,Lf,the greater the well productivity will be. The existence of adsorbed gas can markedly improve the well productivity, and the greater the Langmuir volume, the greater the productivity will be. The conclusions drawn by this study can provide a guidance for the development of unconventional shale gas reservoirs.

A method for predicting the probability of formation of complex hydraulic fracture networks in shale reservoirs: development and application

Shales can form a complex fracture network during hydraulic fracturing, which greatly increases the stimulated reservoir volume (SRV) and thus significantly increases oil or gas production. It is therefore important to accurately predict the probability of formation of the hydraulic fracture network for shale gas exploration and exploitation. Conventional discriminant criteria are presented as the relationship curves of stress difference vs. intersection angle. However, these methods are inadequate for application in the field. In this study, an effective and quantitative prediction method relating to the probability of complex fracture network formation is proposed. First, a discriminant criterion of fracture network was derived. Secondly, Monte Carlo simulation was applied to calculate the probability of the formation of the complex fracture network. Then, the method was validated by applying it to individual wells of two active shale gas blocks in the Sichuan Basin, China. Results show that the probabilities of fracture network are 0.98 for well JY1 and 0.26 for well W204, which is consistent with the micro-seismic hydraulic fracturing monitoring and actual gas production. Finally, the method was further extended to apply for the regional scale of the Sichuan Basin, where the general probabilities of fracture network formation are 0.32–1 and 0.74–1 for Weiyuan and Jiaoshiba blocks, respectively. The Jiaoshiba block has, therefore, an overall higher probability for formation of fracture network than the Weiyuan block. The proposed method has the potential in further application to evaluation and prediction of hydraulic fracturing operations in shale reservoirs.

页岩气缝网优化的数值模拟

为定量评价页岩气储层压裂缝网参数对产量的影响程度,运用页岩渗流机理,通过Eclipse建立页岩气水平井压裂后形成的复杂缝网模型,进行局部网格加密,分析了改变单因素(段间距、簇数、簇间距、次生缝间距、主缝长、次生缝长、主缝导流能力、次生缝导流能力、天然裂缝渗透率)对累计产量的影响,再对所有参数进行多因素正交方案设计,找出影响累计产气量的主控因素先后顺序并得到产量最大化的方案。结果表明,随着段间距、簇数与簇间距的增加,累计产气量随之减少;随着主缝与次生缝的长度增加,累计产气量随之增加;随着天然裂缝渗透率的增加,累计产气量随之增加;影响累计产气量的第一因素是天然裂缝渗透率,排在2到5位的依次是段间距、主缝长、簇间距与簇数,其他4个因素对累计产气量影响不大;正交方案设计中累计产量最多的方案为段间距40m,3簇,簇间距40m,次生缝间距30m,主缝长530m,次生缝长40m,主缝导流能力7×10-3μm2·m,次生缝导流能力2×10-3μm2·m,天然裂缝渗透率0.0008×10-3μm2,累计产量为2.94×108m3。在实际生产中,尽可能提高主裂缝长度,压缩段间距、簇间距与簇数对页岩气产量有较大的提升。研究结果为页岩气压裂缝网部署提供了参考。

基于叠后地震数据的裂缝预测与建模--以太阳-大寨地区浅层页岩气储层为例

太阳—大寨地区在钻井过程中常见泥浆漏失、压裂施工压力高等现象,鉴于叠后三维地震资料几何属性定量预测裂缝的可靠性和精度存在尺度及破碎程度的量化分级问题,提出了基于地震几何属性的裂缝地震相识别和裂缝确定性提取及建模方法。综合应用地震倾角属性、曲率属性和非连续性等多属性,以贝叶斯概率模型为基础,通过无监督聚类分析获得最佳的聚类效果和聚类数;垂向采用逐个时间切片扫描法建立裂缝的空间体系,并对追踪得到的所有线状结构进行清理去噪,简化复杂几何结构,对清理后的裂缝进行网格化重构,计算了裂缝的几何(拓扑)参数,建立了高精度离散裂缝模型。结果表明,应用该方法在太阳—大寨地区浅层页岩气区块准确预测了水平井钻进过程中的断裂和裂缝发育位置,断层和裂缝预测准确率达到92%,有效规避了钻井泥浆漏失,并对压裂设计提供了有力支撑。裂缝地震相识别与离散裂缝网络模型的建立为有效解决该区页岩气藏钻井工程、压裂工程等复杂施工问题提供了依据。