Deformation of shale gas wells casing has hindered the progress of fracturing operations, becoming a significant challenge in field development. Current risk assessment methods for casing deformation in shale gas wells are not only complex and difficult to model but also lack the necessary speed and convenience for field applications. To address these challenges, this study takes the Jingyan block as a practical case study and proposes a casing deformation risk assessment method based on the Analytic Hierarchy Process (AHP). In establishing the indicator system for casing deformation, qualitative methods are applied to rapidly identify the categories of primary influencing factors, resulting in an indicator system that includes natural fractures zones, geological heterogeneity, geostress, and brittle mineral content. Subsequently, a judgment matrix is constructed using the indicator system to calculate the weight values of each indicator. A risk assessment formula for casing deformation is then established. Finally, during the risk assessment process, quantitative methods are employed to determine the risk level of casing deformation using precise numerical values. Research results demonstrate that in the specific application of this block, the method successfully simplified the complex decision-making problem, which was previously difficult to address, into a multi-level single-objective problem. It also enabled a hierarchical quantitative analysis of the qualitative indicators obtained. This systematic approach integrates the influence of various factors on the results, achieving an 88.83% consistency rate compared with actual casing deformation stage in the field and verifying its reliability in field application. This study provides a new method for predicting the high-risk stages of casing deformation. The approach not only offers a clear and straightforward process with predictable results that are readily usable by decision-makers but also provides reference for optimizing fracturing construction designs in subsequent stages.

The reservoir space in the fracture zones around fault-karst reservoirs in the Shunbei area of the Tarim Basin predominantly consists of natural fractures. Acid fracturing is necessary to improve the connectivity of these fracture zones and enhance productivity. However, these reservoirs are characterized by high temperatures (up to 180°C) and high closure stresses (up to 80 MPa), leading to short acid-etched fractures and low conductivity. Hybrid acid stimulation with proppant is a possible technique for building the conductivity of the fracture networks. Nevertheless, the feasibility of proppants migrating into branch fractures to achieve comprehensive conductivity under acid fracturing conditions remains uncertain. This study first identifies the optimal combination of conductivities in main and branch fractures based on productivity simulations. Further, an acid fracturing model for fractured carbonate reservoirs is used to reveal the acid-etched conductivities under different acid injection conditions, and post-etching branch fracture widths are also obtained. Finally, using CFD-DEM coupling methods, the study examines the ability and characteristics of proppant entry into acid-etched branch fractures under varying branch fracture widths and proppant parameters. The results indicate that the acid fracturing process generally meets the flow capacity requirements of the main fractures, achieving an average flow capacity of 1.6 to 34.3 Dc·cm under closure stress of 80 MPa. However, the effectiveness in improving branch fractures is limited, with an average flow capacity of 0.7 to 8.5 Dc·cm and a maximum acid-etched length of only 10 meters. Simulations of proppant entry into fractures reveal that when the post-dissolution branch fracture width exceeds 0.6 mm, with a carrier fluid discharge rate of over 8.3 m3/min and viscosity greater than 25 mPas, 70/140 mesh proppant can effectively enter the fractures (with an entry ratio exceeding 20%). From a productivity perspective, considering the fracture flow capacity requirements and proppant entry capabilities, the study comprehensively recommends suitable processes and parameters. The methodologies established in this study provide valuable references for examining and optimizing the feasibility of related processes.

Understanding the stress state caused by a subsequent failure is crucial for successful refracturing. However, there are many differences between the stress reorientation phenomena of a multi-fracture horizontal well and that of a single fracture in a vertical well, including the interaction of multi-fractures. These factors can lead to a change in the stress field of multiple fractures, which is more complex than that of a single fracture. In this paper, based on the elastic theory of porous media and the mechanism of fluid–structure interaction, a finite element numerical model of multi-fracture stress fields is established. The net pressure loaded on the fracture wall was corrected using the fracture line model, which was solved using the separated coupling method with a staggered strategy, and a full coupling simulation of fluid flow and rock deformation was achieved. The results showed that with an increase in production time, the stress reorientation area around the fracture and at both ends first increased at a faster rate, then slowly decreased, and finally disappeared,indicating an optimal refracturing time window. This suggests that the greater the number of fractures, the greater the fracture inclination and fracture bending degree, and the more unfavorable it is for the formation and maintenance of the stress reorientation area near the fracture and at both ends of the fracture. The reorientation of the stress field between horizontal wells may lead to the fracture of the infill wells, causing bending and propagation towards the pressure-depletion area, thus reducing productivity.

The Leikoupo carbonate reservoirs in the West Sichuan gas field generally exhibit low porosity and permeability characteristics. After acidizing, the fluid flowback rate is only 46%, and a large amount of residual acid remains in the reservoir, causing damage to the pores. In this study, the rheological tests were first carried out to reveal the rheological characteristics of fresh and residual acid with different thickener contents. Then, the change in core permeability before and after acid flooding was tested by core-flood tests, and the effects of acid on pore structure in various scales were analyzed in nuclear magnetic resonance (NMR) tests. The research results show that the average viscosity of residual acid increased to about 157.14% of the fresh acid and exhibited large viscosity fluctuations, which may be caused by the formation of aggregates combined with thickener and insoluble. The change rate of core permeability (both improvement and damage) decreased with the increase in thickener content, and the effect was more significant when the thickener content changed from 0.6% to 0.8%. Under different thickener addition amounts, fresh acid mainly improved the core permeability. After coreflooding, micropores and mesopores (51.26-632.15 mu m) were dissolved and enlarged, forming mesopores and macropores (632.15-3597.73 mu m); when the thickener content increased to 0.8%, the solubility of acid decreased, and the pore volume increment and maximum pore size both decreased. On the other hand, residual acid mainly damages the core, thickener molecules in the acid occupying mesopore, leading to an overall shift in pore distribution from mesopores (145.24-335.53 mu m) to micropores (20.59-126.32 mu m), with the thickener content increased to 0.8%, the damage volume of mesopore increased by 723.90%. Based on the research results, the reduced thickener content was initially applied to the West Sichuan gas field, achieving a better acidizing effect.

川东YL地区陆相致密砂岩气藏埋藏深、岩性致密,压裂改造是实现该区域有效勘探开发的必要手段,但YL地区深层致密砂岩压裂改造面临着破裂压力超高、施工压力超高、闭合压力超高、排量提升困难、缝高控制困难等技术难题,大部分气井压后产能低且产量递减快.储层改造工艺技术能否取得突破,直接影响到了该地区的勘探开发进程.通过分析YL地区深层致密砂岩气藏的储层特征,总结前期现场实践中面临的技术难题及实施经验,提出一套适用于川东深层致密砂岩气藏的压裂改造工艺技术,可有效促进地区勘探开发工作,对同类型的深层致密砂岩压裂改造具有借鉴意义.

元坝地区陆相砂岩储层具有埋藏深、致密、岩性复杂、高压、高温、非均质性强、较薄、含气饱和度普遍较低等特点,气井通常需要进行储层改造后才能获得工业气流,但大部分气井改造难度大、压后产能低、产量递减快.通过对储层深入认识,分析了深层致密砂岩压裂改造难点,结合前期理论探索和现场实践,形成了适用于川东北深层致密砂岩气藏的压裂改造工艺的关键技术,重点解决施工压力高的难题,确保压裂过程的低伤害,提高了压裂规模,基本满足了探井测试需要,有效促进了地区勘探工作,对同类型的深层致密砂岩压裂改造也具有重要借鉴意义.

Fracturing stimulation in deep tight gas reservoir in Eastern Sichuan Basin China shows that natural fractures obviously affect the treatment pressure. Accurate determination of breakdown pressure in the presence of pre-existing fracture can assist engineers better manage expected fracture gradients. The available fracture models for breakdown pressure prediction did not consider possible failure mode of hydraulic fracture influenced by pre-existing fracture. In addition, Elsworth indicates that breakdown pressure is a strong function of fracturing fluid infiltration. Infiltration due to pre-existing fractures is non-negligible to breakdown pressure prediction. To overcome the limitation of current models, a model considering pre-existing fracture is applied to predict breakdown pressure. The stress distribution of pre-existing fracture intersected with perforation hole considering fluid infiltration is described based on stress distribution model of ellipsoid. The breakdown pressure prediction model is built considering uniform stress distribution and 3 possible failure mode, which are tensile failure of matrix, tensile failure of pre-existing fracture and shear failure of pre-existing fracture, described by corresponding failure criterion. Sensitivity studies are conducted to investigate the influence of pre-existing fracture dip angle, orientation and location on failure mode and breakdown pressure. It indicates that the distribution of pre-existing fracture has great effect on hydraulic fracture failure mode and corresponding breakdown pressure. The breakdown pressure (1) increases with increasing dip angle and decreases with increasing orientation when matrix fails, and (2) doesn't always show the same tendency when pre-existing fracture fails. The novel model is further verified against measured breakdown pressure from field fracturing treatment of M3 well in deep sandstone formation in eastern Sichuan Basin.

General fracturing and separate layer fracturing play an important role in sandstone and mudstone thin interbed (SMTI) reservoirs, where one of the main issues is to control the excessive height growth of fracturing. The fracture propagation at the interface depends on the induced stress produced by the hydraulic fracturing construction. This paper employed a poroelastic coupled damage element with the cohesive zone method (CZM) to establish a 2D fracture quasi-static propagation model. A parametric study was performed under different fracture height, fracture width, pumping rate, fluid viscosity, in situ stress, elastic modulus and tensile strength with this model. General fracturing and separate layer fracturing are compared with each other through fracture morphology and induced stress. The simulation results show that the absolute value of induced stress increases with the decrease in matrix stress near the fracture tip. As a result, the propagation of the fractures is much easier due to the weakened degree of compression. The growth of fracture height and width, the increase in pumping rate and the excessively large or small value of fluid viscosity lead to larger induced stress on the interface. Higher in situ stress, lower elastic modulus, and higher tensile strength of the interlayers can control the excessive height growth of fracturing. The simulated results also show that the fractures are more likely to be overlapped with each other in general fracturing compared to that in separate-layer fracturing. Results of the simulations suggest that lower pumping rates, the proper value of fluid viscosity, separate layer fracturing and interlayers with higher in situ stress, lower elastic modulus and higher tensile strength tend to limit fracture height. Finally, the proposed model was applied to a practical oil field case to verify its effectiveness.

Abstract Tight gas plays an important role in the increasing production of natural gas. Staged hydraulic fracturing has been a key technology to make recovery of tight gas economically viable. The JP formation of Western-Sichuan Gas Field is a typically tight gas reservoir with horizontal wells. However, the optimization design of staged fracturing encountered two challenges: Low porosity-low permeability with non-Darcy effect; High heterogeneity with discontinuous distribution of sand bodies and properties variation in the longitudinal direction. The traditional optimization method based on Darcy flow and homogeneous model is not capable in the optimization of fracturing parameters (spacing, length and conductivity) and perforation position. This paper presents a new design method of "one strategy for one well" with better economical results. Firstly, non-Darcy flow character was measured by laboratory displacement experiment. The relationship between pseudo threshold pressure gradient (pseudo TPG) and permeability was fitted based on quasi-linear flow with pseudo TPG. Secondly, long horizontal section heterogeneous reservoir models were built on the basis of log and geological interpretation, which involves homogeneous continuous model, interbedding model with barrier and heterogeneous model composed of different seepage units. With barriers and seepage units located, fracture parameters include fracture spacing, length and conductivity were optimized for the goal of best economical production with numerical simulation. Thirdly, a model of induced stress from hydraulic fractures was established based on displacement discontinuity theory. Combined with the optimal fracture spacing, the best perforation position was located with the target of low initiation pressure. Lastly, based on fractures parameters and perforation positions, the operation parameters are designed. The new design method has been successfully applied to 21 horizontal wells with staged fracturing. Microseismic fracture mapping is conducted to evaluate fractures geometry. The results of post-fracture analysis and post-production evaluation demonstrate the benefits of this new optimization method.

页岩储层具有低孔隙度、超低渗透率的特征,往往需要通过水力压裂才能使气井具备一定的生产能力.拉链压裂是近年来针对页岩气藏缝网压裂的一项新兴工艺,为了认清压裂过程中裂缝应力干扰后地应力场的分布规律并给页岩压裂设计提供参考,首先假设地层为均质、各向同性弹性体,然后通过位移不连续法,建立起地层应力场分布数学模型,并利用线性叠加原理,得到人工裂缝周围水平应力场的分布情况.研究发现:①裂缝周围的地应力随着与裂缝距离的远近有不同程度的增加;②裂缝尖端处存在应力集中现象,且在裂缝尖端附近产生的拉应力使得水平应力有所减小;③裂缝对水平最小主应力的影响程度大于对最大主应力的影响;④随着裂缝条数的增加,诱导应力的叠加干扰对水平主应力的影响不断增强,且水平应力差异性逐渐减小;⑤在裂缝交错排列的区域内,应力干扰较强,应力场分布较复杂.上述研究成果对页岩气水平井组拉链压裂的优化设计具有指导意义.

Abstract Hydraulic fracturing, creating stimulated reservoir volumes, has been widely applied to obtain economic flow in shale gas/oil formations today. However, for a fractured shale vertical well, determining the volume of proppant placed into the pay zone still remains difficult. Previous methods are based mainly upon empirical approaches which, to a large extend, are uncertain and imperfect. This paper established a novel but simple mathematical model to calculate the volume of proppant, merely using optimized parameters of fracture network obtained from numerical simulation. Since the permeability of fracture networks is several orders of magnitude larger than that of the reservoir and the geometry of them is considerably complex, the fracture networks are simplified as a high permeability zone (HPZ) according to the equivalent principle of seepage. HPZ units are selected to build this model based on the following assumptions: (1) the seepage flow in shale involves the matrix flow and fracture flow from HPZ units to wellbore under steady state, (2) a multilayer seepage model is utilized to describe the fluids flowing in HPZ unit and study the characteristic seepage behavior of dual porosity medium, (3) heterogeneity in fracture propagation direction is neglected, (4) the proppant is packed into the fracture uniformly. The model reported here has been successfully applied to XC32 well in Sichuan Basin and its prediction is 408.8m3(40/70-mesh, ceramic proppant). In reality, 400.4m3 of proppant was used and fracturing monitoring showed that the HPZ parameters in the field (length 500~600m, width 130~200m) match well with previous optimized design (length 550m, width 100m). Besides, the resulting flow rate is 7.04×104m3/d in this case, which is a breakthrough for unconventional reservoirs in Sichuan Basin. Because this model considered the vertical heterogeneity of the reservoir and simply utilized HPZ parameters, it is convenient and meaningful to direct the treatment design in the field.

Abstract Sevensprings oilfield is one of the oldest mature-flood fields with target stratum between 1000 and 1200m TVD in China with Strong permeability heterogeneity within the range of 0.01-50mD. Most of its wells have been fractured. But for now, the fractured wells have lost their power to maintain productivity. Early analyses show the wells have gained different production dynamics and the stress field around bottom hole was unclear after nearly 20 years water-flooding. Without a proper refracturing strategy, it still could not awake the wells properly. This paper presents a novel method to determine the refracturing strategy and the priorities of the candidate wells by comprehensive analysis, which considers reservoir properties, remaining oil distributions and induced stress fields. Application shows this method is effective and it can provide a reference for the analogous reservoirs to develop refracturing strategy. First we found out the basic situation of remaining oil and reasons for low-yielding of different wells under various fracture orientation and stratigraphic features through simulation. Combined with these two factors, we can divide the wells into different types which represented by residual oil distribution and location characteristics. After this, we obtained the induced stress field through marching the Waterflooding history. Through analyzing the hydraulic fracture steering angle and steering range, we can figure out the feasibility of steering fracturing to each well type. At last, we made a productivity simulation for each well type with corresponding feature models and fracture steering possibility. Based on this, we can develop the suitable refracturing strategy for every well type and gain the priorities according to the simulated productivity increment. The novel method established in this paper has been effectively applied in Sevensprings oilfield. Before this, there were more than ten well had been refractured, the average productivity growth rate was 34%, and some wells came to capacity drop because of incorrect treatment. Based on this method, we chose several candidates from more than 100 wells prepared to be refractured. And three of them have already been processed. All of them achieved preferable stimulation response. 3-3 shows an increasing fold of 3.85 from 2.57 t /d to 7.64 t /d. Shen-27 shows a daily production increase of nearly three times from 2.57 t /d to 7.64 t /d. Nowadays, larger-scale application was ongoing Application shows this new method to determine refracturing strategy and well stimulation priority is effectively. And it can provide a reference for the analogous reservoirs to improve their re-stimulation response.

Tight reservoir is characterized with low porosity and ultra-low permeability. Horizontal well with multi-stage fracturing is the key technique to maximize stimulated reservoir volume and achieve commercial production. The spacing between perforations has a significant impact on well production. Perforation spacing is currently optimized from the aspects of reservoir simulation. The methods ignore the fact that fracture will generate induced stress field, which may significantly affect the geometry of subsequent fracture. Based on the displacement discontinuity method, this paper established a multi-fracture stress interference model which is able to simulate non-isometric half-length, unequal fracture spacing and arbitrary angle between fracture and wellbore. Data from a tight sandstone reservoir in Sichuan Basin of China are used to analyze the stress field changes and verify the model. The results show that the induced stress creates the maximum compressive stress on both sides of the fracture, and the maximum tensile stress at the fracture tip by stress concentration. The fracture will change the differential horizontal stress ratio in the surrounding area. Position where the differential horizontal stress ratio is lower than 0.3 will be the optimal site to create the complex fractures. Multi-stage fracturing with multiple perforation clusters in one stage is more favorable for complex fracture formation than single perforation cluster in each stage. Data from field verified the proposed perforation optimization method.

Many rocks exhibit nonlinear behavior under the effect of internal and external factors; thus, stress and initiation models based on linear elastic theory are not applicable for these rocks. In accordance with the deformation theory of plastic mechanics, a nonlinear constitutive model is developed in this study based on the power-hardening equation using a piecewise approximation method. A new model for the elastic plastic stress field around the wellbore is then proposed considering the in-situ stress anisotropy. Finally, a new elastic plastic hydraulic fracturing initiation model is developed, coupled with the maximum tensile strength and Mohr Coulomb criteria. Calculations and analyses reveal that the nonlinearity of the constitutive relation has significant effects on the stress distribution, initiation mode, and pressure. The plastic yield has little effect on the radial stress but a significant effect on the circumferential stress. When rock yielding occurs, the stress concentration around the wellbore is reduced, and the circumferential stress decreases or cannot be tensile. In this case, the initiation pressure is much higher than that of the linear elastic model, and the initiation mode includes tensile and shear failure. The initiation mode is comprehensively controlled by the in-situ stress, cohesion, tensile strength, power-hardening index, yield stress, and internal friction angle. The initiation orientation of both initiation modes is along the maximal horizontal principal stress direction; however, there is a failure angle for the shear failure. It is more accurate to predict the initiation mode and pressure using the piecewise power-hardening constitutive equation than the Hubbert and Willis model. (C) 2015 Elsevier B.V. All rights reserved.

A calculation model for stress field due to horizontal well staged fracturing is proposed according to stress superposition principle. The model considers the influence of the wellbore pressure, in-situ stress, fracturing fluid seepage, thermal stress, perforation and artificial cracks. It can accurately adapt to the change of stress field around the wellbore in the process of staged fracturing in horizontal wells, and guide the research of the fracture initiation and extension mechanism. The model focuses on the induced stress caused by artificial cracks in the plane around the horizontal wellbore with the method of the displacement discontinuity. The model can also overcome the limitation of ordinary induced stress analytical models which can only calculate the induced stress in the fracture height plane. Results show that the fracture pressure calculated with the proposed model is consistent with the actual fracture pressure, which demonstrates the accuracy of the model. The artificial fractures can cause great impact on stress field around the wellbore. The stress concentration at the crack tips can result in the reduction of stress components and the obvious increasing of the stress components around a given area of fractures. Meanwhile, the more artificial fractures are fractured, the more serious the stress interference is and the more complex the stress distribution around wellbore is. The research has significance in analyzing the crack initiation and propagation mechanism under the influence of crack interference and provides guidance to fracturing design as well.

Since traditional hydraulic fracturing initiation models are primarily based on linear elastic theory, they are not applicable for the elastoplastic reservoirs. Therefore, it is necessary to explore a new initiation model on the basis of the nonlinear constitutive equation. Considering the total deformation theory of plasticity, a model is established for the stress field around a well. Furthermore, an elastoplastic hydraulic fracturing initiation model is proposed according to the stress distribution model and failure criteria of elastoplastic rock. The results show that once the rock is yielded, the effect of stress concentration around the wellbore is greatly weakened and the circumferential tensile stress decreases and even disappears. The initiation pressure is higher than that predicted by the linear-elastic theory. There are two types of fracturing initiation modes including tensile and shear failures, and the shear failure is characterized by a failure angle. When the hardening index of rock is not greater than 0.5, only shear failure takes place. However, when the hardening index is greater than 0.5, the shear failure tends to happen more frequently when the values of yield stress, hardening index, internal friction angle and cohesion are small; on the contrary the tensile failure occurs.

Abstract XS gas reservoir in Western Sichuan Basin is a typical tight sands hotspot in China, of which the target stratum, namely the 3nd Member of Penglaizhen Formation is braided channel deposition. The sand body with good communication along the river channel is opposite perpendicular to the channel. Moreover, the reservoir with horizontal drilling shows diverse type of sand bodies and strong heterogeneity in vertical and lateral directions. Multi-stage hydraulic fractured horizontal wells have been proven to be effective to enhance gas recovery in tight sandstone gas reservoir. However, one major obstacle has been the previous inability to place the hydraulic-fracture in the complex fluvial tight reservoir to maximize gas production. This paper provides a 3D fracturing design method (3D FDM) considering the influence of various sand-body and flow units on the hydraulic fracture propagation in fluvial tight reservoirs. Firstly, the reservoir was classified into three grades based on its porosity and permeability. A 3D geostatistical reservoir model which was divided into three types, was developed with the sandstone body distributions in vertical and lateral directions. Subsequently, the flow unit boundary was determined by the sand-body permeability and thickness. Then the detailed fracture parameters were implemented in the 3D models and reservoir simulation was used to select the fracture number, space, length and conductivity to achieve economical flow rates. At last, the fracturing simulator was utilized to confirm whether the treatment parameters were appropriate. Results show that the flow unit boundary is a log function of sand-body permeability and thickness. The influence of reservoir grades on fracture space is obvious, which indicates that the fracture space is large in high-grade reservoirs. Comparing various qualities of reservoirs, the fracture length and conductivity in poor-quality reservoirs is considered to be the most significant. Comparison with the fracturing wells with conventional fracturing design method in Xinma gas reservoir, the post-production of the well with 3D FDM increases by 41%, and it shows that 3D FDM is appropriate for the gas development in Penglaizhen Formation.

水力压裂是有效开发页岩储层的关键技术,页岩的可压裂性是评价页岩储层被有效压裂程度的一个定性指标.岩石力学实验、全岩分析等常规方法因受取心层段、成本等限制,求取的可压性指数存在片面、不连续等缺点.借助测井方法代替常规方法求取目标储层岩石力学参数与矿物组成,结合岩石脆性、矿物组分、成岩作用等影响因素建立了单井可压性剖面模型,利用模型计算了孔南地区页岩储层可压性剖面并对其进行了定量评价,模型方法与实验方法的计算结果较为一致.可压性剖面模型的应用,实现了对整个储层的连续评价,可为页岩储层有效开发提供准确参考依据.

A model of coupling the stress equilibrium and fluid continuity equations was proposed to aim at production increasing ability gradually reduced in the process of fracturing gas well production. Based on the Sichuan Western area's geological data, the process of production was simulated to study the change rule of stress field and pore pressure with time. And it also helped to choose appropriate refracturing time. The results showed that the pore pressure reduced and the stress field change range expanded as time goes on. The fitting curve of stress field change range and time helped us to choose appropriate refracturing time. These methods were used to clear the change range of stress field and judge whether implement redirection fracturing. The obtained conclusions were significance for the field operation of refracturing.