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.

Mechanisms of fracture propagation from multi-cluster using a phase field based HMD coupling model in fractured reservoir

Natural fractures(NFs)are common in shale and tight reservoirs,where staged multi-cluster fracturing of horizontal wells is a prevalent technique for reservoir stimulation.While NFs and stress interference are recognized as significant factors affecting hydraulic fracture(HF)propagation,the combined influence of these factors remains poorly understood.To address this knowledge gap,a novel coupled hydromechanical-damage(HMD)model based on the phase field method is developed to investigate the propagation of multi-cluster HFs in fractured reservoirs.The comprehensive energy functional and control functions are established,while incorporating dynamic fluid distribution between multiple perforation clusters and refined changes in rock mechanical parameters during hydraulic fracturing.The HMD coupled multi-cluster HF propagation model investigates various scenarios,including single HF and single NF,reservoir heterogeneity,single HF and NF clusters,and multi-cluster HFs with NF clusters.The results show that the HMD coupling model can accurately capture the impact of approach angle(θ),stress difference and cementation strength on the interaction of HF and NF.The criterion of the open and cross zones is not fixed.The NF angle(a)is not a decisive parameter to discriminate the interaction.According to the relationship between approach angle(θ)and NF angle(a),the contact relationship of HF can be divided into three categories(θ=a,θ<a,andθ>a).The connected NF can increase the complexity of HF by inducing it to form branch fracture,resulting in a fractal dimension of HF as high as2.1280 at angles of±45°.Inter-fracture interference from the heel to the toe of HF shows the phenomenon of no,strong and weak interference.Interestingly,under the influence of NFs,distant HFs from the injection can become dominant fractures.However,as a gradually increases,inter-fracture stress interference becomes the primary factor influencing HF propagation,gradually superseding the dominance of NF induced fractures.

A new interacting capillary bundle model on the multiphase flow in micropores of tight rocks

Surfactants are widely used in the fracturing fluid to enhance the imbibition and thus the oil recovery rate. However, current numerical models cannot capture the physics behind capillary imbibition during the wettability alteration by surfactants. Although the interacting capillary bundle(ICB) model shows potential in characterizing imbibition rates in different pores during wettability alteration, the existing ICB models neglect the influence of wettability and viscosity ratio on the imbibition behavior, making it difficult to accurately describe the oil-water imbibition behavior within the porous media. In this work,a new ICB mathematical model is established by introducing pressure balance without assuming the position of the leading front to comprehensively describe the imbibition behavior in a porous medium under different conditions, including gas-liquid spontaneous imbibition and oil-water imbibition.When the pore size distribution of a tight rock is known, this new model can predict the changes of water saturation during the displacement process in the tight rock, and also determine the imbibition rate in pores of different sizes. The water saturation profiles obtained from the new model are validated against the waterflooding simulation results from the CMG, while the imbibition rates calculated by the model are validated against the experimental observations of gas-liquid spontaneous imbibition. The good match above indicates the newly proposed model can show the water saturation profile at a macroscopic scale while capture the underlying physics of the multiphase flow in a porous medium at a microscopic scale. Simulation results obtained from this model indicate that both wettability and viscosity ratio can affect the sequence of fluid imbibition into pores of different sizes during the multiphase flow, where less-viscous wetting fluid is preferentially imbibed into larger pores while more-viscous wetting fluid tends to be imbibed into smaller pores. Furthermore, this model provides an avenue to calculate the imbibition rate in pores of different sizes during wettability alteration and capture the non-Darcy effect in micro-and nano-scale pores.

Quantitative investigation of multi-fracture morphology during TPDF through true tri-axial fracturing experiments and CT scanning

Due to the reservoir heterogeneity and the stress shadow effect, multiple hydraulic fractures within one fracturing segment cannot be initiated simultaneously and propagate evenly, which will cause a low effectiveness of reservoir stimulation. Temporary plugging and diverting fracturing(TPDF) is considered to be a potential uniform-stimulation method for creating multiple fractures simultaneously in the oilfield. However, the multi-fracture propagation morphology during TPDF is not clear now. The purpose of this study is to quantitatively investigate the multi-fracture propagation morphology during TPDF through true tri-axial fracturing experiments and CT scanning. Critical parameters such as fracture spacing, number of perforation clusters, the viscosity of fracturing fluid, and the in-situ stress have been investigated. The fracture geometry before and after diversion have been quantitively analyzed based on the two-dimensional CT slices and three-dimensional reconstruction method. The main conclusions are as follows:(1) When injecting the high viscosity fluid or perforating at the location with low in-situ stress, multiple hydraulic fractures would simultaneously propagate. Otherwise, only one hydraulic fracture was created during the initial fracturing stage(IFS) for most tests.(2) The perforation cluster effectiveness(PCE) has increased from 26.62% during the IFS to 88.86% after using diverters.(3) The diverted fracture volume has no apparent correlation with the pressure peak and peak frequency during the diversion fracturing stage(DFS) but is positively correlated with water-work.(4) Four types of plugging behavior in shale could be controlled by adjusting the diverter recipe and diverter injection time, and the plugging behavior includes plugging the natural fracture in the wellbore, plugging the previous hydraulic fractures, plugging the fracture tip and plugging the bedding.

Numerical simulation on the multiple planar fracture propagation with perforation plugging in horizontal wells

Intra-stage multi-cluster temporary plugging and diverting fracturing(ITPF)is one of the fastest-growing techniques to obtain uniform reservoir stimulation in shale gas reservoirs.However,propagation geometries of multiple fractures during ITPF are not clear due that the existing numerical models cannot capture the effects of perforation plugging.In this paper,a new three-dimensional FEM based on CZM was developed to investigate multiple planar fracture propagation considering perforation plugging during ITPF.Meanwhile,the fluid pipe element and its subroutine were first developed to realize the flux partitioning before or after perforation plugging.The results showed that the perforation plugging changed the original distribution of the number of perforations in each fracture,thus changing the flux partitioning after perforation plugging,which could eliminate the effect of stress interference between multiple fractures and promote a uniform fluid distribution.The standard deviation of fluid distribution in the perforation plugging case was only 8.48%of that in the non-diversion case.Furthermore,critical plugging parameters have been investigated quantitatively.Specifically,injecting more diverters will create a higher fluid pressure rise in the wellbore,which will increase the risk of wellbore integrity.Comprehensively considering pressure rise and fluid distribution,the number of diverters should be 50%of the total number of perforations(N_(pt)),whose standard deviation of fluid distribution of multiple fractures was lower than those in the cases of injecting 10%N_(pt),30%N_(pt)and 70%N_(pt).The diverters should be injected at an appropriate timing,i.e.40%or 50%of the total fracturing time(tft),whose standard deviation of the fluid distribution was only about 20%of standard deviations in the cases of injecting at20%tftor 70%tft.A single injection with all diverters can maintain high bottom-hole pressure for a longer period and promote a more uniform fluid distribution.The standard deviation of the fluid distribution in the case of a single injection was 43.62%-55.41%of the other cases with multiple injection times.This study provides a meaningful perspective and some optimal plugging parameters on the field design during IPTF.

Cause analysis and solutions of water blocking damage in cracked/non-cracked tight sandstone gas reservoirs

After hydraulic fracturing treatment,a reduction in permeability caused by the invasion of fracturing fluids is an inevitable problem,which is called water blocking damage.Therefore,it is important to mitigate and eliminate water blocking damage to improve the flow capacities of formation fluids and flowback rates of the fracturing fluid.However,the steady-state core flow method cannot quickly and accurately evaluate the effects of chemical agents in enhancing the fluid flow capacities in tight reservoirs.This paper introduces a time-saving and accurate method,pressure transmission test(PTT),which can quickly and quantitatively evaluate the liquid flow capacities and gas-drive flowback rates of a new nanoemulsion.Furthermore,scanning electron microscopy(SEM)was used to analyze the damage mechanism of different fluids and the adsorption of chemical agents on the rock surface.Parallel core flow experiments were used to evaluate the effects of the nanoemulsion on enhancing flowback rates in heterogeneous tight reservoirs.Experimental results show that the water blocking damage mechanisms differ in matrices and fractures.The main channels for gas channeling are fractures in cracked cores and pores in non-cracked cores.Cracked cores suffer less damage from water blocking than non-cracked cores,but have a lower potential to reduce water saturation.The PTT and SEM results show that the permeability reduction in tight sandstones caused by invasion of external fluids can be list as guar gum fracturing fluid>slickwater>brine.Parallel core flow experiments show that for low-permeability heterogenous s andstone reservoirs with a certain permeability ratio,the nanoemulsion can not only reduce reverse gas channeling degree,but also increase the flowback rate of the fracturing fluid.The nanoemulsion system provides a new solution to mitigate and eliminate water blocking damage caused by fracturing fluids in tight sandstone gas reservoirs.

The enhancement of performance and imbibition effect of slickwater-based fracturing fluid by using MoS_(2)nanosheets

Slickwater-based fracturing fluid has recently garnered significant attention as the major fluid for volumetric fracturing;however,lots of challenges and limitations such as low viscosity,poor salt tolerance,and possible formation damage hinder the application of the conventional simple slickwater-based fracturing fluid.In addition,nanomaterials have proven to be potential solutions or improvements to a number of challenges associated with the slickwater.In this paper,molybdenum disulfide(MoS_(2))nanosheets were chemically synthesized by hydrothermal method and applied to improve the performance of conventional slickwater-based fracturing fluid.Firstly,the microstructure characteristics and crystal type of the MoS_(2)nanosheets were analyzed by SEM,EDS,TEM,XPS,and Raman spectroscopy techniques.Then,a series of evaluation experiments were carried out to compare the performance of MoS_(2)nanosheet-modified slickwater with the conventional slickwater,including rheology,drag reduction,and sand suspension.Finally,the enhanced imbibition capacity and potential mechanism of the nanosheet-modified slickwater were systematically investigated.The results showed that the self-synthesized MoS_(2)nanosheets displayed a distinct ultrathin flake-like morphology and a lateral size in the range of tens of nanometers.In the nano-composites,each MoS_(2)nanosheet plays the role of cross-linking point,so as to make the spatial structure of the entire system more compact.Moreover,nanosheet-modified slickwater demonstrates more excellent properties in rheology,drag reduction,and sand suspension.The nanosheet-modified slickwater has a higher apparent viscosity after shearing 120 min under 90℃ and 170 s^(−1).The maximum drag reduction rate achieved 76.3%at 20℃,and the sand settling time of proppants with different mesh in the nano-composites was prolonged.Spontaneous imbibition experiments showed that the gel-breaking fluid of nanosheet-modified slickwater exhibited excellent capability of oil-detaching,and increase the oil recovery to∼35.43%.By observing and analyzing the interfacial behavior of MoS_(2)nanosheets under stimulated reservoir conditions,it was found that the presence of an interfacial tension gradient and the formation of a climbing film may play an essential role in the spontaneous imbibition mechanism.This work innovatively uses two-dimensional MoS_(2)nanosheets to modify regular slickwater and confirms the feasibility of flake-like nanomaterials to improve the performance of slickwater.The study also reveals the underlying mechanism of enhanced imbibition efficiency of the nano-composites.

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.

The influence of multi-metal-veins on fractures propagation investigated by the experiment and simulation

Fracture propagation is affected by multi-metal-veins formed by geological diagenesis in shale during the hydraulic fracturing.However,the influence of multi-metal-veins on fractures propagation remains unclear.To solve the problem,based on the semi-circle bending(SCB)test and the extended finite element(XFEM)theory,the interaction between multi-metal-veins and fractures is investigated.The experimental results reveal that the fractures usually deflect at the upper or lower interfaces between metal veins and rocks(e.g.the specimen S-2),which is different from the propagation behavior of fractures in calcite veins.Meanwhile,the fracture toughness of the specimen S-1 is 24.40%higher than that of the specimen S-2,indicating that the increasing of total thickness of multiple metal veins in-creases the resistance to the fracture vertical propagation.The simulation results show that the increasing of the number,total thickness of veins,the modulus difference between veins and rock,the approach angle and the notch angle all increase the resistance of the fracture passing through metal veins.The maximum deviation distance(Dmax)of the fracture decreases with the number of veins,while thickness combination types of metal veins do not affect Dmax.The reduction of the notch angle leads to the more tortuous fracture propagation path.Finally,we propose a new comprehensive fracture network pattern.Fracture networks are divided into two categories,including orthogonal fracture networks and sub-orthogonal fracture networks,and then divided into six sub-categories further.The research results will provide reference for hydraulic fracturing of shale reservoirs containing multi-metal-veins.

Numerical simulation of fracture propagation in Russia carbonate reservoirs during refracturing

Refracturing treatment is often performed on Russian carbonate reservoirs because of the quick production decline of reservoirs.The traditional refracturing model assumes that a refracture initiates in the normal direction relative to the initial hydro-fracture.This assumption is inconsistent with oilfield measurements of refracture propagation trajectories.Indeed,the existing model is not based on an indepth understanding of initiation and propagation mechanisms of the second hydraulic fractures during refracturing.In this study,we use the extended finite element method to investigate refracture propagation paths at different initiation angles.Both the enriched function approach and phantom mode technique are incorporated into the refracturing model,thereby ensuring that the refracture can freely extend on the structured mesh without any refinement near the crack tips.Key factors including production time,stress anisotropy and initiation angle,and the propped mechanical effect are analyzed in detail.This study provides new insight into the mechanism of refracture propagation in unconventional reservoirs.

纳米聚合物微球在裂缝型碳酸盐岩储层油/水选择性封堵性能评价（英文）

目的:对聚合物微球(PM)在碳酸盐岩基质岩心与裂缝型岩心中封堵效果和油/水选择性进行综合评价。创新点:1.制作裂缝型碳酸盐岩模型并进行等效缝宽度计算;2.显微评价PM的水化膨胀特性;3.进行聚合物微球深层封堵性能评价;4.进行聚合物微球油/水选择性封堵评估。方法:采用纳米级聚合物微球溶液,并以哈萨克斯坦北特鲁瓦裂缝型碳酸盐岩油藏储层温度(54°C)和碳酸盐岩天然裂缝尺寸(0.02~0.03 mm)为实验条件;通过碳酸盐岩裂缝型岩心模型制作、PM基本性能测试、岩心流动实验以及扫描式电子显微镜(SEM)和能谱分析仪(EDS)等微观手段,对PM在碳酸盐岩基质岩心与裂缝型岩心中封堵效果和油/水选择性进行综合评价。结论:1. PM在水中具有良好的分散性和溶胀能力,3 d溶胀率高达300%以上,且对高矿化度盐水具有较强的耐受性。2.PM在基质岩心和裂缝型岩心均具有较好的深部封堵效果;30cm长岩心模型封堵实验表明,封堵后的分段压降均匀分布,岩心基质和裂缝型岩心封堵后的残余阻力系数介于3.29~5.88,封堵率介于69.58%~83.01%,且残余阻力系数越大,封堵率越高;PM在岩心中水化膨胀后可形成有效封堵,且平均封堵率高达70%以上。3.PM封堵的油/水选择系数Rw/o均小于1.0且接近于0,说明PM具有较强的油/水选择性封堵效果;这主要是因为油/水与PM作用机理不同;PM遇水后溶胀且表面粘性增加而粘连在碳酸盐岩壁面,并且不同微球之间相互团聚形成较大体积的颗粒,因此增加了对注入水的封堵效果;PM在煤油中则性能稳定,不产生溶胀和粘连效果,因此对反向注入煤油具有较低的封堵效果。4. SEM成像结果分析认为,PM在岩心喉道或天然微裂缝中的封堵机理主要包括三个方面:(1)PM单体在岩石颗粒表面吸附,降低喉道的尺寸,同时多个单颗粒小球增大了层内比表面积、降低了层内渗透率;(2)PM溶胀后在小尺寸孔道形成了机械捕集;(3)多个PM单体颗粒团聚成网状结构堵塞了大孔道。EDS元素分析技术进一步验证了其作用机理。