Proppant Distribution Research Articles

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.

Simulation study on proppant transport in a horizontal wellbore considering perforation erosion

Perforation erosion caused by pressure drop is widespread during a hydraulic-fracturing treatment. Perforation diameter can change proppant distribution between perforation clusters which affects proppant transport efficiency to fractures. Even though most of the relevant research on proppant transport in the wellbore focuses on the transport state and makes some sensitivity analysis, proppant transport law which considers the impact of perforation erosion is still unclear. 3D CFD wellbore models with a single cluster and double clusters are set in this paper. Simulations are conducted to investigate the proppant transport in the horizontal wellbore under the condition of different perforation erosion circumstances in clean water hydraulic fracturing. We combine the proppant transport and distribution when perforation erosion occurred and did not occur. The results also show that the factors including the location of perforation erosion, the angle of eroded perforations, the degree of perforation erosion, and the injection rate affect the proppant distribution and give some quantitative conclusions. This study provides useful insights into proppant transport in a horizontal wellbore.

Numerical Study of Proppant Transport in Intersected Fractures for Supercritical Carbon Dioxide Fracturing

This study employs Computational Fluid Dynamics (CFD) method to simulate particle transport in supercritical carbon dioxide fracturing. A dynamic leak-off model is integrated into the Eulerian-Eulerian two-fluid model. It systematically examines the transport of different-sized proppants in intersected fractures with leak-off and investigates the effects of proppant size, bypass fracture width, inter-fracture angle, and pumping schedule on the proppant distribution. Results show that the proppant split ratio increases with an increase in bypass fracture width and inter-fracture angle. Injecting larger-sized proppants before smaller-sized proppants can enhance the proppant bed length and height while reducing the proppant split ratio.

Proppant transport law in multi-branched fractures induced by volume fracturing

To further clarify the proppant transport and placement law in multi-branched fractures induced by volume fracturing, proppant transport simulation experiments were performed with different fracture shapes, sand ratios, branched fracture opening time and injection sequence of proppants in varied particle sizes. The results show that the settled proppant height increases and the placement length decreases in main fractures as the fracturing fluid diverts gradually to the branched fractures at different positions. The flow rate in branched fractures is the main factor affecting their filling. The diverion to branched fractures leads to low flow rate and poor filling of far-wellbore branched fractures. The inclined fracture wall exerts a frictional force on the proppant to slow its settlement, thus enhancing the vertical proppant distribution in the fracture. The increase of sand ratio can improve the filling of near-wellbore main fracture and far-wellbore branched fracture and also increase the settled proppant height in main fracture. Due to the limitation of fracture height, when the sand ratio increases to a certain level, the increment of fracture filling decreases. When branched fracture is always open (or extends continuously), the supporting effect on the branched fractures is the best, but the proppant placement length within the main fractures is shorter. The fractures support effect is better when it is first closed and then opened (or extends in late stage) than when it is first opened and then closed (or extends in early stage). Injecting proppants with different particle sizes in a specific sequence can improve the placement lengths of main fracture and branched fracture. Injection of proppants in an ascending order of particle size improves the near-wellbore fracture filling, to a better extent than that in a descending order of particle size.

An Experimental Study on the Impact of the Particle Size and Proportion of Composite Proppant on the Conductivity of Propped Fractures in Coalbed Methane Reservoirs following Pulverized Coal Fines Infiltration

Coalbed methane reservoirs exhibit a low strength and high heterogeneity, rendering them susceptible to coal fines generation during hydraulic fracturing operations. The detrimental impact of coal fines on the conductivity of the propped fracture has been overlooked, leading to a substantial negative effect on the later-stage recovery of coalbed methane reservoirs. Moreover, the particle size distribution of the composite proppant also affects the conductivity of the propped fracture. To mitigate the damage caused by coal fines to the conductivity of the proppant pack in CBM reservoirs, this study conducted conductivity tests on actual coal rock fractures. The aim was to assess the effect of various particle size ratios in composite proppant blends on the conductivity of complex fractures in CBM reservoirs. The ultimate goal was to identify an optimized proppant blending approach that is suitable for hydraulic fracturing in coal seams. The results indicated that, in terms of the short-term conductivity of coalbed methane reservoirs, the conductivity of composite proppants is primarily influenced by the proportion of large or small particles. A higher proportion of large particles corresponds to a stronger conductivity (e.g., the conductivity is highest at a particle ratio of 5:1:1 for large, medium, and small particles). On the other hand, a higher proportion of small particles leads to a poorer conductivity (the conductivity is lowest when the particle ratio is 1:1:5). In the long-term conductivity of coalbed methane reservoirs, the fluid flushing of the fracture surfaces generates coal fines, and small particles can fill the gaps between larger particles, hindering the infiltration of coal fines. Therefore, it is important to control the particle size ratio of composite proppants, with a predominant proportion of larger particles. This approach can maintain long-term conductivity and prevent the excessive infiltration of coal fines, thereby avoiding fracture blockage (e.g., the conductivity is highest at a particle ratio of 5:1:5, followed by a ratio of 3:1:3). Furthermore, considering the influence of proppant placement methods and the support effect on near-wellbore opening fractures and far-end sliding fractures, segmented placement is utilized to fully fill the fractures for short-term conductivity, whereas mixed placement is employed for long-term conductivity to achieve a balance in particle gaps and hinder the infiltration of coal fines. The findings of this study contribute to the understanding of proppant selection and placement strategies for efficient hydraulic fracturing in coalbed methane reservoirs.

On the correlation between proppant addition strategy and distribution

The proppant pumping schedule is critical in hydrofracking because it affects both fluid flow and proppant transport. In the study reported here, a validated CFD-DEM model was employed to study the impact of proppant pumping strategy on proppant transport in a rough rock fracture. Three injection sequences of multi-sized proppants were applied while varying other pumping parameters including injection velocity, the size of large proppants, and the concentration of large proppants. Both vertically and horizontally sheared rough, joint rough, and smooth fractures were adopted to enable a better understanding of the impact caused by fracture geometry. The results reveal that the variation in proppant distribution caused by adjusting the pumping sequence or a single pumping parameter is not absolute. Rather than pumping parameters, the final proppant distribution is governed directly by two competing effects caused by the alteration of proppant bridging effect. It was also found that the proppant volume retained in fractures is under-estimated if the CFD mesh size is too small to reach three times the particle size. The lateral conveyance of proppant could be enhanced by considering the Saffman lift force in CFD-DEM modeling. The results of this study shed light on proppant transport in hydraulic fractures under various addition strategies, which will assist the optimization of fracturing treatments in unconventional reservoirs.

Pulse effects on proppant transport and dune shape in vertical fracture applied in coalbed methane mining engineering during the pulse hydraulic fracturing

Proppant transport plays a very important role in the pulse hydraulic fracturing (PHF). However, it is unclear that the pulse effect mechanism and regularity on the proppant migration in fracture. This study combined PHF and proppant migration for the first time to reveal the pulse effects on the migration and distribution of proppant. This work was conducted based on the Eulerian-Eulerian two-phase model and computational fluid dynamics method. Firstly, the simulations were validated by two typical experiments. Then, the pulse injections of slurry were carried out in a vertical fracture. Last, the influences of pulse shape, amplitude and period were discussed in detail. The results show that the square pulse can decrease the dune deposition height in the near region of fracture, and the decrease has a positive correlation with the pulse period, where the maximum decrease is up to 22.6%. It's found that the square pulse can increase the dune deposition height in the middle and far regions of fracture, and the increments have positive correlation with the pulse period, where the maximum increments are 47.7% and 61.5%, respectively. The present results indicate that the square pulse injection can extend the migration range of proppant. The extended-range effect has a positive association with the pulse period. Besides, results show that the extended-range effect is apparent only when the pulse amplitude is larger than 0.3 m/s. Compared to the sine pulse injection, the square pulse injection provides better extended-range effect. The present findings can provide valuable theoretical guidance for the PHF design and efficient exploitation of coalbed methane.

Micro-scale reconstruction and CFD-DEM simulation of proppant-laden flow in hydraulic fractures

A comprehensive investigation of the dynamical characteristics of proppant-laden flow systems in hydraulic fractures is important for the development of unconventional oil and gas resources. In this paper, we combine the micro-scale reconstruction technique and CFD-DEM method to numerically investigate the mobility and distribution rules of proppant-laden fluid in rough hydraulic fractures. To characterize realistic fracture surface morphology, six synthetic fracture models were assembled based on optical scanning data of real shale from three sets of hydraulic fracturing experiments. In order to accurately simulate the fluid-particle two-phase flow in rough fractures, the lift forces and particle rolling effect are considered in the CFD-DEM model. First, the effectiveness of the used CFD-DEM solver was validated by comparing it to the experimental data. We then examined mechanisms for the typical flow behaviors of proppant particles and fracturing fluid in smooth and rough fractures. Subsequently, the surface area ratio of the synthetic fracture model is adopted to characterize the cross-scale relationship between the micro-scale proppant distribution and fracture’s geometric features induced by the macroscale fracturing parameters (i.e., confining stress, fluid viscosity, flow rate, and sand ratio). Lastly, the parameter effects of the fracturing fluid, proppant particle, and fracture aperture on the dynamic characteristics of particulate flow in the hydraulic fracture are further discussed. In summary, the presented numerical model and findings can help better understand particle transport and distribution in real rock fractures and bridge the connectivity of the micro-scale particle flow and macroscopic fracturing parameter, which is vital for hydraulic fracturing process optimization.

Hydraulic fracture morphology and conductivity of continental shale under the true-triaxial stress conditions

Continental shale oil formations generally exhibit more complex lithology and stronger heterogeneity than marine shale. The coexistence of dense laminas, lithologic interfaces (LIs), and mineral-filled natural fractures (NFs) in such formations can cause complex mechanisms of hydraulic fracture (HF) growth, proppant placement, and conductivity evolution. To obtain an intuitive understanding of this problem, a series of comprehensive laboratory sand fracturing experiments and fracturing conductivity tests were carried out innovatively on downhole shale cores using an improved small-size true triaxial fracturing simulation system combined with multiple examination methods in this work. HF morphology and proppant distribution were characterized through the high-precision CT scanning technique. Moreover, HF conductivity was tested on the cylindrical cores drilled from the fractured specimens. Experimental results show that high breakdown pressure and volatile wellbore pressure during the sand-adding stage were likely presented in the relatively rigid formations. HF growth path is likely to be deflected and bifurcated by the NFs laterally and by the oblique laminas vertically. “╪”-shaped HF also tends to be created due to the interaction of HF with dense horizontal laminas. The local heterogeneity in the continental shale formation can cause significant complexity and uncertainty in HF. The dominant HF nearby the wellbore contains most of the proppant, and the activated laminas, NFs, or/and branches are short of proppant. The volume and area of the proppant-filled HF can only account for less than 20% of the total HF volume and less than 65% of the total HF area, respectively. The distribution of relatively small-size proppant is more uniform and broader than that of large ones. There is a positive correlation between fracture conductivity and the proppant concentration. The conductivity of no proppant-filled fractures (including the HF, activated lamina, and NF) is low and unstable, and can almost be neglected under closure stress beyond approximately 20–25 MPa. The findings in this work are expected to provide practitioners with a bigger map of the performance and effectiveness of the hydraulic fracture they created.

Experiment and simulation of slurry flow in irregular channels to understand proppant transport in complex fractures

Slurry flow and proppant placement in irregular fractures are crucial to evaluate hydraulic fracturing stimulation but need to be better understood. This study aims to investigate how irregular fracture affects proppant transport and distribution using laboratory experiments and micro-scale numerical models. The unresolved method of the computational fluid dynamics (CFD) and the discrete element method (DEM) considers Saffman lift force, Magnus force, and virtual mass force to accurately capture the frequent interaction between proppant and slickwater. Experimental results validated the reliability of the optimized CFD-DEM model and calibrated primary parameters. The effects of crack height and width, bending angle, and distance between the crack and inlet on particle distribution were studied. The results indicated that the improved numerical method could rationally simulate proppant transport in fractures at a scale factor. The small crack height causes downward and upward flows, which wash proppant to the fracture rear and form isolated proppant dunes. A wider region in the fracture is beneficial to build up a large dune, and the high dune can hinder particle transport into the fracture rear. When the crack is close to the inlet, the primary fracture without proppants will close to hinder gas production. The smaller the bending angle, the smaller the proppant dune. A regression model can precisely predict the dune coverage ratio. The results fundamentally understand how complex fractures and natural cracks affect slurry flow and proppant distribution.

Advanced Diagnostics Aid Understanding at Hydraulic Fracturing Test Site 2

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 2021-5514, “Overview of Hydraulic Fracturing Test Site 2 in the Permian Delaware Basin (HFTS-2),” by Jordan Ciezobka, SPE, GTI. The paper has not been peer reviewed. _ The Hydraulic Fracturing Test Site 2 (HFTS-2) is a large collaborative field-based research and development program in the Permian Delaware Basin funded by the US Department of Energy through the National Energy Technology Laboratory and the exploration and production industry with support from academia. The project’s main objective is to improve the understanding of the hydraulic fracturing process through use of advanced diagnostics and collection of through-fracture cores to provide undisputable evidence and attributes of created fractures. Project Background The HFTS-2 project provides the opportunity to address the optimal development of a stacked pay resource that requires simultaneous drilling and completion of tens of thousands of wells across multiple geologic horizons, also known as cube development. The project consists of a series of coupled analytic and field experiments in which research-quality data are acquired in dedicated research wells through full instrumentation at, and in proximity to, hydraulically fractured wells. Furthermore, the unique site design provides an opportunity to understand the effect of reservoir depletion because many child-well stages overlap parent-well areas. The extensive data set acquired was integrated and used to calibrate subsurface models and characterize fracture geometry and proppant distribution. Diagnostics and modeling efforts enabled comprehensive calculations of hydraulic fracturing’s vertical and lateral extent and production-depletion profiles and quantification of fracture growth bias for child-well stages that overlapped parent wells. Results from the project culminated in the development of a series of optimization procedures for increased drilling and completion efficiency, reducing environmental footprint by producing the reservoir from fewer well pads and fracturing stages. Test Site The research well package consists of eight new producing wells, two existing parent wells, and two new dedicated science and observation wells drilled for this project. The new producing wells are landed in various Wolfcamp horizons and have lateral lengths of approximately 7,500 ft. The lateral sections of the wells are spaced approximately 660 ft apart. The two existing parent wells also are in the Wolfcamp formation and have lateral lengths of approximately 5,000 ft. The two new science wells were drilled from the same pad, positioned between laterals B3H and B4H. One science well is a vertical pilot hole used to characterize the reservoir through the collection of mud and drill-cutting samples, electric logs, and whole and sidewall cores. The well also was used to house diagnostic instrumentation. The second science well is a slant well drilled after all wells were stimulated and was used to collect whole cores through the created fractures. The slant core well was instrumented with pressure and temperature gauges to monitor reservoir depletion during production.

Simulation and Analysis of Proppant Transport Patterns in Wellbore-Fracture Systems

Staged multi-cluster fracturing of horizontal wells is one of the most important tools to achieve efficient development of unconventional oil and gas reservoirs. The multi-stage fracturing technique forms complex fractures with multiple clusters and branches in the formation, causing competing diversions leading to more complex proppant transport patterns, and the proppant placement method determines the flow conductivity of complex fractures, so it is necessary to investigate the proppant transport patterns in complex fractures. To address this issue, a field-scale geometric model is established for numerical simulation, and the multiphase flow diversion pattern in the wellbore, the proppant distribution pattern under different network conditions, and the optimization of different construction parameters are investigated. The results are obtained as follows: the distribution of solid and liquid phases in each cluster of the well conforms to the trend of variable mass flow; the proppant is distributed at the heel end in multiple clusters of fractures, and the sand and liquid are unevenly distributed among clusters of fractures, and the number of branching affects the proppant transport; through sensitivity analysis of the influencing factors, the pumping displacement, fracturing fluid viscosity and proppant particle size are optimized, and the construction parameters of 14 m3/min, 5 mPa·s, 70/140 mesh, 12% sand ratio are determined. This study has a certain guiding significance for the optimization of fracturing parameters in this block.

Proppant Distribution Prediction between Perforation Clusters Using Fresh Water in a Horizontal Wellbore.

In multistage, multicluster treatments, distributing the proppant evenly among the multiple perforation clusters is considered one of the key challenges. Uneven proppant distribution in multiple clusters can significantly affect fracture conductivity, which in turn severely affects the well's productivity. Dimensional analysis using the Buckingham π-theorem was utilized to develop the experimental correlations using the experimental data. The laboratory tests data of 100 mesh brown and 40/70 mesh white sands (SG of 2.65) at various proppant concentrations, injection rates, and with various perforation configurations were combined and used to develop the correlation. This paper offers a newly developed experimental correlation for the proppant distribution that may be utilized to forecast the distribution of proppant between various clusters in the multistage, multicluster stimulation. Such correlations are essential to be considered in future hydraulic fracturing treatment designs, as they offer insightful information and aid in optimizing the projected proppant distribution across several perforation clusters within a single hydraulic fracturing stage. Thus, the multistage, multicluster horizontal wellbore achieves uniform proppant distribution between the various perforation clusters.

An improved Eulerian scheme for calculating proppant transport in a field-scale fracture for slickwater treatment

Field-scale proppant transport simulation is vital to the development of unconventional resources. Previous research on proppant transport and distribution has mainly focused on small-scale and experimental-scale proppant simulations, and few studies are related to field-scale proppant deployment. In this paper, through coupling of the slickwater flow, proppant flow, and dynamic crack propagation, an improved Eulerian scheme for calculating proppant transport in a field-scale fracture for slickwater treatment is presented. In the improved Eulerian scheme, the effect of the fracture width on the proppant settling rate and the effect of the increase in the settling bed height on the proppant bed build-up rate are taken into consideration. In addition, a new retardation coefficient is introduced to account for the effect of proppant retardation on the proppant flow. The Eulerian scheme is verified through comparison with published works, including experimental results and simulation results, and sensitivity analysis is conducted. Based on the results of this research, we conclude that the lower viscosity slickwater causes the proppant distribution to become more even, and thus, the proppant bed becomes longer and higher. As the proppant diameter increases, the proppant distribution in the fracture becomes more even, and the fracture area supported by the proppant becomes larger. The optimal initial proppant concentration for obtaining the largest propped fracture area is 0.15–0.25. The greater the density of the slickwater is, the more even the proppant distribution is, and the larger the propped fracture area is.

Stage-by-Stage Hydraulic Fracture and Reservoir Characterization through Integration of Post-Fracture Pressure Decay Analysis and the Flowback Diagnostic Fracture Injection Test Method

Summary The post-fracture pressure decay (PFPD) technique is a low-cost method allowing for stage-by-stage hydraulic fracture characterization. The analysis of the PFPD data is complex, with data affected by both hydraulic fracture and reservoir properties. Available analysis methods in the literature are oversimplified; reservoir or fracture properties are often assumed to be constant along the horizontal well, and therefore changes in the trend of pressure decay data are attributed to hydraulic fracture or reservoir properties only. Moreover, methods analogous to those applied to the analysis of conventional diagnostic fracture injection tests (DFITs) are often used and ignore critical mechanisms involved in main-stage hydraulic fracture stimulation. A conceptual numerical simulation study was first conducted herein to understand the key mechanisms involved in main-stage hydraulic fracturing. An analytical model was then developed to account for the dynamic behavior of the hydraulic fracture, leakoff, proppant distribution, multiple fractures, and propped- and unpropped-closure events. The analytical model is cast in the form of a new straightline analysis (SLA) method that provides stage-by-stage estimates of the ratio of unpropped fracture surface area to total fracture surface area. The SLA method was validated against numerical simulation results. Moreover, to account for the variation of reservoir properties along the horizontal well, the PFPD model is integrated with DFIT-flowback (DFIT-FBA) tests, performed at some points along the lateral, to obtain a reliable stage-by-stage hydraulic fracture and reservoir characterization approach. The practical application of the proposed integrated approach was demonstrated using PFPD and DFIT-FBA data from a horizontal well completed in 22 stages in the Montney Formation. The numerical simulation study demonstrated that the use of proppant and injection into multiple clusters (creating multiple fractures) results in multiple closure events. The closure process may start early after the pump-in period at a pressure significantly higher than the minimum in-situ stress. Using DFIT-based analytical models, which ignore the presence of proppant, causes significant errors in hydraulic fracture and reservoir property estimation. The PFPD field data examined herein exhibited a similar pressure trend to the numerical simulation cases. The ratio of unpropped fracture surface area to total fracture surface area was determined stage by stage using the PFPD SLA method, constrained by DFIT-FBA data. Engineers can use this information to optimize the hydraulic fracture stimulation design in real time, optimize the well spacing, and forecast the production. The cost and time advantages of this diagnostic method make this approach very attractive.

Evaluation of Parent Well Depletion Effects on Fracture Geometry Based on Low-Frequency Distributed Acoustic Sensing in Hydraulic Fracture Test Site-2

Summary Low-frequency distributed acoustic sensing (LF-DAS) has recently received much attention for its ability to monitor fracture propagation at offset wells. Hydraulic Fracture Test Site-2 (HFTS-2), a Department of Energy–sponsored field-based research experiment, has acquired LF-DAS data sets during the stimulation of many horizontal wells in the Wolfcamp Formation of the Permian Basin. Over 100 stimulated stages with different completion designs in four horizontal wells were monitored by two horizontal offset wells and one vertical pilot hole with permanent fibers. The parent well depletion affected all four horizontal wells in almost half of their lateral section. Several studies have been performed on the acquired comprehensive data set. In this study, we apply our novel Green’s function-based inversion algorithm to calculate the fracture width of each stage and investigate the impact of parent well depletion on fracture geometry. The Green’s function-based inversion algorithm has been successfully applied to a few stages of field case studies. The Green’s function matrix was built based on linear elasticity theory (3D displacement discontinuity method) to relate the fracture openings with strain responses measured along the length of the fiber. This novel algorithm only relies on measured strain to solve fracture geometry at the monitoring well. Therefore, it is independent of the physics of the fracture propagation process and can be used to validate hydraulic fracture modeling results. Using our inversion algorithm, we can efficiently and quantitatively interpret LF-DAS data to provide information on fracture geometry and completion efficiency. We analyze more than 100 stages of the LF-DAS measurements obtained at the fiber wells B3H and B4H during B1H, B2H, and B4H stimulations. We apply our inversion algorithm for four data sets covering the stimulation of the abovementioned three wells. The fracture growth at stages in the parent well’s depleted zone is biased more toward upper formation and in the easterly direction. The fracture width at the stages in the parent well’s depletion zone is reduced compared to fracture widths at stages in the nondepleted zone irrespective of the monitoring well location relative to the treatment wells. This difference in fracture widths will affect the proppant distribution to a great extent, thereby affecting the effectiveness of the stimulation. We also illustrate the application of the inversion algorithm for stages that have both conventional fracture hits with “heart-shaped” signals as well as fracture reopening signals. Our inversion algorithm gives a reasonable estimate of the fracture width that aligns with the qualitative analysis of microseismic data sets and statistic summary of fracture hit numbers of HFTS-2. We believe that this quantitative study provides us with insights into the fracture geometry due to parent well depletion effects.

Theoretical and experimental study on the long-term conductivity of heterogeneous artificial fractures in tight reservoirs

Volume fracturing technology is used to achieve economic recovery of crude oil in tight reservoirs. Then, the fluid flows into the wellbore through artificial fractures in the fractured zone, and the reservoir permeability is improved. Therefore, the study of the conductivity of artificial fractures is the key link for the fracturing development of tight reservoirs. Presently, experimental and theoretical studies on conductivity are based on a homogeneous model, which cannot reflect the nonuniform distribution of proppants in actual artificial fractures. Experiments on the long-term nonuniform sand spreading of artificial fractures in tight reservoirs are carried out in this paper with different influencing factors. Then, the influences of the matrix of proppant performance, proppant concentration, reservoir lithology, reservoir permeability and closure stress on the long-term conductivity of artificial fractures are clarified. The calculation model of the long-term conductivity of heterogeneous artificial fractures considering the reservoir characteristics, fracturing technology and reservoir characteristics is established based on the conductivity loss mechanism. Finally, the conductivity model is applied to the 7th tight reservoir block in the Ordos Basin, and the productivity prediction results are compared. The results show that the average loss of the conductivity of the heterogeneous artificial fractures is 26.6% relative to the initial state, and the loss of the conductivity is mainly at the initial stage of closure, accounting for approximately 90% at the condition of 60MPa confining pressure. The calculation accuracy of the theoretical nonuniform conductivity model is 92.2%, which can describe the continuous depression of the artificial fracture conductivity after introduction into the tight reservoir numerical simulation.

Simulation study of micro-proppant carrying capacity of supercritical CO2 (Sc-CO2) in secondary fractures of shale gas reservoirs

Micro-proppants with stronger portability have more potential to migrate to the massive micro-sized secondary fractures (SFs) or natural fractures activated by supercritical CO2 (Sc-CO2) fracturing in shale gas reservoirs. However, the transportation behaviour of micro-proppants in massive SFs has been scarcely studied to date. In this study, we report the simulation of micro-proppant migration across a fracture intersection during Sc-CO2 fracturing based on a combination of computational fluid dynamics and the discrete element method. A straight fracture intersection model was first validated against experimental data from an earlier study. Next, the influential factors, including fluid viscosity, cross angle, proppant diameter, fluid velocity and the ratio of proppant diameter to SF, were examined in the transportation behaviour of micro-proppants in Sc-CO2 fracturing. The results show that the poor proppant distribution in SFs is dominated by the ultralow viscosity of Sc-CO2, but the decrease of proppant diameter to 25 μm presents slurry flow behaviour, resulting in a migration distance around 8 times longer than that of 200 μm and much stronger proppant-carrying capacity into SFs. The transportation behaviour of micro-proppants into SFs depends on the suspended proppants concentration and the rolling proppants from the proppant embankment in the primary fracture (PF), determined by the combined effects of different factors. Fast fluid velocity of 0.2 m/s increases the priority of the proppant embankment formation in SFs. Cross angles greater than 45° limit the suspended proppants in SF, and the proppant embankment in the SF dominantly depends on rolling proppants from PF. Greater SF aperture facilitates proppants transportation into the SF due to the reduced bridging effect, but not into the PF. The key findings are optimized proppant-carrying capacity into SFs and improved stimulated volume during Sc-CO2 fracturing in shale reservoirs.

Transient Flow Performance of a Vertical Well With Multiple Varying Conductivity Fractures in a Tight Oil Reservoir

Summary Due to uneven proppant distribution and varied proppant sizes during hydraulic fracturing, artificial fractures of varying length, asymmetry, and varying conductivity are easily formed near the wellbore. The principal focus of this work is to investigate the pressure transient performance of a vertical well penetrated by multiple asymmetrical fractures with varying lengths and varying conductivities in a tight oil reservoir. A novel fracture flow equation was developed specifically to describe the flow behavior inside the complex artificial fractures mentioned above. By combining with the point source solution of the tight oil reservoir, a semianalytical solution was further obtained to analyze the pressure transient behavior of a vertical well with multiple varying-conductivity fractures in a tight oil reservoir. The accuracy and reliability of the newly-developed solution were verified by comparing with the result of a numerical model. With this new solution, fracture flux distribution for different conductivity modes, namely, linearly declining mode, exponentially declining mode, and elliptically declining mode, shows that the near-wellbore fracture flux of the exponential mode is greater than that of the other two modes, but the flux distribution near the fracture tips is on the contrary. Meanwhile, the transient flow characteristics under the above varying conductivity modes indicate that the exponentially varying conductivity has a significant influence on the early linear flow regimes, while the linear and elliptical mode only has a slight influence on the bilinear flow regime under high conductivity. Parameter sensitivity analysis reveals that the obvious inversion point occurring in the pressure derivative curves of uniform conductivity fractures disappears on the pressure derivative curves of varying conductivity fractures, and a weaker asymmetry, a greater adjacent fracture angle, and a larger fracture number and fracture length ratio are conducive to improve the fracturing stimulation effect. This study deepens our understanding of the transient flow performance of vertically fractured wells and helps to estimate artificial fracture properties and evaluate hydraulic fracturing performance.

Experimental and 3D Numerical Investigation on Proppant Distribution in a Perforation Cluster Involving the Artificial Neural Network Prediction

Summary Uniform proppant distribution in a cluster and a stage with multiple clusters is a primary objective to optimize fracturing parameters and improve the production from each cluster. Because fracturing slurry is typically pumped at high pressure and rate in fields, it is a big challenge to study proppant transport behavior and distribution characteristics through laboratory experiments. There is still a lack of an effective model to quantitatively evaluate proppant distribution based on an actual wellbore configuration. The objective is to propose a novel method to accurately evaluate the distribution uniformity and quickly optimize fracturing parameters based on field conditions. This paper conducts particle transport experiments in a horizontal pipe with six holes at the helical distribution. A 3D numerical model coupling of the computational fluid dynamics (CFD) and discrete element method (DEM) is used to study proppant distribution. Proppant distribution is quantitatively evaluated by the proppant transport efficiency (E) and normalized standard deviation (NSD). The effects of 10 parameters are investigated. An artificial neural network (ANN) model is developed to predict proppant distribution in a cluster. The results identify that proppant distribution among perforations is generally toe-biased in a horizontal wellbore due to a high pumping rate. Proppants with large inertia easily miss the heel-side holes and are suspended to the toe side. The complex vorticity flow carries them to the toe-side perforation regardless of hole orientation. Fluid distribution can significantly change proppant distribution regardless of fluid velocity. The heel-biased fluid distribution leads to the same bias of proppant, and the downward perforations receive more proppants. Proppant transport reaches equilibrium quickly, and the distribution is hard to change unless the injection condition varies. It is a good choice to increase fluid viscosity, add perforation sealers, and inject small mesh proppant, especially for the low density. The ANN model trained by extensive experimental and numerical samples can accurately evaluate proppant distribution uniformity. The study provides an efficient way to optimize injection parameter design and achieve real-time optimization coupled with the fiber-optic downhole diagnostic. It can be a crucial part of artificial intelligence hydraulic fracturing.