Hydraulic Fracture Stages Research Articles

The Flowback Proppant Scaling Mechanism in the Horizontal Shale Oil Wells of Qingcheng Oilfield

Abstract Proppant scaling in the horizontal shale oil wells is a common problem in the Qingcheng Oilfield, one of the largest shale oil producers in China. However, few studies have focused on the mechanism of the proppant scaling during the flowback stage of hydraulic fracturing. To elucidate the scaling mechanism, in this study we collected the samples of produced water and solid scales and analyzed their compositions. The experimental simulations of the static and dynamic scaling processes using fracturing fluids, formation water, and reservoir rocks were also performed. In these experiments, the scale was found to be mainly SiO2 combined with FeCO3 and/or CaCO3. FeCO3 was dominant at the initial stage of the flowback, and CaCO3 became dominant at later stages of the flowback and during the stable production stage. It is believed that the high percentage of ferrous minerals (e.g., 46.4% of ferrocalcite) in multiple formation rocks is an essential reason that the proppant scaling happened during the flowback stage. The Fe2+ and Ca2+ ions were believed to be released via reservoir rock reacting with the fracturing fluid under the reservoir temperature and pressure (e.g. 60 °C, 20MPa). In addition, the FeCO3 formed in the initial flowback stage of the fracturing has the greatest impact on production.

Hydraulic fracturing in the overpressured, isotropically stressed Cane Creek Unit, Paradox Basin

The Cane Creek Unit within the Paradox Basin is an unconventional oil play that poses substantial geomechanical and hydrological challenges. With hundreds of millions of oil barrels in place, this resource is a viable target, but a greater understanding of the subsurface geomechanics is required for more reliable and consistent production. We analyzed a previous hydraulic stimulation of the State 16-2 well, located in the northern part of the basin, to produce recommendations for how future stimulations might be improved. Specifically, we look at three components of the completed stimulation: 1) Spatial correlations of various well logs to identify regions favorable for retaining hydrocarbons within natural fractures; 2) Analysis of pressure-time data from the hydraulic fracturing stages during well stimulation to assess the complexity of the fracture networks; and 3) Evaluation of poroelastic effects from reservoir depletion to assess the potential for future restimulation. Results of our analysis provide quantitative insight about the State 16-2 stimulation and yield specific recommendations. The most important recommendation is to stimulate regions with an intermediate fracture density due to their ability to retain hydrocarbons. Restimulation, if needed, may be more effective if completed after significant depletion due to poroelastic stress changes. While the direction of maximum horizontal stress is a critical factor, it might be less crucial if restimulation is conducted after considerable reservoir depletion.#xD;

Thermoporoelastic Stress Perturbations from Hydraulic Fracturing and Thermal Depletion in Enhanced Geothermal Systems (EGS) and Implications for Fault Reactivation and Seismicity

Hydraulic fracturing then fluid circulation in enhanced geothermal system (EGS) reservoirs have been shown to induce seismicity remote from the stimulation – potentially generated by the distal projection of thermoporoelastic stresses. We explore this phenomenon by evaluating stress perturbations resulting from stimulation of a single stage of hydraulic fracturing that is followed by thermal depletion of a prismatic zone adjacent to the hydraulic fracture. We use Coulomb failure stress to assess the effect of resulting stress perturbations on instability on adjacent critically-stressed faults. Results show that hydraulic fracturing in a single stage is capable of creating stress perturbations at distances to 1000 m that reach 10-5-10-4 MPa. At a closer distance, the magnitude of stress perturbations increases even further. The stress perturbation induced by temperature depletion could also reach 10-3-10-2 MPa within 1000 m - much higher than that by hydraulic fracturing. Considering that a critical change in Coulomb failure stress for fault instability is 10-2 MPa, a single stage of hydraulic fracturing and thermal drawdown are capable of reactivating critically-stressed faults at distances within 200 m and 1000 m, respectively. These results have important implications for understanding the distribution and magnitudes of stress perturbations driven by thermoporoelastic effects and the associated seismicity during the simulation and early production of EGS reservoirs.

Mitigation of Fracturing Fluid Leak-Off and Subsequent Formation Damage Caused by Coal Fine Invasion in Fractures: An Experimental Study

During the hydraulic fracturing process of coalbed methane (CBM) reservoirs, significant amounts of secondary coal fines are generated due to proppant grinding and crack propagation, which migrate with the fracturing fluid into surrounding fracture systems. To investigate whether coal fines can form plugs to reduce fluid leak-off during the hydraulic fracturing stage, we conducted physical simulation experiments on coal seam plugging and unplugging to demonstrate that coal fines indeed contribute to reducing fluid leak-off during hydraulic fracturing. We also explored the plugging mechanisms of coal fines under different concentrations and particle sizes in fracturing fluids, and revealed the damage law of coal fines of temporary plugging on reservoir permeability. Research results indicate the leak-off volume of fracturing fluids containing coal fines is lower than an order without coal fines, demonstrating a significant effect of coal fines in decreasing fluid leak-off. The temporary plugging rate of coal fines increases with higher concentrations and decreases with larger particle sizes, achieving rates exceeding 90%. The high temporary plugging effect of coal fines results from the superposition of internal and external filter cakes. Under conditions of small particle size and high concentration, the damage to fractures during the fine return process is minimized. Considering the potential damage of coal fines to propping fractures and wellbore, the concentration of coal fines in fracturing fluids should be kept relatively low while ensuring a high temporary plugging effect. Overall, these findings provide crucial insights into optimizing the temporary plugging performance of coal fines during the hydraulic fracturing stage and controlling their behavior during the fracturing fluid flow-back stage, thereby enhancing reservoir fracturing effectiveness and improving CBM production rates.

Assessment and optimization of maximum magnitude forecasting models for induced seismicity in enhanced geothermal systems: The Gonghe EGS project in Qinghai, China

Seismic activity induced during the development of Enhanced Geothermal Systems (EGS) is frequent and poses significant hazards. This study aims to accurately forecast the maximum magnitude (Mmax) of induced earthquakes to effectively manage seismic risks. Focusing on the EGS project in Gonghe County, Qinghai Province, we evaluated and optimized various widely-applied Mmax forecasting models, while also endeavoring to directly forecast maximum magnitudes in the post-closure phase. Initially, advanced deep learning models (such as PhaseNet and GaMMA) were employed to process seismic data, coupled with VELEST and HypoDD methods for earthquake relocation. Subsequently, four currently widely recognized maximum magnitude (Mmax) forecasting models (H14, NRBE, V16, and G17) were utilized to forecast and assess Mmax during nine hydraulic fracturing stages, six post-closure stages exhibiting tailing effects, and the entirety of the 2019–2021 period in the Gonghe EGS project. The findings indicate significant disparities in the efficacy of different forecasting models during hydraulic fracturing stages, with no model fully aligning with the complex physical mechanisms of induced seismicity. NRBE and G17 models tend to overestimate Mmax forecasting, potentially escalating production costs, whereas H14 and V16 models yield results closer to actual values but are susceptible to the influence of real seismic breakthroughs. Furthermore, distinct discrepancies were observed in the Mmax forecasting performance of the same model between hydraulic fracturing and post-closure stages. Attempts to directly forecast Mmax post-closure achieved certain efficacy, likely due to the cumulative injection volume exerting a degree of control over induced seismic activity in both stages. Lastly, to overcome limitations in current Mmax forecasting models, a hybrid model Y24, integrating the advantages of four forecasting models, was proposed, demonstrating higher accuracy and reliability in forecasting during both hydraulic fracturing and post-closure stages. The study's findings provide crucial technical support and decision-making basis for the seismic risk management of EGS projects or shale gas development projects employing hydraulic fracturing, underscoring their significance in ensuring the safety and sustainability of new energy and resource development endeavors.

Assessment of two recent hot dry rock thermal energy production projects

In this paper, we present analyses of laboratory and field data indicating that the current two-well, injection-production system, connected with multiple hydraulic fractures, is a very promising method for extracting heat from hot dry rock (HDR) systems to generate electricity. The current two-well system could be expanded to a three-well system consisting of one injection well and two symmetric producing wells connected via the central hydraulic fracture emanating from the injection well. To improve a uniform distribution of the injected fluid among all hydraulic fracture stages in the injection well, we advocate for field implementation of a newly designed well stimulation technique, the GeoThermOPTIMAL.We first present an analysis of the post-fracturing flow data obtained from an HDR geothermal injection well at the Utah FORGE Enhanced Geothermal System (EGS) research field site. The site is adjacent to the Roosevelt hydrothermal (HT) field. The objective of the study is to assess the effectiveness of well stimulation in extracting heat from the low-permeability, hot dry granitoid rock in the Utah FORGE research site. The study includes interpreting pressure falloff data obtained during the well stimulation process and employing laboratory-measured core data as a major input in the interpretation of the field falloff data. As a confirmation of the robustness of our analysis in Utah FORGE, we reviewed and analyzed the flow test results published for an injection-production doublet at the Blue Mountain EGS (Project Red) commercial site in Nevada. From the analyses of these two field tests, we have concluded that the interpretation and findings of the Blue Mountain EGS pilot test are consistent with the interpretation and findings from the Utah FORGE field research project test results.In summary, our engineering assessments began with laboratory experiments conducted on various core samples, including those from a granite outcrop and the Utah FORGE geothermal reservoir. These experiments aimed to measure key parameters such as matrix and fracture permeabilities, and porosities (km≈10−18m2, kf,eff≈10−15m2,ϕm≈10−1,andϕf≈10−4). These data served as guides and inputs for analytical and numerical solutions used to match the field pressure response of the geothermal wells. While we did not have core samples from the Blue Mountain EGS wells, we successfully applied the Utah FORGE analysis approach to the Blue Mountain site with cautious optimism.

Application of the block factor analysis in the implementation of hydraulic fracturing during oil fields development

The relevance of this study is due to the need to optimize the oil production process in the fields of the West Siberian province. At the moment, the actual oil recovery factor often deviates from the design values, which leads to inefficient production and loss of resources. Therefore, the purpose of the study is to develop a meth-odology for optimizing the process of monitoring and regulating an oil field development facility using block factor analysis and de-signing hydraulic fracturing cracks. The work uses methods such as block factor analysis, 3D modeling, hydrodynamic modeling, and mathematical modeling. The result of the study is a developed methodology for optimizing the process of monitoring and regulat-ing an oil field development facility. The article also discusses the main reasons for the deviation of actual oil production from calcu-lated values, including hydraulic fracturing technology. Unsuccess-ful cases of this procedure and their causes were identified. The features of the block factor analysis tool and the proactive analysis method are described, as well as how to use it at the design and modeling stage of hydraulic fracturing to improve the efficiency of the well-stimulation operation. Successful implementation of hy-draulic fracturing allows one to approximate the actual oil recovery factor to design values, which is important for increasing the effi-ciency of production at the field and optimizing the use of re-sources.

Numerical modeling of fracture propagation of supercritical CO2 compound fracturing

The exploitation of shale gas is promising due to depletion of the conventional energy and intensification of the greenhouse effect. In this paper, we proposed a heat-fluid-solid coupling damage model of supercritical CO2 (SC-CO2) compound fracturing which is expected to be an efficient and environmentally friendly way to develop shale gas. The coupling model is solved by the finite element method, and the results are in good agreement with the analytical solutions and fracturing experiments. Based on this model, the fracture propagation characteristics at the two stages of compound fracturing are studied and the influence of pressurization rate, in situ stress, bedding angle, and other factors are considered. The results show that at the SC-CO2 fracturing stage, a lower pressurization rate is conducive to formation of the branches around main fractures, while a higher pressurization rate inhibits formation of the branches around main fractures and promotes formation of the main fractures. Both bedding and in situ stress play a dominant role in the fracture propagation. When the in situ stress ratio (σx/σy) is 1, the presence of bedding can reduce the initiation pressure and failure pressure. Nevertheless, it will cause the fracture to propagate along the bedding direction, reducing the fracture complexity. In rocks without bedding, hydraulic fracturing has the lengthening and widening effects for SC-CO2 induced fracture. In shale, fractures induced at the hydraulic fracturing stage are more likely to be dominated by in situ stresses and have a shorter reorientation radius. Therefore, fracture branches propagating along the maximum principal stress direction may be generated around the main fractures induced by SC-CO2 at the hydraulic fracturing stage. When the branches converge with the main fractures, fracture zones are easily formed, and thus the fracture complexity and damage area can be significantly increased. The results are instructive for the design and application of SC-CO2 compound fracturing.

Quantitative Analysis of Hydraulic Fracturing Test Site 2 Completion Designs Using Crosswell Strain Measurement

Summary The implementation of effective completion design configurations during hydraulic stimulation is critical for the economic development of unconventional reservoirs. Low-frequency distributed acoustic sensing (LF-DAS)-based crosswell strain measurement is an advanced monitoring technique used to diagnose completion design efficiency but has been primarily restricted to qualitative analysis. In this study, we apply our novel Green-function based inversion algorithm to calculate fracture geometry (i.e., width) using the Department of Energy sponsored Hydraulic Fracturing Test Site 2 (HFTS-2) data set. The adopted algorithm relies on a 3D displacement discontinuity method to construct geomechanical models inverting linear elastic strain to hydraulic fracture widths. We use the inversion algorithm to calculate dynamic fracture widths using LF-DAS data recorded at two horizontal monitoring wells with permanent optical fiber installations. The inverted fracture widths at the monitoring wells from more than 100 hydraulic fracturing stages are used to diagnose the efficiency of eight unique completion designs implemented across three fracturing wells. We develop several metrics to evaluate completion design efficiency including the evenness of fracture widths at the monitoring wells, fracture density (i.e., number of fracture hits per foot), and fracture-width-density (i.e., fracture width/stage length). We observe a significant impact on completion efficiency with varying degrees of limited entry, tapered configurations, and stage length designs. Results indicate improved hydraulic stimulation is achieved with the implementation of limited-entry designs for extended stage lengths (ESLs), but no observable trend for normal stage lengths (NSLs). Tapered configurations significantly improve efficiency for ESLs but indicate little impact on normal-length designs. Reducing the space between perforation clusters (PCs) is determined to negatively impact design performance. Additionally, our quantitative analysis describes the impact of the nearby depletion zone on completion design efficiency. The methodology developed in this study provides operators with another level of quantitative information to optimize hydraulic fracturing treatments and reduce costs associated with the development of unconventional wells.

Predicting gas flow rate in fractured shale reservoirs using discrete fracture model and GA-BP neural network method

In the process of shale gas exploitation, the hydraulic fracturing technology is generally used to generate the stimulate reservoir volume (SRV). The network connectivity between natural fractures (NFs) and hydraulic fractures (HFs) significantly affects gas production rate in the hydraulic fracturing stage. To study the influence of natural fracture characteristics on gas flow behavior, a discrete fracture model considering matrix and fracture behaviors is developed. It is found that the increase of natural fracture permeability and distribution density leads to the increase of gas production rate, whereas large orientation angle may cause its decrease. To determine the nonlinear relationship between the natural fracture parameters and gas production rate, the method of back propagation (BP) neural network with genetic algorithm (GA) was applied to make intelligent prediction for the shale gas production. The gas flow rate values for different natural fracture parameters (e.g., permeability, density, orientation) were calculated by discrete fracture model, and used as input data for training and prediction in the GA-BP neural network. Results demonstrate the applicability of forecasting model, which is suitable for shale gas prediction during the operation of horizontal wells if more data profiles could be collected.

Unveiling Key factors governing seismogenic potential and seismogenic productivity of hydraulic fracturing pads: Insights from machine learning in the Southern Montney Play

One of the most challenging works in mitigating seismic hazard related to injection-induced earthquakes (IIE) is to adequately estimate the activity level of IIE caused by individual hydraulic fracturing (HF) pad. Reliable estimation is largely dependent on comprehensively deciphering the relationships between IIE and the controlling factors. To deal with this conundrum, in this study, we first build an enhanced earthquake catalog with more than 30,000 earthquakes for the southern Montney Play (SMP), in western Canada between 2014 and 2022. We then associate these detected earthquakes to their corresponding HF pads (357 in total). We train the supervised machine-learning algorithm “eXtreme Gradient Boosting” (XGboost) to systematically evaluate how seven geological and eight operational factors contribute to the seismogenic potential (occurrence of IIE) and seismogenic productivity (number of IIE) of these HF pads. Our XGBoost classification model first suggests that cumulative injected volume and the location of the HF pads are the key factors deciding whether IIE would occur or not. Next, using the Shapley Additive Explanations (SHAP) values to quantitatively interpret the outputs from XGBoost, we reveal that contributions from operational and geological factors could be comparable to the seismogenic productivity. The top 3 most influential features are the number of HF stages targeting the Lower Middle Montney formation, cumulative volume from preceding injections, and whether the HF pads are located within the Fort St. John graben. In the interim, the seismogenic potential model reveals that the ranking of determinants governing the seismogenic productivity of IIE is somewhat different, signifying distinct fundamental mechanisms that influence the two phenomena (occurrence vs. number). Our results provide comprehensive understanding on the key operational and geological factors controlling seismogenic pattern and pave the way for forecasting the activity level of HF-related IIE for individual HF pad in the SMP area.

Accurate Prediction of the Proppant Distribution in a Hydraulically Fractured Stage.

One of the greatest challenges in stimulating a single hydraulic fracturing stage with multiple clusters is ensuring that the proppant is equally distributed across all clusters. In this paper, the Buckingham pi theorem was applied to implement a dimensional analysis to establish an empirical correlation. The experimental correlation was developed by acquiring and integrating the data of various independent variables, such as different proppant characteristics (i.e., size, density, and concentration), using a wide range of internal diameters of the horizontal wellbore and multiple perforation configurations, and utilizing many carrier fluids with different viscosities. This work presents a newly enhanced experimental correlation for the distribution of proppants by incorporating the effect of gravity on proppant particles. The correlation proved its reliability in forecasting the proppant distribution with an average percentage error of less than 10%. The developed correlation has the potential to serve as a tool for forecasting proppant distributions among multiple clusters in multistage hydraulic fracturing treatments in the field.

Reservoir and Fracture Characterization for Enhanced Geothermal Systems: A Case Study Using Multifractured Wells at the Utah Frontier Observatory for Research in Geothermal Energy Site

Summary For enhanced geothermal systems (EGS), multistage hydraulic fracturing along a deviated or horizontal well is a key technology used to create a high-conductivity fracture network between injection and production wells in deep, low-permeability geothermal reservoirs. The purpose of the created fracture network is to allow for the efficient transfer of fluid, heated by the geothermal reservoir, from the injection to the production well; therefore, well spacing (between injection and production wells) and hydraulic fracturing must be designed not only to promote connectivity between well pairs but also to mitigate thermal short-circuiting and thermal breakthrough. Analysis of post-fracture pressure decay (PFPD) data measured after each stage of a hydraulic fracturing treatment can be used to provide critical reservoir and fracture parameters required for well and hydraulic fracturing design optimization; this method provides a low-cost alternative and complementary approach to in-situ observation techniques, such as core-through experiments, fiber optics, or image logs in offset wells. Until now, PFPD has primarily been applied to multifractured horizontal wells (MFHWs) completed in low-permeability hydrocarbon reservoirs. The goal of this study is therefore to develop a methodology to estimate fracture and reservoir parameters using stage-by-stage PFPD data associated with EGS projects. An analytical model is proposed herein to estimate fracturing fluid efficiency, fracture length, average fracture aperture, average fracture conductivity, and reservoir permeability for different possible fracture geometries in EGS reservoirs. PFPD data collected for three hydraulic fracture stages in the injection well at the Utah Frontier Observatory for Research in Geothermal Energy (FORGE) site were analyzed to demonstrate the practical application of the proposed method. The results of this study indicate that, due to the presence of natural fractures in the target (granitic) reservoir, the hydraulic fracturing treatment (using slickwater) in the openhole section resulted in low fracturing fluid efficiency and small hydraulic fractures. In contrast, hydraulic fracturing treatments conducted in the perforated casedhole wellbore resulted in higher fracturing fluid efficiency and created larger hydraulic fractures even with smaller injected volumes. The results of the PFPD analysis were confirmed using a Formation MicroScanner image log and microseismic data collected during each stage of hydraulic fracturing.

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.

Computational Fluid Dynamics Modeling of Pseudotransient Perforation Erosion in a Limited-Entry Completion Cluster

Summary Hydraulic fracturing in limited-entry (LE) completion designs relies on maintaining a high bottomhole treating pressure (BHTP). LE requires high perforation friction to maintain an even distribution of the hydraulic fracturing slurry. As sand exits the perforations, the perforations start to erode. The erosional change in the perforation alters the desired perforation friction and subsequent BHTP. As operators rely on multistage hydraulic fracturing to generate economic production, the issue of perforation erosion becomes inherently repetitive from stage to stage and cumulatively a significant issue. The industry has seen how a perforation can change from a before-and-after perspective with downhole cameras and imaging techniques before and after treatments. However, a more detailed understanding of the dynamic process of perforation erosion can give a better expectation of perforation performance throughout a hydraulic fracturing treatment and not just pretreatment compared to post-treatment. Computational fluid dynamics (CFD) is a quickly emerging tool in the industry. CFD aims to model fluid flow by numerically solving the Naiver-Stokes equations within a specified domain. Along with modeling fluid systems, CFD has the capability to model dispersed particles within the fluid. Once the particles are introduced into the fluid, the domain can also be eroded away within the CFD model. By utilizing the erosional capabilities of CFD, paired with the flow of a hydraulic fracturing slurry, perforation erosion can be investigated transiently throughout an entire hydraulic fracturing stage. This work presents a better dynamic understanding of perforation erosion rather than just a “before vs. after” comparison. The CFD modeling methodology used to achieve the correct erosional pattern observed in the field is presented. Throughout this work, four different hydraulic fracturing completion parameters are investigated to determine the respective roles in perforation erosion. The four parameters include proppant size, proppant concentration, fracturing fluid viscosity, and proppant concentration ramping schedules. By investigating the impact that controlled design parameters have on perforation erosion, perforation erosion can be better anticipated to deliver improved completion results.

Geochemical Modelling of the Fracturing Fluid Transport in Shale Reservoirs

Field operations report that at least half of the fracturing fluid used in shale reservoirs is trapped. These trapped fluids can trigger various geochemical interactions. However, the impact of these interactions on well performance is still elusive. We modeled a hydraulic fracture stage where we simulated the initial conditions by injecting the fracturing fluid and shutting the well to allow the fluids to soak into the formation. Our results suggest a positive correlation between the dissolution and precipitation rates and the carbonate content of the rock. In addition, we observed that gas and load recovery are overestimated when geochemical interactions are overlooked. We also observed promising results for sea water as a good alternative fracturing fluid. Moreover, we observed better performance for cases with lower-saline connate water. The reactions of carbonates outweigh the reactions of clays in most cases. Sensitivity analysis suggests that the concentration of SO4, K and Na ions in the fracturing fluid, and the illite and calcite mineral content, along with the reservoir temperature, are the key factors affecting well performance. In conclusion, geochemical interactions should be considered for properly modeling the fate of the fracturing fluids and their impact on well performance.

Distributed acoustic sensing time-lapse vertical seismic profiling during zipper-fracturing operations: Observations, modeling, and interpretation

Recent advances in distributed acoustic sensing (DAS) technology allow active seismic monitoring of stimulated rock volume (SRV) development. We showcase an interstage DAS vertical seismic profiling survey acquired during a zipper-fracturing stimulation. Incident P waves scattered by the SRV and converted to S waves are observed in the data. The signals are associated not only with hydraulic fracturing stages of the instrumented well but also with the fracturing of an adjacent well in the zipper group. A workflow is developed to monitor and characterize the SRV, fracture closure time, and interactions between zipper wells. The 3D full-wavefield modeling confirms the data interpretation and provides additional insight. As a result, we have been able to estimate SRV properties, including SRV height, width, and the fracture closure time for all wells within the zipper group. Moreover, for adjacent wells, the length and azimuth of SRV can be constrained. Our work provides critical information for optimizing hydraulic fracturing operations.

Evolution of Near-Well Damage Caused by Fluid Injection through Perforations in Wellbores in Low-Permeability Reservoirs: A Case Study in a Shale Oil Reservoir

Abstract During the development of shale oil resources, fluid injection is usually involved in the process of hydraulic fracturing. Fluid injection through perforations causes near-well damage, which is closely related to the subsequent initiation and propagation of hydraulic fractures. This study is focused on the characterization of the temporal and spatial evolving patterns for near-well damage induced by fluid injection through perforations in the early stage of hydraulic fracturing. A coupled hydromechanical model is introduced in a case study in a shale oil reservoir in northwestern China. The model considers porous media flow during fluid injection. It also considers elasticity in the rock skeleton before the damage. Once the damage is initiated, a damage factor is employed to quantify the magnitude of injection-induced damage. Results show that damage evolution is highly sensitive to perforation number and injection rate in each individual perforation. Damage propagation is more favorable in the direction of the initial maximum horizontal principal stress. The propagation of damage is drastic at the beginning of fluid injection, while the damage front travels relatively slow afterward. This study provides insights into the near-well damage evolution before main fractures are initiated and can be used as a reference for the optimization of perforation parameters in the hydraulic fracturing design in this shale oil field.

Effect of fracture-induced stress on casing integrity during fracturing in horizontal wells

As a necessary technical method for shale gas development, hydraulic fracturing technology may cause casing failure while realizing actual reservoir reformation. The fracture-induced inhomogeneous stress generated while the hydraulic fracture is one of the main reasons for the non-uniform compression and failure of the casing. The fracture-induced stress field is mainly related to the fracture net pressure and is unrelated to the initial in-situ stress. The non-uniform load difference near the fracture is more significant, and the mechanical environment of the casing deteriorates. In this study, we combined the fracture-induced stress calculation model and the casing-cement-formation system stress distribution model to analyze the mechanical properties of the system during hydrofracturing. We used the model to calculate the casing stress distribution under fracture-induced stress and analyzed various influencing factors that affect the maximum equivalent stress (MES) on the casing. The studies show that the closer to the fracture, the greater the induced stress and MES in the casing, and the risk of casing collapse increases. The wall thickness of the casing has an influence on the MES. The larger the wall thickness, the smaller the MES. The MES of the casing reaches the maximum value when the elastic modulus of the cement stone is close to that of the stratum. Softer formation increases the potential that the fracture-induced stress transfers to the casing. The potential is responsible for the greater stress of the casing. By increasing hydraulic fracturing stages, reducing hydraulic fracturing wellhead pressure, increasing casing wall thickness and reducing the elastic modulus of cement stone can reduce the casing stress and alleviate casing damage.

Asymmetric propagation mechanism of hydraulic fracture networks in continental reservoirs

AbstractHydraulic fracturing technology is relatively mature in North America, but under complex geological conditions, such as those in China, the application of this technology still faces great challenges. At present, techniques for the numerical simulation of hydraulic fracture networks are mainly based on the prediction of the fracture half-height and half-length, which cannot capture the heterogeneity of continental low-permeability sandstone reservoirs in China and the distribution of the asymmetric hydraulic fracture network present in them. Therefore, determining the asymmetric propagation mechanism of hydraulic fracture networks is very important for improving the recovery rates of continental reservoirs. In this paper, taking the Ordos Basin in China as an example, the spatial distribution of the stress field of a heterogeneous continental reservoir is precisely predicted by reservoir mechanical heterogeneity modeling. By using a microseismic monitoring method, the 3-D morphology of the hydraulic fracture network is determined. Through the coupling of multisource data, the frequency distributions of the determined in situ stress magnitudes in different hydraulic fracturing stages are obtained. The propagation direction of the hydraulic fracture network changes under the control of the horizontal stress difference (Δσ) and the presence of natural fractures. The smaller Δσ is, the greater the deflection of the hydraulic fracture propagation direction. The asymmetric propagation of these fractures is related to the frequency distribution of Δσ. As the frequency of Δσ approaches a normal distribution, the two wings of the hydraulic fracture network become basically equal in length, and as Δσ deviates more from a normal distribution, the difference between the two wings of the hydraulic fracture network increases. These research results will provide new insight for modeling, exploring, and developing continental reservoirs.