Hydraulic Fracturing In Horizontal Wells Research Articles

Numerical simulation of stress shadow in multiple cluster hydraulic fracturing in horizontal wells based on lattice modelling

Multiple cluster hydraulic fracturing is widely used in the development of shale reservoir. The morphology of multiple fractures propagating from multiple cluster is complex due to the stress shadow effect. The design and operation of multiple cluster hydraulic fracturing in horizontal wells require adequate knowledge of the effect of different factors, including rock properties, in-situ stresses and fluid properties on the fracture morphology. In this paper, lattice simulation, a new particle based computational method was used to investigate the multiple cluster hydraulic fracturing in shale. The results showed that stress anisotropy and cluster spacing play an important role on geometry of the propagating fracture. The middle hydraulic fracture is restricted to propagate when cluster spacing is decreased. Simultaneous, two-step and sequential fracturing scenarios in a single horizontal well were simulated. The simultaneous and sequential fracturing showed to mainly affect the fracture propagation morphology with little effect on fracture length, while the middle fracture is shorter than its two side fractures in two-step fracturing. In two horizontal models, the simultaneous and sequential fractures showed similar morphology during multiple cluster hydraulic fracturing. In term of stimulated reservoir volume (SRV), zipper fracturing showed the largest SRV during multiple cluster hydraulic fracturing in two horizontal wells.

Further Investigation of Forced Imbibition in Unconventional Oil Reservoirs for Enhanced Oil Recovery

One of the popular EOR methods for unconventional oil reservoirs is taking advantage of the spontaneous imbibition during the completion stage of a multistage hydraulic fractured horizontal well. An abundant amount of completion fluid is injected during the operation and is expected to boost oil production through counter-current imbibition before the well opens for production. While most similar studies focused on modeling the spontaneous imbibition, this process occurs with soaking pressure involved in real life, which is defined as forced imbibition. Our previous study discussed the mechanisms and demonstrated the difference between spontaneous imbibition and forced imbibition through experiments and numerical simulation. The soaking pressure negatively impacts the efficiency of imbibition due to a high-pressure barrier, which further impairs the production enhancement. This study further investigated factors that may affect the recovery during this soaking stage in a more realistic reservoir model. The model is validated through lab experiments and mimics a quarter of a hydraulic fracturing stage. The effects of cluster spacing, permeability, and wettability were studied under different soaking pressures. The results indicated that, regardless of the soaking pressure, imbibition is an effective method to enhance the recovery of an unconventional oil reservoir. The results are highly sensitive to the cluster distances and only effective within the stimulated reservoir volumes. The matrix permeability and wettability are also important factors to be considered. The objective is to provide a better picture for the accurate design of fracturing completion so that an optimum oil production enhancement can be achieved.

Integrated workflow of temperature transient analysis and pressure transient analysis for multistage fractured horizontal wells in tight oil reservoirs

Multistage hydraulic fracturing of horizontal wells is one of the most effective techniques for developing unconventional reservoirs. Understanding the amount and location of hydraulic fractures is of great significance for guiding reservoir development. Pressure is by far the most commonly used data for hydraulic fracture analysis. However, for complex hydraulic fractures, pressure inversion procedure inevitably produces multiple solutions, which may lead to errors in production prediction and optimization design. In recent years, the application of distributed temperature sensors makes it possible to real-time monitor the wellbore temperature distribution. By using the integrated inversions of temperature transient analysis (TTA) and pressure transient analysis (PTA), we can eliminate one degree of freedom and address the above problem of multiple solutions. In this study, a thermo-hydraulic coupling mathematical model is proposed to describe the temperature and pressure fields for multistage fractured horizontal wells (MFHWs) during the single-phase oil production process. Then, the above model is numerically solved by using COMSOL Multiphysics. Accordingly, the time-dependent pressure drop and complex nonlinear heat transfer are investigated in detail. The results show that convective heat transfer occurs in the vicinity of the intersections of the hydraulic fractures and the wellbore. This causes the temperature change of the above intersections is quite different from that of other sections of the wellbore. Thereby, the locations of hydraulic fractures can be identified from the temperature time derivative curve. On the other hand, the length of hydraulic fractures can be obtained by conventional PTA. Consequently, the geometries and the conductivities of hydraulic fractures can be determined by integrating workflow of TTA and PTA. This depicts that TTA can serve as a companion means of PTA to investigate the distribution of hydraulic fractures.

Modelling of fractured horizontal wells with complex fracture network in natural gas hydrate reservoirs

Shale gas resources (SGR), as a representative of natural gas hydrate reservoirs, have been the main energy supply for the energy consumption currently. The multi-scale pore structure of shale, complicated seepage mechanisms, including Knudsen diffusion, matrix deformation, stress sensitivity, non-Darcy flow and spatial fracture network stimulated by hydraulic fracturing technology have posed huge challenges to an accurate prediction and assessment of shale gas recovery. A full understanding of gas seepage mechanism of shale gas is the critical and scientific issue to develop carbon hydrogen energy resources effectively. It is very urgent to establish a comprehensive mathematical model to analyze the productivity capacity through simultaneously considering various flow mechanisms and fractures network system. To fill this gap, this paper presents a comprehensive numerical model of hydraulic fracturing horizontal well with discrete fracture network where embedded discrete fracture model (EDFM) is employed to characterize the coupled phenomenon between discrete fracture network and fractured SGR. And then two numerical discretization methods, e.g., finite difference and finite-volume, are used to numerically discretize the equations, subsequently, the Newton-Raphson iterative method is adopted to obtain the final solutions. Finally, the sensitivity analysis experiments are employed to investigate the effects of the key parameters. The results can provide some certain guidance for the optimization of stimulated treatment in natural gas hydrate reservoirs.

Nonlinear Autoregressive Neural Networks to Predict Hydraulic Fracturing Fluid Leakage into Shallow Groundwater

Hydraulic fracturing of horizontal wells is an essential technology for the exploitation of unconventional resources, but led to environmental concerns. Fracturing fluid upward migration from deep gas reservoirs along abandoned wells may pose contamination threats to shallow groundwater. This study describes the novel application of a nonlinear autoregressive (NAR) neural network to estimate fracturing fluid flow rate to shallow aquifers in the presence of an abandoned well. The NAR network is trained using the Levenberg–Marquardt (LM) and Bayesian Regularization (BR) algorithms and the results were compared to identify the optimal network architecture. For NAR-LM model, the coefficient of determination (R2) between measured and predicted values is 0.923 and the mean squared error (MSE) is 4.2 × 10−4, and the values of R2 = 0.944 and MSE = 2.4 × 10−4 were obtained for the NAR-BR model. The results indicate the robustness and compatibility of NAR-LM and NAR-BR models in predicting fracturing fluid flow rate to shallow aquifers. This study shows that NAR neural networks can be useful and hold considerable potential for assessing the groundwater impacts of unconventional gas development.

Water use for shale gas development in China’s Fuling shale gas field

A large volume of water is required in shale gas development, especially for large-scale hydraulic fracturing in horizontal wells. This study focuses on 334 shale gas wells in the largest production field Fuling in China. Models are formulated to estimate the water use at each stage of the development process, including pre-drilling preparation, drilling and cementing, fracturing, gas testing, production testing. Domestic water used by employee community of shale gas companies are also fully considered. The results show that the average fracturing water use per well was 34,756.0 m3 in Fuling, which accounted for 98% of the total water use. By the end of 2017, the total fracturing water used in Fuling was 1.09 × 107 m3, and a total of 2.28 × 106 m3 of flowback fluid was achieved with 2.16 × 106 m3 of water reused. In addtion, the domestic water used by the employee community was found to be 2.19 × 106 m3, which was equivalent to the water saved from the flowback fluid. China’s special “development campaign” mode for shale gas extraction is the reason. The results improve the understanding of water use in China’s shale gas development and also provide important implications for water management.

A global sensitivity analysis and reduced-order models for hydraulically fractured horizontal wells

We present a systematic global sensitivity analysis using the Sobol method which can be utilized to rank the variables that affect two quantity of interests -- pore pressure depletion and stress change -- around a hydraulically-fractured horizontal well based on their degree of importance. These variables include rock properties and stimulation design variables. A fully-coupled poroelastic hydraulic fracture model is used to account for pore pressure and stress changes due to production. To ease the computational cost of a simulator, we also provide reduced order models (ROMs), which can be used to replace the complex numerical model with a rather simple analytical model, for calculating the pore pressure and stresses at different locations around hydraulic fractures. The main findings of this research are: (i) mobility, production pressure, and fracture half-length are the main contributors to the changes in the quantities of interest. The percentage of the contribution of each parameter depends on the location with respect to pre-existing hydraulic fractures and the quantity of interest. (ii) As the time progresses, the effect of mobility decreases and the effect of production pressure increases. (iii) These two variables are also dominant for horizontal stresses at large distances from hydraulic fractures. (iv) At zones close to hydraulic fracture tips or inside the spacing area, other parameters such as fracture spacing and half-length are the dominant factors that affect the minimum horizontal stress. The results of this study will provide useful guidelines for the stimulation design of legacy wells and secondary operations such as refracturing and infill drilling.

Understanding the effects of hydraulic fracturing flowback and produced water (FPW) to the aquatic invertebrate, Lumbriculus variegatus under various exposure regimes

Hydraulic fracturing of horizontal wells is a cost effective means for extracting oil and gas from low permeability formations. Hydraulic fracturing often produces considerable volumes of flowback and produced water (FPW). FPW associated with hydraulic fracturing has been shown to be a complex, often brackish mixture containing a variety of anthropogenic and geogenic compounds. In the present study, the risk of FPW releases to aquatic systems was studied using the model benthic invertebrate, Lumbriculus variegatus and field-collected FPW from a fractured well in Alberta. Acute, chronic, and pulse toxicity were evaluated to better understand the implications of accidental FPW releases to aquatic environments. Although L.variegatus is thought to have a high tolerance to many stressors, acute toxicity was significant at low concentrations (i.e. high dilutions) of FPW (48 h LC50: 4–5%). Chronic toxicity (28 d)of FPW in this species was even more pronounced with LC50s (survival/reproduction) and EC50s (total mass) at dilutions as low as 0.22% FPW. Investigations evaluating pulse toxicity (6 h and 48 h exposure) showed a significant amount of latent mortality occurring when compared to the acute results. Additionally, causality in acute and chronic bioassays differed as acute toxicity appeared to be primarily driven by salinity, which was not the case for chronic toxicity, as other stressors appear to be important as well. The findings of this study show the importance of evaluating multiple exposure regimes, the complexity of FPW, and also shows the potential aquatic risk posed by FPW releases.

Development and Application of a Production Data Analysis Model for a Shale Gas Production Well

This paper presents the development and application of a production data analysis software that can analyze and forecast the production performance and reservoir properties of shale gas wells. The theories used in the study were based on the analytical and empirical approaches. Its reliability has been con- firmed through comparisons with a commercial software. Using transient data relating to multi-stage hydraulic fractured horizontal wells, it was confirmed that the accuracy of the modified hyperbolic method showed an error of approximately 4% compared to the actual estimated ultimate recovery (EUR). On the basis of the developed model, reliable productivity forecasts have been obtained by analyzing field production data relating to wells in Canada. The EUR was computed as 9.6 Bcf using the modified hyperbolic method. Employing the Pow Law Exponential method, the EUR would be 9.4 Bcf. The models developed in this study will allow in the future integration of new analytical and empirical theories in a relatively readily than commercial models.

On rock deformation during hydraulic fracturing in horizontal wells

The article studies problems of rock deformation during the hydraulic fracturing in horizontal wells. The schemes show stresses acting on the rock during the fracturing. The article analyzes the Prats equation showing that powerful deformation processes can occur during fracturing operations in tectonically active areas. Schemes of deformation processes during the multi-stage hydraulic fracturing and formation fluid selection are presented. The rock mass above the reservoir between the cracks in the unperturbed part is held in zones with initial reservoir pressure (reference zones). The sizes of these zones decrease with an increase in the sizes of the well drainage zones and become destroyed. When the drainage areas are closed, the rock mass moves over the reservoir between the cracks. An increase in the number of hydraulic fracturing stages and a decrease in the distance between fractures can cause seismic manifestations during hydrocarbon production, especially in tectonically active areas.

A review of analytical and semi-analytical fluid flow models for ultra-tight hydrocarbon reservoirs

In the last decade, numerous approaches, e.g., analytical and semi-analytical pressure solutions, production decline curve, reservoir-scale numerical models, have been used to increase our understanding of fluid transport in hydraulically fractured ultra-tight reservoirs and to improve predictions of well production. Among these approaches, analytical and semi-analytical methods have proved useful to petroleum engineers, because of the balance between the reliability of theoretical model outputs and the computational cost. Analytical or semi-analytical solutions can be used to analyze pressure-transient responses, to estimate hydraulic and induced fracture properties, to forecast production, and to optimize well spacing and multi-stage hydraulic fracking.This work reviews the development of analytical/semi-analytical multi-linear and radial flow models for hydraulically-fractured horizontal wells over the past decade. In particular, the review summarizes and compares the fundamental physics and mathematics of the gas transport mechanisms that are important in unconventional reservoirs. We highlight the analytical approaches that have successfully coupled 1) reservoir spatial heterogeneity, e.g., subdivision of the stimulated reservoir volume (SRV) and fractal SRV, 2) non-continuum flow mechanisms, e.g., Knudsen diffusion, surface diffusion, and gas slip, into diffusivity equations, and 3) the impact of pressure depletion on gas desorption, and pore size change in propped and unpropped fractures. We also discuss the gas permeability models that have been proposed in the past decade and the challenges that remain to the development of oil flow models. Our knowledge of fluid transport, especially for confined fluid at multiple reservoir scales, remains incomplete, and our understanding of flow contributions from different flow regions, and mass transfer between them remains limited.

Optimal design of fracturing initiation position and breakdown pressure in horizontal well fracturing

The fracture initiation mechanism of horizontal wells is significantly different from that of vertical wells and conventional directional wells. Therefore, the study of fracture initiation mechanism and fracture initiation pressure in horizontal wells is of great significance to the optimal design of hydraulic fracturing in horizontal wells. In order to determine the fracturing initiation pressure, the fracturing position and the initiation direction, the stress state and stress distribution of borehole are analyzed. The optimal model of fracture initiation position and breakdown pressure is established and the calculation process is proposed.

Modeling Hydraulically Fractured Shale Wells Using the Fast-Marching Method With Local Grid Refinements and an Embedded Discrete Fracture Model

Summary Recently, fast–marching–method (FMM) –based flow simulation has shown great promise for rapid modeling of unconventional oil and gas reservoirs. Currently, the application of FMM–based simulation has been limited to using tartan grids to model the hydraulic fractures (HFs). The use of tartan grids adversely impacts the computational efficiency, particularly for field–scale applications with hundreds of HFs. Our purpose in this paper is to extend FMM–based simulation to incorporate local grid refinements (LGRs) and an embedded discrete fracture model (EDFM) to simulate HFs with natural fractures, and to validate the accuracy and efficiency of the methodologies. The FMM–based simulation is extended to LGRs and EDFM. This requires novel gridding through the introduction of triangles (2D) and tetrahedrons (2.5D) to link the local and global domain and solution of the Eikonal equation in unstructured grids to compute the diffusive time of flight (DTOF). The FMM–based flow simulation reduces a 3D simulation to an equivalent 1D simulation using the DTOF as a spatial coordinate. The 1D simulation can be carried out using a standard finite–difference method, thus leading to orders of magnitude of savings in computation time compared with full 3D simulation for high–resolution models. First, we validate the accuracy and computational efficiency of the FMM–based simulation with LGRs by comparing them with tartan grids. The results show good agreement and the FMM–based simulation with LGRs shows significant improvement in computational efficiency. Then, we apply the FMM–based simulation with LGRs to the case of a multistage–hydraulic–fractured horizontal well with multiphase flow, to demonstrate the practical feasibility of our proposed approach. After that, we investigate various discretization schemes for the transition between the local and global domain in the FMM–based flow simulation. The results are used to identify optimal gridding schemes to maintain accuracy while improving computational efficiency. Finally, we demonstrate the workflow of the FMM–based simulation with EDFM, including grid generation; comparison with FMM with unstructured grid; and validation of the results. The FMM with EDFM can simulate arbitrary fracture patterns without simplification and shows good accuracy and efficiency. This is the first study to apply the FMM–based flow simulation with LGRs and EDFM. The three main contributions of the proposed methodology are (i) unique mesh–generation schemes to link fracture and matrix flow domains, (ii) DTOF calculations in locally refined grids, and (iii) sensitivity studies to identify optimal discretization schemes for the FMM–based simulation.

Numerical simulation of sequential, alternate and modified zipper hydraulic fracturing in horizontal wells using XFEM

With the large-scale commercial exploitation of shale gas around the world, the multi-interval fracturing technique in horizontal well has played an important role to stimulate shale gas reservoirs. The commonly used fracturing methods in reservoir stimulation are the sequential fracturing, the alternate fracturing, and the latest proposed modified zipper fracturing (MZF), which has improved the shale gas production significantly. However, the mechanism of stimulation has not been well understood yet. This paper presents some numerical simulation results for the three different fracturing patterns by use of extended finite element method (XFEM). The numerical solution mainly considers the influences of the in-situ stress difference and the fracturing spacing on fracture propagation. The analytical parameters include the maximum principal stress, the principal stress direction and the fracture width distribution. The numerical results indicate that the induced stress from adjacent fractures is the key factor affecting the fracture configuration. And the stress interference becomes significantly serious when fracture spacing decreases or fracture number increases. Moreover, the in-situ stress difference can counteract the effect of stress interference on the fracture deviation and reduce the extent of deviation. Compared with the other two fracturing techniques, MZF generates larger maximum induced stress, but less change of the principal stress direction, which ensures a desired propagation path. Therefore, the optimal fracture spacing of MZF is smaller than that of sequential fracturing and alternate fracturing. Under the same stress difference and fracture spacing, MZF generally achieves better formation fracturing effects. The results obtained in this paper are of benefit to guide the high-efficient practices of hydraulic fracturing in horizontal wells.

Probing hydraulically-fractured wells in unconventional shale reservoirs under cyclic CO2 injection: Variation of thermophysical properties

Despite the recent growth in oil production from unconventional reservoirs, existing hydraulically-fractured horizontal wells face challenges of poor recovery with the rapid production decline over a short life span. Enhanced recovery techniques, such as cyclic CO2 injection can be a solution to this impending problem and lead to energy independence for the foreseeable future. However, mechanisms occurring around the hydraulically fractured wells are far from fully understood. The primary motivation of this study revolves around addressing this limitation. Specifically, we explored the evolution of various thermophysical properties occurring around hydraulically-fractured wells in liquid-rich unconventional reservoirs using a holistic, integrated modeling framework.Available well-logs and other data from Howard County in the Midland Basin formed the basis for constructing representative 3D structural models that capture the Midland Basin stratigraphy. We used a simulator to create multistage hydraulic fractures that allowed integration into numerical reservoir-flow simulation models. Then, both convective and diffusive flow within a multicomponent compositional simulation modeling paradigm is used to examine the role of molecular diffusion in performance under cyclic CO2 injections in hydraulically-fractured well.The simulation results indicate that molecular diffusion yields an incremental oil recovery of 6% compared to models that do not. Our analysis reveals different thermophysical properties transition from near wellbore regions to outer regions into the rock matrix. Changes in total mole fractions of CO2, methane, and hydrocarbons with C7+ fraction, pressure and saturation variation, viscosity reduction and the surface tension over 14 injection-soaking-production cycles are tracked. The analyses of the evolution of these thermophysical properties provide us with means to evaluate the efficiency of the solvent injection process. The simulation results explain how, when, and where CO2 disperses into the reservoir.

A simulation study comparing the Texas two-step and the multistage consecutive fracturing method

Multistage hydraulic fracturing in horizontal wells is a critical technique for developing unconventional oil and gas resources. Stress interactions among neighboring fractures cause immature fracture development. The Texas two-step fracturing (TTSF) method is a new technique that aims to enhance fracture complexity and conductivity. This paper compares the fracture development of consecutive fracturing and the TTSF. The fracturing sequence in the multistage fracturing method has a significant effect on the fracture length, fracture width and injection pressure. The consecutive fracturing results in relatively uneven fracture length and width. Certain fractures in consecutive fracturing are restrained to be closed due to the strong stress shadowing effect. In contrast, TTSF has considerable potential for alleviating the negative effects of stress interactions and producing a larger stimulated reservoir volume.

Advanced Hydraulic Fracture Characterization Using Pulse Testing Analysis

Effective hydraulic fracture characterization is important for successful reservoir stimulation. This represents one of the primary challenges for completion engineers in the oil and gas industry, especially for unconventional tight gas reservoirs which are important sources of gas production in the US. Multi-stage hydraulic fracturing in horizontal wells is the most popular completion method for these types of reservoirs. An advanced methodology has been developed to characterize hydraulic fractures via pulse testing analysis. This technique combines analytical solutions and numerical modeling based on the pressure pulse response recorded at offset wells before, during, and after horizontal well fracture operations to characterize fracture orientation, height, and length. Different conceptual models were tested for random well pair spacing and orientations to generate correlations and families of type curves for a single-stage vertical fracture characterization. The methodology was then expanded to be implemented in more complex cases of multi-stage fractures. For validation and calibration purposes, a case study for a single fracture characterization was presented to match the numerical results with the field data. A good agreement in fracture orientation, height, and length was obtained with this reasonably cost-effective technique.

TECHNOLOGICAL TRENDS OF OIL SERVICE INDUSTRY DEVELOPMENT

The article analyzes domestic technologies used in the extraction of oil in traditional fields, in the development of hard-to-recover hydrocarbon reserves, as well as offshore fields. The results of the analysis of innova- tive development programs of the largest oil and gas companies: Rosneft, Gazprom, Gazprom Neft and Zarubezhneftare are presented. In the course of the study, it was determined that oil and gas companies pay attention to technologies for developing unconventional resources, increasing the efficiency of developing existing fields, developing hydrocarbons on the continental shelf, developing and implementing technologies for modeling oil and gas systems and identifying promising areas, including subsea production systems field equipment in the Far North, intelligent control of hydrocarbon production processes; a set of technologies aimed at improving the wells productivity; artificial intelligence, the Internet of things, the concept of «intelligent field» and «intelligent platform». The dependence of the efficiency of the oil industry on the development of the oilfield services market has been substantiated. The directions for the development of technologies, in the implementation of which oil and gas companies are interested at present, are identified. The characteristics of innovative technologies allowing to increase the efficiency of hydrocarbon exploration and production processes are given, on the basis of which technological trends in the oil service industry are identified: technology for multi-stage hydraulic fracturing of horizontal wells, chemical flooding, BigData technology, visualization of multidimensional information arrays, geological and hydrodynamic modeling of the reservoir, technologies for digital analysis of reservoir material and fluids, machine learning or intelligent analog from the data. The issues of developing strategies for the innovative development of the oilfield services industry are covered. The existing problems of oilfield service companies in the field of technological development are revealed.

Applicability of deep neural networks on production forecasting in Bakken shale reservoirs

The unconventional shale and tight formations, such as the Bakken in Williston Basin, are becoming an important hydrocarbon sources since the development of advanced horizontal drilling and multi-stage stimulation techniques. The appropriate completion and stimulation designs are crucial to maximize the well productivity and oil recovery. Although reservoir simulations are commonly used for production analysis, the modeling of hydraulic fractures and intrinsic complexity of shale have restricted an understanding of the fluid flow behavior. Owing to the available of a large amount of data in unconventional tight and shale reservoirs, data-driven approaches, such as deep neural networks (DNNs), provide an alternative approach for production analysis in these formations.In this study, a total of 2919 wells including 2780 multi-stage hydraulic fractured horizontal wells and 139 vertical wells in Bakken Formation were collected and analyzed using a deep learning method and Sobol's global sensitivity analysis. In the deep learning model, one-hot encoding method was used to deal with the categorical data. Xavier initialization, dropout technique, and batch normalization were evaluated to develop a reliable deep neural network model. Moreover, k-fold cross validation was used to evaluate the prediction ability and robustness of models. Prior to the performance evaluation of DNN algorithms, an optimum DNN model was achieved by optimizing the dropout layer, activation function, and hyperparameters of DNN models. It is found that the number of hidden layers and neurons in each layer have significant effects on the performance of models. The optimized DNN model has 3 hidden layers and 200 neurons for each layer. The prediction performance of DNN models is acceptable with the low mean squared errors for both 6- and 18-months cumulative oil productions. Furthermore, the importance of each parameter was studied using the Sobol's analysis. Results show that the average proppant placed per stage is the most important parameter, which accounts for more than 35% of variability in both 6- and 18-months cumulative oil productions. These data-driven models can be readily updated when the new well information becomes available. It is worth mentioning that the proposed DNN models can be directly integrated into existing hydraulic fracturing design routines.

Mechanism of casing failure during hydraulic fracturing: Lessons learned from a tight-oil reservoir in China

Abstract Casing failures have been systematically encountered during multi-stage hydraulic fracturing of horizontal wells in some unconventional reservoirs of China. Such failures usually manifest themselves as excessive localized radial deformation of the casing after some fracturing stages, which prevent the bridge plugs of subsequent stages from being installed to the design depths, or even result in abandonment of all remaining fracturing stages. In this paper, aiming at clarifying the casing failure mechanism during hydraulic fracturing, we performed an integrated investigation of tight-oil wells in northwest China, by analyzing the field-gained data and modeling possible mechanisms responsible for the casing failure. The investigation results show that, radial deformation of the casing due to alteration of in-situ stresses, even jointly with poor cement sheath, is far smaller than that observed in the field which could reach the order of magnitude of 1–3 cm. In contrast, we find that shear slips of pre-existing fractures/faults crossing the casing can deform the casing to the observed magnitude, justifying a conclusion that casing failure is due to the shear of pre-existing fractures/faults. This modeling-derived conclusion is supported by the records of micro-seismic events. In addition, lead impression blocks have also run for determining the deformed shape of the casing, and the results match the modeling results for the casing sheared by activated fractures/faults. Effect of fracturing pressure, in-situ stresses, length and orientation of pre-existing fractures/faults on the slippage of the fractures/faults and thus the deformation of the casing are demonstrated by a series of sensitivity studies. Additionally, some insights are derived for mitigating the casing failure in future fracturing jobs in similar unconventional reservoirs.