Hydraulic fracture treatments may induce complex network geometries that are challenging to incorporate in numerical flow simulators. To capture this complexity, we propose a workflow that integrates a semi-stochastic Discrete Fracture Network (DFN) generator constrained by Microseismic events, core data and an efficient Perpendicular Bisector (PEBI) grid generator for the explicit discretization of the network. We applied this workflow to evaluate the effect of DFN related uncertainties on production performance. We developed a DFN model that constrains the location of natural fractures by microseismic events and samples fracture characteristics from core-data-based Probability Density Functions (PDFs). The model also interconnects natural and hydraulic fractures through a geomechanics-based algorithm. For an efficient fracture discretization, we developed a PEBI meshing technique capable to conform to low-angle intersections of extensively clustered network, incorporating optimization algorithms that reduce highly skewed cells, and ensure good mesh quality. Finally, to evaluate the impact of DFN related uncertainties on production, we implemented an efficient Monte Carlo (MC) methodology that minimizes flow simulations. We implemented the workflow in a stage of a hydraulic fracture treatment to evaluate the impact of two type of DFN related uncertainties on production: those coming from the randomness of DFN modeling and those coming from the lack of accurate knowledge of PDF parameters. We show that the proposed DFN modeling approach can be applied to calculate the "Fluid-Producing DFN (FP-DFN)," which is the network area connected to the well and able to produce, to minimize flow simulations for the MC runs. After performing efficient-based MC simulations with our DFN model, we were able to generate the FP-DFN Cumulative Density Function (CDF) incorporating the aforementioned uncertainties. From this CDF, different percentiles were selected with the respective DFN realizations for fluid simulations. We show that the developed PEBI meshing algorithm is capable to grid efficiently these complex DFN geometries with good mesh quality. Finally, 20-year production simulations suggest that a difference of several MSTB between the lowest and highest percentiles may exist revealing the effect of the DFN related uncertainties on production. Our integrated workflow provides a methodology to efficiently model and mesh explicitly complex DFN systems for numerical fluid simulations, incorporating microseismic and core data. Furthermore, this methodology, together with the implementation of an efficient MC technique, allows a quantitative evaluation of the impact on production forecast of DFN related uncertainties.

This paper adopts an empirical-analytical hybrid model of dynamic drainage volume (DDV) into a novel workflow of integrated production analysis to evaluate and predicate the performance of multi-stage fractured horizontal well (MFHW). A weak (integral) form of macroscopic mass balance model with moving boundary is developed for the expanding productive region (drainage volume) during long-term transient-flow regimes in non-static shale reservoirs saturated with compressible fluids. An analytical-empirical formulation of DDV is derived using concept of impulse response and multi-variable regression method, which includes the effects of different diffusivity within both stimulated-reservoir volume (SRV) and unstimulated matrix, fracture half-length, and fracture spacing etc. The effects of stress-dependent reservoir and pressure-dependent fluid properties on production analysis are incorporated by a pressure-dependent correction factor. To verify the accuracy of our integrated analysis, firstly, we start with a synthetic simulation example with known parameters. In the next stages, several field examples are examined with our integrated analysis approach to evaluate and predicate the performance of MFHW. The size of DDV and associated average reservoir pressure, recovery factor (RF) and phase saturation (oil/gas/water) are achieved. The half-length of primary fracture and diffusivity within SRV are also evaluated by coupled with a correction factor, and the ultimate drainage volume (estimated as ultimate recovery, EUR) is also predicated at abandonment condition, which indicates the maximum size of system affected by single-well production for us to optimize well spacing. Moreover, the contributions of both unstimulated-reservoir matrix and stimulated-reservoir volume (SRV) are quantified with changing time, respectively. The proposed approach has the following novel contributions: (1) capability to ascertain DDV and associated average reservoir pressure throughout different transient-flow regimes; (2) coupled the non-static, fluid compressibility, multi-phase flow and moving flow boundary effects into production history analysis; and 3) simplicity and efficiency; does not require comprehensive inputs as opposed to sophisticated numerical simulations, but could obtain almost all of the necessary parameters for evaluation and predication.

Liquid carbon dioxide (CO 2 ) fracturing technology is one of the waterless fracturing technologies. It has the advantages of avoiding the use of water, reducing damage, and increasing production by improving the reservoir pressure. However, the low viscosity of liquid CO 2 and the difficulty to pump proppant are the main technical challenges. No conventional thickening agent can provide the required thickening used in 100% liquid CO 2 . In this paper, the problem of thickening gelled liquid CO 2 has been solved by developing a new surfactant and thickening agent. Surface active agent can make the liquid CO 2 gel by forming wormlike micelle or cylinder micelles structure. The cylinder micelles enhance the viscosity through entanglement inter-actions above a critical concentration. Rheology and friction properties of liquid CO 2 gel are evaluated through high pressure pipeline rheological experimental device. The viscosity of liquid CO 2 gel fluid changes under different pressures (10 to 20MPa), temperatures (0 to 100 °C)and different shear rates. The experiment result shows that the effective viscosity of liquid CO 2 gel fluid is between 7.654 ~ 20.012mPa.s. The liquid CO 2 was thickening with viscosity increase at 86 to 498 times under the same conditions. The field application of the new liquid CO 2 based gel fracturing fluid in two wells of Jilin oil field in China shows that the production has been increased over 100%. 19.8 m 3 of proppant has been successfully pumped to the reservoir in one well, and the mean proppant concentration is 6.8%. Liquid CO 2 based gel fracturing fluid provides a new fracturing system with less formation damage to fracturing operation. This paper will be beneficial to all engineers and technologists who are currently working at waterless fracturing applications.

The Glauconite Formation in southern Chile is an unconventional resource made up of approximately forty percent clay and glauconite, thirty-four percent feldspar, twenty-three percent quartz, and three percent tuff. Like many unconventional reservoirs outside the United States, establishing commercial production from the Glauconite Formation was difficult given the make-up of the reservoir, the availability of equipment and materials, and the logistics associated with drilling, completing, and fracture stimulating wells in a remote area like Tierra del Fuego in southern Chile. This paper describes the effort to establish commercial production from the Glauconite Formation beginning with a couple of marginal wells in late 2011 through a nearly seventy-five well development by early 2016. As part of this effort, a basis of fracture design was established by developing a profile with depth of in-situ stress, Young's Modulus, and leak-off coefficient. These geomechanical assumptions were then tested and modified with core and pump-in data and used to make revisions to the fracture stimulation design. The designs were optimized to ensure that the critical fracture dimensions (fracture length, conductivity, and height) were achieved to maximize well performance. Next, a data collection plan was developed to capture key information about completions, mini-frac analysis, fracture design and execution, fluid, proppant, and chemical additives, reservoir quality, and post fracture flowback and clean-up data. The database was then utilized to monitor the Glauconite fracture stimulation program to ensure that the basis of design for the fracture program maintains viability and to ensure that the appropriate equipment and materials were mobilized for fracture optimization and to meet the program objectives. This paper focuses on the key elements of well completions and fracture stimulation practices as they apply to tight gas and unconventional formations by using the database to manage project risks and develop appropriate mitigation strategies. For example, preliminary fracture stimulation designs were based on initial reservoir permeability estimates of 4 md, however, the data collection plan incorporated a well test program which determined that the actual reservoir permeability was nearly one thousand times less. Another example was the rock mechanics and geomechanical data derived from dipole sonic logs indicated little in-situ stress contrast and raised concerns about the ability to achieve the desired fracture dimensions. In addition, the log derived Young's Modulus was low and inconsistent with the core tri-axial compression and ultrasonic data as well as the on-site mini-frac net pressure data. As a result, a number of tri-axial compression tests were conducted and it was determined that the Young's Modulus was much higher than indicated from the logs. The collected data and monitoring program resulted in significant treatment modifications ranging from the small cross-linked stimulations conducted initially to linear gel, hybrids, and ultimately treated water fracture stimulations as equipment and materials became available. This work is beneficial as it: Conducts an indepth well analysis and evaluation to develop a basis of fracture design, Builds a database of important reservoir quality, completion, mini-frac, fracture, and post fracture clean-up data, Utilizes the database to monitor the fracture design basis, manage material and equipment needs in a remote area, and to maximize well performance.

Proppants are placed in fractures to provide highly conductive paths for hydrocarbons to flow from the reservoir to the wellbore. Hydraulic fracturing technology is constantly improving to achieve better production performance. Ultra-lightweight (ULW) proppants are one of the technologies introduced to improve fracturing effectiveness. Compared to sand, ULW proppants can be carried farther and distributed more evenly within fractures, resulting in more propped fracture area. This paper evaluates the impact of ULW proppants on production performance in tight reservoirs and examines characteristics of formations where ULW proppants are most beneficial. To explore the advantages of ULW, hydraulic fracture models are developed. These models help in understanding the fracture geometric properties. This information is then incorporated into reservoir production models to evaluate the impact on production performance. Fractures using ULW proppants and the resulting well productivity are compared to those using sand. No technology provides a solution for all situations, and neither do ULW proppants. To better understand if ULW proppants bring the most benefit for production performance, data-mining techniques were used to identify ULW proppant field applications. Results showed that ULW proppants had better vertical distribution within the fractures than sand (sand had a tendency to settle to the lower part of fractures, leaving the upper part unpropped). In a thick reservoir formation with insufficient vertical conductivity, fractures created by ULW proppants connected larger volumes of rock, leading to higher well productivity and increased EUR. This study discusses the benefits that ULW proppants can bring to unconventional producers and identifies potential candidate formations where ULW proppant may be very effective. Field cases are included to show the benefits of ULW and the circumstances where they can bring the most value.

The Bakken unconventional resource in Williston Basin is becoming an important component of hydrocarbon sources in North America. Although advanced horizontal drilling and multi-stage stimulation techniques being successful to exploit Bakken formations, appropriate completion and stimulation designs are crucial to maximize the well productivity and oil recovery of the shale or tight reservoirs. Data-driven approaches, such as deep neural network modeling and global sensitivity analysis, are promising methods to evaluate hidden correlations between multi-stage hydraulic fracturing strategies and well productions. In this study, a total of 2919 wells including 2780 multi-stage hydraulically fractured horizontal wells and 139 vertical wells in the Bakken formation were collected and analyzed using a deep learning method and Sobol's sensitivity analysis. 18 features of a single horizontal well were extracted from the raw data resources. These features contain five aspects: well location and geometry, Bakken formation thickness, hydraulic fracture characterization, fracturing fluid, and proppant. 6 months' and 18 months' cumulative production were utilized to characterize the after-stimulation performance of horizontal wells. In the deep learning model, one-hot encoding method was used to deal with the categorical data. Xavier initialization, dropout technique, Batch Normalization, Adadelta optimizer were applied to develop the reliable deep neural network. Moreover, k -fold cross validation approach was used to evaluate the prediction ability and robustness of the models. Finally, the importance of each parameter was studied using the Sobol's sensitivity analysis. Deep learning neural networks were firstly and successfully developed to predict the oil production of hydraulically fractured horizontal wells. The overall performance of deep network models is acceptable with a low mean squared error between estimated and measured oil production. The configuration type of networks has little effect on the performance of deep network models. While the number of layers and neurons in each layer have a significant effect on the performance of models. The best number of layers ranges from 4 to 7, and best number of neurons in each layer is between 100 and 200. Sobol's sensitivity analysis indicates that the average proppant placed per stage is the most important parameter contributing to ~ 35% of both the 6 months' and 18 months' cumulative oil production variability. Moreover, the interaction effects among parameters should be considered during the hydraulic fracturing design. Results from this work can be used to optimize multi-stage hydraulic fracturing design for new Bakken wells. The proposed deep learning method and sensitivity analysis provide a potential workflow to evaluate well after-stimulation performance for multi-stage fractured horizontal wells and can be integrated into reservoir decision-making routines.

Hydraulic fracturing is a very robust tool in terms of not only increasing production in tight reservoirs but also accelerating production from reservoirs with higher permeability and porosity. The success of a hydraulic fracturing treatment is highly correlated with control of the created fracture geometry. Control of fracture growth and geometry is challenging in formations where the boundary lithologies are not highly stressed compared to the pay zone, allowing out-of-zone migration of fractures. As several factors influence the growth and geometry of fractures, including the reservoir, wellbore, and fluid/proppant parameters, it requires a good understanding of reservoir parameters, including stress distribution along with appropriate use of corresponding wellbore components and fluid/proppant for successful and efficient results. Our objective is to outline the main differences between different fracture models along with the key parameters and their significance in fracture performance. Fracture treatment designs involve selecting fracturing fluids, additives, proppant materials, injection rate, pump schedule, and fracture dimensions. Although hydraulic fracturing has become more important due to development of unconventional resources in tight formations, the use of fracture models before implementation of the treatment is limited, leading to undesired fractures either with limited growth or propagation out of zone. Literature lacks a study that combines the evaluation of different fracture models in an optimization process where economics is taken into account with an objective function maximizing the net present value (NPV), providing detailed information on the financial side of this technical phenomenon, too. In this study, different numerical fracture models are used to design the fractures in a tight oil reservoir, the performance of designed fractures are analyzed to measure the success of different numerical models applied in design along with an overview of critical operational parameters together with the significance of parameters, including size, number, and location, phasing angle of perforations, fluid and proppant type, rock strength, porosity, and permeability on fracture design optimization‥ In our paper, a comprehensive literature review of previous studies on tight oil reservoirs and hydraulic fracturing provides a thorough theoretical comparison of fracture models used in oil industry along with the analysis of significance of each factor throughout the process of hydraulic fracturing tight oil reservoirs. An objective function that maximizes NPV is used in this study investigating the phenomenon not only from the physical but also the economical aspects of fracturing that is still an expensive but an effective way of production enhancement technique when applied wisely.

This paper presents a novel analytical solution to predict the expansion of drainage volume for compound transient linear flow system consisting of stimulated-reservoir volume (SRV) and unstimulated shale matrix. The distance of investigation (DOI) has been demonstrated to be a useful notion for production data analysis; e.g., optimization of spacing of hydraulic fractures, and evaluation of stimulated-reservoir volume (SRV). However, the DOI concept has been mainly used to evaluate dynamic drainage volume (DDV) for the linear flow system within SRV. Thus, in view of production from both SRV and unstimulated shale/tight sand matrix; the DOI (or DDV) of transient linear flow in compound multi-stage fractured reservoirs has not been determined yet. In this work, we derive the DDV equation analytically for compound transient linear flow system under constant-flowing-pressure and constant-production-rate condition for the compound linear flow system. To that end, coupled with the analytical equation calculating the pressure and DDV of linear flow within only SRV, the compound linear flow solution within both SRV and unstimulated matrix is derived. Laplace transform and numerical inversion are implemented to obtain the semi-analytical solution. The pressure front is calculated by implementing the impulse respond concept, which is the maximum rate of pressure response. In addition, a relation was established between DOI and square root of time using multivariable regression, based on results of 2000 cases calculated from our semi-analytical solution. The cases capture the impact of several parameters, including different diffusivities within SRV and unstimulated matrix, hydraulic fracture length, and fracture spacing. Our solution suggested that the DOI demonstrates a linear relation to the square-root-of-time for both linear flow within SRV and the compound linear flow system. The advancement of DDV within stimulated-reservoir volume is significantly faster than that within unstimulated matrix. The majority of production is attributed to size of stimulated-reservoir volume. To verify the accuracy of the new DDV equations, we analyze the synthetic production data from a series of fine-grid numerical simulations. Finally, real-time average reservoir pressure and ultimate oil recovery were evaluated for a few selected wells from one of the US shale plays. This work has the following contributions: (1) provide a practical equation of DDV for multi-stage fractured horizontal well; (2) capability to ascertain DDV and associated average reservoir pressure throughout different transient-flow regimes for fractured horizontal well; (3) calculation of oil recover factor. The latter is important in project economics.

Hydraulic fracturing plays a significant role in unconventional oil and gas reservoirs. The hydraulic fracture initiation and propagation mechanism is fundamental important, but is understood unclearly. The large-scale hydraulic fracturing experiment, with the sample size of 30in*30in*36in, can simulate reservoir stimulation under the in-situ stress with the acoustic emission (AE) monitoring. AE is used to monitor fracture initiation and propagation in real-time and analyze the source mechanism of rocks. The shear slippage can effectively enhance reservoir permeability, which makes the source of AE events important. In order to characterize the source mechanism, two methods are used in this paper: (1) the moment tensor inversion analysis, using P-wave first-motion polarities and amplitudes to determine crack type classifications from a unified decomposition of eigenvalues; (2) the single wave characteristic parameter analysis, using RA value (=the rise time/the maximum amplitude in mV) and average frequency (= AE ring down-count/the duration time) respectively as horizontal axis and vertical axis to plot a scatter diagram. According to large-scale experiments with sandstone, coal and shale, results show that: (1) The conclusions obtained by the two methods are similar. Using the single wave characteristic parameter analysis to evaluate fracture mechanism in fracturing simulation experiment, the fractures are classified into two major groups: tensile fractures and shear fractures. (2) Tight sandstone only produces tensile fractures. The coal, shale and naturally fractured sandstone blocks have more complex mechanism with tensile and shear fractures, due to the existence of favorable natural fractures under specific in-situ stress and the injection pressure. (3) Spatial and temporal distribution of hypocenters is observed. A bi-wing planar fracture is formed in tight sandstone, but non- planar fracture networks exist in coal and shale blocks. This work can help engineers establish a proper model for the estimation of effective stimulated reservoir volume (ESRV) using the microseismic data in hydraulic fracturing.

The Glauconite Formation is a low permeability unconventional resource in southern Chile. Like many unconventional reservoirs outside the United States establishing commercial production from the Glauconite Formation was difficult given the nature of the reservoir, the availability of equipment and materials, and the logistics associated with drilling, completing, and fracture stimulating wells in a remote area like Tierra del Fuego in southern Chile. To be successful fracture stimulating wells in this environment it was critical to develop a deep understanding of the relationship between reservoir quality, completions, mini-frac analysis, fracture design, execution, and post fracture production data. To this end, a database was developed and the key completion and fracture stimulation parameters were captured. This paper describes a statistical evaluation of nearly seventy wells fracture stimulated in the Glauconite Formation in southern Chile. The analysis will attempt to discover the key fracture design parameters that drive well performance in this unconventional resource. Some key questions to be addressed include: What type of fracture fluid (cross-linked, linear gel, hybrid, or treated water frac's) results in better well performance? What is the effect of treatment volume on well performance? What is the effect of proppant volume, proppant type, and proppant size on well performance? Is there a relationship between fracture fluid efficiency, load recovery, reservoir quality and well performance? These and more questions will be addressed in this paper. This paper will also use the information in the database and the results of the statistical evaluation to conduct a fracture optimization study and determine the optimum fracture design which maximizes well performance and economic objectives. This work benefits the petroleum industry by: Conducting a statistical analysis of the important completion and fracture stimulation parameters to determine the success drivers for well performance in an unconventional tight gas reservoir, Utilizing the statistics to identify well completion and fracture stimulation risks and risk mitigation strategies,

In the end of 2012, the breakthrough of 15 stages fracturing treatment of horizontal well-JiaoYe 1HF, located in Jiaoshiba block, Fuling gas play, Chongqing, China, with the post-fracturing gas production 203,000 m 3 /d ( Lu, et al., 2013 ; Zhou, et al., 2013 ), which opened the new page of shale gas exploration and development in China. The reason of the success may be owed to the adaptable strategy and corresponding parameters so as to maximize Effective Stimulated Reservoir Volume(ESRV) ( Jiang, et al., 2011 ; Jia, et al.,2012 ). A systematic method was employed in this study which contains physical simulation in lab, numerical simulation, and fracturing fluid additives development as well. Firstly, a comprehensive formation evaluation was conducted such as rock lithology, pore throat size, porosity, permeability, rock mechanics, three dimensional stress, pore structure, maturity, total organic content, total gas content including free gas and absorbed gas, etc ( Jia, et al.,2012 ). Secondly, a three axis laboratory test of fracture propagation physical simulation on a lot of large scale rock samples were conducted, from which the network fracture mechanism and correspondingly, the key control factors may be available consequently( Zhang, et al.,2013 ); Thirdly, a systematic laboratory tests of fracture conductivity for many conditions such as various fracture type and, proppant type, concentration and placement mode in different closure stress and time, etc. were conducted, so that the conductivity characteristic of network fracture may be obtained so as to utilize in the design of pumping schedule( Jia, et al.,2014 ); Fourthly, a new mathematical model of coupling flowing interference and stress shadow interference was put forward and a "W" type fracture distribution was correspondingly anticipated. After that, a new optimization model for well pattern and well space, fracture parameters and fracturing treatment parameters can be optimized simultaneously ( Jiang, et al., 2013 ). Fifthly, alternately pumping mode of "spearhead acid, slick water, gel, slick water, gel……" and "70/140 mesh proppant, 40/70 mesh proppant, 30/50 mesh proppant "was put forward based on the object of main fracture net pressure during the course of fracturing treatment( Jiang and Jia, et al, 2011 , 2013 ). Sixthly, a new flow back model was put forward and the relative flow back parameters such as shut-in time and flow back rate as well may be optimized correspondingly( Jiang, et al, 2013 ). The above mentioned technology have been applied in a large scale (more than 200 wells) in Fuling shale gas play, therefore, expected results are obtained with the average gas production more than 300,000 m 3 /d, and the highest open flow capacity as high as 1,580,000 m 3 /d. Now, Fuling shale gas field is the largest one in China, its annual production is more than 5 billion m 3 . Therefore, it has a great significance on the hydraulically fracturing technology in other lithology such as tight sandstone and carbonate reservoirs.

Carbonate reservoir with low permeability is developed using fracturing technology to effectively stimulate the reservoir for a higher productivity. However, as the carbonate reservoir features extreme heterogeneity, not every fracture is created equally as is obtainable through acidizing fracturing or using proppant. The objective of this study is to help make the decision among acid fracturing or proppant fracturing, to achieve an economically and operationally feasible treatment through extensive research of field cases on critical factors and numerical simulation. An ideal fracturing method of a carbonate reservoir should yield a high conductive fracture with a potential for long production duration under depletion scenario within an economic limit. We first review real field cases to identify critical parameters affecting fracture geometry and productivity; then we validate and quantify their individual effectiveness using 3D synthetic models with numerical simulation. In the simulation work, both treatments are evaluated by simulating the production of the reservoir for 1,500 days post treatment. Results are compared for different reservoir parameter variations including porosity, permeability, temperature, depth and young's modulus. Simulation of the field is continued for 1,500 days after the treatment to see the effect of the production enhancement for both types of treatment. This is also done to include long term loss of fracture conductivity and its effect on the overall production. Fracture geometry from each case is also analyzed and compared to the base case scenario. Even though hydraulic fracturing and acidizing technologies have been the dominant stimulation methods in unconventional resources and many variants have been developed, there is still no well-defined guideline which can help an operator to select the stimulation techniques suitable for their particular fields. This paper focuses on factors influencing decision making on the stimulation of carbonate reservoirs based on reservoir characterization. The advantages and limitations of proppant fracturing and acid fracturing are compared based on field applications, which can enable an operator to make quick and informed decision on which stimulation should be used. Numerical effort confirmed and quantified our observations. Comparisons have been drawn on different types of proppant and acid treatments and their effectiveness on the target reservoir. The study eventually comes up with identifying main factors of reservoir for treatment selection and recommendations are presented from these findings that which type of reservoir is best suited for which type of treatment. The novelty of the study is summary of previous field cases with a clear guideline on making decision in carbonate reservoir stimulation. As a further extension to this study, PVT data can also be included to see the extent of reservoir fluid change effect on the outcome of the treatment.

We developed a fully coupled thermo-hydro-mechanical (THM) model for hydraulic fracturing treatments, which was verified via comparison to published literature. This model was then utilized to investigate complex fracture network propagation in naturally fractured reservoirs. Mixed finite volume and finite element methods were used to solve this coupled system, in which the MPFA L-method was employed to evaluate the fluid-heat, inter-element flux because of the existence of full tensor permeability caused by imbedded fractures. To elucidate the crossing behaviors as hydraulic fractures meet inclined natural fractures, we extended Gu et al.'s (2011) crossing criterion to a 3D scenario. Moreover, we integrated the modified Barton et al.'s model ( Barton et al., 1985 ) proposed by Asadollahi (2009) to address the shear dilation process, which is helpful for accurately estimating the dynamical fracture aperture responding to changes of stresses, fluid pressure, and temperature. Numerical experiments showed that principal factors controlling the complexity of the induced fracture network included stress anisotropy, injection rate, natural fracture distribution (fracture dip angle, strike angle, spacing, density, and length), fracture filling properties (the degree of cementation and permeability), fracture surface properties (cohesion and friction angle), and tensile strength of intact rock. We found that: (1) the lower the injection rate and the smaller the stress anisotropy, the more complex fracture network the could be developed; (2) high tensile strength could increase the possibility of the occurrence of shear fractures; and (3) under the conditions of large permeability of fracture-filling combined with small cohesive strength and friction coefficient, shear slip could become the dominant mechanism for generating a complex fracture network. The model developed and the results presented can be used to understand the propagation of complex fracture networks and aid in the design and optimization of hydraulic fracturing treatments.

The Lower Triassic Montney Formation produces from the Western Canadian Sedimentary Basin. This shale play is extensive as it covers nearly 57,000 square miles. The play consists of landing intervals in the Lower, Middle, and Upper Montney Formation for which the oil and gas industry uses multiple fractured horizontal well completions to recover natural gas. Both cased and open hole completions are utilized in the Montney Formation. Identifying the key drivers for success of multiple fractured horizontal wells is not straightforward, especially in unconventional reservoirs like the Montney. One study by Christie et al investigated the completion trends of four Montney operators since 2005 and showed the average completion interval length, the average number of fracture stages, and the volume of proppant used per fracture all increased over time. Al-Alwani et al, provided a statistical analysis of both open and cased hole Montney completions based on publically available data. The authors showed that for the entire well population, cumulative gas recovery per stage declines as the number of completed stages increased. It was also shown that cased hole wells performed much better than open hole wells although the completion costs were at least 50% greater. However, this statistical analysis did not differentiate between completions in the Upper, Middle, or Lower Montney nor did it include perforation cluster data. This work documents the statistical analysis of 296 cased-hole horizontal gas well completions in the Upper and Lower Montney. The work extends the previous statistical study of Montney completions by focusing on cased hole completions, including completion cluster information, and examining the performance of Upper and Lower Montney completions separately. Results of this analysis show that cumulative gas production per cluster decreases as more perforation clusters are placed in both the Upper and Lower Montney. The study demonstrates that the cumulative gas production per cluster and initial gas production (IP) is higher for the Upper Montney Formation than the Lower Montney Formation. This work benefits the industry by: Providing a more focused statistical analysis of horizontal gas well cased hole completion performance in the Montney, compared to recent literature documenting industry practices. Identifying a maximum recommended liquid per cluster amount for completions in the Montney Formation. Providing a comparison of Upper and Lower Montney cased hole completion performance.

The staged fracturing and microseismic monitoring techniques are used for horizontal well stimulation in the Fuling shale gas field. From the analysis of the microseismic data, most of the wells are well stimulated. However, there are still some zones which are not broken thoroughly between adjacent two clusters. When decreasing the cluster space in the adjacent well, this bad phenomenon can be avoided. The cluster space is the key factor for the multi-stage hydraulic fracturing. How to choose it? Two things must be concerned, one is the fracture geometry, and the other is the induced stress field between each two adjacent fractures. A three-dimensional (3D) multi-fracture propagation model was developed. The mixed boundary element method was used to describe the propagation of the 3D fractures. The fluid flow in a fracture was modeled by the lubrication equation and the Navier-Stokes equations. The fluid flow in the wellbore was considered as the one-dimensional flow. Newton-Raphson and Picard iterative methods were used to discrete the 3D multi-fracture propagation model. Based on the geomechanics parameters of the Fuling shale reservoir, the fracture geometry and stress interference between each two adjacent fractures are studied. Numerical simulations are carried out to study the influences of the cluster arrangements, fluid displacement and viscosity, bedding plane, shale anisotropic, etc. on the fractures geometry, net pressure inside the fractures and induced stress fields, which reveals the fracture propagation interference mechanism of multi-stage hydraulic fracturing. An optimized cluster space exits for a specific well. 20-25 meter cluster space is recommended for the shale gas formation with well-developed bedding planes, and 25-35 meter recommended for the shale gas formation with non-developed bedding planes. The results are used for the on-site perforation cluster spacing optimization in about ten shale gas wells in Fuling shale gas field, the microseismic signals are full in the shale formation between two adjacent fractures. The 3D multi-fracture propagation model are established, and the fractures geometry and induced stress fields are studied, which can help to optimize the perforating cluster space and hydraulic fracturing parameters.

Horizontal well drilling and multistage hydraulic fracturing are essential to economic recovery of unconventional tight/shale reservoirs. Multiple transverse fractures are ideally supposed to be perpendicular to the minimum stress direction, but slanted fractures might be seen in practice, which might bring a better connection between wellbore and fractures. However, for the same fracture half-length, the stimulated reservoir area might be less. Thus, the well performance of slanted faractures is full of uncertainty. Little research work is currently conducted on the horizontally slanted fracture scenario. Our transient pressure analysis of horizontal well performance with slanted hydraulic fractures utilizes the concept of rate-normalized pressure and transient productivity index. The novel Fast Marching Method (FMM) is adopted to characterize the drainage volume evolution for multi-stage horizontal wells and validate the proposed methodology. Sensitivity studies contrast transient pressure behavior and productivity index for slanted fracture angles from 0 to 90 degrees, e.g. from longitudinal to transverse fracture angles. Additionally, transient pressure behavior and long term reservoir performance of horizontal well for different scenarios are investigated, such as reservoir anisotropy and different proppant allocation strategies under the constraints of given horizontal well spacing and total proppant mass. Contrast to what we are usually expecting, results show that for the same fracture spacing, and the same total proppant mass, the well with slanted fractures will have a higher productivity index than that for strictly transverse fractures. Different from productivity index, the long term reservoir performance, however, turns out to play a different game, given specific horizontal well spacing and the same total proppant mass. Reservoir performance for horizontal well with slanted hydraulic fractures can be significantly improved by optimally allocating the proppant and designing hydraulic fracture placement strategies through this research.

Hydraulic fracturing is an effective approach to bring economic productions for unconventional gas reservoirs. A numerical model is developed to model the complex fracture network after hydraulic fracturing. Particular treatments for full-tensor effects and fractures of different scales are integrated in the method to deliver fast evaluating the effect of hydraulic fracturing on recovery of unconventional gas reservoirs. A discrete fracture model of the complex fracture network is firstly built up as the high-resolution reference model. Then numerical simulation grids are determined according to the fracture scales, fracture distribution and well locations. During numerical simulation, primary hydraulic fractures are treated explicit as the reference model, while relatively small-scale hydraulic fractures and natural fractures are upscaled into dual porosity grids by global upscaling procedures under multipoint flux approximation scheme. An integrated output least squares method, which aims to minimize the total bias of simulation results, is adopted to obtain the optimal transmissibility connection list of the simulation model. An application case is designed to validate the proposed method. The results show that the proposed model can improve the computational efficiency for predicting the effect of hydraulic fracturing, and can maintain an equivalent numerical precision at the same time. This model can serve as a reliable tool for fast evaluating of different plans in hydraulic fracturing of unconventional gas reservoirs.