bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Approach to the Modeling of Hydraulic Fracturing Treatments in Naturally Fractured Reservoirs
Authors: Li Sanbai , Zhang Dongxiao , Li Xiang 
Published: August 2016

Abstract
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.
3D Multi-Fracture Propagation Modeling and Perforating Cluster Space Optimisation for the Fuling Shale Gas Reservoir
Authors: Xiao Jialin , Rong Mang , Li Kuidong , Liu Xiang , Zhang Hui , Zhu Haiyan 
Published: August 2016

Abstract
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.
Far-Field Diversion in Hydraulic Fracturing and Acid Fracturing: Using Solid Particulates to Improve Stimulation Efficiency
Authors: Williams Vanessa , McCartney Elizabeth , Nino-Penaloza Andrea 
Published: August 2016

Abstract
The industry has long recognized the need to divert stimulation fluids away from a path of least resistance into one that stimulates new/more reservoir volume. However, relatively little research has been published specifically on the application of solid particulate diverters to increase fracture complexity in the far-field and to control fluid loss in acid fracturing. As the industry focuses more on well economics and increasing stage efficiency, proper engineering and application of far-field dissolvable solid particulate diversion technologies can increase overall well productivity in propped hydraulic fracturing and acid fracturing applications.
To support the concept of far-field diversion in propped hydraulic fracturing and acid fracturing, laboratory studies including bridging tests, diversion efficiency through permeability reduction, and dissolution rates have been performed. To enhance these studies, operational guidelines and engineering the field application will help determine when different types of diversion can improve efficiency.
Combining the information learned from laboratory testing and the new operational efficiency guidelines, a recommendation will be presented on the optimal way to run dissolvable solid particulate diverters in order to increase reservoir contact in the far-field. Multiple techniques exist to increase fracture complexity in the industry today. However, chemical diversion using solid particulates with an optimized particle size distribution enables the ability to reach more hydrocarbons in the reservoir. In addition, an advanced solid particulate diverter will be discussed for propped fracturing which includes the combination of particulate diverter material and a specially designed proppant to keep the fracture network open in the far-field.
Far-Field Diversion Agent Using a Combintion of a Soluble Particle Diverter with Specially Engineered Proppant
Authors: Spurr Naima , Gomaa Ahmed M. , Pirogov Alexander , McCartney Elizabeth 
Published: August 2016

Abstract
The objective of this study is to introduce a technique of far-field diversion using a mixture of soluble solid particles and an engineered proppant to ensure the temporarily bridged fractures re-open and remain propped for hydrocarbon flow after the soluble material has fully dissolved. Far-field diversion is required inside the fracture network to increase complexity by creating additional branch fractures through overcoming stresses holding the natural fractures closed. Usually, diverter particles temporarily bridge inside the fracture to create a low-permeability zone that increases the net pressure within the fracture and enables redirection of the next fluid stage to previously unstimulated intervals. However, if the diversion does not include proppant, the created fracture may close after particle dissolution.
The tests performed in this study were: bridging tests to determine the optimal particle size and loadings for a fracture width of 0.04 in.; pack permeability tests to optimize the particle size distribution, temporarily reduce fracture conductivity and increase pressure; and full characterization testing of the proppant as it will remain in the fractures after the soluble particles disappear. Conductivity of the proppant pack was also determined. Two types of particle diverters (Diverter A and B) were tested. Diverter A is typically used for low- to medium-temperature application (less than 225°F) and Diverter B for high-temperature applications (greater than 225°F). The two diverters have nearly the same particle size and distribution, the only difference being a variance in particle shape.
Results obtained highlighted reducing the proppant size to a larger mesh number to better place the proppant inside the far-field area with good vertical coverage. Therefore, the diverter particles were selected to be in the medium size range (10 to 50 mesh) while the proppant particles were selected to be in the fine size range (70 to 140 mesh). The crush stress at which the proppant generated less than 10 wt-% fines was 14,000 psi, while at 15,000 psi the proppant generated exactly 10 wt-% fines. The average acid solubility of this proppant in the mixture of HCl:HF was 3.4%, well below the 7% API requirements. A loading of 0.5 ppg of Diverter A was needed to bridge and plug the 0.04-in. slot width, while it needed only 0.25 ppga of Diverter B to plug the same width. Both diverters significantly reduced the conductivity of the test slot discs. After the soluble particles dissolved, conductivity was provided through the 100 mesh ceramic proppant pack that was not previously attainable because there was no proppant.
Comprehensive Analysis of Shale Elastic Properties, Microseismic Monitoring Results and Hydraulic Fracturing Parameters
Authors: Sijin He , Zhiliang Liu , Gang Xu , Jianghua Chang , Xiaoping Wan , Fei Cheng , Kaiyuan Du 
Published: August 2016

Abstract
At the present, shale gas wells in South China WY area have good gas production, but there are still many producing wells with poor performance. This is because we do not fully understand the shale gas reservoir storage and production mechanism and characteristics, which leads to the difficulty of shale gas "sweet spot" prediction. This is not conducive to future development of this field. In this paper, through comprehensive analysis of main shale elastic properties, microseismic monitoring data and the hydraulic fracturing stimulation, we need to provide beneficial theoretical basis for the WY block's future hydraulic fracturing stimulation. This paper is mainly based on the interpretation of log data to select optimized key elastic parameters of the shale gas reservoir. We analysis the shale formation elastic properties (such as P- and S-wave impedance, P- and S-wave velocity ratio, brittleness, TOC, etc.), and then find out the relationship between different elastic parameters. Based on the magnitude and number of microseismic event, the overall length, height and direction of the event distribution, we can provide guidance for the hydraulic fracturing stimulation through the integration of different elastic parameters. We analyzed fracturing operation parameters including fluid volume, total amount of sand, stop fracturing pressure and other important stimulation parameters in WY block shale reservoir, combined with elastic properties of shale, microseismic events, and seismic attributes, utilized the means such as logging cross-plot, line chart and other means to provide a clear idea of analysis, according to the reservoir characteristics of seismic information in the area at the same time. Comprehensive analysis through a variety of methods can predict good fracturing stimulation zone within the shale reservoir, avoid fracturing difficulties, improve the quality of hydraulic fracturing operation, and provide beneficial guidance for the work area's next step field development.
Numerical Modeling and Candidate Selection of Re-Fracturing with Micro-Seismic Data in Shale Gas Productions
Authors: Xu Ben , Li Yanchao , Yuan Tao , Qin Guan , Yin Congbin , Xiao Jianfeng 
Published: August 2016

AbstractShale oil and gas wells had drastic decline characteristics in the first few production years. Operators may have to drill new wells or re-fracturing the well to maintain the same production level. Properly designed and implemented re-fracturing stimulation will improve the EUR as much as two-fold.In this paper, we present a practical methodology to model re-fracturing operation and predict the shale gas production after re-fracturing in the shale gas reservoirs. In this approach, a new mathematical model is presented to improve the understanding of the correlation between the micro-seismic magnitude and the shape factor in the dual-porosity system. Shape factor can characterize the fluid transfer between matrix and fractures in the system, and micro-seismic mapping has been widely used to monitor hydraulic fracturing responses and to evaluate stimulation results in shale gas production. Application of dual porosity model allows accurate modeling shale gas flow in fractured reservoirs, which incorporates heterogeneity of the reservoir and corrected permeability by Langmuir isotherm. Analyzing micro-seismic locations and magnitudes provides useful information of the induced fractures, such as fracture orientation, width, spacing, etc. The shape factor is dependent on fracture characteristics and micro-seismic magnitudes, which is estimated by history match analysis of 6 shale gas producing wells in the Longmaxi play. The shape factor function and the permeability of induced fractures are then modified with the new micro-seismic data by the proposed mathematical model to estimate the shale gas production after the re-fracturing treatment.Comparing the simulated results with well production history, the present model is able to accurately estimate the shape factor in the dual-porosity model, which consequently enhances the prediction of shale gas production. According to stimulated fracture network, dead gas area, and production enhancement, re-fracturing candidates are selected and evaluated with high production decline rate.The proposed mathematical model is important to simulate and optimize re-fracturing in shale gas productions. A robust mathematical model that accurately describes the micro-seismic data and the shape factor is presented and essential to better forecast and optimize shale gas production during the lifespan of the well. We presented a process on how to design and plan for a re-fracturing stimulation.
Modeling Dynamic Drainage Volume for Multi-Stage Fractured Wells in Composite Shale Systems: New Analytical Solution for Transient Linear Flow
Authors: Zheng Da , Moghanloo Rouzbeh Ghanbarnezhad , Yuan Bin , Dong Xiaomeng 
Published: August 2016

Abstract
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.
Experimental Investigation on Hydraulic Fracture Initiation and Geometry in the Definite Plane Perforating Technology of Horizontal Well
Authors: Yuan Liang , Hou Bing , Shan Qinglin , Chen Mian , Xiong Zhenyu , Zhang Ruxin 
Published: August 2016

Abstract
Definite plane perforation of horizontal wells is an effective method of SRV fracturing for oil and gas well. It can control fractures to propagate along the radial direction of the wellbore for the optimal reservoir stimulation effect.
A large-scale (the sample size is 300 mm*300 mm*300 mm) true tri-axial hydraulic fracturing simulation system is utilized to conduct the contrast test under conditions of DDP and conventional perforation considering different horizontal stress difference, in which the fracturing pressure, the geometry of crack initiation and propagation as well as the near-wellbore friction resistance are compared and analyzed. It was the first time to perform such indoor comparative tests. In this paper, a model of the wellbore in perforating operations is designed and a cement block with the size of 300 mm*300 mm*300 mm is selected to conduct the fracturing experiment under tri-axial stresses. Slick water with viscosity of 10mPa.s is selected as the fracturing fluid in the experiment and a displacement of 60ml/min is adopted. In the experimental process, confining pressure is firstly loaded on the cement block, and then the fracturing fluid is injected into the wellbore through the hydraulic pump and pipeline.
The results of the experiment indicate that, DDP has following advantages compared to CP: (1) It greatly reduces the fracturing pressure; (2) It effectively reduces the near-wellbore friction resistance, which is in favor of the fracture propagation in the formation. (3) It can control fractures to propagate along the radial direction of the wellbore, reducing the complexity of wellbore fractures, effectively connecting the reservoir, and improving the post-fracturing performance. It is also verified from the experiment that, the stress difference between vertical stress and maximum principal stress is the key factor that affects the fracture geometry during fracturing in DDP technology of horizontal well, high stress difference will create single straight transverse fracture while low stress difference will create straight multiple fractures without interactions.
Therefore, during the SRV fracturing operations in field, the DDP technology of horizontal well can be adequately utilized to optimize the fracture operation so as to create hydraulic fractures whose propagation direction are controlled near well bore and effectively connect with reservoir, which would improve the fracturing results.
A Multistage Theoretical Model To Characterize the Liquid Level During Steam-Assisted-Gravity-Drainage Process
Authors: Yang Yang , Huang Shijun , Liu Yang , Song Qianlan , Wei Shaolei , Xiong Hao 
Published: August 2016

Summary
The technology of steam-assisted gravity drainage (SAGD) with a dual horizontal well pair has been widely adopted in thermal recovery for heavy oil in recent years. However, the close distance between injector and producer makes it easy to cause steam breakthrough, which means lower thermal efficiency as well as higher investment. It is generally acknowledged that there is a vapor-liquid interface between the injector and producer. A suitable liquid level is desired to prevent steam from being produced directly; otherwise, an overly high liquid level would influence oil productivity or even submerge the injector. The existence of a liquid level generates a temperature difference (i.e., subcool) between two wells. Subcool has widely been used to characterize the liquid level in research, yet it is inaccurate. Further studies are still needed on how to maintain a suitable and stable liquid level in SAGD development.
In addition to the heat-loss model and geometric features of the steam chamber (SC), mass conservation, energy conservation, and gravity-drainage theory are used to develop a multistage mathematical model for liquid-level characterization during the SAGD process. The new model is validated against both field data and simulation results. On the basis of this model, an optimal production/injection ratio (PIR) at different times could be calculated to maintain a stable liquid level above the producer, avoiding steam channeling accordingly. Besides, the model can also be used to predict optimal steam-injection rate under constant-pressure injection. Other SAGD dynamic performance predictions, such as SC expansion speed, could also be derived from this model. In addition, recommendations for liquid-level adjustment are offered on the basis of field conditions.