bluuebunny/crossref_metadata_2025_split huggingface dataset:
Generic Correlations for Proppant Pack Conductivity
Authors: Barree R. D. , Miskimins J. L. , Conway M. W. , Duenckel R. 
Published: January 2016

Abstract
With the large number of fracture stages, and size of jobs being pumped in horizontal wells, many companies have elected to use non-standard, or non-commercial natural sands as propping agents. The Stim-Lab Proppant Conductivity Consortium, supported by approximately 50 proppant suppliers, pumping service companies and operators, has developed consistent laboratory conductivity test procedures over the past 30 years that have become de-facto industry standards. One outcome of this long history of proppant testing is a set of correlations that can predict the baseline conductivity, as a function of closure stress and rock (substrate) properties, within the range of uncertainty of laboratory tests. Inputs to the correlations are basic material property measurements such as specific gravity and median particle size of the sieve distribution. The correlations can be used to compare materials of unknown properties to standardized data sets, or to develop useful predictions of how a non-standard material is likely to perform. The correlations are general enough for application to brown sand, white sand, resin-coated materials, and ceramic proppants of various sizes and densities. These correlations have been found to be sufficient for comparing proppants and for estimating their performance in production computations, when adjustments for appropriate damage and cleanup are made to the calculated baseline conductivity values.
Mesh-Free Numerical Simulation of Pressure-Driven Fractures in Brittle Rocks
Authors: Douillet-Grellier T. , Pramanik R. , Pan K. , Albaiz A. , Jones B. D. , Pourpak H. , Williams J. R. 
Published: January 2016

Abstract
A better understanding of failure in heterogeneous rock materials can benefit a wide range of areas, from earthquake engineering to petroleum engineering. Study of such failure is of particular interest in the field of hydraulic fracturing. The prediction of this breakage phenomenon is a big challenge for the scientific community. Traditional continuum modeling techniques have the advantage of using classical nonlinear material models, however they often fail to accurately capture the complexity of the fractured geometry and path of multiple intersecting fractures. In particular, mesh dependence of the fracture path, 3D representation of natural fractures and their intersections, closing of an opened fracture, or shear in fractures, are difficult to accurately capture using these techniques.
The use of the smoothed particle hydrodynamics (SPH) method for simulation of fracture in solids is relatively recent, where mesh free methods like SPH have the potential to overcome the previously mentioned limitations of mesh based methods. Simulation of the initiation and propagation of pressure-driven fractures in brittle rocks is presented in this study. By exploiting techniques commonly used in traditional continuum methods, we have implemented an elasto-plastic SPH model, which is based on the Drucker-Prager yield criterion, and the Grady-Kipp damage model. Results show that SPH is able to correctly predict the evolution of fracture in brittle rocks.
The SPH method has been applied to the solution of crack propagation in a variety of test cases, including a pressurized borehole, 2D line crack, and 3D penny shaped crack. The influence of initial in-situ stresses was also accounted for. Comparison of SPH results for these cases to analytical solutions shows that SPH may be applied to accurately simulate the evolution of fluid-driven fractures in brittle rocks. Such model is a vital tool in correctly predicting fracture propagation in highly heterogeneous formations, for instance, shale formations.
Lessons Learned From Refractured Wells: Using Data to Develop an Engineered Approach to Rejuvenation
Authors: Li Chunlou , Han Jiahang , LaFollette Randy , Kotov Sergey 
Published: January 2016

Abstract
During the life time of a production well, sometimes it is inevitable that remediation methods have to be adopted for different reasons. Hydraulic fracturing is one of the common ways to boost production by either reopening existing fractures or creating new fractures. Considering the large number of unconventional wells that have experienced sharp production declines and the current tight budget for drilling new wells, refracturing will certainly become an important technology worthy of more investigation.
This paper reviews the production and completion data for a number of wells that have been re-stimulated by hydraulic fracturing since 2011. Wells with enough production data were selected to evaluate their production responses by comparing both the cumulative production in a fixed period of time before and after the re-stimulation and by evaluating incremental production increase normalized by amount of proppant used to restimulate the well. Wells involved in the study had been producing from various formations for different periods of time before restimulation. In addition to the analysis above, this study went a step further by attempting to understand the reasons behind inconsistent results after refracturing: high performance of some wells and the failure of the others to meet production expectations.
Two re-completion effectiveness indexes are defined in the paper based on production performance before and after restimulation and on re-completion job size. Overall, the study shows mixed results. Although some formations demonstrated much more favorable response than others, it was also possible for wells producing from the same formation to have extremely different responses to the restimulation. Candidates for restimulation should be evaluated carefully, to include their level of depletion, the petrophysical and geomechanical properties of the rock, and previous well completion and stimulation. These data and measurements are required to engineer an appropriate refracturing or recompletion design. The study also shows very promising results from refracturing some long-producing conventional wells, which indicate opportunities to rejuvenate old wells with hydraulic fracturing.
This study provides an overview of the lessons learned from examination of a limited data set of hydraulic fracturing restimulations done in the past five years.
A Case Study of Completion Effectiveness in the Eagle Ford Shale Using DAS/DTS Observations and Hydraulic Fracture Modeling
Authors: Wheaton B. , Haustveit K. , Deeg W. , Miskimins J. , Barree R. 
Published: January 2016

Abstract
The objective of this study was to evaluate treatment distribution and fracture geometry in a multi-stage, multi-cluster fracture completion performed in a horizontal Eagle Ford well. Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) data were acquired on the subject well. The DAS/DTS-observed fracture treatment distributions were then modeled in a three-dimensional fracture model in an effort to visually represent resultant fracture geometries. This process was used to evaluate the impacts on the resulting treatment distributions that occurred as a result of stress-shadowing between fractures. The ultimate goal was to understand the influence that adjacent fractures within a stage and adjacent stages have on fracture distribution, fracture geometry, and completion effectiveness.
DAS/DTS data suggest a high level of interference between adjacent fractures. Interference between adjacent fractures within a given stage, and from adjacent fracture stages, results in a consistent geometric predominance for fracture growth in the most heel-ward perforation cluster. DAS/DTS results also indicate that an excessive number of perforation clusters, spaced closely together, magnify the negative effects of stress shadowing, and potentially diminish completion effectiveness.
Operationally, the DAS/DTS data showed that the surface pressure response originally attributed to downhole diversion from particulate diverters was in fact not due to diversion. Once a dominate fracture was established in a given stage, it remained dominate throughout the entire stage even though two diverter drops per stage were incorporated into the treatment. Finally, the DAS/DTS data indicated that a significant portion (71%) of the stages experienced intra-stage communication. The large majority of this communication was due to plug leakage.
Acoustics-Based Flow Monitoring During Hydraulic Fracturing
Authors: Stokely Christopher L. 
Published: January 2016

Abstract
A "semi-empirical" acoustics-based flow model is presented based on large scale flow loop testing using water, water thickened with a linear gel, and linear gel slurries containing various amounts of proppant. The flow model predicts volumetric flow rate through individual perforation clusters from calibrated high fidelity accelerometer measurements and knowledge of the fluid type and perforation cluster geometry. This model is applicable to the plug-and-perf completion often used in hydraulic fracturing of unconventional resources. The accelerometer data provides a benchmark for downhole fiber-optic distributed acoustic sensing (DAS).
Custom flow loops were constructed and tested to measure acoustic signals generated by fluid turbulently flowing through simulated downhole perforations using water, water with a linear gel, and slurries containing ceramic proppant. Flow rates, perforation-hole sizes, number of clusters, number of perforations per cluster, fluid viscosity, and proppant slurry density were varied in a controlled way. These parameters were adjusted to represent a downhole stimulation treatment. The data was evaluated using symbolic regression with a 1,000-core compute cluster. Approximately three trillion analytic models were evaluated and scored for prediction accuracy and model simplicity.
The data indicated that all of the fluids became significantly louder above a critical threshold. This threshold was observed to strongly depend on fluid viscosity, while no dependence was observed on the amount of proppant in the slurry. The discharge coefficient showed significant variability, even among repeated experiments when no erosion was present. Very different behaviors for the coefficient of discharge were observed between water and gelled water. The measurements and model provide a benchmark for wellbore monitoring with fiber-optic distributed acoustic measurements during stimulation. Accurate real-time flow allocation estimation allows for an immediate adjustment of treatment strategy using, for example, diverter spheres. Accurate flow allocation could possibly allow changes in stage designs to tune individual flow rates.
Analytic expressions were derived relating the root-mean-square of the acoustic signal to both the perforation pressure loss and the flow speed per perforation as a function of cluster injection rate, viscosity, perforation diameter, and number of perforations. The relative importance of each of these variables was investigated and is quantitatively described. Several models for flow and accuracy were investigated and are discussed.
Identification of Activated Fracture Networks Using Microseismic Spatial Anomalies, b-values, and Magnitude Analyses in Horn River Basin
Authors: Yousefzadeh Abdolnaser , Li Qi , Virues Claudio , Aguilera Roberto 
Published: January 2016

Abstract
We analyzed microseismic spatial and temporal distribution, magnitudes, b-values and treatment data to interpret and explain the observed anomalies in microseismic events recorded during exploitation of Shale Gas reservoirs in the Horn River Basin of Canada.
We estimated the directional diffusivity to define the microseismicity front curve for each stage of hydraulic fracturing. Based on our definition of front curves, we managed to separate most of the microseismic events data that are related to natural fracture activation from hydraulic fracturing events. We analyzed the b-values for microseismic events of each stage before and after separating fracture activation microseismic events from original data and created a map of b-values in the study area. This allowed us to locate activated fractures mostly in the northeastern part of the study well pad. The b- value map agrees with our assumption of activated fracture locations and high ratio of seismic activities.
Suggested fracture locations agree with anomalous events' density, energy distribution and treatment data. We are defining and proposing intermediate b-values for calculation of the stimulated reservoir volume (SRV) in areas with both hydraulically fractured events and events related to natural fracture network activation in those instances where the separation of events based on their origin is not viable.
Recent Advancements in Far-Field Proppant Detection
Authors: Palisch Terry , Al-Tailji Wadhah , Bartel Lew , Cannan Chad , Czapski Matt , Lynch Keith 
Published: January 2016

Abstract
The combination of multistage hydraulic fracture treatments with horizontal drilling technology has been the primary driver to the successful development of resource plays. More than 85% of wells drilled in North America today employ these methods. However, while these technologies have been wildly successful, only recently has the industry begun to address in earnest, the efficiency of current practices. These completion and development optimization efforts require an understanding of which portions of the reservoir have not been adequately contacted/stimulated and are thereby failing to contribute to production, and ultimate hydrocarbon recovery. Understanding where the proppant is located, both near- and far-field, is the starting point for these evaluations, and is the basis for this paper.
Traditional fracture mapping technologies provide indirect estimates of fluid distribution within the fracture network. However, there is little direct correlation between fluid distribution and proppant location, and since most unpropped portions of fractures rapidly collapse, identification of the proppant location better represents the region which contributes to ultimate recovery. Near-wellbore detection of proppant can provide insight into whether all perf clusters (in the case of plug and perf) have received proppant as well as the impacts of proppant overflush. Conversely, accurate determination of far-field proppant placement will affect everything from well and stage spacing, to stage design and refrac candidate selection, and allow significant optimization of diversion techniques. While knowledge of both near- and far-field proppant location is necessary for the industry to overcome the single-digit recovery factors that are now projected in many unconventional plays, far-field proppant detection techniques have been largely absent to date.
This paper briefly reviews the current "state of the industry" regarding near-wellbore proppant detection technology. It then presents a novel far-field proppant detection technique which utilizes electro-magnetic differencing and a specialty detectable proppant. This includes a description of the technology as well as the methodology of the technique. In addition, the paper reviews the design and results from a recent (first-ever) field deployment of this technology in a horizontal Permian Basin well. Visualization of the proppant in the far-field is also shown.
This paper should be beneficial to all engineers and technologists currently interested in evaluating completion efficiencies as well as fracture stimulation effectiveness. Understanding proppant location in both the near- and far-field regions has significant impact on well spacing, stage and perf cluster spacing, and ultimate recovery from stimulated horizontal wells.
The Application and Misapplication of 100-Mesh Sand in Multi-Fractured Horizontal Wells in Low-Permeability Reservoirs
Authors: Al-Tailji W. H. , Shah K. , Davidson B. M. 
Published: January 2016

Abstract
With multi-fractured horizontal wellbores being the primary means to economically access hydrocarbon resources in low- and ultra-low permeability reservoirs, a multitude of completion and stimulation practices can be employed along the lateral section of the wellbore. Completion (staging method, perforations, cluster spacing, etc.) and stimulation (fluid type, proppant type, proppant concentrations, etc.) design parameters are typically adjusted in order to accelerate hydrocarbon recovery and improve ultimate recovery.
One practice that has been gaining popularity as a method of maximizing contact area and accelerating hydrocarbon recoveries in many shale plays is the combination of thin water-based fracturing fluids, small-mesh proppants (mostly 100 mesh sand with some 40/70 mesh sand), and a high intensity of injection points in each fracture stimulation stage. The theory behind this practice is that thinner fluids and smaller mesh proppants can generate more fracture complexity in shale formations, thereby increasing contact area which is of high importance in very low permeability reservoirs, and smaller mesh proppants can be transported at larger distances than larger proppants such as 20/40 and 30/50 mesh.
Historic hydraulic fracturing practice prior to the shale boom had previously utilized small quantities of small mesh proppants such as 100 mesh sand to assist with hydraulic fracture generation and placement. However, many publications often cautioned against the use of significant quantities of these small proppants, due to the adverse impact it would have on fracture conductivity in tight gas reservoirs with permeabilities on the order of 0.01 to 1 millidarcy or greater. However, many shale plays currently in development, such as the Bakken, Eagle Ford, and Haynesville formations, have significantly lower permeabilities than tight gas plays, on the order of 1 to 1,000 nanodarcy (Walls and Sinclair, 2011), potentially elevating 100 mesh sand to "proppant" status.
This paper will critically evaluate the historic and contemporary uses of 100 mesh sand both as a placement aid as well as a proppant in very low permeability reservoirs. The effects of fracture conductivity in naturally-fractured reservoir will be explored in order to determine how much conductivity is sufficient to adequately drain the reservoir, and if using 100 mesh sand as a proppant is appropriate for this purpose. An evaluation of large datasets from publically-derived completion and production data to statistically evaluate the successes of different completion practices and a couple of specific case studies will be presented to illustrate some ways where operators can exceed the statistical mean well performance in their particular area, without needing to resort to using large fluid volume waterfrac treatments with small mesh proppants.
A Coupled Geomechanics and Fluid Flow Modeling Study for Hydraulic Fracture Design and Production Optimization in an Eagle Ford Shale Oil Reservoir
Authors: Curnow Jennifer S. , Tutuncu Azra N. 
Published: January 2016

Abstract
The benefits of hydraulic fracturing horizontal wells in unconventional reservoirs for production enhancement are evident; however, the best methods to truly increase recovery efficiency through these stimulations are still under examination. Analogous to how operators and service companies discovered that Barnett-style slickwater treatments were not successful in all reservoirs, companies are beginning to recognize the importance of engineered stimulations, specifically in regard to geomechanics. Rather than perforating for only production purposes, hydraulic fracturing design has now turned its focus to perforating for reservoir rock stimulation. Enhanced fracture network complexity through induced fractures greatly increases the contact area and reservoir drainage for maximum productivity. However, to accomplish the stimulation of both primary and secondary fracture networks, the coupled behaviors of geomechanics and fluid flow in response to the hydraulic fracturing operations must be considered. In this research study, development of a coupled geomechanics and fluid flow model for the purpose of hydraulic fracture design optimization through the evaluation of different stimulation patterns with primary focus on how the stress and strain distributions within the reservoir that affect porosity and permeability, ultimately influence flow has been discussed in detail. The patterns under consideration include the Zipper, Texas Two-Step, and Modified Zipper designs. Although the Texas Two-Step Pattern requires a special down-hole tool and as such is very difficult operationally to perform, it is being considered in this analysis for conceptual purposes concerning the stress behavior within a single lateral well. Furthermore within these patterns, the well locations and hydraulic fracture properties have been analyzed to determine the optimum design for a shale oil reservoir based on recovery efficiency and generated fracture complexity.
The results of this study indicate that with the staggered fracture placement offered by the Modified Zipper Pattern, a highly conductive secondary complex fracture network is generated allowing for enhanced hydrocarbon recovery. In comparison to the Zipper and Texas Two-Step Patterns, the Modified Zipper Pattern reduces the stress anisotropy within the formation to a much greater extent, aiding in the fracture generation process to increase the flow area. This advantage coupled with its high oil recovery factor and potential for greater drilling density discerns the Modified Zipper as the ideal pattern for the development of an Eagle Ford-type shale oil reservoir.
Interpretation Methodology for Fracture Calibration Test Before-Closure Analysis of Normal and Abnormal Leakoff Mechanisms
Authors: Liu Guoqing , Ehlig-Economides Christine 
Published: January 2016

Abstract
Recent analytical models for abnormal and normal leakoff mechanisms of the pressure falloff behavior in fracture calibration tests (DFITs) provide means to match virtually all of the behavior. The match provides both the parameters related to normal leakoff behavior including closure pressure and the leakoff coefficient as well as abnormal leakoff parameters including tip extension distance and minimum fracture propagation pressure, closure pressures, leakoff coefficients, and leakoff areas for the coupled primary and secondary fracture system. The purpose of this paper is to provide a methodology for identifying these behaviors and quantifying all of the before closure parameters of interest to design of the main fracture treatment.
We use the behaviors seen on the log-log Bourdet and the G-function derivatives to identify a sequence of flow regimes and to estimate starting values for the parameters associated with each leakoff behavior. Simulation result with these starting estimated values are able to catch all identified leakoff features. Then we adjust the parameter starting values to achieve a global smooth match for the falloff data.
Equations developed for quick estimation of the starting values facilitate the model match with data. Several field cases with pressure dependent leakoff (PDL), tip-extension, multiple-closure phenomenon and transverse storage are taken as examples to illustrate the comprehensive modeling capability. The additional parameters quantified by this methodology have their reasonable physics and greatly enhance understanding of the role of tip extension and the induced secondary fracture system in the hydraulic fracture stimulation.