bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simulation of Coupled Hydraulic Fracturing Propagation and Gas Well Performance in Shale Gas Reservoirs
Authors: Wang Xu , Winterfeld Philip , Ma Xu , Ye Dengsheng , Miao Jijun , Wang Yonghong , Wang Cong , Wu Yu-Shu 
Published: June 2014

Abstract
Hydraulic fracturing combined with horizontal drilling has been the technology that makes it possible to economically produce natural gas from unconventional shale gas reservoirs. For best performance of fracturing stimulation, hydraulic fracturing designing parameters, such as different proppants, fracturing liquids, and injection rate and pressure, should be evaluated before the oeration in a particular reservoir system. Traditional evaluation and optimization approaches are usually based on the simulated fracture properties along, such as fracture areas. In our opinion, the better methodologyshould be also related to production data from the stimulated wells afterwards, because the enhanced production is the ultimate goal.
In this paper, we present a general fully-coupled numerical framework to simulate the hydraulic induced fracture propagation and post-fracture gas well performance. This three-dimensional, multi-phase simulator focuses on: (1) fracture width increase and fracture propagation that occurs as slurry is injected into the fracture, (2) erosion caused by fracture fluid and leakoff, (3) proppant subsidence and flowback, and (4) multi-phase fluid flow through various-scaled anisotropic natural and man-made fractures. Mathematical and numerical details on how to fully couple the fracture propagation part and the fluid flow part are discussed. Fracturing and production operation parameters, properties of the formation, and reservoir, fluid, and proppant properties are all taken into account in this model. The well may be horizontal, vertical, or deviated, as well as open-hole or cemented. This simulator is verified based on benchmarks the literature. We show its application by simulating the fracture network (hydraulic and natural fractures) propagation and production data history matching of field production data in China. We conduct a series of real-data modeling studies with different combinations of fracturing parameters and present the methodology to design fracturing operations with feedback of simulated production data. This unified model aids in the optimization of hydraulic fracturing design, operations, and production.
Strategic Delineation of a Tight Oil Play
Authors: Garibaldi Luis , Mathukutty Shibu , Cullick A. S. 
Published: June 2014

Abstract
This paper describes a comprehensive methodology to rank drilling locations in a very large, unconventional tight-oil area based on both surface and subsurface characteristics. A North American case study is presented.
Operators entering new prospect areas with little well control must make decisions on locating limited numbers of exploratory wells. Large prospect areas can be characterized by a variety of different mineral rights, surface-permitting obligations, uncertainties in geologic subsurface characteristics, complexity of topography, a variety of available infrastructures, potential operational issues, and environmental and regulatory challenges. The decision to appraise an acreage position is very complex and has a high level of risk.
One solution to rank and risk candidate drilling locations is a procedure that considers the most critical variables needed for appraisal. The variables are used to generate optimized drilling location scenarios under various uncertainties and constraints using a mathematical probabilistic-optimization procedure and a ‘scorecard’ of surface cultural characteristics.
Probabilistic Forecasting of Horizontal Well Performance in Unconventional Reservoirs Using Publicly-Available Completion Data
Authors: Voneiff G. , Sadeghi S. , Bastian P. , Wolters B. , Jochen J. , Chow B. , Chow K. , Gatens M. 
Published: June 2014

Abstract
In this paper, we present a methodology to predict the performance of horizontal gas wells in unconventional reservoirs using publicly available completion data. Our process combines public domain data with statistical analysis and probabilistic simulation methods to forecast well performance without a detailed reservoir characterization. We have tested our methodology using a 425-well dataset from the unconventional Montney resource play in British Columbia, Canada. We believe this workflow can be applied to other resource plays with similar data.
In our SPE Paper 167154 [1], we determined the sensitivity of production performance to completion parameters using multivariate regression analysis on the same 425-well dataset from the Montney formation. We found that the number of fracture stages and the number of perforation clusters per stage were the most influential predictors of well performance.
In this paper, we discuss how we combined the regression analysis results with probabilistic methods to predict well performance. The model converts the deterministic regression coefficients into probabilistic distributions to account for parameters not considered in the original regression analysis, including reservoir properties. The results of our study show that by using this model, we can match the range of actual well performance outcomes with a 95% confidence.
Considering the importance of shale gas resources to the North American energy supply and the difficulty of characterizing shale gas reservoirs, this methodology offers a distinct advantage by providing a predictive model for well performance without the need for a detailed reservoir characterization. This also could be a beneficial tool to use in scoping studies where high-level, rapid evaluation is required.
CO2-Based Enhanced Oil Recovery from Unconventional Reservoirs: A Case Study of the Bakken Formation
Authors: Liu G. , Sorensen J. A. , Braunberger J. R. , Klenner R. , Ge J. , Gorecki C. D. , Steadman E. N. , Harju J. A. 
Published: June 2014

Abstract
As one of the largest unconventional resources in the world, the Bakken petroleum system has approximately 7.4 billion barrels of recoverable oil as estimated by the U.S. Geological Survey in 2013. These resources lie in a 200,000-square-mile area in North America. However, primary recovery rates are low, typically 3%–5%. The use of carbon dioxide (CO2) as an injection fluid may reduce the hydrocarbon viscosities in the reservoir and allow additional trapped oil to be produced. Another benefit of CO2 injection is to mitigate climate change.
In this study, detailed petrophysical and geological field models focusing on the Middle and Lower Members of the Bakken Formation in the Bailey and Grenora areas of western North Dakota were developed based on field characterization, well log interpretation, and laboratory core analysis by scanning electron microscopy, ultraviolet fluorescence, and standard optical microscopy techniques. A fine-scale model with a pair of horizontal wells was extracted from the initial Bailey model to examine the potential effectiveness of CO2-based oil recovery techniques. Based on characterization results for the simulation investigation, two three-stage hydraulic fractures were incorporated into the model for CO2 injection and oil production wells, respectively, as well as the characterized oil properties such as swelling test and minimum miscibility pressure measurement from selected reservoirs. A total of four cases for simulation were designed to enhance oil recovery by CO2 injection. These cases were run on a single porosity–permeability model to test the basic concepts and later incorporate these results into a dual porosity–permeability model.
The results show that CO2 injection may play a significant role in increasing oil production. Results of this study indicate that production can be enhanced by 43% to 58% compared to cases without CO2 injection. Since a single-porosity, singlepermeability model was used, relative permeability curves that represent the fractures and matrix were both tested to determine the effects of this variable on the outcome. The results indicated that CO2 enhanced oil recovery (EOR) is very sensitive to the relative permeability, and that result varied over 100% between the cases. This case study for CO2 storage in the Bakken Formation provides a basic guideline to address CO2-based EOR. Specifically, the efforts provide modeling input for future investigations that could lead to the design and implementation of a possible pilot-scale field test.
Modification of the Transient Linear Flow Distance of Investigation Calculation for Use in Hydraulic Fracture Property Determination
Authors: Behmanesh H. , Tabatabaie S. H. , Heidari Sureshjani M. , Clarkson C. R. 
Published: June 2014

Abstract
Long-term transient linear flow of hydraulically-fractured vertical and horizontal wells completed in tight/shale gas wells has historically been analyzed using the square-root of time plot. Pseudovariables are typically used for compressible fluids to account for pressure-dependence of fluid properties. Recently, a corrected pseudotime has been introduced for this purpose, where the average pressure in the distance of investigation (DOI) is calculated using an appropriate material balance equation. Therefore, the distance of investigation calculation is critically important in the determination of the linear flow parameter (product of fracture half-length and square-root of permeability, xf√k) as well as in the calculation of contacted fluid-in-place. Until now, the DOI for transient linear flow has been determined empirically, and may not be accurate for all combinations of fluid properties and operating conditions.
In this work, we have developed analytically-based equations for transient linear flow DOI for different operating conditions. Two different approaches were used: the impulse respond concept, and transient/boundary-dominated flow intersection method. The performance of these approaches was tested by analyzing synthetic production data from a series of fine-grid numerical simulations. These simulation runs were set up to obtain accurate estimates of the linear flow parameter for different operating conditions.
The calculated linear flow parameters determined by using our new DOI formulations and the input values in the numerical simulation are in good agreement. Of the two new DOI calculation methods provided, the unit impulse method provides more accurate results.
Linear flow analysis based on the DOI calculations presented in this work is significantly improved over previous formulations.
Using Simplified Local Density/ Peng-Robinson Equation of State to Study the Effects of Confinement in Shale Formations on Phase Behavior
Authors: Ma Yixin , Jamili Ahmad 
Published: June 2014

Abstract
A large amount of hydrocarbon fluids in shale formations are stored within the organic matters where the pore sizes are in the order of nanometer scales. Inside these nanopores, the interactions between the fluid molecules and porous walls play such an important role that can change the phase behavior as well as transport mechanisms of the hydrocarbon fluids. For a shale gas reservoir, the natural gas in the reservoir is usually stored in two forms, free gas and adsorbed gas. The region where free gas is stored has negligible fluid-wall interactions while the region for adsorbed gas is under strong pore wall influence. The current available equations of state cannot capture the phase behavior of the adsorbed gas phase due to the ignorance of the fluid-wall interactions.
This work focuses on modifying the Peng-Robinson equation of state (PR-EOS) using the Simplified Local-Density (SLD) theory. From the modified PR-EOS, the fluid density at any arbitrary position inside the pore can be calculated using the local density approximation. A density profile for any particular hydrocarbon fluids can be obtained by calculating the local densities of the fluids at each discretized interval along the pore. From the density profile one can distinguish the regions of adsorbed phase, transition phase and bulk phase of the fluids. The thickness and averaged fluid densities for each phase can also be obtained from the model. Once the thickness of the absorbed phase is known, it is possible to determine whether adsorption is a single layer or multilayer.
Our preliminary results show that depending on fluid types, either a single layer or multilayer adsorption is presented in those nanometer pores near the pore wall. The pore size range we focused on was from 100 nm to 1 nm. Methane and n-Butane were considered as fluids. When the pore size gets smaller and smaller, the absorbed layers at opposite pore walls can be merged together and result in the absence of the bulk fluid phase in the center areas of the pores. In this case, all the fluids in the pore are under influence of the wall. Our results also indicate that the fluid-wall interactions can have a much larger impacts on light components (methane) rather than heavy components (n-butane). That is, the density of the adsorbed phase of methane is more than two times the free gas density of methane (bulk density), while the n-butane adsorbed density is only slightly higher than its bulk density. The model has also been validated with molecular simulations for accuracy approval.
Modeling the Influence of Pressure Depletion in Fracture Propagation and Quantifying the Impact of Asymmetric Fracture Wings in Ultimate Recovery
Authors: Mata D. , Cherian B. , Gonzales V. , Higgins-Borchardt S. , Han H. 
Published: June 2014

Abstract
In 2014, more than 30,000 wells will be drilled in different unconventional plays across the US. As drilling density increases, chances are these new wells will be located in the vicinity of a producing unit. When the new well is being completed, the pressure depletion around the producing well affects the principal stress regime, creating low stress compartments that attract the majority of the slurry injected. This condition has been studied in the past for vertical wells and results confirmed that the asymmetric propagation of the fracture wings leaves vast sections of the reservoir un-stimulated affecting well performance. This study uses a dataset from the Williston basin to evaluate the impact of this condition in modern horizontal completions. Pore pressure maps from single well models are used to build a multi-well geomechanical model, a numerical fracture simulator is used to understand fracture geometry and quantify wing asymmetry and a multi-well production model is created to estimate the impact in ultimate recovery. Finally, this paper concludes with a series of recommendations regarding completion design and production strategy that can reduce the severity of fracture asymmetry and increase EUR.
Probabilistic Estimate of Global Coalbed Methane Recoverable Resources
Authors: Dong Zhenzhen , Holditch Stephen A. , Ayers Walter B. , Lee W. John 
Published: June 2014

Abstract
Because today's oil and gas industry recognizes the value of coalbed methane (CBM) resources, CBM exploration and development activities, once uniquely North American, are now under way on a global scale. Many publications address technically recoverable resources (TRR) of CBM in small geographic areas. However, there is little publicly information about the magnitude of TRR for coalbed methane on a global scale. Uncertainty exists in geologic and engineering data and, consequently, in the results of calculations made with these data. The uncertainty of the problem begs for a probabilistic solution.
Our objective was to determine distribution of CBM TRR worldwide. To achieve this goal, we developed a computer program, called Unconventional Gas Resource Assessment System (UGRAS). The program integrates a Monte Carlo technique with an analytical reservoir simulator. The combination provides an excellent means to predict production profiles for a wide variety of reservoir characteristics and producing conditions. Using UGRAS, we established the probabilistic distribution of original gas-in-place (OGIP), TRR and recovery factor (RF) for selected coals in U.S. and derived a representative recovery factor distribution for CBM reservoirs. CBM recovery factors follow a log-logistic distribution, with a P50 of 38%. We extended the distribution of gas recovery factors gained from our analyses of U.S. coals to estimate global CBM TRR. Global technically recoverable CBM is estimated to be 500 (P90) to 3,000 (P10) Tcf, with a P50 value of 1,600 Tcf.
UGRAS is a robust tool that may be used to evaluate and rank coalbed methane gas resources worldwide. Results of this work verify the existence of significant technically recoverable coalbed methane resources worldwide and can guide industry to better target its exploitation efforts in coals, worldwide.
A Novel Completion Method for Sequenced Fracturing in the Eagle Ford Shale
Authors: Kraemer C. , Lecerf B. , Torres J. , Gomez H. , Usoltsev D. , Rutledge J. , Donovan D. , Philips C. 
Published: June 2014

Abstract
In multistage fracturing of unconventional formations such as the Eagle Ford shale, wells are traditionally stimulated by fracturing several perforation clusters simultaneously. While the technique is operationally efficient, there is evidence from production logs, microseismic monitoring, and other measurements that several clusters produce below expectations or do not produce at all. This condition is to a degree because stages penetrate zones with stress heterogeneities, and consequently, fractures propagate unevenly from all of the clusters.
Evenly fracturing all clusters in heterogeneous zones is challenging in long horizontal sections penetrating heterogeneous reservoirs. Furthermore, efforts to improve well economics result in reducing completion time by extending the length of each stage even further to decrease the number of interventions required for completing the well. To address this challenge, a new sequenced fracturing technique has been developed based on a novel composite fluid comprising of degradable fibers and multi-sized particles that diverts the remaining stimulation fluids to understimulated regions of the wellbore. The composite fluid is delivered downhole at high-concentration, to create temporary plugs in clusters already stimulated thereby creating diversion with a minor amount of material. The solids degrade completely after the fracturing treatment has been completed, leaving no residual formation or fracture conductivity damage. The channel fracturing technique (Gillard et al. 2010) was chosen as the preferred fracturing method for use in tandem with the composite fluid. This technique has been reported to increase effective fracture length while reducing risk of screenout with respect to other conventional methods.
The new composite fluid was used in a campaign where its effects were monitored with microseismic instruments. A case study presents field experiments where wells from the same pad are fractured in a similar fashion with and without diversion. In one application, with similar water and fluid volumes, the well treated with this technique produced more than 15% per stage than its conventionally treated offset well. The signature of the composite fluid, clearly visible on all measurement techniques, has proven consistent across stages of various lengths and wells having different characteristics.
How Reliable Is Production Data Analysis?
Authors: Anderson D. M. , Thompson J. M. 
Published: June 2014

Abstract
It is well known that the analysis of production data (Rate Transient Analysis) involves the solution of an inverse problem. We measure the response of the system, typically production rates and flowing pressures, and then proceed to search for the appropriate reservoir model description that created it. Typically, this is accomplished through the minimization of an objective function consisting of the difference between the simulated response and the actual response. In practice, production analysis is complicated by two important problems: 1) The mathematical models (analytical or numerical) that we use to describe well production may not provide an adequate and full description of the true well-completion-reservoir system. This is especially true if the system is complex and asymmetric, as is the case in unconventional plays. And 2) The production response almost certainly contains significant errors and/or disturbances caused by outside influences. This makes the process of error minimization difficult and non-unique. As a result, it is impossible to know whether or not we are obtaining reliable results from production analysis, as there are simply too many unknown variables in the system we are trying to model.
The objective of this work is to determine the best procedure for solving the inverse problem of production analysis in a consistent and reliable way, and to quantify just how reliable the results are. We wish to do this in an environment free of complications, such as those identified previously in 1) and 2). To accomplish this, simulated production responses from known models are analyzed, but the full set of model input parameters are withheld; only basic input parameters are provided, such as what would typically be available in practice. Since the "answer key" is available, this study allows us to objectively evaluate and optimize production data analysis best practices.
Computational Prediction of Solvent and Surfactant Properties Using the Conductor-Like Screening Model (COSMO) For Chemical Enhanced Oil Recovery Research
Authors: Bennetzen Martin V. , Andersen Jin U. , Mogensen Kristian 
Published: June 2014

Abstract
Enhanced oil recovery (EOR) methods often involve water-based flooding where surfactants, co-solvents and/or other chemicals are present in the aqueous phase being injected into the oil-bearing rock. The chemical flood may facilitate oil recovery by altering physical and chemical properties of the water-oil-chemical(s) system present in the porous medium such as interfacial tension, phase partitioning and liquid-liquid mixing. Prior to testing the efficiency of a chemical flood, initial laboratory experiments are routinely conducted to investigate the phase behaviour and thermodynamic properties (e.g. brine compatibility) of the present fluid system. However, such laboratory screening experiments consume significant time that scales linearly with the number of chemicals and combinations hereof to be characterized.
The Conductor-Like Screening MOdel (COSMO) has been developed over the last decades with the aim of predicting thermodynamics of complex mixtures based on single-molecule charge distributions. The charge distributions are calculated based on the molecular structure using density functional theory (DFT) to estimate molecular energies of quantum mechanical origin. Despite the fact that applications of COSMO have predominantly been used for biomedical, environmental, and chemical engineering research, applications of the theory show great promise for EOR research.
In this paper we demonstrate the versatility of applying the COSMO-theory to predict thermodynamic properties of water-oil systems, such as liquid-liquid mixing, phase partitioning, solubility, interfacial tension and ternary phase diagrams. Moreover, we describe an in-house developed database of 3D charge density landscapes of 100+ surfactants and present an in-depth analysis hereof with respect to single molecule properties as well as water-oil-surfactant system properties. Strikingly, we show that COSMO-theory in combination with a specific application of probability theory and the method of moments (MoM) can be used to estimate system properties such as interfacial tension, critical micelle concentration and phase partition coefficients.
We demonstrate that COSMO-theory provides a powerful framework for large-scale, fast and inexpensive initial computational prediction of single-molecule and continuum system properties. In particular we foresee that future applications of COSMO-theory to accurately estimate model input-parameters for chemical EOR simulators, such as UTCHEM, would be highly beneficial to the EOR research community.