bluuebunny/crossref_metadata_2025_split huggingface dataset:
Performance Evaluation of CO2 Huff-n-puff Processes in Tight Oil Formations
Authors: Song Chengyao , Yang Daoyong 
Published: November 2013

Abstract
Techniques have been developed to experimentally and numerically evaluate performance of CO2 huff-n-puff processes for unlocking resources from tight oil formations. Experimentally, core samples collected from a tight formation with a permeability range of 0.27-0.83 mD are used to conduct a series of coreflooding experiments. The performance of four recovery schemes, i.e., waterflooding, immiscible CO2 huff-n-puff, near-miscible CO2 huff-n-puff, and miscible CO2 huff-n-puff processes, is evaluated with the tight core samples. The waterflooding process leads to a higher oil recovery factor in comparison with the immiscible CO2 huff-n-puff process, while both the near-miscible and miscible CO2 huff-n-puff processes result in higher recovery efficiency compared to that of waterflooding. Theoretically, numerical simulation is performed to match the experimental measurements obtained in the different recovery schemes. There exists a generally good agreement between the experimental measurements and simulated results. The tuned numerical model is then employed to optimize the injection pressure and soaking time during CO2 huff-n-puff processes. It is found that the optimum injection pressure of the CO2 huff-n-puff process can be set around the minimum miscibility pressure (MMP) between crude oil and CO2, while the soaking time can be optimized for maximizing oil recovery.
Effects of Non-Darcy Flow and Penetrating Ratio on Performance of Horizontal Wells with Multiple Fractures
Authors: Zhang Feng , Yang Daoyong Tony 
Published: November 2013

Abstract
A novel slab source function has been formulated and successfully applied to examine effects of non-Darcy flow and penetrating ratio on performance of a horizontal well with multiple fractures in a tight formation. The Barree-Conway model is incorporated in the mathematical model to analyze non-Darcy flow behaviour in the hydraulic fractures, while the pressure response under non-Darcy flow is determined by two dimensionless numbers (i.e., relative minimum permeability (kmr) and non-Darcy number (FND)). More specifically, such a slab source function in the Laplace domain has assigned a geometrical dimension to the fracture. A semi-analytical method is then applied to solve the newly formulated mathematical model by discretizing the fracture into small segments. The newly developed function has been validated with numerical solution obtained from a reservoir simulator. Non-Darcy effect becomes more evident at a smaller relative minimum permeability (kmr&lt;0.05) and a larger non-Darcy number (FND&gt;10). The non-Darcy number is found to be more sensitive than the relative minimum permeability, resulting in a larger pressure drop even at a larger kmr. In addition, the non-Darcy flow is found to impose a significantly impact on the early-stage bilinear/linear flow regime, resulting in an additional pressure drop that is similar to lowering the fracture conductivity. The pressure response can be classified into two categories by a penetrating ratio of 0.5. When the penetrating ratio is decreased, the early bilinear/linear flow regime occurs, followed by an early radial flow regime.
Multi-Porosity, Multi-Permeability Models for Shale Gas Reservoirs
Authors: Haghshenas B. , Clarkson C. R. , Chen S. 
Published: November 2013

Abstract
Numerical simulations are commonly used for studying and forecasting the production from conventional reservoirs. However, limitations of the Darcy’s equation have been noted for shale gas reservoirs due to the complexities associated with nano-scale pores, organic-rich heterogeneous rocks, and extremely-low permeability. In addition, the classical dual porosity/permeability models do not adequately describe the complex physics and dynamics in shales.
This paper utilizes a novel multi-porosity, multi-permeability model in a commercial simulator, incorporating the structural details of shale reservoirs. The generated models account for the storage capacity of shales by mapping three different porosity systems (i.e., organic, inorganic, and natural fractures) with guidance from recent results of microscopic petrophysical studies such as SEM, TEM, and SANS/USANS. Desorption is set to be active only in organic matter. To capture different transport controls in reservoirs with an overwhelming number of fine pore throats, the models include three different permeability conduit networks including organic and inorganic matrix, and natural fractures. Physical properties contributing to flow capacity such as formation wettability are set to be optionally active in corresponding zones. We also consider the diffusion effect in shale matrix grids based on pore size distribution.
Three configurations are used to investigate the connectivity among the three porous systems and the impact of each configuration on ultimate recovery of gas is evaluated. In Configuration 1, an interconnected organic pore system (which feeds the natural fracture system) is largely independent of the inter-granular matrix pore system. However, Configuration 2 assumes that the organic pores feed the inorganic matrix pore system which in turn feeds the fracture system. In Configuration 3, the organic and inorganic pore systems feed the natural fractures in parallel.
The results of this study demonstrate that the selected pore connectivity configuration has a significant impact on shale gas production, underscoring the need to carefully choose the configuration to match pore-scale observations.
Diffusion and Flow Mechanisms of Shale Gas through Matrix Pores and Gas Production Forecasting
Authors: Shi Juntai , Zhang Lei , Li Yuansheng , Yu Wei , He Xiangnan , Liu Ning , Li Xiangfang , Wang Tao 
Published: November 2013

Abstract
The transport mechanism of gas moving through matrix pores is the bottleneck of conquering the difficulties in shale gas development. The matrix pores can be divided into organic and inorganic matrix pores. The transport mechanism of shale gas in organic and inorganic matrix pores is different. However, the present gas transport model only focused on the gas transport in organic matrix pores, in addition, the impact of organic and inorganic mass ratio has been largely neglected by shale gas transport models in the literature, leading to an unclear recognition of shale gas production discipline and large derivation between prediction results by the present models and actual performance of shale gas wells.
In this paper, both the pore size distribution and water distribution in shale matrix pores are investigated. Furthermore, a new diffusion-slippage-flow model in combination with the gas transport mechanism is proposed. Also, the organic content effect is considered and the range of Knudsen number is quantified. Finally, a gas production model based on this gas transport mechanism is derived and employed to reveal the discipline of shale gas production.
The preliminary results illustrate that Knudsen diffusion is not suitable for shale gas reservoirs. This is because Knudsen number is generally less than 10, especially for such shale gas reservoirs with higher initial reservoir pressure. Gas moving through shale matrix pores to fractures is mainly divided into two forms: in organic matrix pores, both slip effect and transition diffusion mechanism are dominant; in inorganic matrix pores, the gas-water two-phase flow controls the gas transport mechanism because of the presence of water in these pores.
The efforts of this work will provide a more accurate technique for forecasting shale gas production, and also give some insights into scientific evidence to the rational development of shale gas reservoirs.
A New Coring Technology to Quantify Hydrocarbon Content and Saturation
Authors: Bjorum Matt 
Published: November 2013

Abstract
The industry is challenged to accurately determine the total hydrocarbon composition and saturations in both conventional and unconventional reservoirs. Several attempts in coring technology advances have been employed in the past with limited success. These attempts include methods to collect expelled pore space fluids and gases for further analysis. The attempts have resulted in technologies that provide limited core in terms of length and diameter, low recovery percentages, poor success ratios and complicated core processing. Pressure coring itself has been viewed as a solution but introduces inherent safety concerns by bringing high-pressure systems to the surface. The combination of poor reliability and safety risks has resulted in infrequent use of the various technologies and methods to analyze pore fluids and gases. A new tool has been developed to overcome the safety concerns, simplify core processing and provide the means for quantitative answers.
Addressing the Water Issues of Tomorrow
Authors: Fedorov Andrey , Cox Angelica 
Published: November 2013

Abstract
The pressing water concerns of tomorrow demand that we target our time and technology in order to improve the fluid mixtures applied in fracturing operations. This challenge is intensified by the concomitant need to make use of produced water. Compelled toward this alternative as we continue to extract our remaining resources from the ground, we must account for the fact that the water we use will invariably decrease the strength of the composite fluids. Therefore, new chemicals are required to ensure stable results when testing these fluids.
Fresh Water scarcity across much of the Permian Basin is particularly critical and necessitates the pumping of produced water, thereby conserving dwindling reserves. The major problem with this approach is the need to balance the fluid recipe with chemical additives. Produced water is highly ionized and as such becomes less stable at heated temperatures, giving a smaller window to adjust chemicals for a precise formula. Hence, an innovative chemical solution is indispensable. A scale inhibitor was found to prevent scale deposition by sequestering the cationic scale-forming ions, and distorting the crystalline lattice structure. What is more, this product exhibits good thermal stability and is also very effective ion stabilizations. Accordingly the novel scale inhibitor was implemented and successfully pumped for more than 200 stages in West Texas.
Modeling Two-Phase Flowback From Multi-Fractured Horizontal Tight Gas Wells Stimulated with Nitrogen Energized Frac Fluid
Authors: Williams-Kovacs J. D. , Clarkson C. R. 
Published: November 2013

Abstract
In recent years it has become common practice to energize water-based fracs placed in tight gas formations with nitrogen to enhance well clean-up and maximize future reservoir performance. Despite the operational benefits, the addition of a second gas phase in the fractures complicates the quantitative analysis of flowback data.
In this work we expand on the model presented by Clarkson and Williams-Kovacs (2013) for the quantitative analysis of two-phase (water+gas) flowback data using analytical history-matching for the estimation of hydraulic fracture properties. Similar to the previous work, our interpretation is that the early flowback data corresponds to wellbore + fracture volume depletion (storage), under the assumption that fracture storage volume is much greater than wellbore storage. In cases where multi-phase matrix flow exists, this flow-regime is followed by multi-phase transient matrix linear flow. From these two flow-regimes bulk permeability (dominated by fracture permeability), effective fracture half-length and other parameters can be estimated.
To account for the addition of a nitrogen gas phase we make the assumption of perfect mixing between the hydrocarbon gas phase and nitrogen gas phase where gas composition varies as a function of time. Using this method, nitrogen mole fraction declines from an elevated value and approaches hydrocarbon gas phase nitrogen content (from standard gas analysis) once all injected nitrogen has been depleted (commonly after the flowback period). Further, all wells analyzed previously using the developed methodology have been single-phase dry shale gas wells, where we have assumed that gas is primarily sourced from the adsorbed state during flowback and fracture depletion is immediately followed by single-phase matrix linear flow. In these cases there has also been no condensate production. In the tight gas case presented in this paper, all gas is sourced from free gas and significant condensate production is seen, therefore further changing the dynamics of the problem. For the analysis, we assume that the well is being flowed above the dew point and therefore there is no free condensate flowing in the reservoir. In this example the well has also been shut-in during the flowback period to install production tubing and therefore we will examine the impact of shut-in on effective hydraulic fracture half-length. With this example we show that shutting in the well during flowback decreases the effective half-length and therefore hinders long-term production potential.
Microscopic Dynamics of Water and Hydrocarbon in Shale-Kerogen Pores of Potentially Mixed-Wettability
Authors: Hu Yinan , Devegowda Deepak , Striolo Alberto , Civan Faruk , Sigal Richard 
Published: November 2013

Abstract
Distribution of alkanes and water in organic pores of shale, referred to as kerogen, is essential information required for estimation of shale-reservoir oil- and gas-in-place, adsorption of hydrocarbon, and fate of frac-water. A practical modeling approach is presented for proper description of the kerogen pore systems with different mixed wettability, surface roughness, tortuous paths, and material disorder. Three kerogen models, namely activated kerogen, kerogen free of active sites, and grapheme-slit pore, with proper surface-oxidized functional groups and high-temperature-and-pressure maturation, are constructed by simulation. Distribution of octane and water in the organic pores of these models is predicted by molecular dynamics simulation. Comparison of results reveals the importance of accurate characterization of kerogen pore systems by particular pore morphology, surface activation, and pore size. The improved kerogen models provided here are shown to determine the placement, distribution, and trapping of frac-water in shale depending on the maturity of the kerogen within organic-rich shales.
Optimization of Cardium Fracture Design, Fracture Spacing, and Wellbore Spacing
Authors: Hards Eric , Taylor Robert , Wang Zuoyang , Fyten Glen , Storozhenko Ken 
Published: November 2013

Abstract
In this study of fracture design applications in the Cardium formation, a workflow designed to address the optimization of fracture size, fracture spacing, and wellbore spacing was applied to the Garrington and Pembina areas. This was performed using specific wells selected after conducting a field-wide analysis of the geological parameters relative to fracture analysis. The result was an increased understanding of how the well performance relates to locations throughout the entire reservoir rather than only a well-by-well analysis basis.
The following is an overview of the workflow used: Analysis of raw log data to calculate input data for the fracture simulator and geologic model.Importation of public domain log data from multiple wells in the study area to create a geologic model.Use of calibrated fracture simulator model to optimize fracture design based on resulting production and associated economics.Use of calculated log parameters in geological modeling software for creation of representative three-dimensional (3D) reservoir grids of reservoir pressure, relative oil permeability, porosity, and water saturation.Importation of reservoir grid properties into a fully compositional numeric reservoir simulator for optimization of fracture and wellbore spacing based on production and associated economics.
Optimization of Duvernay Fracture Design Workflow
Authors: Taylor Robert , Hards Eric , Fyten Glen , Hoch Ottmar , Storozhenko Ken , Stobo Barry , Niebergall Greg 
Published: November 2013

Abstract
In this study of the Kaybob area of the Duvernay formation, a process for fracture design optimization utilizing an expanded work flow was developed. Geologic maps of reservoir properties were created using specific wells selected after conducting a field-wide analysis of the geological parameters relative to fracture analysis. The result was an increased understanding of how the reservoir properties relate to various locations throughout the entire reservoir area studied rather than only a well-by-well analysis basis.
The following is an overview of the workflow used: Importation of public domain log data for multiple wells in study area.Analysis of raw log data to calculate input data for fracture simulator.Use of calculated log parameters in geological modeling software for creation of representative three-dimensional (3D) reservoir grids of reservoir pressure, relative oil permeability, porosity, and water saturation.Selection of representative wells based on accessing both typical and anomalous geological parameters as observed in the model.
In addition, a discussion is provided of the following: 5.Typical fracture design parameter ranges.6.How reservoir maps may be used to populate the grid in a fully compositional numeric reservoir simulator.7.The advantages a compositional reservoir simulator with dual permeability capability provides in characterizing production from a gas-condensate reservoir with complex fracture geometry.8.Fracturing fluid types considerations.
Viking Stimulation: Lessons Learned
Authors: Fyten Glen , Taylor Robert , Mehrabi Pejman , Hards Eric , Hoch Ottmar 
Published: November 2013

Abstract
In this study of the Viking formation, fracturing treatment design was optimized for the Red Water, Plato, and Dodsland areas. Fracturing treatment design for the Viking formation has evolved greatly over the last three years, with stair-step changes in production and associated economics. Some areas that lagged in production have now become the best producing Viking assets. The primary design changes that have led to these improvements in production include the following: Control of clay fines migration, given that clay content in the Viking formation can exceed 50 vol%.Control of clay swelling.Prevention of paraffin precipitation caused by injected fracturing fluids having a temperature below the cloud point of the wax in the crude.Paraffin crystal structure modification to help mitigate production issues associated with any precipitated paraffin.Use of larger proppant sizes, higher proppant concentrations, and more aggressive proppant schedules.Optimization of fracture size and spacing. Because this has been the basis of much of the success in the Viking formation in recent years, a detailed discussion follows.
Integrated Horizontal Well Placement and Hydraulic Fracture Stages Design Optimization in Unconventional Gas Reservoirs
Authors: Ma Xiaodan , Plaksina Tatyana , Gildin Eduardo 
Published: November 2013

Abstract
Horizontal wellbore drilling and hydraulic fracturing technologies have become standard development practices in unconventional gas reservoirs. In order to tap into the full potential of gas shale reservoirs and to produce them economically, it is essential to optimize not only the locations of hydraulic fracture (HF) stages along the given wellbore, but also the wellbore trajectory inside the reservoir. To deal with these two challenges simultaneously and in a seamless fashion, a framework of numerical optimization algorithms can be established. Application of such discrete optimization approach to the above-stated problem allows to enhance production from shale gas reservoirs and to increase the net present value (NPV) of unconventional assets.
The novel hierarchical optimization structure operates in the following way: it places a horizontal wellbore (or wellbores) on the upper level and then distributes HF stages along the fixed well trajectory (or trajectories) on the lower level. Both levels of the framework use gradient-based stochastic strategy, namely, the simultaneous perturbation stochastic approximation (SPSA). Application of this optimization technique permits to depart from the common practice of distributing HF stages evenly. We demonstrate utility of this idea with highly heterogeneous geologic systems that require HF spacing with non-even intensity. To assess efficiency of our approach, we compare the results obtained from SPSA optimization with those from Covariance Matrix Adaptation Evolution Strategy (CMA-ES) that is a stochastic, derivative-free numerical method. The developed framework is tested on stimulation data from synthetic models. Our findings show that the systematic approach to optimization of horizontal wellbore and HF stages placement can improve the NPV of unconventional projects.
Relations between Shear and Compressional Wave Velocities of Geological Formations in Alberta, Canada Based on a Log-Derived Database
Authors: Soltanzadeh Hamidreza 
Published: November 2013

Abstract
For decades, the Alberta Basin has been the subject of several underground operations for mining and conventional and unconventional petroleum production. In addition, it is a potential locus for new underground operations such as geothermal energy production, storage of compressed air, and CO2 storage. Considering the importance of this region, a database of rock properties based on the existing wireline logs in more than 2200 wells in Alberta was developed by the author. This database includes rock properties such as porosity, density, shear and compressional wave velocities and dynamic elastic parameters for the formations intersected by these wells, along with the statistical analyses of these data to evaluate the reliability of the measurements. In this paper, it is shown that the data presented in this database might be utilized to study potential meaningful relationships between shear and compressional wave velocities for different geological formations in Alberta. These relationships can be extremely valuable because shear sonic logs are usually scarce compared to compressional sonic logs. Developing such correlations is common in the field of geophysics and they are widely used to estimate shear wave velocities from measured values of compressional wave velocities for various seismic interpretation applications and geomechanical characterization. Studies presented in this paper show that, for a notable number of geological formations in the Alberta Basin, strong linear correlations exist between shear and compressional wave velocities. As one of the major targets for conventional and unconventional oil recovery, the Viking Formation in Alberta was selected to demonstrate the capabilities of the developed database.