bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Fully Coupled Multiphase Multicomponent Flow and Geomechanics Model for Enhanced Coalbed-Methane Recovery and CO2 Storage
Authors: Wei Zhijie , Zhang Dongxiao 
Published: April 2013

Summary
Enhanced coalbed-methane (ECBM) recovery by the injection of CO2 and/or N2 is an attractive method for recovering additional natural gas resources, while at the same time sequestering CO2 in the subsurface. For the naturally fractured coalbed-methane (CBM) reservoirs, the coupled fluid-flow and geomechanics effects involving both the effective-stress effect and the matrix shrinkage/swelling, are crucial to simulate the permeability change and; thus gas migration during primary or enhanced CBM recovery. In this work, a fully coupled multiphase multicomponent flow and geomechanics model is developed. The coupling effects are modeled by introducing a set of elaborate geomechanical equations, which can provide more fundamental understanding about the solid deformation and give a more accurate permeability/porosity prediction over the existing analytical models. In addition, the fluid-flow model in our study is fully compositional; considering both multicomponent gas dissolution and water volatility. To obtain accurate gas solubility in the aqueous phase, the Peng-Robinson equation of state (EOS) is modified according to the suggestions of Søreide and Whitson (1992). An extended Langmuir isotherm is used to describe the adsorption/desorption behavior of the multicomponent gas to/from the coal surface.
With a fully implicit finite-difference method, we develop: a 3D, multiphase, multicomponent, dual-porosity CBM/ECBM research code that is fully compositional and has fully coupled fluid flow and geomechanics. It has been partially validated and verified by comparison against other simulators such as GEM, Eclipse, and Coalgas. We then perform a series of simulations/investigations with our research code. First, history matching of Alberta flue-gas-injection micropilot data is performed to test the permeability model. The commonly used uniaxial-strain and constant-overburden-stress assumptions for analytical permeability models are then assessed. Finally, the coupling effects of fluid flow and geomechanics are investigated, and the impact of different mixed CO2/N2 injection scenarios is explored for both methane (CH4) production and CO2 sequestration.
Application of Reservoir-Centric Stimulation Design Tool in Completion Optimization for Eagle Ford Shale
Authors: Kanneganti K. T. , Oussoltsev D. , Grant D. , Ball N. , Offenberger R. M. 
Published: April 2013

Abstract
Completion design for unconventional shale plays in North America is a topic of high current interest. Although the practice of stimulating shale horizontal wells with large slickwater treatments is slowly changing to the use of Hybrid/Crosslink treatments in certain plays, little has changed with the method of completion design itself. Most laterals are completed using a ‘cookie cutter’ approach in which the number of stages and clusters, cluster spacing and other design parameters are based on statistics, past experience, rules of thumb or client shared knowledge, and are not tuned to the specific conditions in a particular well.
This paper presents a case study from the Eagle Ford Shale and describes a step-by-step workflow to simulate hydraulic fractures using a state of the art, reservoir-centric stimulation design tool (RCSD). The presented approach incorporated petrophysical data acquired in a vertical pilot hole with horizon interpretation, a discrete fracture network (DFN) model conditioned by seismic interpretation, image log data from a horizontal well, and completion data into a hydraulic fracture simulator. Simulation of fracture geometry was performed stage-by-stage in the RCSD tool using the recently developed unconventional fracture model (UFM), which is optimized specifically for complex fracture networks. The modeled fracture network was calibrated to microseismic events via fluid rheology and fluid loss variables while also accounting for a stress shadowing effect.
The output of the simulator includes a list of parameters such as fracture surface area, fracture propped surface area, and hydraulic fracture network geometry that can be used for the determination of estimated stimulated volume (ESV) as well as inputs into reservoir simulation for production history matching and forecasting. Also, this application of the RCSD tool in the Eagle Ford Shale provides an ability to test most aspects of the completion design by modeling stimulated volume change with respect to pumping schedule and completion parameters.
How Much Can You Extend the Reach of Coiled Tubing in Horizontal Wells Using Pressure-Hammer/Pulsing Tools
Authors: Guo Boyun , Li Jun , Feng Yin 
Published: April 2013

Abstract
Coiled Tubing (CT) has been widely used in well drilling, completion and work over operations. A characteristic challenge with CT is its inability to reach far in horizontal wells. As the lateral length extends, CT's stability to reach working depth decreases due to friction. Excessive friction causes work string lock-up and motor stall. The pulse pressure generated by hammer/pulsing tools has been proven to help change the CT from static to dynamic friction, resulting in extended-reach capability. It is not clear as how much can the hammer/pulsing tools extend the reach of CT in horizontal wells. This creates a gap between the design and application of the tools. This paper fills the gap.
An analytical model was developed in this project to predict the extended reach of CT in horizontal wells. The model considers pressure-induced piston effect, ballooning effect, and buckling effect on the elongation/shortening of the work string. The time-dependent elongation/shortening can change the work string from static to dynamic condition. Due to the fact that the dynamic friction coefficient is less than the static friction coefficient, it is expected that the released friction force would be translated to the extended reach of the CT string. Model analyses show that the elongation/shortening of CT string for a given CT/well/hammer condition is negligible in a certain range of depth, meaning that the given hammer/pulsing tool will not work in this range of depth. This theory is found consistent with data from wells with hammer/pulsing tool installations. This paper provides well drilling and completion engineers a handy technique to select hammer/pulsing tools for their applications in CT operations.
Drainage Against Gravity: Factors Impacting the Load Recovery in Fractures
Authors: Parmar Jaskaran S. , Dehghanpour Hassan , Kuru Ergun 
Published: April 2013

Abstract
Horizontal wells in the tight reservoirs are stimulated using multistage hydraulic fracturing. The fracturing fluid used in this operation is generally water based. A very low percentage of fracturing water is recovered during the flowback operation. Non-recovered water can block the gas flow and damage the reservoir. The water recovery in propped fractures is controlled by microscopic displacement efficiency and fracture areal sweep efficiency. Microscopic displacement efficiency is mainly controlled by capillarity, and has been studied extensively. Areal sweep efficiency during water drainage in propped fractures is controlled by mobility ratio and displacement direction relative to gravity direction, which needs further investigation.
This paper reports various fracture drainage experiments to understand the effect of gravity, surface properties, and viscosity on fracture sweep efficiency and total load recovery. A visual cell was built to model a propped fracture. Glass beads were packed in the space between two glass plates, and the pack was then saturated with the fracturing fluid. This simulates the initial conditions before opening the well for flowback. For simulating the water drainage against gravity, representing a fracture element below the horizontal well, the gas was injected at the bottom of the cell. Four sets of experiments were conducted to study the effect of injection pressure, interfacial tension, wettability, and fluid rheology on sweep efficiency and load recovery. Glass beads were chemically treated to alter their wettability from hydrophilic to hydrophobic. For each test, normalized fluid recovery was obtained by measuring the mass of produced fluid and using the material balance. The cell was kept in a dark room in front of a light box, and pictures were taken at regular time intervals. These images were later used to compare the drainage patterns. The results suggest that water recovery in an upward displacement very low mainly due to poor sweep efficiency. Increasing the injection pressure does not improve water recovery. Reducing surface tension and using treated hydrophobic sand improves the sweep efficiency and in turn the load recovery.
Modeling of Supercritical Fluid Adsorption on Organic-Rich Shales and Coal
Authors: Clarkson C. R. , Haghshenas B. 
Published: April 2013

Abstract
An important component of hydrocarbon storage in coalbed methane and organic-rich shales is sorption within organic matter. Natural gas sorption isotherms measured in these systems may include a combination of adsorption onto the internal surface area and absorption within the organic matter. The focus of the current work is the modeling of adsorbed fluids.
There have been multiple models proposed for modeling single- and multi-component adsorption on coal and shale, of which the most popular remain the simple Langmuir model and its extension to multi-components. In this work, we first review various approaches used for modeling adsorption on coal and organic-rich shale, including newer approaches such as the 2D Equation-of-State (2D-EOS) method. We discuss extensions of simple approaches, such as the Langmuir and Dubinin- Radushkevich (D-R) equations, to modeling supercritical, single-component fluids. The applications of these models to coal and shale datasets will be demonstrated. An important finding of the current work is that the simple Langmuir/D-R models are mostly adequate for modeling supercritical, single-component adsorption on coals and shales, provided that certain adjustments are made to account for supercritical fluid properties, such as adsorbed-phase density. The 2D-EOS model was found to be superior for modeling high-pressure CO2 excess adsorption on shale, however.
Several multi-component adsorption models are used to predict binary component adsorption (CH4-CO2) on shale and to investigate CO2 selectivity over CH4 for two shale systems as a function of pressure and gas composition. This information is useful for designing enhanced recovery operations in dry shale. A dataset containing heavy hydrocarbon adsorption on shale was also examined to determine the importance of adsorption in "liquid-rich" systems. The change in selectivity of heavier hydrocarbons with addition of CO2 was examined using binary gas adsorption modeling; it was found that CO2 could reduce heavy hydrocarbon component selectivity which provides a possible mechanism for enhanced recovery.
Modeling Vertical Multifractured Wells in Vaca Muerta Shale Oil Play, Argentina
Authors: Monti Luciano J. , Suarez Mariano I. , Thompson Anthony R. , Vega Leonardo 
Published: April 2013

Abstract
Oil production from the unconventional Vaca Muerta play is increasing as a result of a rigorous appraisal and exploitation strategy. Multiple wells have already demonstrated the potential of the Neuquén Basin, however optimization is still ongoing to determine the best practice for completing wells.
A stand out difference of the Vaca Muerta play is its thickness (100 m to 450 m), as such a development strategy based solely on vertical wells is being considered in addition to the horizontal well strategy more commonly applied in other shale plays.
The thickness of the Vaca Muerta formation creates new challenges and opportunities due to the stratigraphic variation in petrophysical and mechanical properties which can affect fracture effectiveness and well productivity. Completion design, geology and production performance need to be linked. Specifically, the geology of the Vaca Muerta formation, as is the case in most reservoirs, varies significantly more in the vertical direction in comparison to the horizontal direction. With optimum solutions not necessarily being intuitive, numerical simulation is critical as it enables a large number of variables to be analyzed and their individual impact understood and quantified.
The objective of this paper is to present the four different approaches that have been used to build numerical models to represent the vertical wells in Vaca Muerta.
These are: A single layer model with a planar fracture placed in a zone of improved permeability to represent the Stimulated Rock Volume (SRV) which is then surrounded by undisturbed matrix.A multilayer model with multiple planar fractures placed in an undisturbed matrix.A multilayer model with multiple planar fractures (one per stage), the SRV surrounding the fractures and the undisturbed matrix behind it.A multilayer model, where the SRV is modeled within a dual porosity model.
This work shows how these models were constructed, the measurements that were honored and the estimation and justification of values assumed for unknown parameters. The impact of the different methodologies on the time taken and quality of the history match obtained and subsequent forecasts is also discussed.
YPF has collected an extensive data set including PLTs, microseismic surveys, downhole pressure gauges, and pressure build ups, which has been used to constrain the numerical models. Building and history matching these models has been challenging but enables conclusions to be made about rock, fluid and completion interaction that cannot be obtained otherwise. The simpler models, have in some cases, enabled rapid estimates to be made for EUR which have subsequently been supported by the results from the more detailed modeling approaches.
Effect of Shear Rate on the Activity of Enzymes Used in Hydraulic Fracture Cleanup of Tight Unconventional Reservoirs
Authors: Barati Reza , Ouyang Chris 
Published: April 2013

Abstract
Injection of high or low concentration polymeric solutions in order to propagate a fracture and distribute proppants to keep the fracture open is a common practice in hydraulic fracturing of unconventional tight formations. In addition to the propagation of a main fracture, low concentration polymeric fluids open the already existing network and extend the network connected to the main fracture. Considering the very low permeability of the formation and small width of the fractures in the network, and also considering the importance of fracture cleanup and effective length during the production phase, using low concentrations of breakers is recommended to degrade the more concentrated polymeric fluid and increase the conductivity of the fracture.
Enzymes have been used successfully as breakers for fracturing fluids for many years. Enzymes are polymer specific, environmentally benign, easy to handle, miscible in the fluid, equipment friendly and not consumed because they act as catalysts. These properties make enzymes much more attractive than the oxidizer class of breakers. Enzymes are known to be temperature and pH sensitive and their properties under the targeted temperature, pH and shear rate must be measured.
In this study, the effect of high shear rates, applied during the injection of hydraulic fracturing fluids, on the activity of enzymes was studied. Enzyme activity was measured using a viscometric assay. Reversibility of changes in the activity of enzyme was studied by first shearing the polymer-enzyme mixture at high shear rates; then reducing the shear rate after a certain time, and finally comparing the activity with the activity of the same concentration of enzyme with lower shear rate history. Moreover, the effect of changes in the shear rate on the shear sensitivity of enzymes was investigated for a wide range of shear rate and polymer concentration.
Understanding the shear sensitivity of enzymes will improve the fracturing fluid injection condition. This will assure the activity of the enzymes after reaching the fracture and the more efficient cleanup of the fracture(s).
Forecasting Well Performance in a Discontinuous Tight Oil Reservoir Using Artificial Neural Networks
Authors: Bansal Y. , Ertekin T. , Karpyn Z. , Ayala L. , Nejad A. , Suleen Fnu , Balogun O. , Liebmann D. , Sun Q. 
Published: April 2013

Abstract
Improving the economics of the production and development of an unconventional reservoir system is a key to meeting increased demand for hydrocarbons in the near future. In general, reservoir development is vastly assisted by using hard-computing models to evaluate the potential of the formation. These models have been used to identify infill drilling locations and forecast production. However, preparing the simulation models for discontinuous tight oil reservoir systems poses a challenge with hard-computing protocols. This paper discusses a methodology developed to depict the production characteristics of a reservoir via the geological properties of the reservoir. The methodology discussed in the paper is time efficient and is proven to generate effective results.
The methodology discussed in the paper utilizes Artificial Neural Networks (ANN) to map the existing complex relationships between seismic data, well logs, completion parameters and production characteristics. ANNs developed in this work are used to forecast oil, water and gas cumulative production for a two year period. The results obtained are also extended to identify potential infill drilling locations. This work enables the practicing engineer and the geoscientist to analyze an entire reservoir in a time efficient manner.
The workflow is demonstrated on a discontinuous tight oil reservoir located in West Texas. The results discussed in the paper show the robust nature of the methodology. The workflow also helps in improving the resolution of the production surfaces which help in identifying productive, yet undrilled, locations in the reservoir. The production surface for the entire field is forecasted within a one minute time frame (~6600 locations). The method developed will help in avoiding low producing wells prior to drilling, and thus, is expected to help in the economic development of complex tight oil reservoirs.
Beyond Linear Analysis in an Unconventional Oil Reservoir
Authors: Peng Ye , Lifu Chu , Iwan Harmawan , Mark Williams 
Published: April 2013

Abstract
Current linear analysis is based upon the tri-linear model, which assumes a continuous and homogeneous porous medium within each flow region. This recent study, however, reveals that a discontinuous stimulated reservoir volume (SRV) is extensively associated with horizontal wells with fewer frac stages and/or within areas with high-stress anisotropic ratio. To characterize such isolated SRV scenarios, three parameters—fracture half-length, SRV permeability, and the half-width for each isolated SRV—must be inferred from the analysis, which creates a difficult challenge for the existing rate transient analysis (RTA) procedure. This paper presents a new RTA methodology and associated diagnostic plots to infer all three parameters simultaneously using the information beyond the linear flow period. The analyzed results illuminate optimizing the number of frac stages and well spacing.
The newly developed "beyond linear analysis" procedure has been used successfully to analyze more than 100 Bakken wells with various completion types and frac stages. The resultant RTA-derived statistics have been used for the construction of type curves, well history matching, completion assessments, and optimal well spacing.
Almost all the wells with fewer than 20 frac stages show an isolated SRV around each hydraulic fracture; these are good candidates for refrac. Although a high number of frac stages (e.g. &gt;30 stages) will boost the initial production rate (IPR) and more quickly deplete the SRV, it is our conclusion that the estimated ultimate recovery (EUR) is not significantly enhanced beyond a certain number of frac stages. Moreover, both the incremental SRV and flow capacity associated with each additional stage steadily decrease. This suggests that there is an optimum number of frac stages and wells that maximize both the IPR and the EUR of a drilling spacing unit (DSU).
This new RTA methodology allows, for the first time, detailed SRV and fracture description. The precise RTA model not only greatly relaxes the dependency on compaction and PVT properties suppression during the history match, but also clarifies the "stress shadow effect" from adjacent stages and the relationship between the shear fracture displacement/dilation and inter- stage intervals.
Seismic-Based Heterogeneous Earth Model Improves Mapping Reservoir Quality and Completion Quality in Tight Shales
Authors: Suarez-Rivera R. , Dahl G. V. , Borgos H. G. , Paddock D. R. , Handwerger Schlumberger D. 
Published: April 2013

Abstract
This paper demonstrates the value of seismic data to define heterogeneous earth models for tight shales, improve reservoir quality and completion quality mapping, and to guide decisions of wellbore placement and completion design. The process includes quantitative classification of rock units at log-scale, definition of sample locations for laboratory testing, characterization of all dominant rock classes, and development of core-to-log transforms for all measured properties. The process also includes classification of the seismic data, based on the log-derived model, and development of class by class rock physics models for populating measured properties across the seismic volume. The quantitative relationship between core, log and seismic measurements allows population of the seismic model with complex properties. The result is a Heterogeneous Earth Model with rock classes representing the large-scale heterogeneity of the geologic system, and rock properties that characterize the behavior of each of the classes. By defining the variability of groups of properties representing reservoir quality and completion quality across the seismic cube, one can map changes in them and use this information to define reservoir potential, landing points and completion design. A case study from the Haynesville field is presented.
Conventional seismic analysis methods generally lack the ability to account for the heterogeneous nature of tight shale systems. Consequently they can provide predictions of properties that while representing the mean behavior of the system, may have a significant error at a local level. Additionally, conventional analysis is often based on rock physics models that are limited to acoustic stimuli, and fail to relate many of the complex factors that influence unconventional reservoir and well performance.
The method presented here is applicable to heterogeneous, organic-rich, oil and gas mudstone systems. Results lead to a well characterized Heterogeneous Earth Model, significantly improved mapping of variability in reservoir quality and completion quality, and better assessment of the opportunities and problems for exploration and long-term field development. This has already resulted in successful application by an operator in the Haynesville/Bossier formations in NW Louisiana, USA.