bluuebunny/crossref_metadata_2025_split huggingface dataset:
Barnett Shale: A Resource Play - Locally Random and Regionally Complex
Authors: Hale Brent W. 
Published: February 2011

Abstract
The Barnett Shale play in north central Texas has 14,382 wells which were originally primarily vertical wells. Currently 68% of the wells are horizontal wells. This Barnett Shale has significant changes in performance and quality as produced fluid type changes, as the depth changes, and as the thickness changes. Completion type is known to have a significant impact on well productivity. This review relates peak month rate to reservoir performance. The peak month rate is shown to be impacted in a predictable manner by horizontal wellbore length, by lateral azimuth, by completion depth, by gross pay interval, and by type of fluid being produced, which ranges from dry gas to oil. A P10/P90 ratio is used to measure the relative uncertainty in performance for the various subsets of the Barnett Shale reviewed.
The Effect of Pressure and Temperature on Brine-CO2 Relative Permeability and IFT at Reservoir Conditions
Authors: Liu Ning , Ghorpade Sachin , Harris Lee , Li Liangxiong , Grigg Reid , Lee Robert 
Published: February 2011

Abstract
Geologic sequestration of CO2 in deep saline aquifers has emerged as a technology with the greatest potential to economically sequester large quantities of CO2 from a wide range of industrial operations for greenhouse gas mitigation. The displacement characteristics of CO2 injected into deep saline aquifers are essential because they control both the migration of CO2 and the available pore space in the reservoir at irreducible saturation conditions. This paper presents the steady-state brine-CO2 relative permeability measurements in a sandstone core under CO2 flooding conditions versus pressure and temperature. The results indicate a strong correlation between pressure and the endpoint relative permeability to CO2. As the pressure increased from 1200 psi to 2600 psi, the end point relative permeability to CO2 increased from 32.4% to 46.8%. Temperature was found not to strongly affect the relative permeability, although the end point relative permeability to CO2 decreased with temperature increase from 31.05°C to 38°C. This paper also describes the effects of pressure and temperature on the interfacial tension (IFT) between CO2 and brine. The IFT was observed to decrease as pressure increased and increase as temperature increased. These data will provide useful information to evaluation, analysis, and optimization of CO2 sequestration in deep saline aquifers.
Making the Case for Shale Clay Stabilization
Authors: Carman Paul S. , Lant Kimberly S. 
Published: February 2011

Abstract
Shale gas plays are very active and there is little time available for the practicing engineer to spend on well studies that would describe the effectiveness of particular treatment chemical additives. Each shale play has variations within its own lithotypes and mineralogy suite, not to mention that shales differ from each other individually in key mineralogical and geomechanical measures. These differences in lithologies, mineralogies and geomechanics within the formation itself should be evaluated to develop a minimum standard application for fields. Particular attention should be paid to the clays as they are the most ion-influenced components of the rock. Clay minerals in shales seem to be misunderstood in some cases. Lithologies and clay mineral suites that should require minimal temporary and/or permanent clay protection are being disproportionately treated with expensive clay protection chemicals.
By evaluating the geologic age, formation temperature, mineralogy, Brinell hardness, and Capillary Suction Time test results one can draw some conclusions about clay responses to fluid exposure. Using the results of these analyses in conjunction with previous experience and other independent well data can give reasonable information to make proper fluid selections in shale reservoir completions.
The results presented in this study show very different responses for several different clay protection chemistries when tested on shales of known clay content. Although most of the shales studied here contain very little, if any, swelling clay, certain additives yielded a questionable response. The study presents both test results and laboratory evaluation techniques for selection of clay protection chemical additives and economical considerations in shale reservoir completions.
Characterization and Simulation of ECBM: History Matching of Forecasting CO2 Sequestration in Marshal County, West Virginia.
Authors: Calderon C. E. , Mohaghegh S. D. , Bromhal G. 
Published: February 2011

Abstract
Uncertainties of CO2 injection-sequestration in a CBM is driven by the complex process of gas desorption-controlled mechanism attributed to the natural characteristics of CBM and to the impact of the wells engaged in the reservoir. This work presents the reservoir characterization and simulation process focused on natural gas production and subsequent CO2 injection into an unmineable coal seam in the Marshall Country West Virginia. Two coal seams (Pittsburgh and Upper Freeport) are the subject of this pilot CO2 sequestration project. Methane is produced from both coal seams; however CO2 is injected only in the Upper Freeport which includes four wells. The shallower Pittsburgh coal is used to observe and detect any possible leakage.
The objective is to build a reservoir simulation model that is capable of matching the methane production history and forecast field potential capacity for CO2 injection and sequestration. Although injection has taken place in two reasonably close wells, these wells exhibit different production and injection behavior.
A commercial simulator is used for modeling. Three realizations of the reservoir were built and history matched base on different Langmuir isotherms. The model which leads to a better approximation of the actual injection profile is selected for further analysis. Upper Freeport formation characteristics, its CO2 storage capacity and CO2 distribution in the reservoir are presented in this article. The model can be used to define safety margins for the maximum bottom-hole pressure during injection.
Case Studies in the Application of Pad Design Drilling in the Marcellus Shale
Authors: Poedjono Benny , Zabaldano John , Shevchenko Irina , Jamerson Christopher , Kuntz Robert , Ashbaugh James 
Published: February 2011

Abstract
The current focus of many US land drilling programs is on major unconventional gas shale plays. In this paper, the authors will discuss the challenges posed by and effective solutions developed for wells drilled in one of these plays: the Marcellus Shale. In response to the economic, real-estate, water disposal, and regulatory challenges the Marcellus Shale presents, multiwell pads have become a common approach. Historically, the Marcellus and Appalachian Basin has been developed using inexpensive, vertical wells drilled using the latest technologies and techniques. While some of these options are still viable, changing conditions make proper surveying and anticollision monitoring imperative. The pad design, surveying, preplanning, and execution of successful multiwell pad drilling require extensive collaboration between service providers and operators, a process that will be addressed in this paper.
Performance of the Hydraulically Fractured Horizontal Wells in Low Permeability Formation
Authors: Belyadi A. , Aminian K. , Ameri S. , Boston A. Light-Foot 
Published: February 2011

Abstract
This paper summarizes the results of the modeling studies to determine the production performance of multiply fractured horizontal well completed in tight sand or Shale formations. A commercial reservoir simulator was utilized to model both single and a dual porosity reservoir with multiple layers. The results were utilized to investigate the flow regimes for horizontal wells with one or multi-stages of hydraulic fracturing stimulation. The impact of reservoir and fracture parameters on the flow regimes and the production performance was also investigated.
Impact of Carbon Dioxide Sequestration in Gas/Condensate Reservoirs
Authors: Ramharack R. , Aminian K. , Ameri S. 
Published: February 2011

Abstract
Sequestration of CO2 in depleted gas condensate reservoir has several advantages including enhanced hydrocarbon liquid recovery. Depleted gas condensate reservoirs have 13 times higher capacity than saline aquifers for CO2 storage. The injection of CO2 vaporizes the liquid that has been trapped in gas condensate reservoirs during the depletion process. This results in an increase in the pore space for storage purposes as well as enhanced economics due to additional liquid recovery. The improvements in liquid recovery will depend on purity of CO2. A compositional reservoir simulator was utilized in this study to investigate the impact of reservoir characteristics including permeability, porosity, heterogeneity, pressure, and temperature on CO2 distribution and interaction with hydrocarbons in the gas/condensate reservoirs. The results have utilized to study CO2 storage and improved liquid recovery.
Optimization of a Solid-Acid Precursor for Self-Destructing Filter Cake
Authors: Rostami Ameneh , Nasr-El-Din A. 
Published: February 2011

Abstract
This paper presents a technology for water-based drilling fluid that is weighted with calcium carbonate. This technology has both functions of drilling and completion fluids and can reach to the total depth of MRC wells. It creates a filter cake that prevents fluid leak off and formation damage during the drilling process, but readily cleans up the filter cake over time. This technology is based on the use of an ester, in a solid form, which hydrolyzes and produces an organic acid. The latter will dissolve calcium carbonate particles that are used as a weighting material in water-based drilling fluids. Polylactic acid (PLA) particles were used in the present study to generate lactic acid.
Experiments were conducted to find an optimum particle size of the solid ester and calcium carbonate particles that should be selected as a compromise between those that are optimal for fluid loss control or filter cake formation and those that are optimal for self-destruction at the desired time and rate. Other set of experiments were conducted to determine the temperature and soaking time required for the solid ester to hydrolyze and for the resulting acid to dissolve calcium carbonate particles.
All experiments showed that in a controllable-condition of temperature, acid concentration, and particle size the clean up efficiency exceeded 70%. The optimum particle size was found to be 50 µm calcium carbonate and 150 µm PLA. The optimum temperature was 230°F for running experiments due to high filter cake removal efficiency, low filtrate volume and not having returned mud high viscosity problems. Enough soaking time is needed for PLA to be hydrolyzed and for the acid to remove the filter cake (20 hours).
Analysis of Stress and Pore Pressure in Naturally Fractured Shale Formations: A Finite Element Based Chemo-Thermo-Poroplastic Model
Authors: Roshan Hamid , Rahman Sheik S. 
Published: February 2011

Abstract
Most shale formations are naturally fractured and wellbore instability is a common problem in these formations. In previous wellbore stability analysis shale formations have been treated as a homogeneous rock which underestimates drilling mud parameters. The aim of this paper is to study the transient change in pore pressure and stress state around a wellbore drilled in a chemically active fractured shale formation. For this purpose a finite element model for coupled chemo-thermo-poro-plasticity is developed. A discrete fracture network is generated based on an object-based hybrid neuro-stochastic simulation. Permeability tensors of the fracture network were calculated by using boundary element method which is based on periodic boundary conditions around the grid block and interface boundary conditions around the fracture edges.
In order to solve the plasticity problem a single step backward Euler algorithm including a yield surface correction scheme is used to integrate the plastic stress-strain relation and an initial stress method is employed to solve the non-linearity of the plastic equation. Super convergent patch recovery is used to accurately evaluate the time dependent stress tensor. The solute advection and thermal convection are also considered due to presence of the natural fracture system.
From the results of this study it was revealed that the pore pressure decreases around the wellbore due to the backflow of chemical and thermal osmosis. When drilling through fractured shale formations, however, the decrease in pore pressure is lower than that of intact shale formations which is mainly due to solute advection through the fractures. Also it was found that the effective radial and tangential stresses can reach yield strength of the rock in presence of fracture system thus casusing serious instability problems. It is more likely to form a plastic zone near the wellbore wall in the presence of natural fracture than otherwise. In this study the formation of plastic zone leads to wellbore failure by exfoliation.
Marcellus Net Fracturing Pressure Analysis
Authors: Gottschling John C. 
Published: February 2011

Abstract
An investigation of the net fracturing pressure of multiple stage HZ Marcellus wells was undertaken to give some indication about the Marcellus differences or similarities in 3 areas of the Appalachian basin. References were cited to support the theory that an increase of the net fracturing pressure is an indicator of fracture complexity. Data used for analysis was taken from treatment reports containing surface rate, pressure and sand concentration. The theory behind the analysis of fracturing pressure and the methodology used were presented and supported with literature references. Calculations to determine the components of the Surface Treating Pressure to Net Pressure relation were done making assumptions about the friction pressure and closure pressure. Compilation of the net pressure data from Areas 1, 2, and 3 was presented and discussed with explanations offered for differences seen between these areas as well as the value of net pressure as an analysis tool.
Innovative Simulation Techniques to History Match Horizontal Wells in Shale Gas Reservoirs
Authors: Fazelipour Waleed 
Published: February 2011

Abstract
Shale-gas plays are the current rage in the US energy industry and have started a new era for hydrocarbon production, worldwide. Drilling is expanding; shale-gas wells are not hard to drill, but difficult to complete. The challenge is to release gas from rock as impermeable as concrete. Horizontal drilling and stimulation are enabling technologies that make development of unconventional shale-formations economically viable. Rocks around wellbores must be fractured before wells can produce significantly. Multistage hydraulic-fracturing treatments create complex conductive networks, represented by stimulated reservoir volumes (SRV) which have been effectively contacted and contribute to higher production profiles.
Reservoir characterization/modeling and simulation offer the best techniques to evaluate well performance and estimate the ultimate recovery. History matching or replicating past well behavior is the first, crucial step in simulation and is very difficult; however, as complex as it is, history matching, which calibrates the simulation-model is required to generate convincing forecasts. Main challenges to simulate past/future production include accurately describing the SRV, its geometry and position; fractures intensities and characterizing matrix/fracture attributes.
This paper presents innovative techniques, which previously were impossible to perform, in order to history-match horizontal wellbores by focusing on the mentioned matrix/fracture challenges to sensitize the complex growth and attributes of hydraulic-fractures. The techniques played an important role in understanding the stimulated shale volumes. Key conclusions of achievements include the capability to generate more reliable forecasts/predictions that are highly critical if it is aimed to understand well performance and optimize its productivity.
This research has led to a game-changing methodology for the global E&P industry that enables operators to develop an early understanding of shale-gas wells performance where such detailed knowledge is vital to optimizing exploitation economics and estimation of reserves and resource potential.
Increasing CO2-Storage Efficiency through a CO2-Brine Displacement Approach
Authors: Akinnikawe Oyewande , Chaudhary Anish , Vasquez Oscar , Enih Chijioke , Ehlig-Economides Christine A. 
Published: February 2011

AbstractPrevious studies have shown that bulk CO2 injection in deep saline aquifers supplies insufficient aquifer storage efficiency and causes excessive risk due to aquifer pressurization. To avoid pressurization, we propose to produce the same volume of brine as is injected as CO2 in a CO2-brine displacement. Previous work showed that this increases the storage efficiency from 2% to 8%. However, this transforms the CO2 storage problem into a brine disposal problem. Therefore, we propose to desalinate the native brine and inject the saturated brine into the same aquifer while producing additional brine to maintain voidage balance.A hypothetical case study using documented aquifer properties of the Woodbine aquifer in Texas indicates that the available volume is insufficient volume to store all of the CO2 being generated by power plants in the vicinity for more than 14 years. However, the CO2-brine displacement increases storage efficiency enough to store the CO2 produced for 84 years at the current rate of coal fired electric power generation. Using the reported brine salinity of the Woodbine aquifer, the energy requirements for CO2 transport and injection, brine production and transport, desalination, and saturated brine injection are estimated consistent with assumptions about the location of injection and production wells, the desalination unit or units, and whether desalinated water can be used by the power plant or for other uses.While this approach may enable CO2 storage, the high energy cost ranging from 7.5% to 16% of the total power generation capacity is not insignificant, and comes with significant land use implications for injection and production wells, pipelines, etc. The importance of these results cannot be overstated.
Improved Stress-Anisotropy Characterization Through Casing in a 43-Year-Old Well Using Sonic and Cement/Borehole Imaging Data
Authors: Miersemann U.. , Marchina P.. , Prinet C.. , Loizzo M.. 
Published: February 2011

Abstract
The RSE-1 well operated by Total is located within the Rousse field in the southwest of France. The 43 year old, depleted gas well has undergone extensive research in order to determine its suitability for CO2 storage. The main objective, in terms of containment, is to avoid the injected CO2 migrating back to the atmosphere or reaching potable aquifers, either through the well or the caprock itself. Openhole data from 43 years ago consisted only of 1-arm caliper and compressional sonic data. In order to predict geomechanical effects on the formation from production or CO2 injection, sonic shear data was acquired to compute elastic properties and the direction of maximum horizontal stresses in anisotropic zones. Breakout orientations from multi-arm/finger-calipers, corresponding to the minimum horizontal stress direction are used to improve the geomechanical analysis, especially in areas of strong stress anisotropy. This paper focuses on the acquisition of good quality stress data through casing essential for a geomechanical analysis of the caprock using sonic and cement/borehole imaging tools.
Since azimuthal sonic data is very sensitive to acoustic anisotropy, the available log was processed together with directional survey data to reveal a 75m-thick stress-induced anisotropic zone in the lower part of the caprock. The fast shear azimuth, which is associated with maximum horizontal stress direction as dispersion curves show the sonic anisotropy being the result of a horizontal stress imbalance, suggested a ENE-WSW compression. Evaluation of 3-D cement imaging data showed borehole breakouts along most of the annulus. The cement thickness map is equivalent to a 36-arm caliper through casing and the computed maximum hole diameter correlates well with the 1-arm openhole caliper data acquired 43 years ago. The associated breakout direction within the zone of anisotropy was determined to vary between NNW-SSE and NNE-SSW.
The fast shear azimuth computed during sonic processing is approximately perpendicular to the breakout direction acquired from the borehole images within the 75m-thick anisotropic zone. The overall NNE-SSW compression was confirmed by other well geometry data from the region. These results suggest that both measurements complement each other very well in a cased-hole environment and could be further used for geomechanical modeling.
The Effect of CO2-Saturated Brine on the Conductivity of Wellbore-Cement Fractures
Authors: Yalcinkaya Tevfik , Radonjic Mileva , Hughes Richard G. , Willson Clinton S. , Ham Kyungmin 
Published: February 2011

AbstractThe efficiency of Carbon Capture and Storage projects is directly related to the long term sealing ability of cemented sections in wellbores penetrating CO2 storage reservoirs. The microfractures inside the wellbore cement and/or microannulus are possible pathways for CO2 leakage to the surface and/or fresh water aquifers and jeopardize safe and long-term containment of CO2 in the subsurface.This paper presents an experimental study which investigates the changes inside the cement internal structure when exposed to acidic brine through an artificial fracture. A 30-day long flow through experiment was conducted using a 1 in by 12 in. cement core and CO2 saturated brine, as a permeant, at a flow rate of 2 ml/min in a core flooding apparatus with10 psi and 600 psi of injection and net overburden pressures (Low Pressure-LP experiment). The same experiment was repeated with 1800 psi and 600 psi of injection and net overburden pressures for 10 days in order to account for the effects of pressure on the degradation process of cement (High Pressure-HP experiment). High-resolution X-ray computed tomography was used to image several subvolumes extracted from the flow-through cores. The images were processed and thresholded, followed by calculation of porosity. Total porosity was observed to decrease from 26% to 22% after 30 days of exposure of LP experiment. The HP experiment did not cause any significant change in total porosity possibly due to the short duration of the experiment.