bluuebunny/crossref_metadata_2025_split huggingface dataset:
Geological Potential for Sequestration of CO2 as Gas Hydrate in the Alberta Portion of the Western Canada Sedimentary Basin
Authors: Cote M. M. , Wright J. F. 
Published: February 2011

Abstract
The Alberta portion of the WCSB has been investigated with respect to the geological potential for the sequestration of CO2 as a metastable, solid crystalline gas hydrate. Based on a coarse-resolution (1 km2) geothermal analysis and industry borehole data, the areas north of Cold Lake and south/southwest of Fort McMurray have been identified as having pressure-temperature (P-T) conditions favourable to the formation and maintenance of CO2 hydrate at target injection intervals of 300-400 m depth. It is estimated that the gross amount of CO2 that could be sequestered as gas hydrate in Alberta is approximately 46 Gt.
The presence of a substantial overburden provides an effective buffer against the propagation of anticipated warmer surface temperatures (due to progressive climate warming) into the ground at depth. Numerical modeling predicts a time frame of between 1000-2000 years for a 3°C change in surface air temperature to effect an increase in ground temperature of 1°C at 300 m depth.
This preliminary regional assessment offers a potential new strategy for the geological sequestration of CO2 in Canada, however considerable additional work is required to advance this idea from concept to practice. Specifically, the acquisition of more reliable ground temperature data and local geothermal gradients, pore water geochemistry, porosity and permeability would be a pre-requisite to the implementation of a small-scale demonstration project in a readily accessible region of northeastern Alberta.
A Novel Chemical Treatment to Enhance Well Productivity in Volatile Oil Reservoirs
Authors: Torres D. E. , Sharma M. M. , Pope G. A. , Ahmadi M. , McCulley C. A. , Linnemeyer H. C. , Gilani S. F. 
Published: February 2011

Abstract
In volatile oil reservoirs, the presence of two fluid phases (gas and oil) near the wellbore is a common problem that affects well deliverability. As the pressure falls below the bubble point the presence of two immiscible phases reduces the oil relative permeability and leads to lower oil production rates. In this paper, we show that the application of fluorinated chemicals can mitigate this impairment associated with gas blocking of volatile oils. We show through laboratory experiments that the treatment not only removes the water from the treated zone, but also modifies the wettability of the rock surface to neutral wet, minimizes capillary trapping and enhances the mobility of oil and gas. The chemical treatment is effective in the presence of connate or flowing water over a range of temperatures. This technique may be used as a curative or preventive treatment in volatile oil reservoirs, potentially increasing oil production rates and recoverable reserves. High-pressure high-temperature (HPHT) coreflood tests were conducted that show that the treatment improved the relative permeability, by a factor of about 1.3 to 2.6 at a GOR of 6000 to 7000 scf/STB in sandstone and limestone cores at low capillary numbers (Nc). Wettability alteration was measured using contact angle and imbibition tests. These tests together with x-ray photoelectron spectroscopy (XPS) analysis were used to screen the selected surfactants. Since this durable enhancement is achieved by treating a small area around the wellbore, it may be applicable in a wide variety of wells.
Mass Diffusion Into Bitumen: A Sub-Pore Scale Modeling Approach
Authors: Taheri S. , Kantzas A. , Abedi J. 
Published: February 2011

Abstract
The increased interest in the production of heavy oil and bitumen has amplified attention paid to solvent-based methods for heavy oil recovery, such as vapor extraction (VAPEX) or miscible flooding.
The diffusion of solvent into oil plays a major role for all the solvent-based recovery methods. Since the diffusion process is governed by the diffusion coefficient, the accurate prediction of mass transfer of the solvent in heavy oil and bitumen is extremely important. The concentration dependency of the diffusion coefficient differs from sample to sample and is determined experimentally in the laboratory. What is measured in the lab as the diffusion coefficient is influenced by different porous medium properties during the solvent injection. Therefore, an effective diffusion coefficient is defined for porous media, which has a dependency on the medium properties.
The main goal of this paper is the prediction of an accurate value for the effective diffusion coefficient from experimentally measured values of diffusion considering the properties of the porous medium.
The medium in this paper can be a micro model pattern, thin section, tomographic image or microscopic picture. The picture is analyzed by an image processing program to distinguish the pore and grain sections. After gridding the pore regions of the picture, virtual porous medium properties are extracted by applying the Navier-Stoke and continuity equations as the governing equations. The diffusion equation is applied to the medium to find the concentration profile of the solvent in the porous medium, and the effective diffusion coefficient of the system is computed from the concentration profile. An extensive investigation of the effects of medium properties on the diffusion coefficient will lead to the capability of predicting the effective diffusion coefficient for other media with different patterns and properties.
Analytical Solutions for Mixed CO2-water Injection in Geothermal Reservoirs
Authors: Wahanik Helmut , Eftekhari Ali Akbar , Bruining J. , Marchesin Dan , Wolf Karl Heinz 
Published: February 2011

Abstract
Concern about global warming is generating interest in reducing the emissions of greenhouse gases such as CO2. One way of reducing CO2 emissions is to replace conventional (hydrocarbon fuels) energy sources for heating buildings by geothermal energy. Recently it was suggested to co-inject carbon dioxide with cold water for simultaneous geothermal energy production and subsurface carbon dioxide storage. Our data correspond to a geothermal energy project proposed for heating the buildings of the Technical University of Delft. After injection of the water/CO2 mixture a complex interaction between physical transport and the phase redistribution of the components, i.e., water and CO2, occurs. This redistribution is usually described in terms of local thermodynamic equilibrium. There are no published complete analytical solutions for 1-D problems involving complex thermodynamics that include CO2 and heat effects in the flow. We take into account the heat effects related to the cold fluid injection and related to the dissolution of CO2.
We give an analytical solution for the model equations for the temperature and for the flow of CO2, vapor and water after combined injection of a cold carbon dioxide-water mixture in a geothermal reservoir. Due to high pressures and temperatures, CO2 is in a supercritical state and it is necessary to determine the phase equilibrium for non-ideal gases. We used a modification of the Peng-Robinson equation of state and an activity coefficient based mixing rule for the thermodynamic calculations. A volume shift procedure is applied to obtain an accurate liquid density. The structure of the solution depends strongly on the injection and initial reservoir conditions. The application of the work is in the effective recovery of heat from geothermal reservoirs with simultaneous CO2 storage. Moreover, the theory provides fundamental understanding of non-isothermal flow of mixtures undergoing mass transfer between phases. The advantage of the analytical model is that it provides a simple methodology to screen injection conditions for optimal geothermal recovery or maximal storage of carbon dioxide.
Analysis of Exploration Expenditure for Unconventional Gas: How Investing in Exploration Would Improve Reserves and Production
Authors: Virine L. 
Published: February 2011

Abstract
In recent years petroleum producers have become engaged in significant expenditure towards exploration and development in conventional and unconventional gas plays in United States and in Canada. How efficient would be such expenditure for different producers and different basins?
This paper describes the methodology of the analysis of correlation between exploration expenditure and producer's reserves and production. A model has been developed to quantitatively assess exploration expenditure, production, and reserves of various producers for different conventional and unconventional gas plays. The model incorporates producer's booked reserves and production from the public sources as well as reserves and production forecasts. The model is used to analyze different types of exploration expenditure, including land, drilling and seismic, incurred at different time periods prior to the booking of reserves and production. The proposed methodology has been used to compare the exploration expenditure of various producers operating in the United States. The analysis has demonstrated an overall positive correlation between exploration expenditure and reserves and production; however the correlation showed significant variance between various producers operating in different plays. The proposed methodology and the result of the study can be applied to the analysis of efficiency of the exploration investment, which in turn can help improve corporate planning process.
Design Considerations to Test Sealing Capacity of Saline Aquifers
Authors: Zeidouni M. , Pooladi-Darvish M. 
Published: February 2011

Abstract
The geological storage of carbon dioxide (CO2) provides the possibility of maintaining access to fossil energy, while reducing emissions of CO2 to the atmosphere. One of the essential concerns in geologic storage is the risk of CO2 leakage from the storage formations. The leakage occurs through possible pathways in the seal. Characterization of the CO2 leakage pathways from the storage formations into overlying formations is required. The aquifer cap-rock may be characterized before CO2 storage. This will allow for the determination of proper storage aquifers and locations for the injection wells. In a companion paper, a flow and pressure test has been suggested for characterization of leakage pathways in aquifer cap-rock. Water is injected in the target aquifer, and the pressure is observed in an overlying aquifer. The pressure data are analyzed to characterize the leakage pathways in the cap-rock. In this work, design considerations to maximize the capability of leakage characterization are presented.
A leakage pathway can be characterized by the leak transmissibility and location parameters. A successful test should be able to provide sufficient information to evaluate the leakage parameters. In this work, different strategies are evaluated in order to achieve a successful test. The strategies include increasing the sampling frequency, use of pulsing, increasing the number of monitoring/injection wells and utilization of prior information. Prior information on the leak is provided through analysis of the pressure derivative curve.
Estimation of the leakage parameters is actually an inverse problem that is generally ill-conditioned and very sensitive to noise. The information provided by different strategies is evaluated, based on their effects on well-posing the inverse problem. The effects are studied based on information and correlation matrices, as well as the confidence interval.
Effect of Oil Viscosity, Permeability and Injection Rate on Performance of Waterflooding, CO2 Flooding and WAG Process in Recovery of Heavy Oils
Authors: Torabi F. , Jamaloei B. Y. , Zarivnyy O. , Paquin B. A. , Rumpel N. J. , Wilton R. R. 
Published: February 2011

Abstract
The economic life of a typical heavy oil reservoir under primary or secondary recovery schemes can be short lived or near their limit, with recovery factors in the range of 5–15%. Waterflooding alone has been successfully practiced in the Lloydminster area of the Western Canada for decades. Heavy oils located in thick reservoirs have benefited from the application of thermal, gravity drainage processes; however, thin, unconsolidated heavy oil reservoirs are unsuitable due to lack of drainage height. These reservoirs may benefit from immiscible CO2 or CO2-WAG processes.
This paper examines the effect of oil viscosity, permeability and injection rate on the performance of heavy oil waterflooding, immiscible CO2 flooding and immiscible CO2 water-alternating-gas (WAG) processes. A series of 11 sand packfloods were conducted using 440 and 1,500 mPa·s heavy oils and sand packs with absolute permeabilities of 12 and 40 μm2. Water injection volumes for the waterfloods were 1.5 pore volumes (PVs) at rates of 0.112, 1.124, and 5.62 cc/min. For the CO2 flooding process, 4.5 PVs of gas were injected at a rate of 1 cc/min. For the WAG process, the water:CO2 slug ratios were varied from 1:1, 1:2 and 2:1. A 99.9% purity CO2 gas stream was used for all gas floods. All experiments were performed at a controlled temperature of 25°C and 345 kPa.
Among the 11 sand packfloods conducted, the waterfloods consistently yielded the highest recovery factor for both heavy oils and sand packs, with 48-52% OOIP recovered and most of this recovery occurring during 0.112 cc/min. During CO2 flooding of the 440 mPa·s oil, 48.5% OOIP was produced from the 40 μm2 sand pack. From the same fluid-sand system, a 1:1 slug ratio, CO2-WAG process produced 42% OOIP. For the 1,500 mPa·s heavy oil, 1:2 and 2:1 slug ratios of CO2-WAG both produced ~25% OOIP from the 40 μm2 sand pack and a 1:1 slug ratio produced 35% OOIP from the 12 μm2 sand pack. All WAG injection schemes were compared on a 2.5 PV injected basis. These results suggest that the role of displaced fluid viscosity plays the most prominent role in the recovery of heavy oil.
Ultra-Lightweight Proppants in Shale Gas Fracturing
Authors: Gaurav A. , Dao E.K. , Mohanty K.K. 
Published: February 2011

Abstract
The goal of the present work is to evaluate ultra light weight proppants for fracturing of shale gas reservoirs. Three ultra light weight proppants (ULW-1, ULW-2, and ULW-3) have been studied. The mechanical properties of the proppant packs as well as single proppants have been measured. Conductivity of proppant packs has been determined as a function of proppant concentration, confining stress, and temperature. The crush strengths of all the three proppant packs are higher than typical stresses encountered in the Barnett shale. ULW-1 and ULW-2 are highly deformable and do not produce many fines. ULW-3 has a higher Young's modulus and produces fines. The proppant conductivity decreases with increasing confining stress, but it is not a strong function of the proppant concentration for bothe ULW-1 and ULW-2. A partial monolayer of ULW-2 (0.07 lbm/ft2) provides slightly less or as much conductivity as a thick proppant pack with a concentration of 0.7 lbm/ft2. At 6000 psi stress, the conductivity of ULW-1 seems to decrease a little as the proppant concentration increases and then increases. Application of light weight proppants in stimulation treatments in shale reservoirs can lead to long propped fractures, which can improve the productivity of fractured shale reservoirs.
Evaluating the Production Potential of Hydraulically Fractured Horizontal Completions Using Engineering and Data-Driven Modeling Techniques
Authors: Shelley R.F. , Dzubin B. , Shah K. 
Published: February 2011

Abstract
Drilling horizontally and hydraulic fracturing is becoming the well type of choice in ultra-low permeability sands and shale. However, as the complexity of these wells increases, the challenge of evaluating the effectiveness of these completions proves more problematic. The reason: There are challenges related to the uncertainties around hydraulic fracturing, wellbore placement/orientation, formation evaluation, and fracture mapping a 1-to-2-mile-long horizontal wellbore. Other difficult-to-model issues such as frac spacing, convergence, compartmentalization methodology, perforation methodology, zone isolation, drillout/cleanup, and other operational procedures have a significant effect on the production result and gas recovery. This paper describes a methodology consisting of both engineering and data-driven modeling techniques, which are intended to quantify these effects and the effects of other decisions made related to the construction and completion of hydraulically fractured horizontal wells. A discussion about the merits and drawbacks of the two approaches and why performance of both produces new understanding about completion and frac effectiveness follows. Several Bakken case histories are presented to demonstrate usefulness and document value.
Microseismic Mapping of Laboratory-Induced Hydraulic Fractures in Anisotropic Reservoirs
Authors: Chitrala Y. , Moreno C. , Sondergeld C. H. , Rai C. S. 
Published: February 2011

Abstract
Microseismic monitoring of hydraulic fractures typically produce spatial and temporal plots of hypocenters without any estimates of uncertainty leading the engineer to believe the hypocenter locations are absolute. The hypocenter location problem becomes more complex in anisotropic shale reservoirs. Hypocenter locations are determined from the arrival times of P-wave and/ S-waves and a known velocity model. The difference in the velocity structure and the complex fracture network make accurate fracture mapping difficult. The fracture properties are a function of the magnitudes and directions of applied stresses. We report on a series of laboratory nanoseismic studies during controlled hydraulic fracturing of limestone, sandstone and a strongly foliated metamorphic rock, pyrophyllite. In addition to hypocenter locations, we report on focal mechanisms, frequency analysis, source dimensions and spectral characteristics of the emitted event. Hydraulic fracturing is dominated by shear failure; fracture alignment is controlled as predicted by applied stresses in isotropic materials. However, hydraulic fracture propagation in anisotropic materials is altered by the magnitude of anisotropy but is predictable when the anisotropic elastic constants are known.
A Green Alternative for Determination of Frac Height and Proppant Distribution
Authors: Mulkern Mark , Masnyk Bob , Kramer Hermann , Sites Joseph 
Published: February 2011

Abstract
As regulations and public awareness regarding hydraulic fracture operations continue to change, it is important to continue to look for options to reduce risk to both the environment and personnel. Current fracture diagnostic technology uses radioactive materials which can pose a high risk from a health, safety and environment (HSE) perspective. Exposures to people and the environment to radioactive chemicals; and the potential to cause pollution or long term detrimental health problems, are great. A technology has been developed to allow fracture diagnostics to be performed with zero-risk to the environment and personnel.
The technology involves using Boron Carbide particles added to the frac slurry as a tag material. Boron Carbide is a ceramic compound that has a 75% abundance of Boron by weight and the same density as Silica. It is a compound that is chemically inert under typical conditions of hydraulic fracturing.
Because Boron is a neutron absorber, post-frac detection is accomplished by using a neutron device utilizing an Am-241Be sealed source which detects descending neutron and gamma count rates, as well as, capture gamma validation by energy discrimination across tagged intervals. This method will give both near and not near well bore dimension and provides Neutron-Neutron (N-N) and Neutron-Gamma (N-G) differences against initial base line reference data.
Field data and analysis of results are presented for a vertical coalbed methane well in Virginia as well as a horizontal Berea Sanstone well in Kentucky.
Flow Rate Behavior and Imbibition in Shale
Authors: Wang Dongmei , Butler Raymond , Liu Hong , Ahmed Salowah 
Published: February 2011

Abstract
Shale is an important source of oil and gas in North America. Most shale reservoirs have a low porosity and ultra low permeability with naturally fractures. Shale formations have long been considered important source rocks, capable of producing oil at economic rates when completed by hydraulically fractured horizontal wells. As part of our investigations of a new chemical imbibition idea (using surfactant or brine formulations) to stimulate oil recovery from shale, accurate determination of shale permeability and porosity is needed to assess potential recovery rates. Our interest in this study is in oil flow through shale, especially relevant to the Bakken formation oil.
Our first studies in this area focused on an outcrop shale, specifically the Odanah member of Pierre Shale in North Dakota. As part of an effort to assess the potential for imbibition to recovery oil from shale, we studied porosity, permeability to oil, permeability to water, and imbibition for the Pierre shale. We found that porosities for Pierre shale cores were relatively high—from 25% to 35%. Bakken oil imbibed into dry Pierre shale cores (up to 5-mm in thickness) to the same extent as could be achieved by forced injection of oil (i.e., achieving the same oil saturations for both processes). Permeability to a clean mineral oil (Soltrol 130) was higher than for Bakken oil—apparently because of deposition of wax/asphaltenes/particulates on the core faces when injecting Bakken oil. Permeability to oil for Pierre shale cores (with no water present) ranged from 3x10-5 to 5x10-4 md when injecting Bakken oil and from 2x10-4 to 1.3x10-3 md when injecting Soltrol 130. For both oils in cores with thicknesses ranging from 0.65 to 5 mm, permeabilities were basically independent of flow rate, in agreement with expectations from the Darcy equation. A saline brine imbibed effectively into oil-saturated Pierre cores, yielding recovery values up to 41% OOIP. During exposure to brine, our results indicated an increase in permeability—presumably by mineral dissolution during forced brine injection and by cracking (possibly due to clay swelling) during spontaneous imbibition. This result is encouraging for the application of imbibition to enhance oil recovery from shale. Prior to these studies, we feared that exposure to brine might reduce shale permeability because of clay swelling.
The laboratory results will help during a current study of surfactant and brine imbibition in Bakken shale.