bluuebunny/crossref_metadata_2025_split huggingface dataset:
Possibility of Bioelectrochemical Conversion of Carbon Dioxide into Methane in Depleted Oil Fields
Authors: Maeda H.. , Ikarashi M.. , Fukushima N.. , Kobayashi H.. , Sato K.. 
Published: November 2015

Abstract
As potential CO2 geological storage site in CCS, utilization of depleted oil/gas reservoirs and aquifer has been proposed. The long-term aim of this research is to establish a biotechnological system to microbiologically convert geologically stored CO2 into methane.
Our recent study revealed that methanogen and exoelectrogen inhabiting subsurface reservoir are involved in the recently discovered bioelectrochemical reaction called electromethanogenesis (CO2 + 8H++ 8e− → CH4 + 2H2O). In this reaction, methanogen receives proton from reservoir brine and electron from a solid electrode. As a result, reduces CO2 into methane. Required electricity for the methane conversion can be obtained from renewable energy sources such as wind or photovoltaic power generations. Single-chambered electromethanogenic reactors were used for an evaluation. The reactors were inoculated with reservoir brine anaerobically collected from Yabase oil field in Japan. Each reactor headspace was filled with mixed gases of N2/CO2 (80/20). The reactors were incubated at 55°C with an applied voltage of 0.75 V. The reactors produced methane at a rate of 386mmol/day m−2. The current-methane conversion efficiency was almost 100%. On the other hand, no significant methane production was detected in the reactors without applied voltage.
To investigate the mechanism of electromethanogenic reaction, the phylogenetic diversity of the microbes on the cathode was analyzed.
The result shows, as for archaea, methanogen closely related to Methanothermobacter thermoautotrophicus dominated. On the other hand, as for bacteria, Thermincola ferriacetica, one of the exoelectrogen, was the dominant spices.
Our experimental research demonstrated for the first time that the possibility of bioelectrochemical methane conversion of carbon dioxide by utilizing microbes indigenous to depleted oil fields.
The final goal of this research is to establish the "Subsurface Methane Regeneration" system, combining CCS and biotechnology, in which geologically-stored CO2 is converted into CH4 by bio-electrochemical process called "Electromethanogenesis".
Finite Element Simulation of a Hydraulic Fracture Interacting with a Natural Fracture
Authors: Chen Zuorong , Jeffrey Robert G. , Zhang Xi , Kear James 
Published: November 2015

Abstract
In this paper, the problem of a hydraulic fracture interacting with a pre-existing natural fracture has been investigated by using a cohesive zone finite element model. The model fully couples fluid flow, fracture propagation and elastic deformation, taking into account the friction between the contacting fracture surfaces and the interaction between the hydraulic fracture and the natural fracture. The effect of the field conditions, such as in-situ stresses, and rock and fracture mechanical and geometrical properties, intersection angle and the treatment parameters (fracturing fluid viscosity and injection rate) on the hydraulic fracture propagation behavior has been analyzed. The finite element modeling results provide detailed quantitative information on the development of various types of hydraulic fracture – natural fracture interaction, fracture geometry evolution and injection pressure history, and allow us to gain an in-depth understanding of the relative roles of various parameters. The value of a parameter calculated as the product of fracturing fluid viscosity and injection rate can be used as an indicator to gauge if crossing or diverting behavior is more likely. In addition, using a finite element approach allows the analysis to be extended to include the effects of fluid leakoff and poroelastic effect, and to study hydraulic fracture height growth through a system of nonhomogeneous layers and their bedding planes.
Simulation of Time-Varying Properties of Organic-Shale Nanopores During Gas Production
Authors: Wang Jing , Luo Haishan , Liu Huiqing , Jiao Yuwei , Wang Chaofeng , Sepehrnoori Kamy 
Published: November 2015

AbstractThe apparent permeability and effective porosity of organic-shale nanopores are time-varying under the impacts of gas adsorption/desorption, non-Darcy flow, and stress dependence during gas production. However, the porosity occupied by adsorbed gas is usually disregarded by industry standard. Moreover, the gas flow regimes are not completely described in most models or simulators; the stress dependence of matrix does not draw adequate attention in current studies. Therefore, an appropriate modeling is urgently needed to simulate the dynamics and performances during gas production. In this paper, we developed a coupled model to characterize time-variation properties by considering contributions of gas adsorption, non-Darcy flow, and stress dependence. After that, we verified the model and demonstrated model application, which lead to new insights into the evaluation of rock properties and gas quantities during gas production. We found that taking account of the volume occupied by adsorbed gas can effectively avoid the significant error of OGIP (Original Gas in Place) in the classical models. Meanwhile, the apparent permeability is significantly reduced by adsorbed gas, but the time-varying apparent permeability affected by gas flow regimes increases during gas production. We also studied the complex behaviors of the effects of stress dependence and various flow regimes. This new model provides with a more clear understanding of the time-varying features of organic-shale nanopores during gas production, which is more advantageous than classical models. As the production process can be more accurately forecasted, more insights can be achieved by the improved simulations.
A New Method for the Estimation of Lost Gas During the Measurement of the Gas Content of Coal
Authors: Lu Meng , Pan Zhejun , Connell Luke D. , Lu Ye 
Published: November 2015

Abstract
In this text the authors present a study on the approach of estimating the lost gas during the retrieval process of coal sample within wellbore. A new method is proposed to improve the accuracy of prediction as the traditional methods often give inaccurate predictions. To this end, the major sources of errors with those traditional methods are first analysed. Then the pertinent modifications are made in this proposed method to have these errors minimised. With the present method the following improvements are made. (1) Physically, the transport equation used here for gas flow in the core includes both advection and diffusion effects; in contrast, the traditional methods are fundamentally based on a linear diffusion equation. (2) Geometrically, the present method considers the the actual shape of the core sample (say, a cylinder), while the routine counterparts have to simplify the geometry of the core to be a one-dimensional spherical object. (3) Numerically, the present method employs the actual retrieval history to specify the boundary conditions of the core sample, and uses a neural network technique to best fit the measurements with the numerical solutions obtained. In contrast, the routine counterparts need to assume a constant or a linearly declining boundary condition such that an analytical solution (in a form of a series) can be obtained. When the relevant sorption isothermal curve for the coal is known, the proposed model contains three parameters to be determined, which are related to the effective permeability, the effective diffusion coefficient, and the initial gas content, respectively. These parameters are determined through best-match of the experimental data by the neural network simulations. An application example is presented in this study and it shows that the proposed method can significantly improve the accuracy of prediction for the lost gas volume or the initial gas content than its traditional counterparts.
Creep: A Neglected Phenomenon in Coal Permeability Evolution and Coalbed Methane Production
Authors: Danesh N. N. , Chen Z.. , Aminossadati S. M. , Kizil M.. , Pan Z.. , Connell L. D. 
Published: November 2015

Abstract
During gas production, coalbed experiences compaction over time when effective stress increases as a result of pressure depletion triggered by escaping gas from micropores through desorption and diffusion. It is deemed that time-dependent compaction deformation (compaction creep) and deterioration of coal structure lead to a decrease in coal permeability. Alteration of compaction rate and permeability of coalbed depends on factors such as coal properties, pore pressure, time, and temperature. Thus far, little studies have been conducted to investigate the impact of compaction creep, viscoelastic, and viscoplastic behavior of coal on permeability. Creep may have such significant impact on coal permeability that its negligence may result in overestimation of Coalbed Methane (CBM) production. Appreciation of creep phenomenon, coal properties such as viscoelasticity and viscoplasticity, and their impact on the interaction of coal permeability and gas production borehole enables optimisation of CBM production. In this study, we aim to examin permeability models and highlight the significance of creep as a factor influencing the evolution of coal permeability and CBM production.
Pore Network Investigation in Marcellus Shale Rock Matrix
Authors: Goral Jan , Miskovic Ilija , Gelb Jeff , Kasahara Jack 
Published: November 2015

AbstractThe ever-growing energy demand and recent discoveries of vast unconventional oil and gas reservoirs have brought significant attention to shale oil and gas resources as potential game-changers for the petroleum industry and energy markets worldwide. The complex structural features and mineralogy of shale has broad implications on the development of the unconventional oil and gas industry. Although shale reservoirs are large in scale and offer the potential for long-lived production, extremely low matrix porosity and permeability, as well as complex heterogeneity, pose major challenges in obtaining economically viable oil or gas. A lack of predictive understanding of microstructure-based heterogeneity in shale limits the effectiveness of currently used production technologies. Hence, addressing the challenges of shale oil and gas production requires an in-depth understanding of microstructural features that control the oil and gas storage, release, and transport mechanisms.Because anisotropy of shale exists across multiple scales, determining changes in pore distribution has proven to be difficult. Recent studies have indicated that shale pores significantly vary in number, size (from nano- to micropores), and classification (organic and nonorganic pores). Thus far, the role of pore network and, more specifically, what pores contribute the most to the gas and/or oil storage or to the production process, is not well understood and remains largely unknown. Hence, it is vital to determine how well different pores are connected and how they create possible flow pathways for hydrocarbon migration.Here we present a comprehensive digital rock physics (DRP) framework for pore network investigation in a Marcellus Shale rock matrix using nano X-ray microscopy (nano-XRM) and focused ion beam scanning electron microscopy (FIB-SEM) data. Pore networks within both organic and nonorganic matter are reconstructed from FIB-SEM images of the shale specimen. Through this process, porosity, pore size distribution, pore connectivity, and mineralogy – organic-matter-hosted and nonorganic-matter-hosted pores – of the sample are obtained. The impact of obtained parameters on fluid flow in shale is analyzed.
Reservoir Characteristics for Unconventional Shale Play of Huai Hin Lat Formation in Northeastern Thailand
Authors: Chumkratoke C.. , Dunn-Norman S.. 
Published: November 2015

Abstract
Recent trends in petroleum production have focused on developing unconventional gas reservoirs such as tight gas and shale gas. Considering worldwide shale gas resource potential, the largest resources exist in the former USSR and in North America, while for China, Central and Southeast Asia the estimated shale gas resource is 1115 TCF. Despite the smaller resource projection, this unconventional resource is of great interest for future development. In Thailand, the primary energy source is oil and natural gas, with 77% of electricity generated from natural gas (EIA, 2011). Yet current production is not enough to support the growing energy demand in Thailand, and there is increasing emphasis in exploring potential unconventional resources to meet this demand.
A study has been conducted to improve reservoir knowledge of the Huai Hin Lat formation, believed to be an important source rock for the gas fields in northeast Thailand. The Huai Hin Lat formation consists of fluvio-lacustrine sediments of Late Triassic. The formation is exposed along the margin of the Khorat Plateau. Petroleum exploration in Khorat Plateau has been ongoing since 1962 and two gas fields have been discovered and commercially produced in the Khorat Plateau since 1988.
Seven shale samples were taken from the Huai Hin Lat formation. All samples are the organic rich fine-grained rocks. The MicroCT technique was measured for porosity parameter. The average porosity of the samples was approximately 4.9%, and a pore size distribution was found. In addition, geochemical analysis was performed to determine total organic content (TOC) of the shale samples. The average TOC was found to be approximately 4.9%.
Permeability was measured for the seven samples using transient pressure pulse decay. The permeability range of the samples was found to be 90 (D to 280 (D and the average permeability of sample was approximately 180 (D. Permeability varies significantly because the shale is somewhat heterogeneous. Natural fractures present in the formation may also affect the value of effective permeability.
This paper provides details regarding the analysis of the Huai Hin Lat samples and the shale's rock properties as they relate to other commercial unconventional gas resources. The work is significant because there are few existing petrophysical evaluations of this formation. Results from this study will identify and highlight key reservoir parameters necessary to further assess the commercial potential of the Huai Hin Lat shale as a shale gas reservoir.
Depth Distribution of Gas Rates From Temperature and Pressure Profiles in Unconventional Gas Wells
Authors: You Z.. , Bedrikovetsky P.. 
Published: November 2015

AbstractEstimating flow rate distribution along the depth in the wellbore is very important for reservoir and production management purposes, because it provides information for distinction of the production rates from different layers. This is critical for optimizing well performance and maximizing recovery of reserves. The temperature and pressure sensors in the well are small and inexpensive, while flowmeters are cumbersome and expensive, and affect the flow in the well. In this study, a mathematical model for pressure and temperature profiles along a gas well has been developed, which is readily used for prediction of flow rates in different layers. Temperature and pressure measurements from gas well in field C (Australia) have been matched with the mathematical model to determine the flow rates from different layers in the well. The proposed model considers the variables as functions of thermal properties at different depth, which is more accurate than previous methods. A simple and effective method is developed for fast estimation of rate distribution along the depth. The proposed approach has been applied to field case for determining gas flow rate in the wellbore and thermal conductivity of the formation from the acquired pressure and temperature data. It allows for recommending well stimulation of layers with low production rate.
Pore-Filling Nature of CH4 Adsorption Behavior in Kerogen Nanopores: A Molecular View Based on Full-Atom Kerogen Models
Authors: Sawa Y.. , Liang Y.. , Murata S.. , Matsuoka T.. , Akai T.. , Takagi S.. 
Published: November 2015

Abstract
Organic rich shale contains kerogen nanopores with characteristic lengths typically less than 100 nm. Adsorption behavior of hydrocarbon gas in the nanopores and the adsorption amount need to be considered for accurately calculating gas-in-place of this type of reservoir. We investigated CH4 behavior in kerogen nanopores under 350 and 400 K. A slit-like pore is constructed with full-atom kerogen models. The corresponding aromaticity is 0.71 and the structure is similar to coal. Two different cases are considered: Pressure and temperature are fixed with isobaric-isothermal ensembles, and different pore sizes from 2 nm to 40 nm (as mesopore models) are obtained by changing the number of CH4 molecules (Case 1); pore size and temperature are fixed with canonical ensembles, in which pressures are ranged from 5 MPa to 70 MPa by changing the number of CH4 molecules (Case 2). For case 2, four different pore sizes from 7.5 nm to 20 nm are useed. It was found that the density of the bulk region in an approximately 40 nm pore was almost the same as that of the bulk phase at the same pressure. However, it becomes higher as the pore size becomes smaller. Because the kerogen molecule is large in terms of size, the packing of kerogen molecules always leaves some cavities, which are capable of hosting CH4 molecules. This is similar to the micropores in activated carbons. The mono-molecular layer model, like the Langmuir model, may not be appropriate. On the other hand, the extended Dubinin-Radushkevich (DR) equation is ready to be implemented to acquire adsorption isotherms for those micropores. The DR model was developed to describe pore-filling state of adsorption behavior in micropores, which has been extended to supercritical conditions by assuming saturated vapor pressures. As anticipated, it was found that the adsorption isotherms were described by the extended DR equation better than the Langmuir model for all pore-size systems that we have studied. Moreover, we show that it is possible to apply the DR equation to describe the gas status in the "bulk region" inside the mesopores. Our work offers a better understanding in the calculation of gas-in-place in organic rich shales providing that we have the pore size distribution and constituents of a certain kerogen.
Modified Hybrid Fracturing in Shale Stimulation: Experiments and Application
Authors: Yin Congbin , Li Yanchao , Wang Subing , Qin Guan , Xu Ben , Zeng Rongke 
Published: November 2015

Abstract
Slick-water fracturing has been widely used in shale stimulation, which provides relatively long fracture length and large-scale complex fracture network without cross-linked gel. The shortcomings of slick-water fracturing are the proppant setting and bridging, which result in low sand concentration that compromises long-term fracture conductivity. A hybrid fracturing strategy is formulated with the combination of slick-water prepad followed with linear gelled, or cross-linked gel to balance the fracture network and long-term fracture conductivity. Compared to common hybrid fracturing, a modified hybrid fracturing is proposed by modified pumping schedules with alternating injection of slick-water, linear gelled fluid, or cross-linked gel, which is used for well stimulation in shale formations with high pressure and temperature.
In this paper, we present an in-house experimental device to simulate fluids and proppant flow in complex fracture network that contains two clusters, main fractures and several secondary fractures, which allows us to separately simulate hydraulic fractures and natural fractures. We have conducted a series of experiments on the slick-water fracs, the hybrid fracs, and the modified hybrid fracs. Compared with conventional hybrid fracs, the modified hybrid fracs with alternating injection of slick-water and cross-linked gel exhibit two advantages. (1) The modified hybrid fracs can form more flow channels in main fracture for viscous fingering, (2) the modified hybrid fracs enhance secondary fracture conductivity because slick-water pad between cross-linked gels reduces inflow rate of slurry into secondary fractures.
Based on the experimental results, an experimental method of fracture conductivity prediction is proposed with data regression method, which can be used for characters selection of pumping schedule in modified hybrid fracturing. Several shale well cases of the same shale gas field in Sichuan basin, Southern China, separately using the slick-water fracs, the hybrid fracturing and the modified hybrid fracturing are illustrated. The stimulated treatment pressure characteristics, long term well production performance of these three scenarios are discussed.
The modified hybrid fracturing has several advantages in shale stimulation, but there are also some difficulties in preventing sand screen out. This paper illustrates some basic experimental mechanisms of field applications of hybrid fracturing. In the future, we will present more field scenarios that are planned to carry out in other shale well pads.
New Models of Brittleness Index for Shale Gas Reservoirs: Weights of Brittle Minerals and Rock Mechanics Parameters
Authors: Hu Yuan , Gonzalez Perdomo M. E. , Wu Keliu , Chen Zhangxin , Zhang Kai , Yi Jie , Ren Guoxian , Yu Yanguo 
Published: November 2015

Abstract
Brittleness indices (BI) commonly used in the petroleum industry are based on elastic modulus or mineralogy that can be calculated from well logs. However, they ignore the weights of these two factors. Also, it is imprecise to calculate BI by considering quartz (or dolomite) as the only brittle mineral in mineralogy-based BI prediction. Shale gas reservoirs like Eagle Ford are rich in carbonate minerals. If the carbonate minerals are ignored in those reservoirs, the value of BI will be greatly underestimated. On the other hand, brittle minerals like quartz, dolomite and calcite play different roles in BI calculation. If we equally treat them without weighting in BI prediction, the BI being calculated will be inaccurate as well. This paper analyzes the influence of calcite on rock mechanics parameters and BI comparing with quartz and clay. Then new models of BI prediction are built to characterize the weight of each brittle mineral and rock mechanics parameter. Based on the least squares method, optimal values of weight coefficients will be obtained by iteration. The results show that calcite improves rock brittleness and should be considered as a brittle mineral in BI prediction. However, the weight of calcite is less than quartz. From the statistics results, quartz &gt; dolomite &gt; calcite &gt; clay occurs in improving BI. The results also show that Young's modulus plays a more important role in BI prediction than Poisson's ratio.
An Experimental Method to Determine the Fracture Toughness of Brittle and Heterogeneous Material by Hydraulic Fracturing
Authors: Too Jun Lin , Falser Simon , Linga Praveen , Khoo Boo Cheong , Cheng Arthur , Palmer Andrew 
Published: November 2015

AbstractIn this paper, a method is proposed to determine the fracture toughness of brittle and heterogeneous material through hydraulic fracturing. The intent of the proposed method is to deploy it on materials whose are not easily determined by standard test. One example of such a material is hydrate-bearing sand, which is unstable under atmospheric pressure and temperature. The pressure-time record, injection flow rate and total volume injection are necessary information to determine the fracture toughness of the material using the classical linear elastic fracture mechanics approach. To verify the method, frozen sand is used as a substitute material and its fracture toughness found using the standard test. Frozen sand has similar composition as natural hydrate-bearing sediment except for the absence of methane gas and high pressure. Then, this method is applied on the hydrate-bearing sand.