Journal articles on the topic 'Enhance gas recovery'
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1
Chapiro, Grigori, and Johannes Bruining. "Combustion enhance recovery of shale gas." Journal of Petroleum Science and Engineering 127 (March 2015): 179–89. http://dx.doi.org/10.1016/j.petrol.2015.01.036.
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Meng, Xingbang, Zhan Meng, Jixiang Ma, and Tengfei Wang. "Performance Evaluation of CO2 Huff-n-Puff Gas Injection in Shale Gas Condensate Reservoirs." Energies 12, no. 1 (December 24, 2018): 42. http://dx.doi.org/10.3390/en12010042.
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When the reservoir pressure is decreased lower than the dew point pressure in shale gas condensate reservoirs, condensate would be formed in the formation. Condensate accumulation severely reduces the commercial production of shale gas condensate reservoirs. Seeking ways to mitigate condensate in the formation and enhance both condensate and gas recovery in shale reservoirs has important significance. Very few related studies have been done. In this paper, both experimental and numerical studies were conducted to evaluate the performance of CO2 huff-n-puff to enhance the condensate recovery in shale reservoirs. Experimentally, CO2 huff-n-puff tests on shale core were conducted. A theoretical field scale simulation model was constructed. The effects of injection pressure, injection time, and soaking time on the efficiency of CO2 huff-n-puff were examined. Experimental results indicate that condensate recovery was enhanced to 30.36% after 5 cycles of CO2 huff-n-puff. In addition, simulation results indicate that the injection period and injection pressure should be optimized to ensure that the pressure of the main condensate region remains higher than the dew point pressure. The soaking process should be determined based on the injection pressure. This work may shed light on a better understanding of the CO2 huff-n-puff- enhanced oil recovery (EOR) strategy in shale gas condensate reservoirs.
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Fang, Zhiming, Xiaochun Li, and Haixiang Hu. "Gas mixture enhance coalbed methane recovery technology: Pilot tests." Energy Procedia 4 (2011): 2144–49. http://dx.doi.org/10.1016/j.egypro.2011.02.099.
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Xue, Liang, Cheng Dai, Lei Wang, and Xiaoxia Chen. "Analysis of Thermal Stimulation to Enhance Shale Gas Recovery through a Novel Conceptual Model." Geofluids 2019 (February 25, 2019): 1–14. http://dx.doi.org/10.1155/2019/4084356.
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To investigate the effect of thermal stimulation on shale gas recovery, a novel conceptual model coupling shale gas flow and temperature is proposed. The adsorption process is nonisothermal, and adsorption capacity changes with temperature. The local thermal nonequilibrium can explicitly describe the convective heat exchange between rock and fluids. The fluid flow model takes Knudsen diffusion, slippage effect, and non-Darcy flow into account. The complex geometry of fracture network due to hydraulic fracturing can also be considered. A series of synthetic tests are designed to demonstrate the model performance. The results show that the dynamic characteristics of heat diffusion and pressure spread can be reasonably obtained. Gas recovery decreases with the increase of volumetric heat transfer coefficient, and there exists a threshold value of the effect of volumetric heat transfer coefficient on gas recovery. Gas recovery increases with the gas and rock thermal conductivity and decreases with heat capacity of rock, but the decrease level becomes insignificant when heat capacity of rock is sufficiently high. Increasing the heating temperature and decreasing the production pressure are beneficial to enhance shale gas recovery, but the rate of recovery enhancement tends to decrease for sufficiently high heating temperature.
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Burachok, Oleksandr, Mariana Laura Nistor, Giovanni Sosio, Oleksandr Kondrat, and Serhii Matkivskyi. "Potential Application of CO2 for Enhanced Condensate Recovery Combined with Geological Storage in the Depleted Gas-Condensate Reservoirs." Management Systems in Production Engineering 29, no. 2 (May 21, 2021): 106–13. http://dx.doi.org/10.2478/mspe-2021-0014.
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Abstract CO2 emissions are considered to be the main contributor to global warming and climate change. One of the ways reducing the emissions to atmosphere is a proper capture and further geological storage of the carbon dioxide. In the oil industry, CO2 is used as one of the injection agents to displace oil and enhance its recovery. Due to the low multi-contact miscibility pressure between CO2 and hydrocarbons, fully miscible condition is quickly reached, leading to efficient displacement and high recovery factors. The utilization of the depleted gas fields for CO2 storage, however, is considered as the option that is more expensive compared to oil field, since the enhanced recovery of gas with CO2 is not effective. For this reason, our study considers the potential use of CO2 EOR in depleted gas-condensate fields. This potential is evaluated by performing numerical simulations for the typical-size gascondensate reservoirs with no active aquifer, in order to estimate both the storage efficiency and the additional oil recovery from condensed C5+ hydrocarbon fractions, that otherwise will be never recovered and lost in the reservoir. Obtained results indicate significant potential for CO2 storage and additional condensate recovery from the typical gas-condensate field of Eastern Ukraine.
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Deng, Jia, Jiujiu He, Jiujiang Li, Lan Zhang, and Fuquan Song. "Well-pattern optimization of CH4 transport associated with supercritical CO2 flooding." Physics of Fluids 34, no. 9 (September 2022): 096106. http://dx.doi.org/10.1063/5.0109412.
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Injecting supercritical CO2 into depleted gas reservoirs enables additional CH4 to be extracted, a process known as CO2 enhanced gas recovery (CO2-EGR). Optimization of the well pattern is another method used to enhance gas reservoir exploitation. The focus of the present work is to address the arrangement of the well pattern when using CO2-EGR. For this purpose, mathematical models with five-spot and seven-spot well patterns are established in steady and unsteady conditions, and their results are validated against previously published models. For the first time, equipotential and streamline charts of the well pattern in CO2-EGR are derived from these models. As a result, the main flow channel of the well pattern is clarified, and the distributions of formation pressure and seepage velocity are determined. Moreover, the relationships between the gas production rate and well pattern parameters such as the producing pressure drop, permeability, formation pressure, temperature, and well spacing are investigated and the factors that influence the recovery ratio are examined. Finally, an optimization strategy for the well pattern parameters in CO2-EGR is proposed to enhance the gas production rate and recovery factor.
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Khadar, R. Hassanzadeh, B. Aminshahidy, A. Hashemi, and N. Ghadami. "Application of Gas Injection and Recycling to Enhance Condensate Recovery." Petroleum Science and Technology 31, no. 10 (May 15, 2013): 1057–65. http://dx.doi.org/10.1080/10916466.2011.604057.
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Azreen Jilani, Noor, Nur Hashimah Alias, Tengku Amran Tengku Mohd, Nurul Aimi Ghazali, and Effah Yahya. "Wettability Modifier for Enhanced Oil Recovery in Carbonate Reservoir: An Overview." Advanced Materials Research 1113 (July 2015): 643–47. http://dx.doi.org/10.4028/www.scientific.net/amr.1113.643.
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This article is an overview of potential application of wettability modifier to enhance oil recovery in carbonate reservoir. In oil and gas industry, oil recovery can be divided into three stages which are primary recovery, secondary recovery and tertiary recovery. The primary recovery is the initial stages of oil recovery. At this stage, oil was displaced toward production well by natural drive mechanisms that naturally exist in the reservoir. Water is commonly used to enhance oil recovery by injected into the reservoir because of it is commercially available, less expensive and capable to maintain the reservoir pressure. In conclusion, smart water flooding is a new technique to solve the complexity problem of carbonate reservoir by manipulating the salinity and ionic composition in high temperature. Hence, smart water can be an excellent candidate as a displacing fluid in chemical flooding for enhanced the oil recovery (EOR).
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Kaita, Aminu Yau, Oghenerume Ogolo, Xingru Wu, Isah Mohammed, and Emmanuel Akaninyene Akpan. "Study of the impact of injection parameters on the performance of miscible sour gas injection for enhanced oil recovery." Journal of Petroleum Exploration and Production Technology 10, no. 4 (December 5, 2019): 1575–89. http://dx.doi.org/10.1007/s13202-019-00793-4.
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AbstractSour gas reservoirs have faced critics for environmental concerns and hazards, necessitating a novel outlook to how the produced sour gases could be either utilized or carefully disposed. Over the years of research and practice, several methods of sour gas processing and utilization have been developed, from the solid storage of sulfur to reinjecting the sour gas into producing or depleted light oil reservoir for miscible flooding enhanced oil recovery. This paper seeks to investigate the impact of injection parameters on the performance of sour gas injection for enhance oil recovery. In designing a miscible gas flooding project, empirical correlations are used and the key parameter which impacts the phase behavior is identified to be the minimum miscibility pressure (MMP). A compositional simulator was utilized in this research work to study the effect of injection parameters such as minimum miscibility pressure, acid gas concentration, injection pressure and injection rate on the performance of miscible sour gas injection for enhanced oil recovery. The findings showed that methane concentration had a significant impact on the MMP of the process. Additionally, an increase in acid gas concentration decreases the MMP of the process as a result of an increase in gas viscosity, consequently extending the plateau period resulting in late gas breakthrough and increased overall recovery of the process.
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Li, Kewen, Changhui Cheng, Changwei Liu, and Lin Jia. "Enhanced oil recovery after polymer flooding by wettability alteration to gas wetness using numerical simulation." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 73 (2018): 33. http://dx.doi.org/10.2516/ogst/2018029.
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Polymer flooding, as one of the Enhanced Oil Recovery (EOR) methods, has been adopted in many oilfields in China and some other countries. Over 50% oil remains undeveloped in many oil reservoirs after polymer flooding. It has been a great challenge to find approaches to further enhancing oil recovery when polymer flooding is over. In this study, a new method was proposed to increase oil production using gas flooding with wettability alteration to gas wetness when polymer flooding has been completed. The rock wettability was altered from liquid- to gas-wetness during gas flooding. An artificial oil reservoir was constructed and many numerical simulations have been conducted to test the effect of wettability alteration on the oil recovery in reservoirs developed by water flooding and followed by polymer flooding. Production data from different scenarios, water flooding, polymer flooding after water flooding, gas flooding with and without wettability alteration after polymer flooding, were calculated using numerical simulation. The results demonstrate that the wettability alteration to gas wetness after polymer flooding can significantly enhance oil recovery and reduce water cut effectively. Also studied were the combined effects of wettability alteration and reservoir permeability on oil recovery.
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Guo, Xiao, Jin Feng, Pengkun Wang, Bing Kong, Lan Wang, Xu Dong, and Shanfeng Guo. "Review on the Mechanism of CO2 Storage and Enhanced Gas Recovery in Carbonate Sour Gas Reservoir." Processes 11, no. 1 (January 5, 2023): 164. http://dx.doi.org/10.3390/pr11010164.
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Carbonate gas reservoirs in the Sichuan Basin have many complex characteristics, such as wide distribution, strong heterogeneity, high temperature, high pressure, high H2S and CO2 content and an active edge or bottom water. In the late stage of exploitation of carbonate sour gas reservoirs, the underground depleted reservoirs can provide a broad and favorable space for CO2 storage. If CO2 is injected into the depleted carbonate sour reservoirs for storage, it will help to achieve the goal of carbon neutrality, and the CO2 stored underground can perform as “cushion gas” to prevent the advance of edge or bottom water, to achieve the purpose of enhanced natural gas recovery. Injecting CO2 into low permeability reservoirs for oil displacement has become an important means to enhance oil recovery (EOR). However, the mechanism of EOR by injecting CO2 into carbonate sour gas reservoirs is not clear and the related fundamental research and field application technology are still in the exploration stage. This paper reviews the main scientific and technical perspectives in the process of injecting CO2 into carbonate sour gas reservoirs for storage and enhancing gas recovery.
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Zhou, Yu, Yafeng Lei, Wei Chen, and Weigang Yu. "Enhance low temperature oxidization of shale gas recovery using hydrogen peroxide." Journal of Petroleum Science and Engineering 164 (May 2018): 523–30. http://dx.doi.org/10.1016/j.petrol.2018.01.053.
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Yang, Yongzhi, Weirong Li, Tiyao Zhou, and Zhenzhen Dong. "Using Polymer Alternating Gas to Enhance Oil Recovery in Heavy Oil." IOP Conference Series: Earth and Environmental Science 113 (February 2018): 012182. http://dx.doi.org/10.1088/1755-1315/113/1/012182.
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Effah, Yahya, Hashimah Alias Nur, Aimi Ghazali Nurul, Amran Tengku Mohd Tengku, and Othman Hafizzuddin. "Nanoemulsion Formulation Using Biodegradable Oil in Enhance Oil Recovery (EOR)." Applied Mechanics and Materials 754-755 (April 2015): 1098–101. http://dx.doi.org/10.4028/www.scientific.net/amm.754-755.1098.
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Nanoemuslion is type of dispersion of emulsion in nanoscale from the effect that forms by shear that inducing rupturing. This small particle size of distribution conduit a higher efficiency in the sweeping trapped oil and lowering the IFT as the small size of nanoparticle provided a larger surface area contact to the reservoir. Thus, nanoemulsion is one of the new implemented techniques of the nanotechnology formulation of chemical flooding in the oil and gas industry. This paper presented the formulation of nanoemulsion using biodegradable oil as the nanoemulsion is the oil in water emulsion. Biodegradable oil is proven able to introduce a several advantages in the industry as it is renewable, environmental friendly, and produced easily in rural areas. In this research, nanoemulsion was formulated using three chosen biodegradable oil which is a corn oil, olive oil and sunflower oil that had been emulsified in the non ionic surfactant (Tween 80) and distilled water. The nanoemulsion that had been formulated was being analyzed based on particle size of distribution. Water flooding oil recovery using the lowest salinity of brine had recovered at average of 50% of IOIP. In the nanoemulsion flooding in enhance oil recover; corn oil has the recovered the highest percentage of IOIP which is 34.38% followed with olive oil 32.79% and sunflower oil 30.23%. Corn oil nanoemulsion is the most optimum biodegradable oil to be act to be act as displacing fluid in EOR chemical flooding in this case of research paper.
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Han, Feng Shan, and Li Song. "Geological Storage of Carbon Dioxide in Coal Seam is Effective Method for Environment Protection and Energy Sustainable Development in China." Advanced Materials Research 616-618 (December 2012): 1591–94. http://dx.doi.org/10.4028/www.scientific.net/amr.616-618.1591.
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The reduction of greenhouse gases emission is a growing concern of many countries. The geological storage of is useful and effective approaches to reduce emission. The oil and natural gas industries have long commercial practice of gas injection, enhanced oil recovery ( -EOR). Because coal seam has strong absorption capacity for ,the coal seam can be used as geological storage reservoirs, and coal seam has such characteristics that coal seam is preference for absorption and postponement for absorption, injection into coal seam can enhanced coal bed methane recovery, -ECBM, is a new energy generated by methane from injection into coal seam, and is beneficial complement of the energy , injection into coal seam can not only reduce greenhouse gases emission and but also enhance coal bed methane recovery, which is very significance to environment protection and energy sustainable development in china.
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Sharif, Shabir, Sadia Sagar Iqbal, Farzana Siddique, Alvina Rafiq Butt, Tasawer Shahzad Ahmad, and Arshad Bashir. "Synthesis, Spectral and Thermal Characteristics of Silica/PVP Nanofluids." Key Engineering Materials 875 (February 2021): 168–76. http://dx.doi.org/10.4028/www.scientific.net/kem.875.168.
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Nanofluid is well known as smart fluid which has high ability to recover oil. Therefore, it gains more significant effect in oil and gas industry. With the low concentration of nanofiller in nanofluid is used to enhance the numerous characteristics for oil recovery applications. Then, the main feature is the size of reinforcing agent and properties along matrix medium. Nano dimensional particles suspension in polymeric matrix have major advantages are stable sedimentation, optical, mechanical, electrical, and rheological properties that can be affected during the synthesis of nanofluids. Therefore nanoparticles/polymeric nanofluid have exceptional characteristics over the conventional fluid. Mixed nanoparticles/polymeric nanofluid in the presence of surfactant have effective interfacial tension and wettability which is evident for the development of nanofluids for oil recovery. In this context, the designed experimental study of silica/PVP nanofluids is synthesized via two step methods and characterized by SEM, TG/DTA, contact angle measurement, centrifugal effect and sedimentation test intended for Enhanced Oil Recovery (EOR) system.
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Devi, Kamalakshi, and Ranjan Kumar Bhagobaty. "Development of Biochemically Enhanced Oil Recovery Technology for Oil Fields – A Review." Nafta-Gaz 77, no. 2 (February 2021): 63–75. http://dx.doi.org/10.18668/ng.2021.02.01.
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Crude oil, a major source of energy, is being exploited as a driver of the economy throughout the world. Being a limited resource, the price of crude oil increases constantly and the exploitation of mature reservoirs becomes essential in order to meet the ever-increasing energy demands. As conventional recovery methods are not sufficient to fulfil the growing needs, there is an incessant demand for developing new technologies which can help in efficient tertiary recovery in old reservoirs. Petroleum biotechnology has been emerging as a branch that can provide solutions to major problems in the oil industry, including increasing oil production from marginal oil wells. The enhanced oil recovery (EOR) method comprises four methods – chemical, thermal, miscible, and immiscible gas flooding – as well as microbial interference to increase recovery of the remaining hydrocarbons trapped in reservoir rocks. Biochemically enhanced oil recovery comprises an array of blooming technologies for tertiary oil recovery methods which is eco-friendly, cost-effective, and efficient in extracting the residual oil trapped in reservoir rocks. Biochemical enhanced oil recovery (BcEOR) is based on the principle of using biochemical by-products produced by microbial species to enhance oil recovery, etc. All these technologies work on the principles of reducing viscosity, increasing permeability, modifying solid surfaces, emulsifying through adherence to hydrocarbons, and lowering interfacial tension. BcEOR technologies either employ the beneficial microorganism itself or the biochemical by-products produced by the microbial species to enhance tertiary oil recovery. This review paper discusses the chronological development of biologically enhanced oil recovery and its various mechanisms.
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Chen, Wei, Yafeng Lei, Yilin Chen, and Jiafeng Sun. "Pyrolysis and Combustion Enhance Recovery of Gas for Two China Shale Rocks." Energy & Fuels 30, no. 12 (November 10, 2016): 10298–305. http://dx.doi.org/10.1021/acs.energyfuels.6b02274.
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Shang, Xiaoji, Zhizhen Zhang, Weihao Yang, J. G. Wang, and Cheng Zhai. "A Thermal-Hydraulic-Gas-Mechanical Coupling Model on Permeability Enhancement in Heterogeneous Shale Volume Fracturing." Mathematics 10, no. 19 (September 23, 2022): 3473. http://dx.doi.org/10.3390/math10193473.
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Heat treatment on shale reservoirs can promote the development of secondary fractures in a matrix on the basis of hydraulic fracturing, forming multi-scale gas–water seepage channels and strengthening the gas desorption. Experimental evidence shows that heat treatment can enhance gas recovery in the same mining life. Heat treatment on a shale gas reservoir is a multi-physical and multi-phase coupling process. However, how the thermal stimulation interacts with nonlinear two-phase flow in heterogeneous shale volume fracturing has not been clear. In this paper, a fully coupled THGM model for heating-enhanced shale-gas recovery in heterogeneous shale reservoirs is proposed. First, the governing equations are formulated for the shale-reservoir deformation involving both gas adsorption and thermal expansion, the permeability evolution model for the cracking process of fractured shale, the gas–water two-phase continuity equation considering the effects of gas solubility and the heat transfer equation for heat conduction and convection. The interactions among stress, temperature and seepage in a heterogeneous shale reservoir were studied. Secondly, a test on shale permeability after 50 °C temperature treatment was conducted. The evolution of temperature, capillary pressure, water and gas saturation and the permeability of shale during the heat treatment of the reservoir were numerically analyzed. Finally, the gas production from a shale gas reservoir was numerically simulated with this THGM model. The numerical results indicated that the thermal-induced fracturing, gas desorption and separation from water make predominant contributions to the evolution of permeability. The heat treatment can enhance cumulative gas production by 58.7% after 27.4 years of heat injection through promoting gas desorption and matrix diffusion.
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Pandey, Jyoti Shanker, Charilaos Karantonidis, Adam Paul Karcz, and Nicolas von Solms. "Enhanced CH4-CO2 Hydrate Swapping in the Presence of Low Dosage Methanol." Energies 13, no. 20 (October 9, 2020): 5238. http://dx.doi.org/10.3390/en13205238.
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CO2-rich gas injection into natural gas hydrate reservoirs is proposed as a carbon-neutral, novel technique to store CO2 while simultaneously producing CH4 gas from methane hydrate deposits without disturbing geological settings. This method is limited by the mass transport barrier created by hydrate film formation at the liquid–gas interface. The very low gas diffusivity through hydrate film formed at this interface causes low CO2 availability at the gas–hydrate interface, thus lowering the recovery and replacement efficiency during CH4-CO2 exchange. In a first-of-its-kind study, we have demonstrate the successful application of low dosage methanol to enhance gas storage and recovery and compare it with water and other surface-active kinetic promoters including SDS and L-methionine. Our study shows 40–80% CH4 recovery, 83–93% CO2 storage and 3–10% CH4-CO2 replacement efficiency in the presence of 5 wt% methanol, and further improvement in the swapping process due to a change in temperature from 1–4 °C is observed. We also discuss the influence of initial water saturation (30–66%), hydrate morphology (grain-coating and pore-filling) and hydrate surface area on the CH4-CO2 hydrate swapping. Very distinctive behavior in methane recovery caused by initial water saturation (above and below Swi = 0.35) and hydrate morphology is also discussed. Improved CO2 storage and methane recovery in the presence of methanol is attributed to its dual role as anti-agglomerate and thermodynamic driving force enhancer between CH4-CO2 hydrate phase boundaries when methanol is used at a low concentration (5 wt%). The findings of this study can be useful in exploring the usage of low dosage, bio-friendly, anti-agglomerate and hydrate inhibition compounds in improving CH4 recovery and storing CO2 in hydrate reservoirs without disturbing geological formation. To the best of the authors’ knowledge, this is the first experimental study to explore the novel application of an anti-agglomerate and hydrate inhibitor in low dosage to address the CO2 hydrate mass transfer barrier created at the gas–liquid interface to enhance CH4-CO2 hydrate exchange. Our study also highlights the importance of prior information about methane hydrate reservoirs, such as residual water saturation, degree of hydrate saturation and hydrate morphology, before applying the CH4-CO2 hydrate swapping technique.
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Tao, Lei, Xiao Yuan, Sen Huang, Nannan Liu, Na Zhang, and Bingchao Li. "3D experimental investigation on enhanced oil recovery by flue gas assisted steam assisted gravity drainage." Energy Exploration & Exploitation 39, no. 4 (April 8, 2021): 1162–83. http://dx.doi.org/10.1177/01445987211006555.
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Flue gas assisted steam assisted gravity drainage (SAGD) is a frontier technology to enhance oil recovery for heavy oil reservoirs. The carbon dioxide generated from the thermal recovery of heavy oil can be utilized and consumed to mitigate climate warming for the world. However, most studies are limited to merely use numerical simulation or small physical simulation device and hardly focus on large scale three-dimensions experiment, which cannot fully investigate the enhanced oil recovery (EOR) mechanism of flue gas assisted SAGD, thus the effect of flue gas on SAGD production performance is still not very clear. In this paper, large-scaled and high temperature and pressure resistant 3D physical simulation experiment was conducted, where simulated the real reservoir to a maximum extent, and systematically explored the EOR mechanisms of the flue gas assisted SAGD. Furthermore, the differences between the steam huff and puff, SAGD and flue gas assisted SAGD are discussed. The experimental result showed that the production effect of SAGD was improved by injecting flue gas, with the oil recovery was increased by 5.7%. With the help of thermocouple temperature measuring sensors, changes of temperature field display that flue gas can promote lateral re-development of the steam chamber, and the degree of reservoir exploitation around the horizontal wells has been increased particularly. What’s more, the addition of flue gas further increased the content of light components and decreased the content of heavy by comparing the content of heavy oil components produced in different production times.
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Shi, Song Lin, Jian Kang, and Meng Li. "Study on CO2 Injection for Enhancing the Oil Recovery at Gao89 Block in Shengli Oilfield." Advanced Materials Research 734-737 (August 2013): 1464–67. http://dx.doi.org/10.4028/www.scientific.net/amr.734-737.1464.
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Gao 89 Block is a low permeability oil reservoir. These reservoirs have difficulty in water injection, poor well condition, and low original production. Gas injection can solve this problem. It is the most efficient recovery method for low-permeability reservoirs at home and abroad. In accordance with the geological features and development actuality of Gao89 Block, the feasibility and optimization of gas injection are studied, the effect of gas injection on the development index and development results are demonstrated. The results indicate that the gas injection can dramatically enhance oil recovery and increase the oil production.
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Xing, Dong, Yong Feng Li, Li Wei, and Jing Wei Zhang. "Current Situation and Prospect of Microbial Residual Oil Gasification." Applied Mechanics and Materials 295-298 (February 2013): 21–25. http://dx.doi.org/10.4028/www.scientific.net/amm.295-298.21.
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Most Oilfield of China has been a stage of Oil recovery with high water, microbial residual oil gasification technology as the oilfield's reserves technology has a good application prospect, especially the use of microorganisms for gasification of residual oil. The study has far-reaching significance, and it mainly turns the difficult mining oil reservoir into natural gas (mainly methane) through microbial degradation. It is the most effective, economical and environment-friendly way to enhance oil recovery efficiency and to extend the reservoir life. This paper summarized the relevant principles of oil microbial degradation and gasification, microbial enhanced oil recovery and Residual oil gasification at home and abroad, and come up with a few new research ideas.
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Yu, J., Y. Han, Y. Li, and P. Gao. "Recovery and separation of iron from iron ore using innovative fluidized magnetization roasting and magnetic separation." Journal of Mining and Metallurgy, Section B: Metallurgy 54, no. 1 (2018): 21–27. http://dx.doi.org/10.2298/jmmb170711050y.
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In this investigation, a pilot-scale fluidized magnetization roasting reactor was introduced and used to enhance magnetic properties of iron ore. Consequently, the effects of roasting temperature, reducing gas CO flow rate, and fluidizing gas N2 flow rate on the magnetization roasting performance were studied. The results indicated that the hematite was almost completely converted into magnetite by a gas mixture of 4 Nm3/h CO and 1 Nm3/h N2 at roasting temperature of 540?C for about 30 s. Under optimized conditions, a high grade concentrate containing 66.84% iron with iron recovery of 91.16% was achieved. The XRD, VSM, and optical microscopy (OM) analyses revealed that most of the hematite, except some coarse grains, was selectively converted to magnetite, and that the magnetic properties were greatly enhanced. Thus, their separation from non-magnetic gangue minerals was facilitated.
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Kim, Hyojae, Yeongseok Jang, Gyeong Won Lee, Seung Yun Yang, Jinmu Jung, and Jonghyun Oh. "Tunable Chemical Grafting of Three-Dimensional Poly (3, 4-ethylenedioxythiophene)/Poly (4-styrenesulfonate)-Multiwalled Carbon Nanotubes Composite with Faster Charge-Carrier Transport for Enhanced Gas Sensing Performance." Sensors 20, no. 9 (April 27, 2020): 2470. http://dx.doi.org/10.3390/s20092470.
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The three-dimensional volumetric application of conductive poly (3,4-ethylenedioxythiophene)/poly (4-styrenesulfonate) (PEDOT:PSS) to multiwalled carbon nanotubes (MWCNTs) has not been widely reported. In this study, the applicability of the 3D PEDOT:PSS-MWCNT composite for a gas sensor was investigated with different PEDOT:PSS concentrations. The gas-sensing performance of the 3D PEDOT:PSS-MWCNT composites was investigated using ethanol and carbon monoxide (CO) gas. Overall, in comparison with the pristine MWCNTs, as the PEDOT:PSS concentration increased, the 3D PEDOT:PSS-MWCNT composites exhibited increased conductivity and enhanced gas sensing performances (fast response and recovery times) to both ethanol and CO gases. Importantly, although the PEDOT:PSS coating layer reduced the number of sites for the adsorption and desorption of gas molecules, the charge-carrier transport between the gas molecules and MWCNTs was significantly enhanced. Thus, PEDOT:PSS can be chemically grafted to MWCNTs to enhance the connectivity and conductivity of a 3D network, leading to possible applications in gas sensors.
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Zhong, Liguo, Cheng Wang, Yigang Liu, Wei Zhang, Xiaodong Han, and Yongtao Sun. "Field application of a modular multiple thermal fluid generator for heavy oil recovery." Journal of Petroleum Exploration and Production Technology 12, no. 1 (November 20, 2021): 227–37. http://dx.doi.org/10.1007/s13202-021-01376-y.
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AbstractA modular multiple thermal fluid generator is introduced to enhance heavy oil production, which consists of water treatment system, fuel injection system, air compressor, central burning and heat exchanging system, and measuring and controlling system. All the components are mounted in three separated light shelters, which are easy to be lifted and installed, especially on the offshore production platform. It could be operated under 350 ℃ and 20 MPa, and the temperature and GWR (ratio of the volume of gas to the equivalent water volume of steam under standard conditions) could be adjusted by the water injection rate under the given heating capability of the central burning chamber. The temperature of the generated fluid is usually 200–300 ℃ with GWR of 200–300 m3/m3. Compared to conventional steam generator, such compact multiple thermal fluid generator is easy to be installed on the offshore oil production platform, and the generated multiple thermal fluid is potential to enhance heavy oil production in mechanisms of reducing heavy oil viscosity by both heating and injected gas, enlarging the heating reservoir chamber, and pressure by injected gas. In the past 10 years, the multiple thermal fluid generator has been applied to more than 40 wells in Bohai Offshore Oilfield and Xinjiang Oilfield in cyclic multiple thermal fluid stimulation (CMTFS in short) process. As a result, the multiple thermal fluid generators were operated soundly, and the heavy oil production of these wells was enhanced remarkably. (The oil production rate was 2–3 times more than cold production.)
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Ayyed, Abbas Kadhim. "Converting Carbon Dioxide in to Methane Gas and Enhance Oil Recovery by using Biotechnology Process." Journal of Petroleum Research and Studies 12, no. 1 (March 20, 2022): 242–66. http://dx.doi.org/10.52716/jprs.v12i1.601.
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Using biotechnology in petroleum industry has many advantages .for example , Microbiologically Enhanced Oil Recovery (MEOR) increase of the productivity of the oil field and decrease the viscosity of the crude oil . It's known that atmosphere has considerable amount of CO2 gas as a result of industrial activities (crude oil production). CO2 gas plays a role in increasing atmosphere temperature and causing global warming. Bioremediation is a viable Biotechnology function for Re-producing depleted wells and global warming. It means Bioremediation uses metabolic adaptation of microorganism, a promising approach, using this technique employs of Methanogenic bacteria to convert CO2 gas in to CH4. Therefore turns carbon dioxide in to carbon which is added to crude oil (so contribute decrease the viscosity for heavy crude oil, This mechanism is a part of the promotion of oil production.it is apart an operation EOR. and Second reacts with Hydrogen by Bacteria to produce methane gas. The aim study, advantage this method increase production. and removal global warming. In this review, we discuss the role of Methanogenic bacteria in transforming CO2 gas into methane gas , that it has a role in crude oil production . Methanogenic bacteria have an important role in petroleum industry and environment during decreasing CO2 amount in the atmosphere and increasing reservoir pressure. MEOR technology uses strains that have a role in crude oil production; these bacterial strains produce biogases (Methane) that increase reservoir pressure. In this study, six strains were isolated from Rumaila oilfield, south of Iraq. These strains were identified based on microscopic and morphological observations. These strains were Methanogenic bacteria. The main part of this study includes identification of bacteria that can consume CO2 gas and making continual lab experiments to isolate and determine the best genus to do this process in oil field. Experiments were done in specific bio-labs for two years, Methanogenic bacteria strains were isolated by using specific selective growth media. The second part of this study is using these strains for bioremediation process of oil wells, which includes providing anaerobic conditions for these strains to transform CO2 gas to methane . Morphological and microscopic observations were conducted to these strains and showed the best kind of these strains according to the ability of transformation of CO2 to methane. The isolated bacteria were called BRS11 strain showed high efficiency in transformation of CO2 to methane.
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Agahzamin, S., A. Mirvakili, and M. R. Rahimpour. "Investigation and recovery of purge gas streams to enhance synthesis gas production in a mega methanol complex." Journal of CO2 Utilization 16 (December 2016): 157–68. http://dx.doi.org/10.1016/j.jcou.2016.07.003.
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Wang, Jinsheng, David Ryan, Martina Szabries, and Philip Jaeger. "A Study for Using CO2 To Enhance Natural Gas Recovery from Tight Reservoirs." Energy & Fuels 33, no. 5 (March 21, 2019): 3821–27. http://dx.doi.org/10.1021/acs.energyfuels.8b04464.
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KING, T. R., M. WANNELL, and T. M. ALQASSAR. "Cross-flow to enhance gas recovery in the Dalton Field, East Irish Sea." Geological Society, London, Petroleum Geology Conference series 6, no. 1 (2005): 687–94. http://dx.doi.org/10.1144/0060687.
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Ziembicki, Piotr, Joachim Kozioł, Jan Bernasiński, and Ireneusz Nowogoński. "Innovative System for Heat Recovery and Combustion Gas Cleaning." Energies 12, no. 22 (November 8, 2019): 4255. http://dx.doi.org/10.3390/en12224255.
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The Polish as well as the global energy economy, including in particular heat generation, is to a great extent based on facilities for the combustion of liquid and gaseous fuels. Globally, a considerable part, and in Poland a vast majority of these facilities are much worn out, and, consequently, they work with low efficiency producing considerable amounts of pollutants, which have a very negative impact on the environment. Therefore, it is of crucial importance to develop innovative solutions that enhance the efficiency of fuel combustion and at the same time reduce emission of pollutants. The paper presents a solution which renders it possible to increase the efficiency of fuel conversion by heating up substrates of combustion processes, heat recovery from combustion gases as a result of their cooling and water vapor condensation and which contributes to a reduction of pollution. The solution brings about significant fuel consumption savings and thus a considerable enhancement of economic and ecological efficiency of heat sources is achieved. The solution is specially dedicated to heat sources of low and medium power. The technology developed and described herein will also allow an elimination of environmental burdens caused by inefficient heat sources already in operation.
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Chen, Run. "Predicted Enhanced Coalbed Methane Recovery and CO2 Sequestration in West Henan Province." Advanced Materials Research 962-965 (June 2014): 168–71. http://dx.doi.org/10.4028/www.scientific.net/amr.962-965.168.
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CO2injection into coal seams can not only enhance coalbed methane recovery (ECBM), but also reduce greenhouse gas emission into atmosphere. This paper describes some factors affecting CBM primary production, ECBM recovery and CO2sequestration in coal seams; and calculates CBM recovery quantity with primary production, the ECBM recovery potential quantity and CO2sequestration capacity in coal seams of West Henan Province. The results show that CBM primary and ECBM recovery potential quantity are estimated to be over 2147.278 and 1656.217 Gm3. The prediction also indicates that CO2sequestration potential quantity is about 3233.79 Gm3.
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Li, Zhao Min, Chao Zhang, Song Yan Li, Dong Zhang, and Shu Hua Wang. "Injection Mode of CO2 Displacement in Heavy Oil Reservoirs." Advanced Materials Research 402 (November 2011): 680–86. http://dx.doi.org/10.4028/www.scientific.net/amr.402.680.
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CO2injection has been an important enhanced oil recovery method adopted at the later stage of oilfield development, and a series of studies and field experiments has been done in recent years. However, there are some problems in this process, such as viscous fingering, gravity override, channeling of CO2in heterogeneous reservoir. These challenging issues are closely related to the CO2injection ways. At present, it is at development stage and calls for more research on optimally choosing CO2injection methods to displace oil. This research mainly uses different CO2injection methods to displace oil, in order to optimally choose the CO2injection method that fit this experiment area, and does research on the effects and principles of CO2drive to enhance oil recovery. Compared with gas flooding and WAG, CO2foam greatly reduce the mobility of the injected gas and expand the sweep volume. This is consistently observed in the numerically simulated foam process at the field level.
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Liu, Zhongzhe, Simcha Singer, Daniel Zitomer, and Patrick McNamara. "Sub-Pilot-Scale Autocatalytic Pyrolysis of Wastewater Biosolids for Enhanced Energy Recovery." Catalysts 8, no. 11 (November 7, 2018): 524. http://dx.doi.org/10.3390/catal8110524.
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Improving onsite energy generation and recovering value-added products are common goals for sustainable used water reclamation. A new process called autocatalytic pyrolysis was developed at bench scale in our previous work by using biochar produced from the biosolids pyrolysis process itself as the catalyst to enhance energy recovery from wastewater biosolids. The large-scale investigation of this process was used to increase the technical readiness level. A sub-pilot-scale catalytic pyrolytic system was constructed for this scaled-up study. The effects of configuration changes in both pyrolytic and catalytic reactors were investigated as well as the effect of vapor-catalyst contact types (i.e., downstream, in-situ) on product yield and quality. The sub-pilot-scale test with downstream catalysis resulted in higher py-gas yields and lower bio-oil yields when compared to results from a previous batch, bench-scale process. In particular, the py-gas yields increased 2.5-fold and the energy contained in the py-gas approximately quadrupled compared to the control test without autocatalysis. Biochar addition to the feed biosolids before pyrolysis (in-situ catalysis) resulted in increased py-gas production, but the increase was limited. It was expected that using a higher input pyrolyzer with a better mixing condition would further improve the py-gas yield.
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Shi, Ji-Quan, and S. Durucan. "A Model for Changes in Coalbed Permeability During Primary and Enhanced Methane Recovery." SPE Reservoir Evaluation & Engineering 8, no. 04 (August 1, 2005): 291–99. http://dx.doi.org/10.2118/87230-pa.
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Summary The natural fracture network of a dual-porosity coalbed reservoir is made up of two sets of orthogonal, and usually subvertically oriented, cleats. Coalbed permeability has been shown to vary exponentially with changes in the effective horizontal stress acting across the cleats through the cleat-volume compressibility, which is analogous to pore compressibility in porous rocks. A formulation for changes in the effective horizontal stress of coalbeds during primary methane recovery, which includes a Langmuir type curve shrinkage term, has been proposed previously. This paper presents a new version of the stress formulation by making a direct link between the volumetric matrix strain and the amount of gas desorbed. The resulting permeability model can be extended readily to account for adsorption-induced matrix swelling as well as matrix shrinkage during enhanced methane recovery involving the injection of an inert gas or gas mixture into the seams. The permeability model is validated against a recently published pressure-dependent permeability multiplier curve representative of the San Juan basin coalbeds at post-dewatering production stages. The extended permeability model is then applied successfully to history matching a micropilot test involving the injection of flue gas (consisting mainly of CO2 and N2) at the Fenn Big Valley, Alberta, Canada. Introduction Over the past 2 decades, coalbed methane (CBM) has become an important source of the (unconventional) natural gas supply in the U.S. On the basis of this experience, CBM has attracted worldwide attention in recent years as a potential clean energy source. Current commercial CBM production occurs almost exclusively through reservoir-pressure depletion, which is simple but considered to be rather inefficient, with an estimated total recovery of generally around 50% (this figure appears to be pessimistic; mature coal plays in the U.S. have now seen recovery of 60 to 80%) of the gas in place. In recent years, enhanced CBM (ECBM) recovery techniques have been proposed as a more efficient means for the recovery of a larger fraction of methane in place. There are two principal variants of ECBM recovery, namely N2 and CO2injection, which use two distinct mechanisms to enhance methane desorption and production. Unlike the primary recovery method, ECBM allows the maintenance of reservoir pressure. The mechanism used in N2 injection is somewhat similar to inert gas stripping because nitrogen is less adsorbing than methane. Injection of nitrogen reduces the partial pressure of methane in the reservoir, thus promoting methane desorption without lowering the total reservoir pressure. On the other hand, CO2 injection works on a different mechanism because it is more adsorbing on coal compared with methane. Carbon dioxide ECBM recovery thus has an added benefit that a potentially large volume of greenhouse gas can be sequestrated in deep coal seams globally.
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You, Shaohua, Xiaofei Sun, and Xiaoyu Li. "Preparation of Modified Colloidal Gas Aphrons and Analysis of the Oil Displacement Effect." Applied Sciences 10, no. 3 (January 31, 2020): 927. http://dx.doi.org/10.3390/app10030927.
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Colloidal gas aphrons (CGAs) offer some advantages in improving oil recovery, but resin and asphaltene deposition problems still occur in CGA flooding. Based on this phenomenon, a new modified colloidal foam system is developed by incorporating a modifier in CGA preparation. The results indicate that the modified CGAs prepared by adding foaming agent sodium dodecyl sulfate (SDS) (concentration: 5 g/L) and GXJ-C (a CGAs modifier from a light fraction of petroleum; concentration: 0.1 g/L) attained the best performance. Oil displacement experiments show that modified CGA flooding had a better effect than water or CGA flooding. There are two important mechanisms via which modified CGAs enhance oil recovery, including decreasing the interfacial tension and enhancing the heavy components in the recovered oil. The developed modified CGA system attained a good oil displacement effect, which is of guiding significance to further improve the oil displacement efficiency and application of foam flooding.
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Liu, Hui Qing, Jing Wang, Peng Cheng Hou, and Bing Ke Wang. "Experimental Investigation of Enhanced Oil Recovery by Thermal Foam Flooding." Advanced Materials Research 236-238 (May 2011): 814–19. http://dx.doi.org/10.4028/www.scientific.net/amr.236-238.814.
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Foam has been widely used in petroleum industry. It could enhance oil recovery by the means of improving mobility ratio, selective plugging and lowering the interfacial tension(IFT) of oil and water. The influences of concentration, temperature, gas-liquid ratio, permeability and oil saturation on the plugging property of 3 foaming agents were studied experimentally. The foaming agent concentration and the ratio of steam to nitrogen for thermal foam flooding were optimized. Displacement experiments were performed to investigate the EOR effect of 2# foaming agent. It was shown that the resistance factor increased with the increase of the concentration, gas-liquid ratio and permeability and the increase velocity slowed down in the later period of experiments. The optimal concentration was 0.5wt% and the optimum gas-liquid ratio was 1:1. The resistance factor reduced with increasing oil saturation. The plugging ability lost when the oil saturation was greater than 0.2. The resistance factors of 1# and 2# foaming agents decreased with increasing temperature but 3# increased. The best concentration was 0.6wt% and the ratio of steam to nitrogen was 3:2 for steam and nitrogen foam flooding. In the process of thermal foam flooding, oil recovery increased by 20.82%, and the sweep efficiency and displacement efficiency was 13% and 24.6% , separately.
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Al-Obaidi, Dahlia A., and Mohammed S. Al-Jawad. "Immiscible CO2-Assisted Gravity Drainage Process for Enhancing Oil Recovery in Bottom Water Drive reservoir." Association of Arab Universities Journal of Engineering Sciences 27, no. 2 (June 30, 2020): 60–66. http://dx.doi.org/10.33261/jaaru.2020.27.2.007.
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The CO2-Assisted Gravity Drainage process (GAGD) has been introduced to become one of the mostinfluential process to enhance oil recovery (EOR) methods in both secondary and tertiary recovery through immiscibleand miscible mode. Its advantages came from the ability of this process to provide gravity-stable oil displacement forenhancing oil recovery. Vertical injectors for CO2 gas have been placed at the crest of the pay zone to form a gas capwhich drain the oil towards the horizontal producing oil wells located above the oil-water-contact. The advantage ofhorizontal well is to provide big drainage area and small pressure drawdown due to the long penetration. Manysimulation and physical models of CO2-AGD process have been implemented at reservoir and ambient conditions tostudy the effect of this method to improve oil recovery and to examine the most parameters that control the CO2-AGDprocess. The CO2-AGD process has been developed and tested to increase oil recovery in reservoirs with bottom waterdrive and strong water coning tendencies. In this study, a scaled prototype 3D simulation model with bottom waterdrive was used for CO2-assisted gravity drainage. The CO2-AGD process performance was studied. Also the effects ofbottom water drive on the performance of immiscible CO2 assisted gravity drainage (enhanced oil recovery and watercut) was investigated. Four different statements scenarios through CO2-AGD process were implemented. Resultsrevealed that: ultimate oil recovery factor increases considerably when implemented CO2-AGD process (from 13.5%to 84.3%). Recovery factor rises with increasing the activity of bottom water drive (from 77.5% to 84.3%). Also,GAGD process provides better reservoir pressure maintenance to keep water cut near 0% limit until gas flood frontreaches the production well if the aquifer is active, and stays near 0% limit at all prediction period for limited waterdrive.
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Kaesti, Edgie Yuda, and Bambang Bintarto. "Peningkatan Perolehan Minyak Dengan CO2 Flooding pada Lapangan “X” Lapisan “Y”." Jurnal Mineral, Energi dan Lingkungan 1, no. 1 (April 26, 2017): 1. http://dx.doi.org/10.31315/jmel.v1i1.1768.
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Enhance Oil Recovery (EOR) adalah salah satu teknik dalam meningkatkan jumlah minyak yang dapat di produksikan. Proses CO2-EOR adalah dengan menginjeksi CO2 pada lapisan produktif dengan tekanan dibawah tekanan rekah formasi. Pada EOR ini menggunakan CO2 karena CO2 mudah larut dalam minyak bumi namun sulit larut pada air dan ketersediaan CO2 pada lapangan migas sangat berlimpah.Pemilihan metode peningkatan perolehan dengan CO2 Flooding pada Lapangan X menggunakan gas CO2 dikarenakan: gas CO2 tidak bereaksi dengan air atau minyak dan ketersediaan gas CO2 yang cukup besar di Lapangan X. Peningkatan perolehan minyak pada lapisan “Y” dapat dilakukan dengan beberapa metode, antara lain dengan Water Flooding (Injeksi Air) dan CO2 Flooding (Injeksi CO2). Pada Lapangan X lapisan Y ini peningkatan perolehan minyak dilakukan dengan metode CO2 Flooding.Sumur-sumur yang digunakan sebagai sumur injeksi pada proses injeksi gas CO2 adalah sumur water flooding dan sumur suspended pada lapisan yang sama. Recovery factor menggunakan skenario pengembangan menggunakan injeksi gas CO2 akan bertambah sebesar 47,05% dari recovery factor pada base case sebesar 58,79% menjadi 86,84% (sama dengan 350 MSTBO).
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Janudin, Nurjahirah, Norli Abdullah, Faizah Md Yasin, Mohd Hanif Yaacob, Muhammad Zamharir Ahmad, and Noor Azilah Mohd Kasim. "Multi-Walled Carbon Nanotubes Functionalized with Carboxyl and Amide for Acetone detection at Room Temperature." Solid State Phenomena 317 (May 2021): 195–201. http://dx.doi.org/10.4028/www.scientific.net/ssp.317.195.
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The functionalization of multi-walled carbon nanotubes (CNT) with amide group is reported as an alternative to enhance response time, recovery time and sensitivity of detecting acetone gas. We have fabricated an interdigitated transducer (IDT) deposited with amide-functionalized CNT. The elemental compositional analysis was characterized using Energy Dispersion X-ray spectroscopy and CHNOS elemental analyzer. The detection of acetone gas was performed in room temperature and digital multimeter was employed to record the changes of resistivity of IDT upon exposure of acetone. Results showed that amide functional group increases sensitivity, shortens the response time as well as recovery time of the sensor.
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Quoc Viet, Tran, Vu Viet Hung, and Nguyen Hai An. "Production technology solutions to enhance heavy oil recovery of marginal fields, offshore Vietnam." Petrovietnam Journal 10 (October 30, 2020): 41–48. http://dx.doi.org/10.47800/pvj.2020.10-04.
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The finding of heavy oil at Dong Do field of Cuu Long basin is a success in exploration. It could be considered as a large heavy oil field offshore Vietnam. Maximising reserve is a challenge to the operator when they think of a suitable development strategy to efficiently and economically exploit the field. Over the past decades, production technology application in heavy oil production has been widely developed in the industry. Apart from the thermal method, pumping technology makes remarkable advances by enlarging the drawdown created over the conventional gas lift in several heavy oil projects.
This paper presents all the production technology solutions that apply to the marginal heavy oil field offshore Vietnam. One of the major solutions is the electric submersible pump (ESP) and gas-lift (GL) combination method to enhance the wellbore lifting efficiency. In doing so, a series of solutions to improve heavy oil recovery have been conducted from design to pilot test whilst optimising the economic yield over the field life. Among them, the application of ESP and GL combination plays as the key driver to reinforce good production performance.
As a result, the design includes an electrical pump system coupled with GL back-up, all integrated with one to boost production and prolong well life. Beside that, closely monitoring and optimising is one factor to give the pump a longer life.
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Pang, Yu, Shengnan Chen, and Hai Wang. "Predicting Adsorption of Methane and Carbon Dioxide Mixture in Shale Using Simplified Local-Density Model: Implications for Enhanced Gas Recovery and Carbon Dioxide Sequestration." Energies 15, no. 7 (March 31, 2022): 2548. http://dx.doi.org/10.3390/en15072548.
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Carbon dioxide (CO2) capture and storage have attracted global focus because CO2 emissions are responsible for global warming. Recently, injecting CO2 into shale gas reservoirs is regarded as a promising technique to enhance shale gas (i.e., methane (CH4)) production while permanently storing CO2 underground. This study aims to develop a calculation workflow, which is built on the simplified local-density (SLD) model, to predict excess and absolute adsorption isotherms of gas mixture based on single-component adsorption data. Such a calculation workflow was validated by comparing the measured adsorption of CH4, CO2, and binary CH4/CO2 mixture in shale reported previously in the literature with the predicted results using the calculation workflow. The crucial steps of the calculation workflow are applying the multicomponent SLD model to conduct regression analysis on the measured adsorption isotherm of each component in the gas mixture simultaneously and using the determined key regression parameters to predict the adsorption isotherms of gas mixtures with various feed-gas mole fractions. Through the calculation workflow, the density profiles and mole fractions of the adsorbed gases can be determined, from which the absolute adsorption of the gas mixture is estimated. In addition, the CO2/CH4 adsorption selectivity larger than one is observed, illustrating the preferential adsorption of CO2 over CH4 on shale, which implies that CO2 has enormous potential to enhance CH4 production while sequestering itself in shale. Our findings demonstrate that the proposed calculation workflow depending on the multicomponent SLD model enables us to accurately predict the adsorption of gas mixtures in nanopores based on single-component adsorption results. Following the innovative calculation flow path, we could bypass the experimental difficulties of measuring the multicomponent mole fractions in the gas phase at the equilibrium during the adsorption experiments. This study also provides insight into the CO2/CH4 competitive adsorption behavior in nanopores and gives guidance to CO2-enhanced gas recovery (CO2-EGR) and CO2 sequestration in shale formations.
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Wang, Tengfei, Liangliang Wang, Haoliang Qin, Cong Zhao, Zongxian Bai, and Xingbang Meng. "Identification of Gas Channeling and Construction of a Gel-Enhanced Foam Plugging System for Oxygen-Reduced Air Flooding in the Changqing Oilfield." Gels 8, no. 6 (June 13, 2022): 373. http://dx.doi.org/10.3390/gels8060373.
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The accurate identification of gas channeling channels during foam-assisted oxygen-reduced air flooding (FAORAF) and the analysis of the main controlling factors are essential to propose reasonable and effective countermeasures to enhance oil recovery (EOR). However, there are few comprehensive studies on identifying gas channeling channels, the influencing factors, and the corresponding plugging EOR systems in FAORAF. The channeling channels of the injection and production wells of the Changqing Oilfield, China, under varying development schemes are identified utilizing fuzzy membership function theory in this work to obtain their primary distribution. The characteristics and influence factors of gas channeling channels are analyzed by numerical simulation using CMG. The recovery performance of each foam blocking system is evaluated by twin-tube sand pack models. As well, based on the features of reservoir fractures, a new gel-enhanced foam plugging system is developed. The results show that channeling channels chiefly develop along NE 60–70° and that foam could reduce gas channeling. Natural and artificial fractures are the principal factors causing gas channeling, followed by the injection method and gas injection rate. Under the premise of the injection and migration efficiency, the optimal gel system is a 0.1% HPAM + 0.1% organic chromium crosslinking agent. The addition of gel increases the viscosity of the liquid phase and strengthens the mechanical strength of the foam liquid film. At a permeability ratio of 12, the recovery factors of the binary plugging systems composed of microspheres, PEG, and gel combined with foam are 40.89%, 45.85%, and 53.33%, respectively. The movable gel foam system has a short breaking time (only 18 days) and a recovery factor of about 40% at a permeability ratio of 20. To be suitable for oil reservoirs with microfractures, an improved ternary gel foam system—0.1% HPAM + 0.1% chromium crosslinking agent + 0.05–0.1% nano-SiO2—is developed. Compared with the binary gel foam system, the recovery rate of the new nano-SiO2 gel foam system after 15 days of ageing using the core splitting test is 25.24% during the FAORAF process, increasing by 12.38%.
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Cannone, Salvatore F., Andrea Lanzini, and Massimo Santarelli. "A Review on CO2 Capture Technologies with Focus on CO2-Enhanced Methane Recovery from Hydrates." Energies 14, no. 2 (January 12, 2021): 387. http://dx.doi.org/10.3390/en14020387.
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Natural gas is considered a helpful transition fuel in order to reduce the greenhouse gas emissions of other conventional power plants burning coal or liquid fossil fuels. Natural Gas Hydrates (NGHs) constitute the largest reservoir of natural gas in the world. Methane contained within the crystalline structure can be replaced by carbon dioxide to enhance gas recovery from hydrates. This technical review presents a techno-economic analysis of the full pathway, which begins with the capture of CO2 from power and process industries and ends with its transportation to a geological sequestration site consisting of clathrate hydrates. Since extracted methane is still rich in CO2, on-site separation is required. Focus is thus placed on membrane-based gas separation technologies widely used for gas purification and CO2 removal from raw natural gas and exhaust gas. Nevertheless, the other carbon capture processes (i.e., oxy-fuel combustion, pre-combustion and post-combustion) are briefly discussed and their carbon capture costs are compared with membrane separation technology. Since a large-scale Carbon Capture and Storage (CCS) facility requires CO2 transportation and storage infrastructure, a technical, cost and safety assessment of CO2 transportation over long distances is carried out. Finally, this paper provides an overview of the storage solutions developed around the world, principally studying the geological NGH formation for CO2 sinks.
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Rochedo, Pedro R. R., Panagiotis Fragkos, Rafael Garaffa, Lilia Caiado Couto, Luiz Bernardo Baptista, Bruno S. L. Cunha, Roberto Schaeffer, and Alexandre Szklo. "Is Green Recovery Enough? Analysing the Impacts of Post-COVID-19 Economic Packages." Energies 14, no. 17 (September 6, 2021): 5567. http://dx.doi.org/10.3390/en14175567.
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Emissions pathways after COVID-19 will be shaped by how governments’ economic responses translate into infrastructure expansion, energy use, investment planning and societal changes. As a response to the COVID-19 crisis, most governments worldwide launched recovery packages aiming to boost their economies, support employment and enhance their competitiveness. Climate action is pledged to be embedded in most of these packages, but with sharp differences across countries. This paper provides novel evidence on the energy system and greenhouse gas (GHG) emissions implications of post-COVID-19 recovery packages by assessing the gap between pledged recovery packages and the actual investment needs of the energy transition to reach the Paris Agreement goals. Using two well-established Integrated Assessment Models (IAMs) and analysing various scenarios combining recovery packages and climate policies, we conclude that currently planned recovery from COVID-19 is not enough to enhance societal responses to climate urgency and that it should be significantly upscaled and prolonged to ensure compatibility with the Paris Agreement goals.
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Grekou, Triantafyllia K., Dimitris E. Koutsonikolas, George Karagiannakis, and Eustathios S. Kikkinides. "Tailor-Made Modification of Commercial Ceramic Membranes for Environmental and Energy-Oriented Gas Separation Applications." Membranes 12, no. 3 (March 9, 2022): 307. http://dx.doi.org/10.3390/membranes12030307.
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Ceramic membranes have been considered as potential candidates for several gas separation processes of industrial interest, due to their increased thermal and chemical stability compared to polymeric ones. In the present study, commercial Hybrid Silica (HybSi®) membranes have been evaluated and modified accordingly, to enhance their gas separation performance for targeted applications, including CO2 removal from flue gas and H2 recovery from hydrogen-containing natural gas streams. The developed membranes have been characterized before and after modification by relative permeability, single gas permeation, and equimolar separation tests of the respective gas mixtures. The modification procedures, involving in situ chemical vapor deposition and superficial functionalization, aim for precise control of the membranes’ pore size and surface chemistry. High performance membranes have been successfully developed, presenting an increase in H2/CH4 permselectivity from 12.8 to 45.6 at 250 °C. Ultimately, the modified HybSi® membrane exhibits a promising separation performance at 250 °C, and 5 bar feed pressure, obtaining above 92% H2 purity in the product stream combined with a notable H2 recovery of 65%, which can be further improved if a vacuum is applied on the permeate side, leading to 94.3% H2 purity and 69% H2 recovery.
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Dong, Zhenzhen, Xinle Ma, Haobin Xu, Weirong Li, Shihao Qian, Zhengbo Wang, Zhaoxia Liu, and Gang Lei. "Molecular Dynamics Study of Interfacial Properties for Crude Oil with Pure and Impure CH4." Applied Sciences 12, no. 23 (November 29, 2022): 12239. http://dx.doi.org/10.3390/app122312239.
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Gas injection has received increasing attention as one of the key technologies to enhance oil recovery. When gas is dissolved in crude oil, it will accelerate the flow of crude oil by reducing the density, viscosity, interfacial tension (IFT), and other properties of crude oil, so IFT is one of the main factors affecting the recovery of the gas drive. The interfacial properties of CH4, one of the principal associated hydrocarbon gases, with crude oil remain unclear. In this study, molecular dynamics (MD) simulations were used to determine the IFTs of pure and impure CH4 with n-decane as well as the IFTs of the ternary systems CH4 + n-hexane + n-decane and CH4 + n-decane + n-nonadecane. Additionally, investigating factors including pressure, temperature, gas composition, and crude oil composition reveals the mechanisms affecting the interfacial properties of CH4 and crude oil. The results demonstrate that CO2 significantly lowers the IFT of CH4 + n-decane; the effect of crude oil components on IFT varies with the properties of the crude oil and, generally speaking, IFT is greater for crude oils containing heavy components than for those containing light components; the effect of temperature on the IFT of the CH4 + n-decane system is more pronounced at low pressure and decreases with increasing pressure. This study contributes to understanding the behavior of CH4 and oil systems in the formation and could be used to enhance the oil recovery technology.
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Zhan, Jie, Zhihao Niu, Mengmeng Li, Ying Zhang, Xianlin Ma, Chao Fan, and Ruifei Wang. "Numerical Simulation and Modeling on CO2 Sequestration Coupled with Enhanced Gas Recovery in Shale Gas Reservoirs." Geofluids 2021 (August 4, 2021): 1–15. http://dx.doi.org/10.1155/2021/9975296.
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CO2 geological sequestration in shale is a promising method to mitigate global warming caused by greenhouse gas emissions as well as to enhance the gas recovery to some degree, which effectively addresses the problems related to energy demand and climate change. With the data from the New Albany Shale in the Illinois Basin in the United States, the CMG-GEM simulator is applied to establish a numerical model to evaluate the feasibility of CO2 sequestration in shale gas reservoirs with potential enhanced gas recovery (EGR). To represent the matrix, natural fractures, and hydraulic fractures in shale gas reservoirs, a multicontinua porous medium model will be developed. Darcy’s and Forchheimer’s models and desorption-adsorption models with a mixing rule will be incorporated into the multicontinua numerical model to depict the three-stage flow mechanism, including convective gas flow mainly in fractures, dispersive gas transport in macropores, and CH4-CO2 competitive sorption phenomenon in micropores. With the established shale reservoir model, different CO2 injection schemes (continuous injection vs. pulse injection) for CO2 sequestration in shale gas reservoirs are investigated. Meanwhile, a sensitivity analysis of the reservoir permeability between the hydraulic fractures of production and injection wells is conducted to quantify its influence on reservoir performance. The permeability multipliers are 10, 100, and 1,000 for the sensitivity study. The results indicate that CO2 can be effectively sequestered in shale reservoirs. But the EGR of both injection schemes does not perform well as expected. In the field application, it is necessary to take the efficiency of supplemental energy utilization, the CO2 sequestration ratio, and the effect of injected CO2 on the purity of produced methane into consideration to design an optimal execution plan. The case with a permeability multiplier of 1,000 meets the demand for both CO2 sequestration and EGR, which indicates that a moderate secondary stimulation zone needs to be formed between the primary hydraulic fractures of injection and production wells to facilitate the efficient energy transfer between interwell as well as to prevent CO2 from channeling. To meet the demand for CO2 sequestration in shale gas reservoirs with EGR, advanced and effective fracking is essential.
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Andlar, Martina, Damir Oros, Tonči Rezić, Roland Ludwig, and Božidar Šantek. "In-Situ Vacuum Assisted Gas Stripping Recovery System for Ethanol Removal from a Column Bioreactor." Fibers 6, no. 4 (November 9, 2018): 88. http://dx.doi.org/10.3390/fib6040088.
Full textAbstract:
A three-step process consisting of biomass hydrolysis, fermentation and in-situ gas stripping by a vacuum assisted recovery system, was optimized to increase the ethanol production from sugar beet pulp. The process combines the advantages of stripping and vacuum separation and enhances the fermentation productivity through in-situ ethanol removal. Using the design of experiment and response surface methodology, the effect of major factors in the process, such as pressure, recycling ratio and solids concentration, was tested to efficiently remove ethanol after the combined hydrolysis and fermentation step. Statistical analysis indicates that a decreased pressure rate and an increased liquid phase recycling ratio enhance the productivity and the yield of the strip-vacuum fermentation process. The results also highlight further possibilities of this process to improve integrated bioethanol production processes. According to the statistical analysis, ethanol production is strongly influenced by recycling ratio and vacuum ratio. Mathematical models that were established for description of investigated processes can be used for the optimization of the ethanol production.
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Lee, Jung Hun, Jeong Hwan Chun, Hyun-Jong Chung, and Wi Hyoung Lee. "Microstructural Control of Soluble Acene Crystals for Field-Effect Transistor Gas Sensors." Nanomaterials 12, no. 15 (July 26, 2022): 2564. http://dx.doi.org/10.3390/nano12152564.
Full textAbstract:
Microstructural control during the solution processing of small-molecule semiconductors (namely, soluble acene) is important for enhancing the performance of field-effect transistors (FET) and sensors. This focused review introduces strategies to enhance the gas-sensing properties (sensitivity, recovery, selectivity, and stability) of soluble acene FET sensors by considering their sensing mechanism. Defects, such as grain boundaries and crystal edges, provide diffusion pathways for target gas molecules to reach the semiconductor-dielectric interface, thereby enhancing sensitivity and recovery. Representative studies on grain boundary engineering, patterning, and pore generation in the formation of soluble acene crystals are reviewed. The phase separation and microstructure of soluble acene/polymer blends for enhancing gas-sensing performance are also reviewed. Finally, flexible gas sensors using soluble acenes and soluble acene/polymer blends are introduced, and future research perspectives in this field are suggested.