Готові списки джерел за темами / Enhance gas recovery

Добірка наукової літератури з теми "Enhance gas recovery"

Автор: Grafiati
Опубліковано: 10 грудня 2022
Оновлено: 28 січня 2023

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Статті в журналах з теми "Enhance gas recovery"

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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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Анотація:
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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3

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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4

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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Анотація:
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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5

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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Анотація:
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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Анотація:
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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8

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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Анотація:
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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9

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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Анотація:
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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10

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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Анотація:
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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Більше джерел

Дисертації з теми "Enhance gas recovery"

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Al-Abri, Abdullah S. "Enhanced gas condensate recovery by CO2 injection." Thesis, Curtin University, 2011. http://hdl.handle.net/20.500.11937/1770.

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Анотація:
Perhaps no other single theme offers such potential for the petroleum industry and yet is never fully embraced as enhanced hydrocarbon recovery. Thomas et al. (2009, p. 1) concluded their review article with “it appears that gas condensate reservoirs are becoming more important throughout the world. Many international petroleum societies are beginning to have conferences specifically oriented to gas condensate reservoirs and discussing all parameters germane to such systems.” Gas condensate reservoirs however, usually experience retrograde thermodynamic conditions when the pressure falls below the dewpoint pressure. Condensate liquid saturation builds up near the wellbore first and then propagates radially away along with the pressure drop. This liquid saturation throttles the flow of gas and thus reduces the productivity of a well by a factor of two to four (Afidick et al., 1994; Barnum et al., 1995; Smits et al., 2001; Ayyalasomayajulla et al., 2005). The severity of this decline is to a large extent related to fluid phase behaviour, flow regime (Darcy or non-Darcy), interfacial forces between fluids, capillary number, basic rock and fluid properties, wettability, gravitational forces as well as well type (well inclination, fractured or non-fractured).Thomas et al. (2009, p. 4) added “... for gas condensate systems which exhibit high interfacial tensions where the pore throats are very small, which may correspond either to low permeability rocks or high permeability rocks but with very large coordination number, the success of flowing the liquid from the rock, once it has condensed, will be limited. In such cases, vaporisation (lean gas cycling) or injection of interfacial tension reducing agents (CO2) may be the only option to enhance the performance.” In their comparison of several EOR mechanisms, Ollivier and Magot (2005, p. 217) reported “since large changes in viscous forces are only possible for the recovery of heavy oil, the reduction (or entire elimination) of interfacial forces by solvents such as injection gases seems to be a practical way to achieve large changes in capillary number.” While the majority of the state of the art publications cover sensational aspects of gas condensate reservoirs such as phase couplings and mass transfer between original reservoir components, very little has been reported on fluid dynamics and interfacial interactions of CO2 injection into such systems. This, along with the conceptual frameworks discussed above, serves as the motive for this research work.High pressure high temperature experimental laboratories that simulate reservoir static and thermodynamic conditions have been established to evaluate the: (1) effectiveness of CO2 injection into gas condensate reservoirs through interfacial tension (IFT) and spreading coefficients measurements at various reservoir conditions, (2) efficiency of the process through recovery performance and mobility ratio measurements; with special emphasis on the rate-dependent, IFT-dependent, and injection gas composition-dependant relative permeabilities, and (3) the behaviour of CO2 injection into gas condensate reservoirs on a field scale through numerical simulations in heterogeneous, anisotropic, fractured and faulted systems. The study also investigates the performance of various reservoir fluid thermodynamic conditions, injection design variables, and economic recovery factors associated with CO2 injection.Condensate recovery was found to be a strong function of CO2 injection pressure (and thus IFT), displacement flow rate, injection gas composition as well as phase behaviour and fluid properties. These parameters control the orientation and continuity of the fluid phases, solubility, gravity segregation, mobility ratio, and the ultimate recovery efficiency. Simulation analysis also suggests that developments of fractured gas condensate reservoirs depend to a large extent on initial reservoir thermodynamic conditions (initial pore pressure and fluid composition) as well as on production operations (natural depletion, waterflooding, continuous CO2 injection, gas injection after waterflooding GAW, or water alternating gas WAG).Much like the interrelation between accuracy and precision in science and engineering statistics, this research work draws a link between the effectiveness (quality metric through IFT measurements) and the efficiency (productivity metric through coreflooding experiments) of CO2 injection into gas condensate reservoirs. The data reported in this research work should help reservoir engineers better characterise gas condensate systems. The results can also aid the engineering design of CO2-EOR and CO2 sequestration projects.
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2

Sidiq, Hiwa H.-Amin. "Enhanced gas recovery by CO[subscript]2 injection." Thesis, Curtin University, 2010. http://hdl.handle.net/20.500.11937/1487.

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Анотація:
The central issue in the physical processes of enhanced gas recovery by carbon dioxide (CO[subscript]2) injection is the extent to which the natural gas will mix with the injected CO[subscript]2 and reduce the calorific value of the natural gas. Mixing in such a system is a diffusion-like process, which definitely depends on the physical properties of the displacing and displaced phases and the heterogeneity of the medium. However CO[subscript]2 undergoes a large change in density in the gas phase as it passes through the critical pressure at temperatures near the critical temperature. At the extreme reservoir conditions with pressure of 6000 psi and temperature of 160 ºC, CO[subscript]2 exhibits a greater viscosity and density when compared to methane. This variation is approximately a factor of three, which is in favour of the CO[subscript]2-natural gas displacement. In contrast, at near supercritical conditions of pressure of 1071 psi and temperature of 31 ºC, the CO[subscript]2 physical properties (viscosity and density) are slightly superior methane’s. Results indicated improved recovery efficiency was obtained with tests that were conducted at higher pore pressure, higher displacement speed and higher methane concentration in the in situ gas. In addition, low quality rock at a lower temperature of 95 ºC also showed better ultimate recovery.In this work, the first ever attempt for measuring interfacial tension (IFT) in a Gas- Gas system, namely supercritical carbon dioxide (SCO[subscript]2) and methane was made. Experiments were conducted at temperatures of 95 °C and 160 °C and pressures from 1000 to 6000 psia, using a modified reverse pendant drop method. It is common knowledge that a thermodynamically stable interface can only exist between two immiscible fluids, nonetheless an “immiscible interface” between two gases (CO[subscript]2- methane) has been observed and is documented within this research work.It was noted that the IFT decreased linearly with both temperature and pressure in the low-pressure range, but was less sensitive at higher pressures. There was a zone in the vicinity of 1500 psia and above that was noted to be independent of temperature where IFT increased sharply. The IFT was almost three times higher at 3000 psia, for the same temperature, compared with 1000 psia. This is attributed to the density of SCO[subscript]2 at 1000 psia being less than 1/3 the density at 3000 psia, at the same temperature.
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3

Prusty, Basanta Kumar. "Sorption behavior of coal for enhanced gas recovery and carbon sequestration /." Available to subscribers only, 2005. http://proquest.umi.com/pqdweb?did=1068249641&sid=13&Fmt=2&clientId=1509&RQT=309&VName=PQD.

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Анотація:
Thesis (Ph.D.)--Southern Illinois University Carbondale, 2005.
"Department of Mining and Mineral Resources Engineering." Includes bibliographical references (leaves 126-138). Also available online.
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4

Goudarzi, Salim. "Modelling enhanced gas recovery by CO₂ injection in partially-depleted reservoirs." Thesis, Durham University, 2016. http://etheses.dur.ac.uk/11645/.

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Анотація:
Carbon Capture and Storage (CCS) is considered as an important solution for CO₂ emission reduction, yet, the CO₂ capture process is highly costly. Thus, combining Enhanced Gas Recovery (EGR) with CCS could potentially offset the costs via additional production of natural gas. Therefore, the objective of this P.hD. is to build a numerical model to simulate CO₂-EGR in partially-depleted gas reservoirs; in particular Centrica Plc's North Morecame gas field. Our numerical model is based on the so-called Method of Lines (MOL) approach. MOL requires selecting a set of persistent Primary Dependent Variables (PDVs) to solve for. In this case, we chose to solve for pressure, temperature and component mass fractions. Additionally, MOL requires recasting of the governing equations in terms of the PDVs, which often requires the evaluation of partial derivative terms of the flow properties with respect to the PDVs. In this work, a method of analytical evaluation of these partial derivative terms is introduced. Furthermore, in a new approach, the mutual solubility correlations for mixtures of CO₂-H₂O and CH₄-H₂O, available in the literature, are joined together using straight lines as a ternary diagram, to form a ternary CO₂-CH₄-H₂O equilibrium model; the equilibrium-model's predictions matched well with the available experimental solubility data. 1D and 2D numerical simulations of CO₂-EGR were carried out. Overall, the 1D results were found to match very well with an existing analytical solution, predicting accumulation of a CH₄ bank ahead of the CO₂ plume and accurately locating the associated shock fronts while considering the partial miscibility of both CO₂ and CH₄ in H₂O. Based on the subsequent model predictions, in the North Morecambe field without drilling any additional wells, 0.6 out 2.3 BSCM, i.e., 26% of the remaining gas can potentially be recovered using CO₂-EGR.
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5

Vasilikou, Foteini. "Modeling CO2 Sequestration and Enhanced Gas Recovery in Complex Unconventional Reservoirs." Diss., Virginia Tech, 2014. http://hdl.handle.net/10919/64320.

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Анотація:
Geologic sequestration of CO2 into unmineable coal seams is proposed as a way to mitigate the greenhouse gas effect and potentially contribute to economic prosperity through enhanced methane recovery. In 2009, the Virginia Center for Coal and Energy Research (VCCER) injected 907 tonnes of CO2 into one vertical coalbed methane well for one month in Russell County, Virginia (VA). The main objective of the test was to assess storage potential of coal seams and to investigate the potential of enhanced gas recovery. In 2014, a larger scale test is planned where 20,000 tonnes of CO2 will be injected into three vertical coalbed methane wells over a period of a year in Buchanan County, VA. During primary coalbed methane production and enhanced production through CO2 injection, a series of complex physical and mechanical phenomena occur. The ability to represent the behavior of a coalbed reservoir as accurately as possible via computer simulations yields insight into the processes taking place and is an indispensable tool for the decision process of future operations. More specifically, the economic viability of projects can be assessed by predicting production: well performance can be maximized, drilling patterns can be optimized and, most importantly, associated risks with operations can be accounted for and possibly avoided. However, developing representative computer models and successfully simulating reservoir production and injection regimes is challenging. A large number of input parameters are required, many of which are uncertain even if they are determined experimentally or via in-situ measurements. Such parameters include, but are not limited to, seam geometry, formation properties, production constraints, etc. Modeling of production and injection in multi-seam formations for hydraulically fractured wells is a recent development in coalbed methane/enhanced coalbed methane (CBM/ECBM) reservoir modeling, where models become even more complex and demanding. In such cases model simulation times become important. The development of accurate simulation models that correctly account for the behavior of coalbeds in primary and enhanced production is a process that requires attention to detail, data validation, and model verification. A number of simplifying assumptions are necessary to run these models, where the user should be able to balance accuracy with computational time. In this thesis, pre- and post-injection simulations for the site in Russell County, VA, and preliminary reservoir simulations for the Buchanan County, VA, site are performed. The concepts of multi-well, multi-seam, explicitly modeled hydraulic fractures and skin factors are incorporated with field results to provide accurate modeling predictions.
Ph. D.
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6

Louk, Andrew Kyle. "Monitoring for Enhanced Gas and Liquids Recovery from a CO2 'Huff-and-Puff' Injection Test in a Horizontal Chattanooga Shale Well." Thesis, Virginia Tech, 2015. http://hdl.handle.net/10919/73806.

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Анотація:
Permanently sequestering carbon dioxide (CO2) in gas-bearing shale formations is beneficial in that it can mitigate greenhouse gas emissions as well as enhance gas recovery in production wells. This is possible due to the sorption properties of the organic material within shales and their greater affinity for CO2 over methane. The phenomenon of preferentially adsorbing CO2 while desorbing methane has been proven in coalbed reservoirs successfully, and is feasible for shale formations. The objective of this thesis is to explore the potential for enhanced gas recovery from gas-bearing shale formations by injecting CO2 into a targeted shale formation. With the advancement of technologies in horizontal drilling combined with hydraulic fracturing, shale gas has become a significant source of energy throughout the United States. With over 6,000 trillion cubic feet (Tcf) of theoretical gas-in-place, Appalachia has proven a major basin for gas production from organic shales. With its extensive shale reserves and lack of conventional reservoirs typically used for CO2 storage, Appalachia's unconventional reservoirs are favorable candidates for CO2 storage with enhanced gas recovery. Enhancing gas recovery not only increases reserves, but extends the life of mature wells and fields throughout the basin. As part of this research, 510 tons of CO2 were successfully injected into a horizontal production well completed in the Chattanooga shale formation, a late Devonian shale, in Morgan County, Tennessee. An extensive monitoring program was implemented during the pre-injection baseline, injection, soaking, and flowback phases of the test. Multiple fluorinated tracers were used to monitor for potential CO2 breakthrough at offset production wells and to help account for the CO2 once the well was flowed back. Results from this test, once the well was put back into normal production state, confirm the injectivity and storage potential of CO2 in shale formations, as well as an increase in gas production rate and quality of gas produced.
Master of Science
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7

Alonso, Benito Gerard. "Models and Computational Methods Applied to Industrial Gas Separation Processes and Enhanced Oil Recovery." Doctoral thesis, Universitat de Barcelona, 2019. http://hdl.handle.net/10803/668115.

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Анотація:
Two main topics are treated in this doctoral thesis from a theoretical and computational point of view: the gas capture and separation from post-combustion flue gases, and the enhanced oil recovery from oil reservoirs. The first topic evaluates the separation of CO2 using three different materials. First, several zeolites from the Faujasite family are studied with a combination of Density Functional Theory (DFT) and Monte Carlo methods. The former is employed to understand the driving mechanisms of adsorption, whereas the latter served to assess the separation of CO2 from a flue gas formed by a ternary mixture of CO2, N2 and O2. Second, the adsorption of CO2, N2 and SO2 into Mg-MOF-74 obtained through DFT calculations is presented to determine the most fundamental gas/MOF interactions. The results are then coupled to a Langmuir isotherm model to derive the macroscopic adsorption isotherms of the three gases in Mg-MOF-74. Finally, the absorption of CO2 and SO2 into three different phosphonium-based Ionic Liquids (ILs) is addressed by using the soft-SAFT equation of state and the COSMO-RS model. From the calculated adsorption/absorption isotherms several properties are obtained, such as the purity in the recovered gas, the working capacity of the materials and their selectivity to capture CO2 in the presence of other contaminant species. The main results obtained from this part of the thesis reveal that the cations of microporous materials are very strong sites of absorption for polar gases (i.e., the Na+ cations in Faujasites or the Mg2+ cations in Mg-MOF-74). This feature makes them very good candidates for CO2 capture, but they can be easily poisoned by other polar gases such as SO2. For this reason, it is highly recommended to desulphurize the flue gas before using any of these adsorbents. Similarly, ILs have higher affinity for SO2 than for CO2. However, the gas/IL interactions are significantly weaker, so they do not become poisoned by SO2. This fact implies that SO2 can be captured and separated from the flue gas by using a phosphonium-based IL. The second topic describes via Molecular Dynamics simulations the interactions of several model oils with different rocks and brines. The obtained insight can be applied in better understanding the interactions of the species present at oil reservoirs, with direct application in enhanced oil recovery processes. To that end, two wettability indicators are monitored to determine the potential recovery of the model oils. First, the oil/water interfacial tension (IFT) under different conditions of temperature, pressure and salinity (i.e., from pure water to 2.0 mol/kg of NaCl or CaCl2). And second, the oil/water/rock contact angle (CA) on calcite (10-14) and kaolinite (001) also as a function of salinity (i.e., from pure water to 2.0 mol/kg of NaCl or CaCl2). The different model oils are built with molecules of different chemical nature representing the Saturate/Aromatic/Resin/Asphaltene (SARA) fractionation model. In a final stage of the doctoral thesis the effect of non-ionic surfactants at the oil/brine IFT is also included. The main results obtained show that the most polar components of oil migrate to the oil/water interface and reduce the IFT. However, the same compounds feel attracted to the rock, who increase the CA and hamper the oil recovery. Some of these interactions are affected by the presence of salt. Specifically, if a water layer is formed between the oil and the rock in a reservoir, electrolytes can diffuse into it and attract the polar components of oil, ultimately increasing the CA. Finally, cations can be attracted to the oil/water interface due to salt/surfactant interactions. Both species interact synergistically to modify their orientation/distribution at the interface and reduce the oil/water IFT.
En aquesta tesi doctoral s’han tractat dos temes principals des d’una perspectiva teòrica i computacional: la captura i separació de gasos de post-combustió, i la recuperació millorada de petroli. El primer tema avalua la separació de CO2 utilitzant tres materials diferents. Primer, s’han estudiat diverses zeolites de la família de les Faujasites amb una combinació de teoria del funcional de la densitat (TFD) i mètodes Monte Carlo per entendre els mecanismes d’adsorció separació de CO2 d’una mescla ternària que conté CO2, N2 i O2. Seguidament, s’ha presentat un estudi TFD d’adsorció de CO2, N2 i SO2 en Mg-MOF-74 per determinar les interaccions fonamentals del MOF amb cada gas. Aquesta informació s’ha acoblat a un model d’isoterma de Langmuir per tal de derivar les isotermes d’adsorció macroscòpiques dels tres gasos en Mg-MOF-74. Finalment, s’ha analitzat l’absorció de CO2 i SO2 en tres Líquids Iònics (LIs) basats en fosfoni mitjançant l’equació d’estat soft-SAFT i el model COSMO-RS. D’altra banda, el segon tema descriu les interaccions de diferents models de petroli amb roques i salmorres, via simulacions de Dinàmica Molecular. El coneixement adquirit en aquesta part de la tesi doctoral es pot aplicar directament a la recuperació millorada de petroli i per entendre millor les interaccions de les espècies presents als pous. Amb aquesta finalitat, s’han controlat dos indicadors de la mullabilitat per determinar la recuperació potencial d’aquests models de petroli. Primer la tensió interfacial (TIF) oli/aigua sota diferents condicions de temperatura, pressió i salinitat (des d’aigua pura a 2.0 mol/kg de NaCl o CaCl2). I segon, l’angle de contacte oli/aigua/roca en calcita (10-14) i caolinita (001) en funció de la salinitat (des d’aigua pura a 2.0 mol/kg de NaCl o CaCl2). Els diferents models de petroli s’han construït amb molècules de diferent naturalesa química representant el model de fraccionament Saturat/Aromàtic/Resina/Asfaltè (SARA). En una etapa final de la tesi doctoral s’ha inclòs l’efecte en la TIF induïda pels surfactants no-iònics a la interfase oli/salmorra.
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8

Bongartz, Dominik. "Chemical kinetic modeling of oxy-fuel combustion of sour gas for enhanced oil recovery." Thesis, Massachusetts Institute of Technology, 2014. http://hdl.handle.net/1721.1/92224.

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Анотація:
Thesis: S.M., Massachusetts Institute of Technology, Department of Mechanical Engineering, 2014.
Cataloged from PDF version of thesis.
Includes bibliographical references (pages 135-147).
Oxy-fuel combustion of sour gas, a mixture of natural gas (primarily methane (CH 4 )), carbon dioxide (CO 2 ), and hydrogen sulfide (H 2 S), could enable the utilization of large natural gas resources, especially when combined with enhanced oil recovery (EOR). Chemical kinetic modeling can help to assess the potential of this approach. In this thesis, a detailed chemical reaction mechanism for oxy-fuel combustion of sour gas has been developed and applied for studying the combustion behavior of sour gas and the design of power cycles with EOR. The reaction mechanism was constructed by combining mechanisms for the oxidation of CH4 and H2S and optimizing the sulfur sub-mechanism. The optimized mechanism was validated against experimental data for oxy-fuel combustion of CH4, oxidation of H2S, and interaction between carbon and sulfur species. Improved overall performance was achieved through the optimization and all important trends were captured in the modeling results. Calculations with the optimized mechanism suggest that increasing H2 S content in the fuel tends to improve flame stability through a lower ignition delay time. Water diluted oxy-fuel combustion leads to higher burning velocities at elevated pressures than CO 2 dilution or air combustion, which also facilitates flame stabilization. In a mixed CH4 and H2S flame, H25 is oxidized completely as CH4 is converted to carbon monoxide (CO). During CO burnout, some highly corrosive sulfur trioxide (SO3 ) is formed. Quenching of SO 3 formation in the combustor can only be achieved at the expense of higher CO emissions. The modeling of a gas turbine cycle showed that oxy-fuel combustion leads to SO 3 concentrations that are one to two orders of magnitude lower than in air combustion and will thus suffer much less from the associated corrosion problems. Slightly fuel-rich operation is most promising for achieving the low CO and oxygen (02) concentrations required for EOR while further minimizing SO 3. Carbon dioxide dilution is better for achiving low 02 in the EOR stream while H20 gives the better combustion efficiency.
by Dominik Bongartz.
S.M.
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9

Gonzalez, Diaz Abigail. "Sequential supplementary firing in natural gas combined cycle plants with carbon capture for enhanced oil recovery." Thesis, University of Edinburgh, 2016. http://hdl.handle.net/1842/20483.

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The rapid electrification through natural gas in Mexico; the interest of the country to mitigate the effects of climate change; and the opportunity for rolling out Enhanced Oil Recovery at national level requires an important R&D effort to develop nationally relevant CCS technology in natural gas combined cycle power plants. Post-combustion carbon dioxide capture at gas-fired power plants is identified and proposed as an effective way to reduce CO2 emissions generated by the electricity sector in Mexico. In particular, gas-fired power plants with carbon dioxide capture and the sequential combustion of supplementary natural gas in the heat recovery steam generator can favourably increase the production of carbon dioxide, compared to a conventional configuration. This could be attractive in places with favourable conditions for enhanced oil recovery and where affordable natural gas prices will continue to exist, such as Mexico and North America. Sequential combustion makes use of the excess oxygen in gas turbine exhaust gas to generate additional CO2, but, unlike in conventional supplementary firing, allows keeping gas temperatures in the heat recovery steam generator below 820°C, avoiding a step change in capital costs. It marginally decreases relative energy requirements for solvent regeneration and amine degradation. Power plant models integrated with capture and compression process models of Sequential Supplementary Firing Combined Cycle (SSFCC) gas-fired units show that the efficiency penalty is 8.2% points LHV compared to a conventional natural gas combined cycle power plant with capture. The marginal thermal efficiency of natural gas firing in the heat recovery steam generator can increase with supercritical steam generation to reduce the efficiency penalty to 5.7% points LHV. Although the efficiency is lower than the conventional configuration, the increment in the power output of the combined steam cycle leads a reduction of the number of gas turbines, at a similar power output to that of a conventional natural gas combined cycle. This has a positive impact on the number of absorbers and the capital costs of the post-combustion capture plant by reducing the total volume of flue gas by half on a normalised basis. The relative reduction of overall capital costs is, respectively, 9.1% and 15.3% for the supercritical and the subcritical combined cycle configurations with capture compared to a conventional configuration. The total revenue requirement, a metric combining levelised cost of electricity and revenue from EOR, shows that, at gas prices of 2$/MMBTU and for CO2 selling price from 0 to 50 $/tonneCO2, subcritical and supercritical sequential supplementary firing presents favourably at 47.3-26 $/MWh and 44.6-25 $/MWh, respectively, compared with a conventional NGCC at 49.5-31.7 $/MWh. When operated at part-load, these configurations show greater operational flexibility by utilising the additional degree of freedom associated with the combustion of natural gas in the HRSG to change power output according to electricity demand and to ensure continuity of CO2 supply when exposed to variation in electricity prices. The optimisation of steady state part-load performance shows that reducing output by adjusting supplementary fuel keeps the gas turbine operating at full load and maximum efficiency when the net power plant output is reduced from 100% to 50%. For both subcritical and supercritical combined cycles, the thermal efficiency at part-load is optimised, in terms of efficiency, with sliding pressure operation of the heat recovery steam generator. Fixed pressure operation is proposed as an alternative for supercritical combined cycles to minimise capital costs and provide fast response rates with acceptable performance levels.
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10

Gilliland, Ellen. "Integrative Geophysical and Environmental Monitoring of a CO2 Sequestration and Enhanced Coalbed Methane Recovery Test in Central Appalachia." Diss., Virginia Tech, 2016. http://hdl.handle.net/10919/73552.

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A storage and enhanced coalbed methane (CO2-ECBM) test will store up to 20,000 tons of carbon dioxide in a stacked coal reservoir in southwest Virginia. The test involves two phases of CO2 injection operations. Phase I was conducted from July 2, 2015 to April 15, 2016, and injected a total of 10, 601 tons of CO2. After a reservoir soaking period of seven months, Phase II is scheduled to begin Fall 2016. The design of the monitoring program for the test considered several site-specific factors, including a unique reservoir geometry, challenging surface terrain, simultaneous CBM production activities which complicate the ability to attribute signals to sources. A multi-scale approach to the monitoring design incorporated technologies deployed over different, overlapping spatial and temporal scales selected for the monitoring program include dedicated observation wells, CO2 injection operations monitoring, reservoir pressure and temperature monitoring, gas and formation water composition from offset wells tracer studies, borehole liquid level measurement, microseismic monitoring, surface deformation measurement, and various well logs and tests. Integrated interpretations of monitoring results from Phase I of the test have characterized enhanced permeability, geomechanical variation with depth, and dynamic reservoir injectivity. Results have also led to the development of recommended injection strategy for CO2-ECBM operations. The work presented here describes the development of the monitoring program, including design considerations and rationales for selected technologies, and presents monitoring results and interpretations from Phase I of the test.
Ph. D.
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Книги з теми "Enhance gas recovery"

1

Wu, Ying, John J. Carroll, and Qi Li, eds. Gas Injection for Disposal and Enhanced Recovery. Hoboken, NJ, USA: John Wiley & Sons, Inc., 2014. http://dx.doi.org/10.1002/9781118938607.

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2

Ti gao shi you cai shou lü li lun yu shi jian wen ji. Beijing: Shi you gong ye chu ban she, 2011.

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3

Specified gas emitters regulation: Quantification protocol for enhanced oil recovery. [Edmonton]: Alberta Environment, 2007.

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4

Specified gas emitters regulation: Quantification protocol for enhanced oil recovery - streamlined. [Edmonton]: Alberta Environment, 2007.

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5

Khosrokhavar, Roozbeh. Mechanisms for CO2 Sequestration in Geological Formations and Enhanced Gas Recovery. Cham: Springer International Publishing, 2016. http://dx.doi.org/10.1007/978-3-319-23087-0.

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6

Kuhn, Michael. CLEAN: CO2 Large-Scale Enhanced Gas Recovery in the Altmark Natural Gas Field - GEOTECHNOLOGIEN Science Report No. 19. Berlin, Heidelberg: Springer Berlin Heidelberg, 2013.

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7

Pembina cardium CO2 monitoring pilot: A CO2-EOR project, Alberta, Canada : final report. Sherwood Park, Alta: Geoscience Publishing, 2009.

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8

United States. Congress. Senate. Committee on Finance. Subcommittee on Energy and Agricultural Taxation. Description of S. 828 (Enhanced Oil and Gas Recovery Tax Act of 1989): Scheduled for a hearing before the Subcommittee on Energy and Agricultural Taxation of the Senate Committee on Finance on August 3, 1989. [Washington, D.C: Joint Committee on Taxation, 1989.

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9

United States Environmental Protect Epa. Enhanced Gob Gas Recovery. Independently Published, 2019.

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10

Frenier, Wayne W., and Murtaza Ziauddin. Chemistry for Enhancing the Production of Oil and Gas. Society of Petroleum Engineers, 2013. http://dx.doi.org/10.2118/9781613993170.

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Providing an overview of the science and technology of the use of production chemicals to enhance and maintain oil and gas production, Chemistry for Enhancing the Production of Oil and Gas is geared towards a technically trained audience. Readers will find a review of the important chemical and physical principles that are common to most, if not all, of the enhancement treatments. The authors also discuss aspects of the use and mechanisms of the complex chemistries that take place with the application of flow assurance chemicals, during stimulation (reactive chemistry and prop fracturing) and chemically improved oil recovery, including the use of chemical tracers. A final chapter emphasizes the importance of health, safety, and environmental compliance in all aspects of oilfield treatments. Most of the chapters found within end with a section where successful chemical enhancement or control methods have been used to solve specific production problems.
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Частини книг з теми "Enhance gas recovery"

1

Xie, Shan, Jin-bu Li, Yang Jiao, Lin Li, and Yong Wu. "Key Technologies for Enhance Gas Recovery of Large Low Permeability Heterogeneous Carbonate Gas Reservoirs." In Proceedings of the International Field Exploration and Development Conference 2021, 2976–87. Singapore: Springer Nature Singapore, 2022. http://dx.doi.org/10.1007/978-981-19-2149-0_277.

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2

Sulak, R. M., G. R. Nossa, and D. A. Thompson. "Ekofisk Field Enhanced Recovery." In North Sea Oil and Gas Reservoirs—II, 281–95. Dordrecht: Springer Netherlands, 1990. http://dx.doi.org/10.1007/978-94-009-0791-1_24.

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3

De Bauw, R., E. Millich, J. P. Joulia, D. Van Asselt, and J. W. Bronkhorst. "Secondary and Enhanced Recovery." In European Communities Oil and Gas Technological Development Projects, 183–244. Dordrecht: Springer Netherlands, 1987. http://dx.doi.org/10.1007/978-94-009-3247-0_4.

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4

Anwar, M. Rafay, N. Wayne McKay, and Jim R. Maddocks. "Enhanced Gas Dehydration Using Methanol Injection in an Acid Gas Compression System." In Gas Injection for Disposal and Enhanced Recovery, 129–51. Hoboken, NJ, USA: John Wiley & Sons, Inc., 2014. http://dx.doi.org/10.1002/9781118938607.ch8.

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5

Sun, Duo, Nagu Daraboina, John Ripmeester, and Peter Englezos. "Capture of CO2and Storage in Depleted Gas Reservoirs in Alberta as Gas Hydrate." In Gas Injection for Disposal and Enhanced Recovery, 305–10. Hoboken, NJ, USA: John Wiley & Sons, Inc., 2014. http://dx.doi.org/10.1002/9781118938607.ch17.

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6

Sun, Chang-Yu, Jun Chen, Ke-Le Yan, Sheng-Li Li, Bao-ZiPeng, and Guang-Jin Chen. "Evaluating and Testing of Gas Hydrate Anti-Agglomerants in (Natural Gas + Diesel Oil + Water) Dispersed System." In Gas Injection for Disposal and Enhanced Recovery, 381–86. Hoboken, NJ, USA: John Wiley & Sons, Inc., 2014. http://dx.doi.org/10.1002/9781118938607.ch23.

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7

Roberts, Erin L., and John J. Carroll. "Densities of Carbon Dioxide-Rich Mixtures Part I: Comparison with Pure CO2." In Gas Injection for Disposal and Enhanced Recovery, 1–28. Hoboken, NJ, USA: John Wiley & Sons, Inc., 2014. http://dx.doi.org/10.1002/9781118938607.ch1.

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8

Tomcej, Ray A. "Post-Combustion Carbon Capture Using Aqueous Amines: A Mass-Transfer Study." In Gas Injection for Disposal and Enhanced Recovery, 177–92. Hoboken, NJ, USA: John Wiley & Sons, Inc., 2014. http://dx.doi.org/10.1002/9781118938607.ch10.

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9

Rigby, Sean, Gerd Modes, Stevan Jovanovic, John Wei, Koji Tanaka, Peter Moser, and Torsten Katz. "BASF Technology for CO2Capture and Regeneration." In Gas Injection for Disposal and Enhanced Recovery, 193–226. Hoboken, NJ, USA: John Wiley & Sons, Inc., 2014. http://dx.doi.org/10.1002/9781118938607.ch11.

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10

Engel, David, and Michael H. Sheilan. "Seven Deadly Sins of Filtration and Separation Systems in Gas Processing Operations." In Gas Injection for Disposal and Enhanced Recovery, 227–41. Hoboken, NJ, USA: John Wiley & Sons, Inc., 2014. http://dx.doi.org/10.1002/9781118938607.ch12.

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Тези доповідей конференцій з теми "Enhance gas recovery"

1

Xue, Ming, Xingchun Li, Xiangyu Cui, Qi Wang, Shuangxing Liu, Jiale Zheng, and Yilin Wang. "A Pilot Demonstration of Flaring Gas Recovery During Shale Gas Well Completion in China." In International Petroleum Technology Conference. IPTC, 2022. http://dx.doi.org/10.2523/iptc-22290-ms.

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Abstract Objectives/Scope As one of the largest emitters in the world, the oil and gas industry needs more efforts on greenhouse gas reduction. Methane, as a potent greenhouse gas, could largely determine whether natural gas could serve as a bridging energy towards a sustainable future. In the past decade, the oil and gas companies in China has significantly enhanced casing gas recovery and reduced large volume of flaring (>20k m3/day). However, the remaining low- to mid- volume flaring gas were left for further recovery. Methods, Procedures, Process Shale gas production in China has met a surge in the number of drilling wells. Those new wells were characterized by a relatively low gas production rate (<1 mill m3/day), in comparison with the shale gas well in the US. As a result, flaring gas during well completion needs to be recycled or used so as to enhance the gas recovery rate. In this study, a pilot demonstration project of flaring gas recovery was carried out to reduce greenhouse gas emission in Weiyuan shale gas region in Sichuan province, China. The technical route of dehydration and natural gas compression was adopted. The recycled natural gas was transformed into compressed natural gas (CNG) and transported to the nearest CNG station for further use. Results, Observations, Conclusions The inlet gas pressure were between 2.85 to 5.82 MPa and the outlet pressure were kept stable around 20 MPa to meet the standard of CNG. The minimum dew point temperature was -65.5 °C and the outlet temperature rise remained below 23 °C. The manufactured device also showed a sound flexibility with recover rate between 523.22 to 1224.38 m3/h, which was the 28% to 157% of the designed capacity. An overall of 21k of natural gas was recoverd. Novel/Additive Information For a single well completion event, a total of 50k of natural gas could be recovered by this device. The device applied in the pilot demonstration has well matched with the local transportation, gas composition, and surface engineering of the well completion and has the potential of popularization and application in the shale gas region in Sichuan. In that case, it could reach a future economic return over 0.6 billion RMB.
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2

Meng, Xingbang, and James J. Sheng. "Experimental Study on Revaporization Mechanism of Huff-n-Puff Gas Injection to Enhance Condensate Recovery in Shale Gas Condensate Reservoirs." In SPE Improved Oil Recovery Conference. Society of Petroleum Engineers, 2016. http://dx.doi.org/10.2118/179537-ms.

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3

Boerrigter, P. M., M. L. Verlaan, and D. Yang. "EOR Methods to Enhance Gas Oil Gravity Drainage - Modeling Aspects." In IOR 2007 - 14th European Symposium on Improved Oil Recovery. European Association of Geoscientists & Engineers, 2007. http://dx.doi.org/10.3997/2214-4609-pdb.24.b20.

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4

Qutob, Hani H., and Ian Retalic. "Do Advanced Drilling Techniques Really Add Reserves and Enhance Recovery?" In SPE Kuwait Oil and Gas Show and Conference. Society of Petroleum Engineers, 2013. http://dx.doi.org/10.2118/167316-ms.

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5

Wang, Deyou, Tao Zhu, Demin Chen, Feng Bao, and David Olsen. "Gas-Steam Slug Flooding to Enhance Recovery from a Medium Heavy Oil Reservoir." In SPE/DOE Improved Oil Recovery Symposium. Society of Petroleum Engineers, 2000. http://dx.doi.org/10.2118/59332-ms.

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6

Jia, Ying, Yunqing Shi, and Jin Yan. "The Feasibility Appraisal for CO2 Enhanced Gas Recovery of Tight Gas Reservoir: Case Analysis and Economic Evaluation." In International Petroleum Technology Conference. IPTC, 2021. http://dx.doi.org/10.2523/iptc-21291-ms.

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Abstract Tight gas reservoirs are widely distributed in China, which occupies one-third of the total resources of natural gas. The typical development method is under primary depletion. However, the recovery of tight gas is only around 20%. It is necessary to explore a new technique to improve tight gas recovery. Injecting CO2 into tight gas reservoirs is a novel trial to enhance gas recovery. The objective of this work is to verify and evaluate the effect supercritical CO2 on enhancing gas recovery and analyze the feasibility of CO2 enhance gas recovery of tight gas reservoir. Taken DND tight sandstone gas reservoir in North China as an example, 34 wells of DK13 wellblock were chosen as CO2 Enhanced gas recovery pilot area with 10-year production history. Six injection scenarios were studied. Numerical simulation indicated that the recovery of the gas reservoir of DK13 well area was improved by 8-9.5 percent when CO2 content of producers reaches 10 percent. The annual CO2 Storage would be 62 million cubic meters (110 thousand tons) and the total CO2 storage would be around 800million cubic meters (1.5 million tons). After the environmental parameter evaluation of injectors and producers, the anticorrosion schemes were put forward and the feasibility evaluation and schemes of facilities were presented. The analysis results indicated that DK13 wellblock was suitable for CO2 enhanced gas recovery no matter geologic condition, injection & production technology and facilities. However, under the current economic conditions, DK13 wellblock was not suitable for CO2to enhance gas recovery. However, if gas price rise or low carbon strategy implement, the pilot test could be carried out. In brief, CO2 could be an attractive option to successfully displace natural gas and decrease CO2 emissions, which is a promising technology for reducing greenhouse gas emission and increasing the ultimate gas recovery of tight gas reservoirs. This economic analysis, along with reservoir simulation and laboratory studies that suggest the technical feasibility of CSEGR, demonstrates that CSEGR can be feasible and that a field pilot study of the process should be undertaken to test the concept further.
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7

Ali, Tarek, Karim Youssef, and Michael Fraim. "Peripheral Co2 Flooding To Enhance Gas Recovery In Carbonate Reservoir." In Qatar Foundation Annual Research Conference Proceedings. Hamad bin Khalifa University Press (HBKU Press), 2014. http://dx.doi.org/10.5339/qfarc.2014.eepp1097.

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8

Haq, Bashirul, Md Abdul Aziz, Abbas Saeed Hakeem, Yazan G. Mheibesh, Mohammed Ameen Ahmed, and Dhafer Al Shehri. "Date-Leaf Carbon Micro-Nanostructured Particles DLCMNPs for Enhance Oil Recovery." In SPE Middle East Oil and Gas Show and Conference. Society of Petroleum Engineers, 2019. http://dx.doi.org/10.2118/194789-ms.

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9

Nisha, Gulshan, and Ch Geeta Harini. "Enhance Recovery of Methane from Gas Hydrate Reservoirs with CO2 sequestration." In Abu Dhabi International Petroleum Conference and Exhibition. Society of Petroleum Engineers, 2012. http://dx.doi.org/10.2118/162521-ms.

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10

Srivastava, Piyush, and Leo U. Castro. "Successful Field Application of Surfactant Additives to Enhance Thermal Recovery of Heavy Oil." In SPE Middle East Oil and Gas Show and Conference. Society of Petroleum Engineers, 2011. http://dx.doi.org/10.2118/140180-ms.

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Звіти організацій з теми "Enhance gas recovery"

1

McGrail, B. Peter, Herbert T. Schaef, Mark D. White, Tao Zhu, Abhijeet S. Kulkarni, Robert B. Hunter, Shirish L. Patil, Antionette T. Owen, and P. F. Martin. Using Carbon Dioxide to Enhance Recovery of Methane from Gas Hydrate Reservoirs: Final Summary Report. Office of Scientific and Technical Information (OSTI), September 2007. http://dx.doi.org/10.2172/929209.

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2

Asvapathanagul, Pitiporn, Leanne Deocampo, and Nicholas Banuelos. Biological Hydrogen Gas Production from Food Waste as a Sustainable Fuel for Future Transportation. Mineta Transportation Institute, July 2022. http://dx.doi.org/10.31979/mti.2021.2141.

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Анотація:
In the global search for the right alternative energy sources for a more sustainable future, hydrogen production has stood out as a strong contender. Hydrogen gas (H2) is well-known as one of the cleanest and most sustainable energy sources, one that mainly yields only water vapor as a byproduct. Additionally, H2 generates triple the amount of energy compared to hydrocarbon fuels. H2 can be synthesized from several technologies, but currently only 1% of H2 production is generated from biomass. Biological H2 production generated from anaerobic digestion is a fraction of the 1%. This study aims to enhance biological H2 production from anaerobic digesters by increasing H2 forming microbial abundance using batch experiments. Carbon substrate availability and conversion in the anaerobic processes were achieved by chemical oxygen demand and volatile fatty acids analysis. The capability of the matrix to neutralize acids in the reactors was assessed using alkalinity assay, and ammonium toxicity was monitored by ammonium measurements. H2 content was also investigated throughout the study. The study's results demonstrate two critical outcomes, (i) food waste as substrate yielded the highest H2 gas fraction in biogas compared to other substrates fed (primary sludge, waste activated sludge and mixed sludge with or without food waste), and (ii) under normal operating condition of anaerobic digesters, increasing hydrogen forming bacterial populations, including Clostridium spp., Lactococcus spp. and Lactobacillus spp. did not prolong biological H2 recovery due to H2 being taken up by other bacteria for methane (CH4) formation. Our experiment was operated under the most optimal condition for CH4 formation as suggested by wastewater operational manuals. Therefore, CH4-forming bacteria possessed more advantages than other microbial populations, including H2-forming groups, and rapidly utilized H2 prior to methane synthesis. This study demonstrates H2 energy renewed from food waste anaerobic digestion systems delivers opportunities to maximize California’s cap-and-trade program through zero carbon fuel production and utilization.
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3

Asvapathanagul, Pitiporn, Leanne Deocampo, and Nicholas Banuelos. Biological Hydrogen Gas Production from Food Waste as a Sustainable Fuel for Future Transportation. Mineta Transportation Institute, July 2022. http://dx.doi.org/10.31979/mti.2022.2141.

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Анотація:
In the global search for the right alternative energy sources for a more sustainable future, hydrogen production has stood out as a strong contender. Hydrogen gas (H2) is well-known as one of the cleanest and most sustainable energy sources, one that mainly yields only water vapor as a byproduct. Additionally, H2 generates triple the amount of energy compared to hydrocarbon fuels. H2 can be synthesized from several technologies, but currently only 1% of H2 production is generated from biomass. Biological H2 production generated from anaerobic digestion is a fraction of the 1%. This study aims to enhance biological H2 production from anaerobic digesters by increasing H2 forming microbial abundance using batch experiments. Carbon substrate availability and conversion in the anaerobic processes were achieved by chemical oxygen demand and volatile fatty acids analysis. The capability of the matrix to neutralize acids in the reactors was assessed using alkalinity assay, and ammonium toxicity was monitored by ammonium measurements. H2 content was also investigated throughout the study. The study's results demonstrate two critical outcomes, (i) food waste as substrate yielded the highest H2 gas fraction in biogas compared to other substrates fed (primary sludge, waste activated sludge and mixed sludge with or without food waste), and (ii) under normal operating condition of anaerobic digesters, increasing hydrogen forming bacterial populations, including Clostridium spp., Lactococcus spp. and Lactobacillus spp. did not prolong biological H2 recovery due to H2 being taken up by other bacteria for methane (CH4) formation. Our experiment was operated under the most optimal condition for CH4 formation as suggested by wastewater operational manuals. Therefore, CH4-forming bacteria possessed more advantages than other microbial populations, including H2-forming groups, and rapidly utilized H2 prior to methane synthesis. This study demonstrates H2 energy renewed from food waste anaerobic digestion systems delivers opportunities to maximize California’s cap-and-trade program through zero carbon fuel production and utilization.
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4

Watts, R. J. Gas miscible displacement enhanced oil recovery: Technology status report. Edited by C. A. Komar. Office of Scientific and Technical Information (OSTI), January 1989. http://dx.doi.org/10.2172/5862401.

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5

Northrop, D. Enhanced gas recovery bibliography, Sandia National Laboratories, December 1975--December 1989. Office of Scientific and Technical Information (OSTI), April 1990. http://dx.doi.org/10.2172/7179808.

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6

Rebscher, Dorothee, and Curtis M. Oldenburg. Sequestration of Carbon Dioxide with Enhanced Gas Recovery-CaseStudy Altmark, North German Basin. Office of Scientific and Technical Information (OSTI), October 2005. http://dx.doi.org/10.2172/918807.

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7

Yegin, Cengiz, Nirup Nagabandi, and Mustafa Akbulut. Thermo- and pH-responsive Supramolecular Gelling Agents for Enhanced Oil and Natural Gas Recovery from Tight Formations. Office of Scientific and Technical Information (OSTI), June 2019. http://dx.doi.org/10.2172/1527099.

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8

Baroni, M. Applications of advanced petroleum production technology and water alternating gas injection for enhanced oil recovery - Mattoon Oil Field, Illinois. Final report. Office of Scientific and Technical Information (OSTI), September 1995. http://dx.doi.org/10.2172/73038.

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9

Baroni, M. R. Applications of advanced petroleum production technology and water alternating gas injection for enhanced oil recovery: Mattoon Oil Field, Illinois. Quarterly report. Office of Scientific and Technical Information (OSTI), September 1993. http://dx.doi.org/10.2172/10131182.

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10

Baroni, M. R. Applications of advanced petroleum production technology and water alternating gas injection for enhanced oil recovery: Mattoon Oil Field, Illinois. [Quarterly report], January--March 1994. Office of Scientific and Technical Information (OSTI), April 1994. http://dx.doi.org/10.2172/10160630.

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