Thematische Bibliographien / Depleted gas reservoirs

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Auswahl der wissenschaftlichen Literatur zum Thema „Depleted gas reservoirs“

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Veröffentlicht am 24. April 2025

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Zeitschriftenartikel zum Thema "Depleted gas reservoirs"

Khaksar, Abbas, Adrian White, Khalilur Rahman, Katharine Burgdorff, Reinaldo Ollarves und Steve Dunmore. „Systematic geomechanical evaluation for short-term gas storage in depleted reservoirs“. APPEA Journal 52, Nr. 1 (2012): 129. http://dx.doi.org/10.1071/aj11010.

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Depleted hydrocarbon reservoirs are attractive targets for short-term gas storage with frequent injection and production cycles. Optimum well completion and injection-storage-production design in depleted reservoirs would require an understanding of important rock mechanical issues. These include drilling and completion challenges of new wells in low-pressure reservoirs accounting for potential rock fatigue due to cyclic injection/depletion and loading and unloading, and determination of maximum sustainable storage pressures that would avoid fracturing and fault reactivation. This paper describes a case study from a coal seam gas project considered for supply to a liquefied natural gas plant in Australia. The paper demonstrates a systematic approach for geomechanical risk assessments for short-term gas storage in depleted sandstone reservoirs. Depleted sandstone gas reservoirs at a depth of 1,000 m with existing pressures of 150–300 psi are considered in this study. Historical and new well data including cores, well logs, drilling, and field data such as injection and minifracture (minifrac) tests are used to develop a field-specific geomechanical model. Field data and laboratory measurements of rock mechanical properties are used to define the stress path factors and the change in in situ stress with depletion and injection in sandstone reservoirs in the study area. Rock mechanics tests on representative core plugs under cyclic loading and unloading simulating operating depletion and injection pressure conditions are used to assess the level of rock fatigue and rock weakening under cyclic loading. Geomechanical analyses show that despite a low fracture gradient in depleted reservoirs and the presence of non-depleted overburden rocks, new high-angled wells can be drilled safely with a relatively low mud weight in the non-depleted sections and with air in the reservoir section. Fracturing and faulting assessments confirm the critical pressures for fault reactivation and fracturing of intact rocks are beyond the planned storage pressures, and a maximum pressure of 200–300 psi beyond the initial reservoir pressures may be possible from fracturing or fault reactivation aspects. Sand production prediction evaluations indicate that new injection-production wells can be completed with no downhole sand control due to a very low risk of sanding even after considering rock weakening associated with cyclic loading. The methodology and overall workflow presented in this paper can be applied when carrying out geomechanical risk assessments for natural gas storage in depleted reservoirs.

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Albadan, Deema, Mojdeh Delshad, Bruno Ramon Batista Fernandes, Esmail Eltahan und Kamy Sepehrnoori. „Analytical Estimation of Hydrogen Storage Capacity in Depleted Gas Reservoirs: A Comprehensive Material Balance Approach“. Applied Sciences 14, Nr. 16 (13.08.2024): 7087. http://dx.doi.org/10.3390/app14167087.

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The efficient use of depleted gas reservoirs for hydrogen storage is a promising solution for transitioning to carbon-neutral energy sources. This study proposes an analytical framework for estimating hydrogen storage capacity using a comprehensive material balance approach in depleted gas reservoirs. The methodology integrates basic reservoir engineering principles with thermodynamic considerations to accurately estimate hydrogen storage capacity in both volumetric drive and water drive gas reservoirs through an iterative approach based on mass conservation and the real gas law. This framework is implemented in a Python program, using the CoolProp library for phase behavior modeling with the Soave–Redlich–Kwong (SRK) equation of state. The methodology is validated with numerical simulations of a tank model representing the two reservoir drive mechanisms discussed. Also, a case study of a synthetic complex reservoir demonstrates the applicability of the proposed approach to real-world scenarios. The findings suggest that precise modeling of fluid behavior is crucial for reliable capacity estimations. The proposed analytical framework achieves an impressive accuracy, with deviations of less than 1% compared to estimates obtained through numerical simulations. Insights derived from this study can significantly contribute to the assessment of strategic decisions for utilizing depleted gas reservoirs for hydrogen storage.

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Xiang, Jinyuan, Tuo Wei, Fengqing Lv, Jie Shen, Hai Liu, Xiaoliang Zhao und Jiuzhi Sun. „Research on the Injection–Production Law and the Feasibility of Underground Natural Gas Storage in a Low-Permeability Acid-Containing Depleted Gas Reservoir“. Processes 12, Nr. 10 (14.10.2024): 2240. http://dx.doi.org/10.3390/pr12102240.

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Depleted gas reservoirs are important places for the rebuilding of gas-storage reservoirs. In order to demonstrate the feasibility of constructing and operating such underground gas storage, a low-permeability gas-storage seepage model considering fracture development was developed and established. The model was solved using semi-analytical methods, and the pressure–response characteristics during natural gas injection were analyzed. The impact of gas injection volume on formation pressure has been clarified, and the calculation method for ultimate injection pressure has been determined. Additionally, through numerical simulation methods, the migration law of acidic gas during gas injection, the variation law of produced acidic gas concentration, and the main control factors affecting the concentration of the produced acidic gas were studied. Furthermore, measures to reduce the concentration of the acidic gas produced were proposed. Finally, injection and production plans were designed for typical depleted acidic gas reservoirs, simulating the operation of gas storage for 12 cycles. The results indicate that the quality of natural gas produced in the third cycle can meet the Class II standard for commercial natural gas. Through this study, the feasibility of constructing gas-storage facilities for acidic depleted gas reservoirs has been demonstrated, and injection and production strategies for this type of gas reservoir have been proposed.

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Heidarabad, Reyhaneh Ghorbani, und Kyuchul Shin. „Carbon Capture and Storage in Depleted Oil and Gas Reservoirs: The Viewpoint of Wellbore Injectivity“. Energies 17, Nr. 5 (02.03.2024): 1201. http://dx.doi.org/10.3390/en17051201.

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Recently, there has been a growing interest in utilizing depleted gas and oil reservoirs for carbon capture and storage. This interest arises from the fact that numerous reservoirs have either been depleted or necessitate enhanced oil and gas recovery (EOR/EGR). The sequestration of CO2 in subsurface repositories emerges as a highly effective approach for achieving carbon neutrality. This process serves a dual purpose by facilitating EOR/EGR, thereby aiding in the retrieval of residual oil and gas, and concurrently ensuring the secure and permanent storage of CO2 without the risk of leakage. Injectivity is defined as the fluid’s ability to be introduced into the reservoir without causing rock fracturing. This research aimed to fill the gap in carbon capture and storage (CCS) literature by examining the limited consideration of injectivity, specifically in depleted underground reservoirs. It reviewed critical factors that impact the injectivity of CO2 and also some field case data in such reservoirs.

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Oshita, Toshiya. „Utilization of depleted Gas/Oil reservoirs.“ Journal of the Japanese Association for Petroleum Technology 67, Nr. 6 (2002): 538–46. http://dx.doi.org/10.3720/japt.67.538.

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Uliasz-Misiak, Barbara, Joanna Lewandowska-Śmierzchalska und Rafał Matuła. „Hydrogen Storage Potential in Natural Gas Deposits in the Polish Lowlands“. Energies 17, Nr. 2 (11.01.2024): 374. http://dx.doi.org/10.3390/en17020374.

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In the future, the development of a zero-carbon economy will require large-scale hydrogen storage. This article addresses hydrogen storage capacities, a critical issue for large-scale hydrogen storage in geological structures. The aim of this paper is to present a methodology to evaluate the potential for hydrogen storage in depleted natural gas reservoirs and estimate the capacity and energy of stored hydrogen. The estimates took into account the recoverable reserves of the reservoirs, hydrogen parameters under reservoir conditions, and reservoir parameters of selected natural gas reservoirs. The theoretical and practical storage capacities were assessed in the depleted natural gas fields of N and NW Poland. Estimates based on the proposed methodology indicate that the average hydrogen storage potential for the studied natural gas fields ranges from 0.01 to 42.4 TWh of the hydrogen energy equivalent. Four groups of reservoirs were distinguished, which differed in recovery factor and technical hydrogen storage capacity. The issues presented in the article are of interest to countries considering large-scale hydrogen storage, geological research organizations, and companies generating electricity from renewable energy sources.

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Gao, Guangliang, Wei Liu, Shijie Zhu, Haiyan He, Qunyi Wang, Yanchun Sun, Qianhua Xiao und Shaochun Yang. „Discussion on the Reconstruction of Medium/Low-Permeability Gas Reservoirs Based on Seepage Characteristics“. Processes 10, Nr. 4 (13.04.2022): 756. http://dx.doi.org/10.3390/pr10040756.

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The construction of underground gas storage mostly focuses on depleted gas reservoirs. However, the depleted gas reservoir used to build underground gas storage in China is located far from the main gas consumption economic zone. It is necessary to reconstruct underground gas storage using nearby reservoirs in order to meet the needs of economic development. The complex three-phase seepage characteristics encountered in the process of reconstruction of underground gas storage reservoirs seriously affect their storage and injection production capacities. Combined with the mechanism of multiphase seepage and the multicycle injection production mode during the process of gas storage construction, the feasibility of rebuilding gas storage in medium- and low-permeability reservoirs was evaluated through relative permeability experiments and core injection production experiments. The results showed that the mutual driving of two-phase oil–water systems will affect the storage space and seepage capacity, that the adverse effect will be weakened after multiple cycles, and that increasing the gas injection cycle can enhance the gas-phase seepage capacity and improve the crude oil recovery. Therefore, we found that it is feasible to reconstruct underground gas storage in medium- and low-permeability reservoirs, which lays a foundation for the development of underground gas storage in China.

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Howard, D. „UNDERGROUND GAS STORAGE-LEGAL ANT REGULATORY REQUIREMENTS IN AUSTRALIA“. APPEA Journal 39, Nr. 1 (1999): 663. http://dx.doi.org/10.1071/aj98045.

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The storage of gas in underground naturally occurring reservoirs takes place in a variety of forms and for a variety of reasons. In many jurisdictions within Australia, the regulatory framework to deal properly with underground gas storage requires attention and, in some cases, significant refinement. Underground natural reservoir storage of gas in Australia is an option which is being increasingly investigated as fields close to infrastructure (such as pipelines and processing plants) become depleted and alternative uses are sought for those depleted reservoirs. In addition, gas storage may give flexibility to spot gas sales and other commercial operations, and facilitate greater market sophistication. Accordingly, it is important for the industry in Australia to understand the legal implications and their impact on this type of storage.

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Kondrat, R. M., und L. I. Khaidarova. „Approbation of the technology for displacing residual gas with nitrogen for the conditions of a depleted gas reservoir in the VS-9 horizon of the Lyubeshivske gas field“. Prospecting and Development of Oil and Gas Fields, Nr. 2(75) (31.08.2020): 16–23. http://dx.doi.org/10.31471/1993-9973-2020-2(75)-16-23.

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Most natural gas reservoirs of Ukraine are depleted to some extent; still they contain significant tail gas reserves. A promising direction for increasing gas recovery from depleted gas reservoirs is the displacement of tail gas from the porous medium with nitrogen which is easily accessible and does not cause corrosion of the down-hole equipment. This article characterizes the technologies for increasing gas recovery from depleted gas reser-voirs by injecting nitrogen into them. The technology of replacing tail gas with nitrogen is tested on the example of the depleted reservoir of ND-9 horizon of Lyubeshivskyy gas field, the productive deposits of which are composed mainly of sandstones with interlayers of limestone and clay. The authors consider fifteen options of injecting ni-trogen into the reservoir, including options of treating the bottom-hole of low-production wells at the beginning of the process of further reservoir development and at the beginning of the injection of nitrogen into the reservoir. In all cases, the reservoir is first redeveloped in the depletion mode until the reservoir pressure decreases to 0,1 from the initial value. After that, nitrogen is injected into one of the producing wells which is transferred to the injection well. The injection of nitrogen into the reservoir continues until the nitrogen content in the last produc-ing well is less than 5 % vol. All options are characterized by high values of the gas recovery coefficient and close values of the dura-tion of the reservoir further development. The positions of the front of the displacement of natural gas by nitrogen at various time points are given. According to the research results, the gas recovery coefficient for tail gas for var-ious options varies from 14,12 to 34,58 %. With the introduction of the technology of injecting nitrogen into the reservoir, the overall gas recovery coefficient increases from 72,25 % (at present development system) to 80,28 % when the residual gas is displaced by nitrogen.

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Xu, Jianchun, Hai Wan, Yizhi Wu, Shuyang Liu und Bicheng Yan. „Study on CO2-Enhanced Oil Recovery and Storage in Near-Depleted Edge–Bottom Water Reservoirs“. Journal of Marine Science and Engineering 12, Nr. 11 (14.11.2024): 2065. http://dx.doi.org/10.3390/jmse12112065.

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The geological storage of carbon dioxide (CO2) is a crucial technology for mitigating global temperature rise. Near-depleted edge–bottom water reservoirs are attractive targets for CO2 storage, as they can not only enhance oil recovery (EOR) but also provide important potential candidates for geological storage. This study investigated CO2-enhanced oil recovery and storage for a typical near-depleted edge–bottom water reservoir that had been developed for a long time with a recovery factor of 51.93%. To improve the oil recovery and CO2 storage, new production scenarios were explored. At the near-depleted stage, by comparing the four different scenarios of water injection, gas injection, water-alternating-gas injection, and bi-directional injection, the highest additional recovery of 3.62% was achieved via the bi-directional injection scenario. Increasing the injection pressure led to a higher gas–oil ratio and liquid production rate. After shifting from the near-depleted to the depleted stage, the most effective approach to improving CO2 storage capacity was to increase reservoir pressure. At 1.4 times the initial reservoir pressure, the maximum storage capacity was 6.52 × 108 m3. However, excessive pressure boosting posed potential storage and leakage risks. Therefore, lower injection rates and longer intermittent injections were expected to achieve a larger amount of long-term CO2 storage. Through the numerical simulation study, a gas injection rate of 80,000 m3/day and a schedule of 4–6 years injection with 1 year shut-in were shown to be effective for the case considered. During 31 years of CO2 injection, the percentage of dissolved CO2 increased from 5.46% to 6.23% during the near-depleted period, and to 7.76% during the depleted period. This study acts as a guide for the CO2 geological storage of typical near-depleted edge–bottom water reservoirs.

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Dissertationen zum Thema "Depleted gas reservoirs"

Sun, Duo. „Storage of carbon dioxide in depleted natural gas reservoirs as gas hydrate“. Thesis, University of British Columbia, 2016. http://hdl.handle.net/2429/59341.

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More than 120 depleted natural gas reservoirs in Alberta, Canada have been identified as potential sites for CO₂ storage at temperature and pressure conditions at which CO₂ may form gas hydrate. Reservoir simulations presented in the literature have demonstrated the feasibility of storing CO₂ in such reservoirs. In this thesis, the injection of CO₂ in a laboratory size reservoir (packed bed of silica particles) serving as a physical model for a depleted reservoir was studied. The hypothesis was that injecting CO₂ into the reservoir at gas hydrate formation conditions will be beneficial in terms of increased CO₂ storage density. It is noted that CO₂ is stored not only as hydrate but also some is dissolved in the residual pore water (not converted to hydrate) and some as a gas in the remaining pore space. The results indicate that hydrate formation enhances the CO₂ storage density. The work also demonstrated that substances like tapioca starch added to the water in small quantities (1 wt %) delayed the onset of hydrate nucleation in the earlier stage but subsequently more CO₂ was stored as hydrate compared to the tapioca starch-free systems. The delay in nucleation decreases the risk to form a hydrate plug in the injection system. The injection of the CO₂-rich mixture (90 mol % CO₂/10 mol % N₂), which is a typical composition of a flue gas after CO₂ capture process, into a reservoir with CH4 (simulating residual natural gas) was also studied in the laboratory reservoir. It was found that the total CO₂ storage density (in hydrate, gaseous and dissolved state) decreased from 143 kg/m³ (the CO₂ injection into a CH₄ free reservoir) to 119 kg/m³. Finally, relevant phase equilibrium data were obtained in a constant volume high pressure vessel and by calorimetry. The results were found to be in good agreement with thermodynamic model calculated values within ± 40 kPa and ± 0.2 K, respectively.
Applied Science, Faculty of
Chemical and Biological Engineering, Department of
Graduate

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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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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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Bashir, Hayatu. „Methane adsorption into sandstones and its role in gas recovery from depleted reservoirs“. Thesis, University of Salford, 2018. http://usir.salford.ac.uk/46762/.

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Depleted gas reservoirs represent the most viable option for research and development and are the most preferred method for Enhanced gas recovery and sequestration application. The adsorption process acts as a displacement mechanism in the enhanced gas recovery, therefore investigating this process will lead to a better understanding of methane recovery in the EGR-CO₂ process. Despite many pilot studies on EGR-CO₂ in depleted reservoirs, no projects have moved to commercial phase, due to both technical and economic issues. This research demonstrated the role of adsorption as a mechanism for gas displacement in the EGR-CO₂ process by investigating the interaction of the mineral components of sandstones (i.e. Quartz, Plagioclase, feldspar and clays), with methane (CH₄), the effect of pressure and the interaction between water/brine and methane (CH₄) gas in a competitive sorption environment for sandstones and their constituents. The first series of tests were conducted using commercial helium pycnometer to quantify the effect of experimental parameters (pressure, contact time) and water on void volume of sandstone core samples. The average of the measured void volume using helium was 8.017cm³ for Bandera and 4.5171cm3 for the Scioto sandstones with a deviation of less than 0.002 cm³ and 0.001 cm³ indicating little dependence on pressure in void volume measurement. Water content of 5.62 wt. % and 5.48wt. % for both samples respectively can reduce the dry capacity by as much as 12.53% and 11.20%. Subsequently, a manometric adsorption apparatus was self-fabricated specifically for this research to quantify the methane adsorption capacity of sandstone cores samples. The experiments were conducted using dry sandstone core samples. Methane (CH₄) adsorption capacity of sandstones was investigated using dry sandstone samples. The methane (CH₄) adsorption capacity varied for the different sandstone types, which for the present studies Bandera and Scioto are considered. The Scioto sandstone has the largest CH₄ adsorption capacity of the tested samples with a maximum amount of adsorbed CH₄ of 0.110 mmol/g while the Bandera sandstone had significantly less CH₄ sorption capacity with a maximum amount of adsorbed CH₄ of 0.089 mmol/g. Using X-ray diffraction (XRD) results, the Scioto sample had the highest total amount of clays present (22%) compared to Bandera (14%) and had the highest adsorption capacity. The previous analyses imply that high content of clay minerals in the Scioto sample relative to the Bandera provides extra surface area for adsorption of methane (CH₄). As a result, it can be concluded that there exists a correlation between methane (CH₄) adsorption capacity and surface area of clay present in the samples. Finally, the methane (CH₄) adsorption capacity of sandstones saturated with water or brine at a particular water/ brine content (33, 65 and 91%) was investigated. The analysis showed that for water saturated core samples the CH₄ adsorption capacity decreased by 47.21, 54.47 and 60.89 % for Scioto and 10.26, 24.36, and 38.03% for Bandera relative to dry core samples. The loss of methane adsorption capacity was due to increase in water content (33, 65 and 91%) and was much lower than that of dry samples at the same experimental pressure (0 - 400 psia). The presence of brine in sandstone samples caused an overall decrease in methane adsorption capacity of 30.17,43.57 and 69.83% for Scioto and 28.90, 42.58 and 52.85% for Bandera compared to dry samples. These results indicate that methane adsorption of clay minerals found in a combined state with sandstone rock fabric as the case in real reservoirs will be influenced by its structural, physical, geotechnical, and geological properties. Experimental data verification were conducted using the repeatability and best fit method. Two replicate runs were conducted to investigate the reproducibility of the isotherm measurements. The average data deviation was 0.33 and 0.42 for dry Scioto and Bandera samples respectively, while the deviations were 3.85 and 3.59 for samples saturated with water and brine respectively between the first and repeat experiments. Excellent repeatability of experimental data for both sandstone samples (Scioto and Bandera) was observed.

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Seo, Jeong Gyu. „Experimental and simulation studies of sequestration of supercritical carbon dioxide in depleted gas reservoirs“. Diss., Texas A&M University, 2003. http://hdl.handle.net/1969.1/135.

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he feasibility of sequestering supercritical CO2 in depleted gas reservoirs. The experimental runs involved the following steps. First, the 1 ft long by 1 in. diameter carbonate core is inserted into a viton Hassler sleeve and placed inside an aluminum coreholder that is then evacuated. Second, with or without connate water, the carbonate core is saturated with methane. Third, supercritical CO2 is injected into the core with 300 psi overburden pressure. From the volume and composition of the produced gas measured by a wet test meter and a gas chromatograph, the recovery of methane at CO2 breakthrough is determined. The core is scanned three times during an experimental run to determine core porosity and fluid saturation profile: at start of the run, at CO2 breakthrough, and at the end of the run. Runs were made with various temperatures, 20°C (68°F) to 80°C (176°F), while the cell pressure is varied, from 500 psig (3.55 MPa) to 3000 psig (20.79 MPa) for each temperature. An analytical study of the experimental results has been also conducted to determine the dispersion coefficient of CO2 using the convection-dispersion equation. The dispersion coefficient of CO2 in methane is found to be relatively low, 0.01-0.3 cm2/min.. Based on experimental and analytical results, a 3D simulation model of one eighth of a 5-spot pattern was constructed to evaluate injection of supercritical CO2 under typical field conditions. The depleted gas reservoir is repressurized by CO2 injection from 500 psi to its initial pressure 3,045 psi. Simulation results for 400 bbl/d CO2 injection may be summarized as follows. First, a large amount of CO2 is sequestered: (i) about 1.2 million tons in 29 years (0 % initial water saturation) to 0.78 million tons in 19 years (35 % initial water saturation) for 40-acre pattern, (ii) about 4.8 million tons in 112 years (0 % initial water saturation) to 3.1 million tons in 73 years (35 % initial water saturation) for 80-acre pattern. Second, a significant amount of natural gas is also produced: (i) about 1.2 BSCF or 74 % remaining GIP (0 % initial water saturation) to 0.78 BSCF or 66 % remaining GIP (35 % initial water saturation) for 40-acre pattern, (ii) about 4.5 BSCF or 64 % remaining GIP (0 % initial water saturation) to 2.97 BSCF or 62 % remaining GIP (35 % initial water saturation) for 80-acre pattern. This produced gas revenue could help defray the cost of CO2 sequestration. In short, CO2 sequestration in depleted gas reservoirs appears to be a win-win technology.

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Nogueira, de Mago Marjorie Carolina. „Effect of flue gas impurities on the process of injection and storage of carbon dioxide in depleted gas reservoirs“. Thesis, Texas A&M University, 2005. http://hdl.handle.net/1969.1/2613.

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Previous experiments - injecting pure CO2 into carbonate cores - showed that the process is a win-win technology, sequestrating CO2 while recovering a significant amount of hitherto unrecoverable natural gas that could help defray the cost of CO2 sequestration. In this thesis, I report my findings on the effect of flue gas ??impurities?? on the displacement of natural gas during CO2 sequestration, and results on unconfined compressive strength (UCS) tests to carbonate samples. In displacement experiments, corefloods were conducted at 1,500 psig and 70??C, in which flue gas was injected into an Austin chalk core containing initially methane. Two types of flue gases were injected: dehydrated flue gas with 13.574 mole% CO2 (Gas A), and treated flue gas (N2, O2 and water removed) with 99.433 mole% CO2 (Gas B). The main results of this study are as follows. First, the dispersion coefficient increases with concentration of ??impurities??. Gas A exhibits the largest dispersion coefficients, 0.18-0.25 cm2/min, compared to 0.13-0.15 cm2/min for Gas B, and 0.15 cm2/min for pure CO2. Second, recovery of methane at breakthrough is relatively high, ranging from 86% OGIP for pure CO2, 74-90% OGIP for Gas B, and 79-81% for Gas A. Lastly, injection of Gas A would sequester the least amount of CO2 as it contains about 80 mole% nitrogen. From the view point of sequestration, Gas A would be least desirable while Gas B appears to be the most desirable as separation cost would probably be cheaper than that for pure CO2 with similar gas recovery. For UCS tests, corefloods were conducted at 1,700 psig and 65??C in such a way that the cell throughput of CO2 simulates near-wellbore throughput. This was achieved through increasing the injection rate and time of injection. Corefloods were followed by porosity measurement and UCS tests. Main results are presented as follows. First, the UCS of the rock was reduced by approximately 30% of its original value as a result of the dissolution process. Second, porosity profiles of rock samples increased up to 2.5% after corefloods. UCS test results indicate that CO2 injection will cause weakening of near-wellbore formation rock.

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Ozturk, Bulent. „Simulation Of Depleted Gas Reservoir For Underground Gas Storage“. Master's thesis, METU, 2004. http://etd.lib.metu.edu.tr/upload/12605723/index.pdf.

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For a natural gas importing country, &ldquo
take or pay&rdquo
approach creates problems since the demand for natural gas varies during the year and the excess amount of natural gas should be stored. In this study, an underground gas storage project is evaluated in a depleted gas Field M. After gathering all necessary reservoir, fluid, production and pressure data, the data were adapted to computer language, which was used in a commercial simulator software (IMEX) that is the CMG&rsquo
s (Computer Modelling Group) new generation adoptive simulator, to reach the history matching. The history matching which consists of the 4 year of production of the gas reservoir is the first step of this study. The simulation program was able to accomplish a good history match with the given parameters of the reservoir. Using the history match as a base, five different scenarios were created and forecast the injection and withdrawal performance of the reservoir. These scenarios includes 5 newly drilled horizontal wells which were used in combinations with the existing wells. With a predetermined injection rate of 13 MMcf/D was set for all the wells and among the 5 scenarios, 5 horizontal &ndash
6 vertical injectors &
5 horizontal - 6 vertical producers is the most successful in handling the gas inventory and the time it takes for a gas injection and production period. After the determination of the well configuration, the optimum injection rate for the entire field was obtained and found to be 130 MMcf/D by running different injection rates for all wells and then for only horizontal wells different injection rates were applied with a constant injection rate of 130 MMcf/d for vertical wells. Then it has been found that it is better to apply the 5th scenario which includes 5 horizontal &ndash
6 vertical injectors &
5 horizontal - 6 vertical producers having an injection rate of 130 MMcf/d for horizontal and vertical wells. Since within the 5th scenario, changing the injection rate to 1.3 Bcf/d and 13 Bcf/d, did not effect and change the average reservoir pressure significantly, it is best to carry out the project with the optimum injection rate which is 130 MMcf/d. The total gas produced untill 2012 is 394 BCF and the gas injected is 340 BCF where the maximum average reservoir pressure was recovered and set into a new value of 1881 psi by injection and cushion gas pressure as 1371 psi by withdrawal. If 5th scenario is compared with the others, there is an increase in injection and production performance about 90%.

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Ozkilic, Ismet Oke. „Simulating Co2 Sequestration In A Depleted Gas Reservoir“. Master's thesis, METU, 2005. http://etd.lib.metu.edu.tr/upload/12606639/index.pdf.

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Carbon dioxide is one of the greenhouse gases which have strong impacts on the environment and its amount in the atmosphere is far beyond to be ignored. Carbon dioxide levels are projected to be reduced by sequestering it directly to the underground. High amounts of carbon dioxide can be safely stored in underground media for very long time periods. Storage in depleted gas reservoirs provides an option for sequestering carbon dioxide. In 2002, production of Kuzey Marmara gas reservoir has been stopped due to gas storage plans. Carbon dioxide sequestration in Kuzey Marmara field has been considered in this study as an alternative to the gas storage projects. Reservoir porosity and permeability maps were prepared with the help of Surfer software demo version. These maps were merged with the available Kuzey Marmara production information to create an input file for CMG-GEM simulator and a three dimensional model of the reservoir was created. History match of the field model was made according to the 1998-2002 production data to verify the similarity between the model and actual reservoir. Kuzey Marmara field is regarded as a candidate for future gas storage projects. The reservoir still contains producible natural gas. Four different scenarios were prepared by considering this fact with variations in the regional field properties and implemented into previously built simulation model. These scenarios primarily focus on sequestering carbon dioxide while producing as much as natural gas possible. After analyzing the results from the scenarios it is realized that
CO2 injection can be applied to increase natural gas recovery of Kuzey Marmara field but sequestering high rate CO2 emissions is found out to be inappropriate.

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Saffou, Eric. „Geomechanical characterization and reservoir Simulation of a carbon storage project in e-m depleted Gas field in South Africa“. University of the Western Cape, 2020. http://hdl.handle.net/11394/8218.

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Philosophiae Doctor - PhD
Geomechanical analysis and integrity assessment of hydrocarbon reservoirs upon depletion and injection are crucial to ensure that CO2 storage projects can be safely implemented. The Bredasdorp Basin in South Africa has great potential for CO2 storage, given its hugely available exploration data. However, there has not been any geomechanical characterization carried out on this basin to determine its integrity issues. This study aims to investigate the feasibility of a carbon storage project in the E-M depleted gas field. The preliminary geological assessment demonstrates that Zone 2 and Zone 3 display acceptable injectivity for CO2 injection of the E-M gas field. Seismic lines display faults that could affect the caprock's integrity during depletion and carbon storage. Geomechanical characterization provides a guideline as to how geomechanical analysis of depleted fields can be done for a safe CO2 sequestration practice. The geomechanical model constructed at a depth of 2570 m indicated that the magnitudes of the principal vertical, minimum, and maximum horizontal stresses in the field are respectively 57 MPa, 41 MPa, and 42-46 MPa. Fault and fracture stabilities were examined before and after depletion. It was found that faults and fractures in compartments C1 and C2 of the reservoir are stable before and after depletion, while normal faults (FNS8 and FNS9) in compartment C3 dipping SW were critically stressed. The minimum sustainable pressure of the reservoir determined by simulating depletion is 6 MPa. Below that, pressure depletion causes normal faulting in reservoir compartments C1 and C2. The maximum sustainable pressure, on the other hand, was found to be 25 MPa. The geomechanical studies also reveal that it is possible that the reservoir experienced compaction of 8 cm during depletion and will experience an uplift of 3.2 cm during 71 years of injection. The economic model of a CO2-enhanced gas recovery project in E-M gas field, the annual expenses (Aexp) of carbon capture and storage range between Zar20 3.31 × 109 and Zar20 4.10 × 109. The annual revenues (RA) were estimated to be Zar20 1.42 × 1010. The cash flow analysis derived from Aexp and RA confirms that enhanced gas recovery could partially offset the cost of CO2 storage if a minimum of 5 % of CO2 fraction is allowed in the natural gas recovered. Geological and geomechanical studies have demonstrated that carbon storage is physically feasible in the E-M gas field. However, the project's completion lies in the among the gas recovered to balance the cost of CO2. http://

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Pamukcu, Yusuf Ziya. „Simulating Oil Recovery During Co2 Sequestration Into A Mature Oil Reservoir“. Master's thesis, METU, 2006. http://etd.lib.metu.edu.tr/upload/3/12607418/index.pdf.

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The continuous rising of anthropogenic emission into the atmosphere as a consequence of industrial growth is becoming uncontrollable, which causes heating up the atmosphere and changes in global climate. Therefore, CO2 emission becomes a big problem and key issue in environmental concerns. There are several options discussed for reducing the amount of CO2 emitted into the atmosphere. CO2 sequestration is one of these options, which involves the capture of CO2 from hydrocarbon emission sources, e.g. power plants, the injection and storage of CO2 into deep geological formations, e.g. depleted oil reservoirs. The complexity in the structure of geological formations and the processes involved in this method necessitates the use of numerical simulations in revealing the potential problems, determining feasibility, storage capacity, and life span credibility. Field K having 32o API gravity oil in a carbonate formation from southeast Turkey was studied. Field K was put on production in 1982 and produced until 2006, which was very close to its economic lifetime. Thus, it was considered as a candidate for enhanced oil recovery and CO2 sequestration. Reservoir rock and fluid data was first interpreted with available well logging, core and drill stem test data. Monte Carlo simulation was used to evaluate the probable reserve that was 7 million STB, original oil in place (OOIP). The data were then merged into CMG/STARS simulator. History matching study was done with production data to verify the results of the simulator with field data. After obtaining a good match, the different scenarios were realized by using the simulator. From the results of simulation runs, it was realized that CO2 injection can be applied to increase oil recovery, but sequestering of high amount of CO2 was found out to be inappropriate for field K. Therefore, it was decided to focus on oil recovery while CO2 was sequestered within the reservoir. Oil recovery was about 23% of OOIP in 2006 for field K, it reached to 43 % of OOIP by injecting CO2 after defining production and injection scenarios, properly.

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Clarke, Amy Louise. „Evaluating the variability of static carbon dioxide storage capacity estimates through integrated analysis of reservoir structure, aquifer performance and thermodynamic behaviour : case studies from three depleted triassic gas fields on the UK continental shelf“. Thesis, Durham University, 2014. http://etheses.dur.ac.uk/10644/.

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Evaluation of the variability of theoretical and effective CO2 storage capacity estimation within depleted gas reservoirs is dependent on the integrated analysis of reservoir structure, aquifer performance and thermodynamic behaviour. Four published theoretical CO2 storage capacity methods and one effective method have been used to estimate the capacity and variability of two Triassic depletion drive reservoirs and two Triassic water drive reservoirs located within the UK Southern North Sea and East Irish Sea Basin. Input parameters to the storage capacity equations have shown a degree of natural variability whereas others are more accurately constrained. As such, attempts have been made to more accurately constrain the most variable input parameters. The geometric, petrophysical and production characteristics of the reservoirs are analysed. Material balance methods are used to assess the reservoir drive mechanism of the reservoirs. If reservoirs are found to experience a water drive, the aquifer strength is estimated. The gas compressibility factor, gas formation volume factor and CO2 density is estimated under initial reservoir temperature conditions using six equations of state for comparison of results. These results are then input to storage capacity equations producing a range of estimates. The most susceptible parameter to variability was the cumulative volume of water influx to a reservoir, We. Variability was also found to be the result of error in estimation of the original gas in place. As such, the water drive reservoirs made further use of aquifer modelling to achieve more precise estimates of OGIP and We. The effective capacity coefficients for the various reservoirs have been estimated to assess the proportion of pore space available for CO2 storage. The effective CO2 storage capacity constitutes a fraction of the theoretical CO2 storage capacity which ranges between 0 (no storage possible) and 1 (all theoretically accessible pore volume is occupied by CO2). Overall, it was found that depletion drive reservoirs have the potential to store greater volumes of CO2 than water drive reservoirs whose aquifer waters occupy the newly liberated pore space.

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Buchteile zum Thema "Depleted gas reservoirs"

van der Harst, A. C., und A. J. F. M. van Nieuwland. „Disposal of Carbon Dioxide in Depleted Natural Gas Reservoirs“. In Climate and Energy: The Feasibility of Controlling CO2 Emissions, 178–88. Dordrecht: Springer Netherlands, 1989. http://dx.doi.org/10.1007/978-94-009-0485-9_11.

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Sun, Duo, Nagu Daraboina, John Ripmeester und 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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Liu, Tuan-hui, Fa-jun Guo, Xi Chen, Zeng-qiang Xi, Ming-qian Zhao, Yang-yang Bi, Ya-ni Wang, Meng-yuan Xian und Bo Zhang. „Evaluation of Reasonable Storage Capacity of Water - Driven Depleted Gas Reservoirs“. In Proceedings of the International Field Exploration and Development Conference 2021, 2816–29. Singapore: Springer Nature Singapore, 2022. http://dx.doi.org/10.1007/978-981-19-2149-0_261.

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Yang, Yu, Qi-lin Xu, Liang-wei Jiang, Qian Zhang, Dong-jie Huang, Xin Liu, Rong-he Liu, Jian-guo Liu und Yu-zhe Cui. „Salt Precipitation Law of Formation Water During CO2 Injection into Depleted Gas Reservoirs“. In Springer Series in Geomechanics and Geoengineering, 325–42. Singapore: Springer Nature Singapore, 2024. http://dx.doi.org/10.1007/978-981-97-0268-8_27.

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Zatsepina, Olga Ye, Hassan Hassanzadeh und Mehran Pooladi-Darvish. „Geological Storage of CO2as Hydrate in a McMurray Depleted Gas Reservoir“. In Gas Injection for Disposal and Enhanced Recovery, 311–29. Hoboken, NJ, USA: John Wiley & Sons, Inc., 2014. http://dx.doi.org/10.1002/9781118938607.ch18.

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Zhang, Jian-guo, Zhong-guo Tan, Yi-fei Lan und Chen-yang Zhao. „Construction of UGS in Low Permeability and Sulfur-Bearing Depleted Gas Reservoir“. In Springer Series in Geomechanics and Geoengineering, 134–43. Singapore: Springer Singapore, 2020. http://dx.doi.org/10.1007/978-981-15-2485-1_15.

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Xiong, Zanfu, Jian Hou, Qingjun Du und Zheng Chen. „Simulation Study of Hydrogen Storage in a Depleted Gas Reservoir: Microbiological Influences in Porous Media“. In Progress and Challenge of Porous Media: Proceedings of the 16th Annual Meeting Conference on Porous Media, 149–62. Singapore: Springer Nature Singapore, 2025. https://doi.org/10.1007/978-981-96-2983-1_12.

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Esfandi, Tanin, Yasin Noruzi, Mir Saeid Safavi und Saeid Sadeghnejad. „Surrogate Boosting Models for Well Placement Prediction During Hydrogen Storage in a Depleted Gas Reservoir“. In Progress and Challenge of Porous Media: Proceedings of the 16th Annual Meeting Conference on Porous Media, 1081–95. Singapore: Springer Nature Singapore, 2025. https://doi.org/10.1007/978-981-96-2983-1_92.

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BOSSIECODREANU, D., Y. LEGALLO, J. DUQUERROIX, N. DOERLER und P. LETHIEZ. „CO2 Sequestration in Depleted Oil Reservoirs“. In Greenhouse Gas Control Technologies - 6th International Conference, 403–8. Elsevier, 2003. http://dx.doi.org/10.1016/b978-008044276-1/50065-9.

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BECH, N., und P. FRYKMAN. „Storage of CO2 in Depleted Hydrocarbon Reservoirs in Low-Permeability Chalk“. In Greenhouse Gas Control Technologies - 6th International Conference, 397–402. Elsevier, 2003. http://dx.doi.org/10.1016/b978-008044276-1/50064-7.

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Konferenzberichte zum Thema "Depleted gas reservoirs"

Konstantinou, Charalampos, Matheos Giakoumi, Panos Papanastasiou, Andreas V. Olympios, Fanourios Kourougianni, Alexandros Arsalis und George E. Georghiou. „Green hydrogen storage capacity estimations in depleted gas reservoirs“. In 2024 3rd International Conference on Energy Transition in the Mediterranean Area (SyNERGY MED), 1–5. IEEE, 2024. https://doi.org/10.1109/synergymed62435.2024.10799311.

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Konstantinou, C., M. Giakoumi und P. Papanastasiou. „Green Hydrogen Storage in Depleted Gas Reservoirs“. In International Geomechanics Conference. ARMA, 2024. https://doi.org/10.56952/igs-2024-0452.

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ABSTRACT: This study explores the potential of repurposing depleted natural gas reservoirs for green hydrogen storage, utilizing the material balance equation (MBE) framework. The presence of an aquifer, a common feature in many depleted reservoirs, is considered, and the Carter and Tracy aquifer model is applied alongside the Peng-Robinson equation of state for hydrogen. A case study is conducted using a reference reservoir geometry with varying hydraulic properties (porosity and permeability) and a range of natural gas production rates. Results indicate that natural gas production rate, formation permeability, and porosity are critical factors not only for gas extraction but also for determining the feasibility of hydrogen storage. The study finds that typical sandstone reservoirs are most suitable for hydrogen storage, while formations with very high or low permeability present challenges. The findings highlight that with appropriate reservoir management, depleted gas reservoirs could serve as an effective hydrogen storage solution, contributing to a more flexible and resilient energy system. Future research should focus on understanding biochemical reactions in these reservoirs when exposed to hydrogen, which remains a relatively unexplored area. 1. INTRODUCTION The management of energy, a critical component in the transition from conventional energy resources to renewables, requires bridging the gap between demand and supply, often through the use of energy storage. One form of storage is hydrogen gas which is an energy carrier that can be used to store, transport, and deliver energy produced from other sources. In this energy transition, green hydrogen which is produced via electrolysis using renewable energy sources could play a vital role (Kourougianni et al., 2024). Although the production of green hydrogen is largely secured from a technological standpoint, the limited storage capacity remains a significant barrier to further development. Current storage technologies can accommodate limited volumes. To store large quantities of hydrogen, subsurface formations like aquifers, caverns, and depleted oil and gas reservoirs are promising candidates. Depleted oil and gas reservoirs are porous media which host fluids within their pore network, which once accommodated hydrocarbons. Together with aquifers, they can store large volumes accommodating variations on a weekly basis with TWh in terms of energy storage capacity (Edlmann et al., 2021).

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Galic, Hrvoje, Stephen John Cawley, Simon Richard Bishop, Frederic Gas und Steven Todman. „CO2 Injection Into Depleted Gas Reservoirs“. In SPE Offshore Europe Oil and Gas Conference and Exhibition. Society of Petroleum Engineers, 2009. http://dx.doi.org/10.2118/123788-ms.

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Panja, Palash, Eric Edelman, Carlos Vega-Ortiz, Rasoul Sorkhabi und Milind Deo. „Understanding Hydrogen Flow in Depleted Natural Gas Reservoirs“. In 58th U.S. Rock Mechanics/Geomechanics Symposium. ARMA, 2024. http://dx.doi.org/10.56952/arma-2024-0623.

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ABSTRACT: Large-scale hydrogen storage is crucial for addressing the intermittent nature of renewable energy sources, which vary seasonally and diurnally. For storing energy over days to months, large-scale subsurface storage becomes essential. In this study, the potential of depleted natural gas reservoirs is explored as suitable storage media. This research comprises two main components. Firstly, it investigates the mixing of hydrogen and methane under subsurface conditions to examine the influence of molecular diffusion and gravity. Secondly, it explores flow dynamics during injection, shut-in, and production operations under varying geological parameters. Synthetic reservoir models are developed by changing absolute permeability, and porosity. During an annual cycle, hydrogen is initially injected into the reservoir for 6 months, followed by a 3-month shut-in period. Finally, hydrogen is produced from the reservoir over the course of 3 months. The hydrogen concentration in the produced gas is analyzed to understand the variation over time. Additionally, the cumulative recovery of hydrogen is calculated to measure the total amount of hydrogen successfully extracted from the reservoir over time. By analyzing various scenarios, the study aims to gain a comprehensive understanding of hydrogen behavior within the reservoir. 1. INTRODUCTION Hydrogen is considered to play a critical role in energy transition to a low-carbon world primarily due to its utilization as a zero-carbon fuel when combusted with oxygen. However, transportation and long-term storage of hydrogen are among the most challenging issues in this potentially significant energy technology. Underground storage presents a viable solution, leveraging existing geological formations to securely store hydrogen on a large scale. Existing literature provides a comprehensive overview of the technical, economic, and environmental considerations associated with underground hydrogen storage. For this study, we investigate depleted natural gas reservoirs as possible storage sites for hydrogen. The exploration of hydrogen underground storage technology has garnered significant attention in recent years, with a multitude of studies focusing on various methodologies such as depleted reservoirs, aquifer salt caverns, and excavated caverns (Bai et al. 2014; Heinemann et al. 2018; Caglayan et al. 2020; Liu et al. 2020; Epelle et al. 2022; Jahanbani Veshareh et al. 2022; Małachowska et al. 2022; Muhammed et al. 2022; Uliasz-Misiak et al. 2022; Hematpur et al. 2023). For this study, we investigate depleted natural gas reservoirs as possible storage sites for hydrogen. In other studies, the current challenges, future directions, perspectives and prospects for underground hydrogen storage and the utilization of natural hydrogen resources were discussed (Epelle et al. 2022; Muhammed et al. 2022; Uliasz-Misiak et al. 2022; Hematpur et al. 2023). Despite significant progress in the field, several challenges persist, ranging from technical hurdles to regulatory and policy frameworks.

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de Kok, J. „Monitoring Injectivity for CO2 Injection in Depleted Gas Reservoirs“. In SPE Europe Energy Conference and Exhibition. SPE, 2024. http://dx.doi.org/10.2118/220119-ms.

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Abstract Determining the injectivity of CO2 injection wells in depleted gas reservoirs is important, because injectivity directly impacts the operating envelope of the injector. Injectivity evolves over time due to changing fluid properties, but it can also change by processes like hydrate formation or fracturing (summarized in the skin parameter). This paper investigates how accurate injectivity monitoring is, based on coupled well-reservoir simulation and identifies threshold values for identifying injectivity loss or gain. The relation between bottomhole pressure (BHP) and rate is a function of several reservoir properties and fluid properties, each carrying its own uncertainty. This paper quantifies the impact of these uncertainties on injectivity for CO2 injection into depleted gas reservoirs using a coupled wellbore and reservoir simulator. The analysis is performed for three scenarios with varying pipeline conditions and reservoir properties, representative for CCS projects in the Netherlands. The resulting BHP uncertainty is translated to equivalent skin values. This is the threshold value above or below which the observed bottomhole pressure data conclusively suggests injectivity gain or loss. A good estimate of the fluid properties is important to accurately determine injectivity (changes). Although the uncertainty in density is small when using the appropriate Equation of State (like Span & Wagner for pure CO2), the deviation when using a standard Equation of State (like Peng-Robinson) is significant. The parameter having the largest impact is reservoir pressure for high injectivity reservoirs and relative permeability for low injectivity reservoirs. The combined effect of all parameters (with the exception of reservoir pressure) is equivalent to a skin value of approximately 3 for the selected cases. Without reducing the uncertainty, it is not possible to distinguish between uncertainty in injectivity and actual wellbore damage of that magnitude. There are ways to decrease the uncertainty in both estimated average reservoir pressure and fluid properties, like the collection of bottomhole temperature data. Shut-in pressure data will further reduce the average reservoir pressure estimate. However, the presence of skin will be difficult to assess from pressure transient data due to wellbore storage and near-wellbore cooling. Rate dependent skin can be assessed when there is rate variation. Permeability and relative permeability changes in the near-wellbore will be difficult to distinguish from wellbore damage. History matching the observed data by a coupled wellbore-reservoir simulator will further decrease the uncertainties. Monitoring tools for CO2 injection in depleted reservoirs are yet to be developed. This paper improves the understanding of the uncertainties related to injectivity monitoring, which haven’t been quantified so far. Also, the value of a coupled wellbore and reservoir simulator is demonstrated in this paper.

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Mathias, S. A., J. G. Gluyas, R. Bissell und N. Muller. „Simulating CO2 Injection in Depleted Gas Reservoirs“. In Fourth EAGE CO2 Geological Storage Workshop. Netherlands: EAGE Publications BV, 2014. http://dx.doi.org/10.3997/2214-4609.20140071.

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Shtepani, Edmond. „CO2 Sequestration in Depleted Gas/Condensate Reservoirs“. In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 2006. http://dx.doi.org/10.2118/102284-ms.

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Li, Dexuan, und Hamid Emami-Meybodi. „Hydrogen Mixing Dynamics in Depleted Gas Reservoirs“. In SPE Annual Technical Conference and Exhibition. SPE, 2024. http://dx.doi.org/10.2118/220710-ms.

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Abstract Depleted gas reservoirs are suggested as a suitable choice for the sessional storage and utilization of hydrogen (H2) with the presence of surface infrastructure, large storage capacity, and available history data. However, hydrogen mixing with in-situ natural gas and cushion gas leads to contamination and subsequent loss of hydrogen. Hydrodynamic dispersion is an important driving mechanism for gas mixing during cyclic hydrogen injection/withdrawal. Accordingly, we investigate the mixing dynamics of hydrogen, cushion gas, and in-situ gas and their impacts on the recovery factor and purity of back-produced hydrogen. We construct a numerical model based on the finite-element method considering hydrodynamic dispersion. The model is then utilized to examine the mixing dynamics of injected hydrogen under various geological and operational parameters. The results reveal that the amount of injected cushion gas and in-situ significantly influences the purity of produced hydrogen. As the cushion and in-situ gas amount increases, the H2 purity, as well as the H2 recovery factor, decreases in each withdrawal. The hydrodynamic dispersion negatively impacts the produced H2 purity due to the expansion of the mixing region, leading to H2 contamination and a reduced recovery factor. The ultimate hydrogen recovery factor is around 6% lower when hydrodynamic dispersion is considered. However, compared with cushion and in-situ gas amount, the hydrodynamic plays a minor role in the performance of underground hydrogen storage.

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Bonnett, Nigel, Bob Williamson und Peter Oakes. „High Angle Drilling In Severely Depleted Reservoirs“. In SPE Asia Pacific Oil and Gas Conference and Exhibition. Society of Petroleum Engineers, 1998. http://dx.doi.org/10.2118/49984-ms.

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Frailey, Scott M. „Material Balance Reservoir Model for CO2 Sequestration in Depleted Gas Reservoirs“. In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 2004. http://dx.doi.org/10.2118/90669-ms.

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Berichte der Organisationen zum Thema "Depleted gas reservoirs"

Freifeld, Barry, Curtis Oldenburg, Preston Jordan, Lehua Pan, Scott Perfect, Joseph Morris, Joshua White et al. Well Integrity for Natural Gas Storage in Depleted Reservoirs and Aquifers. Office of Scientific and Technical Information (OSTI), September 2016. http://dx.doi.org/10.2172/1431465.

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Bauer, Stephen J., Douglas A. Blankenship, Barry L. Roberts, Barry Freifeld, Scott Perfect, Grant Bromhal, Curtis Oldenburg et al. Well Integrity for Natural Gas Storage in Depleted Reservoirs and Aquifers. Office of Scientific and Technical Information (OSTI), Januar 2017. http://dx.doi.org/10.2172/1432270.

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Freifeld, Barry M., Curtis M. Oldenburg, Preston Jordan, Lehua Pan, Scott Perfect, Joseph Morris, Joshua White et al. Well Integrity for Natural Gas Storage in Depleted Reservoirs and Aquifers. Office of Scientific and Technical Information (OSTI), September 2016. http://dx.doi.org/10.2172/1338936.

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Cooper, Paul W., Mark Charles Grubelich und Stephen J. Bauer. Potential hazards of compressed air energy storage in depleted natural gas reservoirs. Office of Scientific and Technical Information (OSTI), September 2011. http://dx.doi.org/10.2172/1029814.

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Gardner, William Payton. Preliminary formation analysis for compressed air energy storage in depleted natural gas reservoirs :. Office of Scientific and Technical Information (OSTI), Juni 2013. http://dx.doi.org/10.2172/1089981.

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Gherardi, Fabrizio, Tianfu Xu und Karsten Pruess. Exploratory Simulation Studies of Caprock Alteration Induced byStorage of CO2 in Depleted Gas Reservoirs. Office of Scientific and Technical Information (OSTI), November 2005. http://dx.doi.org/10.2172/908464.

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Bruce. L52282 State-of-the-Art Assessment of Alternative Casing Repair Methods. Chantilly, Virginia: Pipeline Research Council International, Inc. (PRCI), Juli 2007. http://dx.doi.org/10.55274/r0010195.

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Many natural gas storage wells suffer damage during normal storage operations. Storage operators spend upwards of $100 million per year recovering lost deliverability. Damage to casings in gas storage wells is largely the result of localized loss of metal from corrosion; however, other types of damage do occur. Individual corrosion pits can be found either on the inside or outside of the casing wall. Repair methods that are currently used for natural gas storage well casings include patches, plugs, liners, etc. While currently-used repair methods can be a cost-effective means of repairing damaged casings as compared to the cost of running an entirely new casing, there is a need to identify and develop alternative casing repair methods that are more economical and/or do not have inherent operational disadvantages. Many of the current repair methods are proprietary, and as a result, are relatively costly to perform. In addition, many of these repair methods (e.g., tube and packer system repairs) result in a decreased cross-sectional area, which creates operational limitations due to flow restrictions and reduces the ability to perform well logging operations. The objective of this project was to review current state-of-the-art casing repair technologies to identify more cost effective alternatives. The most prominent form of underground U.S. gas storage is depleted reservoirs. American Petroleum Institute specification 5CT contains the industry standard design guidance for new casings; however, there are no industry standard repair procedures and each state has their own. The most common state required repair integrity test is pressure testing. Casings must withstand tensile, burst, and collapse loads. Most state repair procedures do not specify a target mechanical property that defines repair success. It is therefore easy to assume that a repair should return a casing back to its original integrity level; however, it may not be necessary. The major types of damage mechanisms are corrosion, threaded connection separation, sealant leaks, split casings, and drill bit damage. While a literature search indicated that the most commonly used types of cost effective repair processes are squeezes, liners, and plating, industry feedback indicated that liner repair is the most commonly used repair process. Adhesively bonded, helically-wound, steel strip repair and magnetic pulse welding are the most promising alternative repair technologies identified, mainly because both are applicable for a broad range of damage types and as an alternative to both traditional casing liner and expandable tubular repair technologies.

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Flamberg, Stephanie. PR-727-23700-R01 Underground Storage Failure and Near Miss Trending. Chantilly, Virginia: Pipeline Research Council International, Inc. (PRCI), August 2024. http://dx.doi.org/10.55274/r0000080.

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This report describes the contents of a comprehensive Microsoft Excel database of underground storage (UGS) failure and near miss incidents. The database captures underground storage-related incidents from depleted oil and gas reservoir, aquifer, and salt cavern facilities in the United States, Canada, and Europe sourced from publicly available literature and participating, anonymous operators. The intent of the database is to help operators understand and improve key practices involved in the design, construction, operations, maintenance, and integrity management of underground storage assets through trending and lessons learned from the reported incidents.

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Lord, David, und Raymond Allen. Modeling Study of Reduced Tubing Size Effects on Flow in Depleted Reservoir Natural Gas Storage Wells. Office of Scientific and Technical Information (OSTI), Januar 2021. http://dx.doi.org/10.2172/1765465.

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Doughty, Christine, und Curtis Oldenburg. Carbon Dioxide Plume Evolution Following Injection into a Depleted Natural Gas Reservoir: Modeling of Conformance Uncertainty Reduction Over Time. Office of Scientific and Technical Information (OSTI), Januar 2019. http://dx.doi.org/10.2172/1616071.

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