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1
Khaksar, Abbas, Adrian White, Khalilur Rahman, Katharine Burgdorff, Reinaldo Ollarves, and Steve Dunmore. "Systematic geomechanical evaluation for short-term gas storage in depleted reservoirs." APPEA Journal 52, no. 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, and Kamy Sepehrnoori. "Analytical Estimation of Hydrogen Storage Capacity in Depleted Gas Reservoirs: A Comprehensive Material Balance Approach." Applied Sciences 14, no. 16 (August 13, 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, and 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, no. 10 (October 14, 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, and Kyuchul Shin. "Carbon Capture and Storage in Depleted Oil and Gas Reservoirs: The Viewpoint of Wellbore Injectivity." Energies 17, no. 5 (March 2, 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, no. 6 (2002): 538–46. http://dx.doi.org/10.3720/japt.67.538.
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Uliasz-Misiak, Barbara, Joanna Lewandowska-Śmierzchalska, and Rafał Matuła. "Hydrogen Storage Potential in Natural Gas Deposits in the Polish Lowlands." Energies 17, no. 2 (January 11, 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, and Shaochun Yang. "Discussion on the Reconstruction of Medium/Low-Permeability Gas Reservoirs Based on Seepage Characteristics." Processes 10, no. 4 (April 13, 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, no. 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., and 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, no. 2(75) (August 31, 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, and Bicheng Yan. "Study on CO2-Enhanced Oil Recovery and Storage in Near-Depleted Edge–Bottom Water Reservoirs." Journal of Marine Science and Engineering 12, no. 11 (November 14, 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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Hoteit, Hussein, Marwan Fahs, and Mohamad Reza Soltanian. "Assessment of CO2 Injectivity During Sequestration in Depleted Gas Reservoirs." Geosciences 9, no. 5 (May 5, 2019): 199. http://dx.doi.org/10.3390/geosciences9050199.
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Depleted gas reservoirs are appealing targets for carbon dioxide (CO 2 ) sequestration because of their storage capacity, proven seal, reservoir characterization knowledge, existing infrastructure, and potential for enhanced gas recovery. Low abandonment pressure in the reservoir provides additional voidage-replacement potential for CO 2 and allows for a low surface pump pressure during the early period of injection. However, the injection process poses several challenges. This work aims to raise awareness of key operational challenges related to CO 2 injection in low-pressure reservoirs and to provide a new approach to assessing the phase behavior of CO 2 within the wellbore. When the reservoir pressure is below the CO 2 bubble-point pressure, and CO 2 is injected in its liquid or supercritical state, CO 2 will vaporize and expand within the well-tubing or in the near-wellbore region of the reservoir. This phenomenon is associated with several flow assurance problems. For instance, when CO 2 transitions from the dense-state to the gas-state, CO 2 density drops sharply, affecting the wellhead pressure control and the pressure response at the well bottom-hole. As CO 2 expands with a lower phase viscosity, the flow velocity increases abruptly, possibly causing erosion and cavitation in the flowlines. Furthermore, CO 2 expansion is associated with the Joule–Thomson (IJ) effect, which may result in dry ice or hydrate formation and therefore may reduce CO 2 injectivity. Understanding the transient multiphase phase flow behavior of CO 2 within the wellbore is crucial for appropriate well design and operational risk assessment. The commonly used approach analyzes the flow in the wellbore without taking into consideration the transient pressure response of the reservoir, which predicts an unrealistic pressure gap at the wellhead. This pressure gap is related to the phase transition of CO 2 from its dense state to the gas state. In this work, a new coupled approach is introduced to address the phase behavior of CO 2 within the wellbore under different operational conditions. The proposed approach integrates the flow within both the wellbore and the reservoir at the transient state and therefore resolves the pressure gap issue. Finally, the energy costs associated with a mitigation process that involves CO 2 heating at the wellhead are assessed.
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Iskandar, Utomo P., and Usman Usman. "Co2 Storage Capacity Estimation Of Depleted Oil And Gas Reservoirs In Indonesia." Scientific Contributions Oil and Gas 34, no. 1 (February 15, 2022): 53–59. http://dx.doi.org/10.29017/scog.34.1.791.
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Implementation of co2 capture and geological storage technology at the scale needed To achieve a significant and meaningful reduction in co2 emissions requires knowledge of The available co2 storage capacity. Various geological formations located across many Islands in indonesia appear to be potential to store the anthropogenic co2, particularly in Depleted oil and gas reservoir. These depleted oil and gas reservoirs are appropriate Candidates for co2 storage. However, the capacity of this geological formation has not Been estimated yet. The objective of this study is to estimate the storage capacity of depleted Oil and gas reservoirs in indonesia using the methodology, developed by carbon Sequestration leadership forum (cslf). Screening result from our databases showed there Were 103 depleted oil and gas fields were considered depleted from their np/ult ratio (hydrocarbon cumulative production over ultimate recovery) which were 55%. However, Only 48 fields had complete data to estimate. We used the methodology that was Initially developed by cslf but then it had been simplified by poulsen et al. We considered This methodology as the most convenient to use in this country scale of assessment despite Of any simplification had been made. Estimation result showed riau and south sumatra Region have large storage capacities which are around 229 and 144 mtco2 respectively. The estimates of co2 storage capacity reflects the actual capacity that was based on data Availability during the assessment. The potential storage capacity might change as data Becoming more available. Hence, the storage capacity map resulted from this study is not Conclusive estimation. However, this study indicates that indonesia has huge potential of Co2 storage in depleted oil and gas reservoirs.
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Akai, Takashi, Naoki Saito, Michiharu Hiyama, and Hiroshi Okabe. "Numerical Modelling on CO2 Storage Capacity in Depleted Gas Reservoirs." Energies 14, no. 13 (July 2, 2021): 3978. http://dx.doi.org/10.3390/en14133978.
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Making an accurate estimate of the CO2 storage capacity before the commencement of a carbon capture and storage (CCS) project is crucial to the project design and feasibility investigation. We present herein a numerical modelling study on the CO2 storage capacity in depleted gas reservoirs. First, we show a simple volumetric equation that gives the CO2 storage capacity in a depleted gas reservoir, which considers the same volume of CH4 at reservoir pressure and temperature conditions produced from the reservoir. Next, the validity and the limitations of this equation are investigated using a numerical reservoir simulation with the various reservoir characteristics of reservoir heterogeneity, aquifer water encroachment, and rock compaction and its reversibility. Regardless of the reservoir heterogeneity, if a reservoir is subjected to a weak or moderate aquifer support, the volumetric equation provides an estimate of the CO2 storage capacity as structurally trapped gas within 1% of that estimated from numerical simulations. The most significant factor influencing the CO2 storage capacity is the reversibility of rock compaction, rather than the degree of rock compaction. If reservoir rocks have a strong hysteresis in their compaction and expansion behaviour, the material balance equation will overestimate the amount of structural CO2 trapping. All the simulation results show a fairly consistent amount of trapped CO2 as a dissolved component in water, which is 15%∼17% of the structurally trapped CO2. Overall, our study presents the validity and the limitation of the simple material balance equation for estimating the CO2 storage capacity, which helps with designing a CCS project at the early stage.
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Stefănescu, Dan-Paul. "Physical - chemical interaction of injection waters with depleted gas formations." MATEC Web of Conferences 343 (2021): 09006. http://dx.doi.org/10.1051/matecconf/202134309006.
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In order that the physical - chemical interaction of the injection water with the porous-permeable or fissured medium of reservoirs do not lead to their degradation, it is necessary that the waters to meet a number of quality conditions. The treatment and conditioning of the injectable waters is imperative to do so due to the fact that their provenance is different, such as reservoir waters, wastewater resulting from various operations – petroleum operations, meteoric waters, etc. and, in particular, due to the very large volumes of injected water. Failure to follow the steps associated with the water treatment process inevitably leads to premature reduction of the injection wells receptivity. This aspect, as well as another, will be analysed in the context of this article. The injection of water in different geological formations, usually highly depleted, is a connected and defining one in the process of extraction of natural gas from reservoirs. The claim is based on the fact that the very large volumes of reservoir water taken from natural gas stream must be stored safely, otherwise their free discharge would create a real ecological catastrophe
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Kondrat, R. М., and L. І. Haidarova. "Improving the efficiency of additional development of depleted gas reservoirs by displacing the residual gas with nitrogen." Prospecting and Development of Oil and Gas Fields, no. 1(78) (March 29, 2021): 25–34. http://dx.doi.org/10.31471/1993-9973-2021-1(78)-25-34.
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Based on the analysis of publications in domestic and foreign scientific and technical publications, the directions of increasing gas recovery from depleted gas reservoirs, which include the displacement of residual gas from the porous medium with nitrogen, are substantiated. Nitrogen can be obtained from the air in any oil and gas producing area using membrane, adsorption or cryogenic types of plants produced by the industry. The final gas recovery factor can be adjusted by choosing certain values of technological parameters that characterize the process of reservoir development. Using hypothetical digital models, the influence on the total final gas recovery factor and the residual gas recovery factor of the pressure of the beginning of nitrogen injection into the reservoir, the rate, duration and cyclicity of its injection, the system for locating production and injection wells on the gas-bearing area and the technological modes of their operation was investigated. The results of the studies are shown in the form of graphical dependencies of the final gas recovery factor and the gas recovery factor for residual gas on the investigated determining parameters. Using the research results, the optimal values of the parameters of the nitrogen injection process into a depleted gas reservoir of square and round shapes and the corresponding values of the gas recovery coefficient have been established. The results of the studies performed indicate a significant technological efficiency of the displacement of residual gas by nitrogen from depleted gas reservoirs. Depending on the system of placement of production and injection wells in the gas-bearing area and the technological parameters of the nitrogen injection process into the reservoir, the gas recovery factor for the residual gas varies on average within the range of 53,97 – 61,82 %.
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Feder, Judy. "Modeling Evaluates CO2 EOR, Storage Potential in Depleted Reservoirs." Journal of Petroleum Technology 73, no. 06 (June 1, 2021): 63–64. http://dx.doi.org/10.2118/0621-0063-jpt.
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This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 200560, “CO2-EOR and Storage Potentials in Depleted Reservoirs in the Norwegian Continental Shelf,” by Elhans Imanovs, SPE, and Samuel Krevor, SPE, Imperial College London, and Ali Mojaddam Zadeh, Equinor, prepared for the 2020 SPE Europec featured at the 82nd EAGE Conference and Exhibition, originally scheduled to be held in Amsterdam, 8–11 June. The paper has not been peer reviewed. A combination of carbon dioxide (CO2) enhanced oil recovery (EOR) and storage schemes could offer an opportunity to produce additional oil from depleted reservoirs and permanently store CO2 in the subsurface in an economically efficient manner. The complete paper evaluates the effect of different injection methods on oil recovery and CO2 storage potential in a depleted sandstone reservoir in the Norwegian Continental Shelf (NCS). The methods include continuous gas injection (CGI), continuous water injection (CWI), water alternating gas (WAG), tapered WAG (TWAG), simultaneous water above gas coinjection (SWGCO), simultaneous water and gas injection (SWGI), and cyclic SWGI. CO2 EOR and Storage in the NCS In recent years, the number of newly explored fields in the NCS has decreased. Approximately 47% of total resources in the NCS have been produced, and approximately 20% of resources are estimated as recoverable reserves. To fill in the gap between energy demand and recoverable reserves, EOR methods could be employed. One of the most efficient EOR methods is CO2 injection, because complete microscopic sweep efficiency can be achieved, leading to a total depletion of the reservoir. The three major types of CO2 EOR processes—miscible, near-miscible, and immiscible—are described and discussed in the full paper. Four primary CO2-trapping mechanisms are used in the subsurface: structural/stratigraphic, solubility, residual, and mineral trapping. The main locations for underground geological storage are depleted oil and gas reservoirs, coal formations, and saline aquifers. Currently, underground CO2 storage is believed to be a major technology to dramatically reduce CO2 amounts in the atmosphere. According to the International Energy Agency, 54 major oil basins around the world have the potential to produce 75 Bsm3 of additional oil and store 140 Gt of CO2. CO2 EOR and storage projects in the NCS could have several benefits. First, surface and subsea facility availability in the NCS region reduces capital expenditures. Second, in addition to the revenue from extra oil production, carbon credits could be awarded for the CO2 storage. The main challenges of CO2 EOR and storage offshore projects are high operational and capital expenditures. In depleted reservoirs, these include modification of offshore platform materials; additional power supply for CO2 compression and recycling; and replacement of the tubing because wet CO2 is highly corrosive, resulting in scale, asphaltene, and hydrates formation. Contamination of a gas cap with injected CO2 might lead to loss of hydrocarbon gas market value. Only one CO2 EOR project has been implemented offshore—the Lula field in Brazil’s Santos Basin—meaning that industry has very limited experience in such projects.
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Burachok, Oleksandr. "Enhanced Gas and Condensate Recovery: Review of Published Pilot and Commercial Projects." Nafta-Gaz 77, no. 1 (January 2021): 20–25. http://dx.doi.org/10.18668/ng.2021.01.03.
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The majority of the Ukrainian gas condensate fields are in the final stage of development. The high level of reservoir energy depletion has caused significant in situ losses of condensed hydrocarbons. Improving and increasing hydrocarbon production is of great importance to the energy independence of Ukraine. In this paper, a review of the pilot and commercial enhanced gas and condensate recovery (EGR) projects was performed, based on published papers and literature sources, in order to identify those projects which could potentially be applied to the reservoir conditions of Ukrainian gas condensate fields. The EGR methods included the injection of dry gas (methane), hydrocarbon solvents (gas enriched with C2–C4 components), or nitrogen and carbon dioxide. The most commonly used and proven method is dry gas injection, which can be applied at any stage of the field’s development. Dry gas and intra-well cycling was done on five Ukrainian reservoirs, but because of the need to block significant volumes of sales gas they are not being considered for commercial application. Nitrogen has a number of significant advantages, but the fact that it increases the dew point pressure makes it applicable only at the early stage, when the reservoir pressure is above or near the dew point. Carbon dioxide is actively used for enhanced oil recovery (EOR) or for geological storage in depleted gas reservoirs. In light of the growing need to reduce carbon footprints, CO2 capture and sequestration is becoming very favourable, especially due to the low multi-contact miscibility pressure, the high density under reservoir conditions, and the good miscibility with formation water. All of these factors make it a good candidate for depleted gas condensate reservoirs.
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Kondrat, Roman, and Liliia Matiishyn. "Improving the efficiency of hydraulic fracturing in wells with depleted gas reservoirs." Prospecting and Development of Oil and Gas Fields, no. 4 (November 1, 2023): 7–13. http://dx.doi.org/10.69628/pdogf/4.2023.07.
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The reasons for the low production rate of gas wells in depleted gas reservoirs are presented, including low natural permeability of productive formations and contamination of the bottomhole zone with solid phase and liquid. The methods of gas inflow stimulation to the bottom of wells are presented, among which hydraulic fracturing (HF) is worthy of attention for low permeability formations and deterioration of the bottomhole zone. The essence of hydraulic fracturing is described. Conventional and high-power hydraulic fracturing, its technology, scope, materials and chemicals used, and technological efficiency are characterized. During hydraulic fracturing in wells at depths of more than 600 m, to which the main proven gas reserves are confined, vertical and near-vertical fractures will mainly form. With a small reservoir thickness, vertical fractures can damage the cement stone behind the production casing, which in depleted gas reservoirs will help create conductive channels from the gas reservoir to the upper horizons. With a vertical fracture, gas flow to the well will be in one direction along the fracture and other volumes of the wellbore zone within the fracture radius will not be fully covered by filtration. To improve the efficiency of hydraulic fracturing in wells in depleted gas reservoirs, it is proposed to create a horizontal fracture in thin formations or several vertical fractures in formations of large thickness by preliminary hydraulic sandblasting perforation (HSP) or gas hydrosandblasting perforation (GHBP). When preliminary creating horizontal channels in the bottomhole zone, tubing with a perforator is gradually rotated to a certain angle, and when creating vertical channels, they are gradually raised to a certain height. After the perforation channels are created, hydraulic fracturing is performed. With the sequential use of hydraulic sandblasting perforation and hydraulic fracturing, it is possible to create a grid of cracks of increased length in the bottomhole zone in the specified directions. Using known analytical dependences, the length of individual perforation channels during gas-hydro-sandblasting perforation with a nozzle diameter of 4.5 and 6 mm in the perforator and the fracture radius during hydraulic fracturing were determined. The degree of increase in gas flow rate separately from hydraulic fracturing and hydraulic fracturing from their sequential implementation is estimated
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Kondrat, R. M., O. R. Kondrat, and L. I. Khaidarova. "EXTRACTION OF THE RESIDUAL GAS DEPLETED GAS RESERVOIRS NITROGEN INJECTION." Prospecting and Development of Oil and Gas Fields, no. 2(71) (June 25, 2019): 20–29. http://dx.doi.org/10.31471/1993-9973-2019-2(71)-20-29.
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The relevance and feasibility of extracting residual gas from depleted gas deposits is shown. The possible directions of the extraction of residual gas from depleted gas deposits by its displacement from a porous medium of non-hydrocarbon gases are characterized. The use of nitrogen to displace natural gas from a porous medium has been substantiated. Using the GEM compositional modeling module, which is included in the licensed computer program CMG (Computer Modeling Group), studies were made of the effect of the pressure of the start of injection of nitrogen into the reservoir and the duration of its injection period on the gas recovery coefficient for residual gau. The study was conducted for deposits of square and round shape. The research results are presented in the form of graphical dependencies of the current reservoir pressure, nitrogen content in borehole products and gas recovery coefficient for residual gas from the pressure of the start of injection of nitrogen into the reservoir and the duration of the period of its injection. Using the results of the research, the optimal values of the parameters of the process of injecting nitrogen into the exhausted gas deposits of square and round forms and the corresponding values of the gas recovery coefficient were established. For the considered deposits of square and rounded forms, they are 0.29 Рin and 14.8 months, 0.31 Рin and 12.9 months, respectively. At the time of reaching the volumetric nitrogen content in the producing gas of 5 %, the gas recovery coefficient for residual gas for a square-shaped deposit is 83.91 %, for a round-shaped deposit – 77.49 %. The physical nature of the process of displacing residual gas with nitrogen from depleted gas deposits of square and round forms is characterized.
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Guo, Xiao, Jin Feng, Pengkun Wang, Bing Kong, Lan Wang, Xu Dong, and Shanfeng Guo. "Review on the Mechanism of CO2 Storage and Enhanced Gas Recovery in Carbonate Sour Gas Reservoir." Processes 11, no. 1 (January 5, 2023): 164. http://dx.doi.org/10.3390/pr11010164.
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Carbonate gas reservoirs in the Sichuan Basin have many complex characteristics, such as wide distribution, strong heterogeneity, high temperature, high pressure, high H2S and CO2 content and an active edge or bottom water. In the late stage of exploitation of carbonate sour gas reservoirs, the underground depleted reservoirs can provide a broad and favorable space for CO2 storage. If CO2 is injected into the depleted carbonate sour reservoirs for storage, it will help to achieve the goal of carbon neutrality, and the CO2 stored underground can perform as “cushion gas” to prevent the advance of edge or bottom water, to achieve the purpose of enhanced natural gas recovery. Injecting CO2 into low permeability reservoirs for oil displacement has become an important means to enhance oil recovery (EOR). However, the mechanism of EOR by injecting CO2 into carbonate sour gas reservoirs is not clear and the related fundamental research and field application technology are still in the exploration stage. This paper reviews the main scientific and technical perspectives in the process of injecting CO2 into carbonate sour gas reservoirs for storage and enhancing gas recovery.
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Ying, Qiqi, Duocai Wang, Hong Zhang, Yintong Guo, Hejuan Liu, Yujia Song, and Xin Chang. "Deformation Characteristics and Permeability Properties of Cap Rocks in Gas Storage of Depleted Reservoirs under Alternating Load." Processes 11, no. 11 (October 30, 2023): 3114. http://dx.doi.org/10.3390/pr11113114.
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Gas reservoirs have significant engineering characteristics of injection and extraction. The reservoir cap rock is subjected to cyclic alternating loading and has the potential risk of seal failure. Therefore, it is necessary to study the stress−percolation−damage mechanism of the reservoir cap rock in depleted gas reservoirs. The rock Mechanics Test System (MTS) was used to study the permeability characteristics of a typical mud shale cap layer under different loading and unloading rates, analyze the deformation characteristics and permeability performance evolution law of the rock under the confining pressure alternation, and study the effects of loading and unloading rate, confining pressure and number of cycles on the permeability of the cap rock. The test results show that with the increase in the number of cycles, the hysteresis loop moves in the direction of axial strain increase offset. The overall morphology is presented as an elongated type, and the damage of the specimen is small in the cyclic confining pressure; At the beginning of the cycling period, the permeability decreases with the increase in the confining pressure in the form of a negative exponential. At the later stage of the cycling period, the permeability basically stays unchanged, and is maintained at a low level; At low confining pressure, permeability also decreases in a negative exponential form with the increase in the number of confining pressure cycles; The greater the loading and unloading rate at the beginning of the cycle, the more the permeability decreases; There is a tendency of sealing improvement under cyclic loading in the gas storage of depleted reservoirs with mud shale as the cap layer. The results of the study can provide technical parameters for the evaluation of the cap sealing of gas storage of depleted reservoirs.
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Mucciarelli, M., F. Donda, and G. Valensise. "Earthquakes and depleted gas reservoirs: which comes first?" Natural Hazards and Earth System Sciences Discussions 2, no. 12 (December 12, 2014): 7507–19. http://dx.doi.org/10.5194/nhessd-2-7507-2014.
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Abstract. While scientists are paying increasing attention to the seismicity potentially induced by hydrocarbon exploitation, little is known about the reverse problem, i.e. the impact of active faulting and earthquakes on hydrocarbon reservoirs. The recent 2012 earthquakes in Emilia, Italy, raised concerns among the public for being possibly human-induced, but also shed light on the possible use of gas wells as a marker of the seismogenic potential of an active fold-and-thrust belt. Based on the analysis of over 400 borehole datasets from wells drilled along the Ferrara-Romagna Arc, a large oil and gas reserve in the southeastern Po Plain, we found that the 2012 earthquakes occurred within a cluster of sterile wells surrounded by productive ones. Since the geology of the productive and sterile areas is quite similar, we suggest that past earthquakes caused the loss of all natural gas from the potential reservoirs lying above their causative faults. Our findings have two important practical implications: (1) they may allow major seismogenic zones to be identified in areas of sparse seismicity, and (2) suggest that gas should be stored in exploited reservoirs rather than in sterile hydrocarbon traps or aquifers as this is likely to reduce the hazard of triggering significant earthquakes.
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Ban, Shengnan, Hejuan Liu, Xinxing Wei, Xilin Shi, Haijun Mao, Yujia Song, and Hongying Tan. "The Application of the Fuzzy Comprehensive Evaluation Method in the Sealing Evaluation of Caprocks in Underground Gas Storage." Applied Sciences 13, no. 17 (August 29, 2023): 9753. http://dx.doi.org/10.3390/app13179753.
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The good sealing caprocks are significant for the integrity of underground gas storage (UGS) in depleted natural gas reservoirs. The screening of parameters, weight assignment, and evaluation method are important for evaluating the sealing performance of caprocks. Many factors can affect the sealing performance of caprocks, including caprock thickness, lithology, brittleness, porosity and permeability, breakthrough pressure, etc. In this paper, the dominant factors in the sealing performance of caprocks in UGSs are systematically analyzed, and the weights of these factors are analyzed by the analytic hierarchy process (AHP). The fuzzy comprehensive evaluation method (FCEM) is applied in the sealing evaluation of caprocks in three typical underground gas reservoirs (i.e., Zhujiadun, Xu-2, and Xing-9) in China. The sandstone reservoir in the Zhujiadun gas field is only about 20 m, and the thickness of the overlying mudstone is about 600 m. The caprock of the Xu-2 gas reservoir in Zhongba gas field is well distributed and developed, and the breakthrough pressure is relatively large. The caprock of Xing-9 gas field is mudstone with a thickness of over 400 m. The results show that the breakthrough pressure and permeability are the key parameters affecting the sealing ability of caprocks, with weights of 0.4291 and 0.2157, respectively. Among these three examples of gas fields, the sealing performance of caprocks in Zhujiadun gas storage is the best. The evaluation procedure and methods proposed in this paper are valuable for the evaluation of the tightness of caprocks in depleted gas reservoirs.
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Bybee, Karen. "CO2 Storage as Hydrate in Depleted Gas Reservoirs." Journal of Petroleum Technology 63, no. 04 (April 1, 2011): 80–82. http://dx.doi.org/10.2118/0411-0080-jpt.
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Mucciarelli, M., F. Donda, and G. Valensise. "Earthquakes and depleted gas reservoirs: which comes first?" Natural Hazards and Earth System Sciences 15, no. 10 (October 7, 2015): 2201–8. http://dx.doi.org/10.5194/nhess-15-2201-2015.
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Abstract. While scientists are paying increasing attention to the seismicity potentially induced by hydrocarbon exploitation, so far, little is known about the reverse problem, i.e. the impact of active faulting and earthquakes on hydrocarbon reservoirs. The 20 and 29 May 2012 earthquakes in Emilia, northern Italy (Mw 6.1 and 6.0), raised concerns among the public for being possibly human-induced, but also shed light on the possible use of gas wells as a marker of the seismogenic potential of an active fold and thrust belt. We compared the location, depth and production history of 455 gas wells drilled along the Ferrara-Romagna arc, a large hydrocarbon reserve in the southeastern Po Plain (northern Italy), with the location of the inferred surface projection of the causative faults of the 2012 Emilia earthquakes and of two pre-instrumental damaging earthquakes. We found that these earthquake sources fall within a cluster of sterile wells, surrounded by productive wells at a few kilometres' distance. Since the geology of the productive and sterile areas is quite similar, we suggest that past earthquakes caused the loss of all natural gas from the potential reservoirs lying above their causative faults. To validate our hypothesis we performed two different statistical tests (binomial and Monte Carlo) on the relative distribution of productive and sterile wells, with respect to seismogenic faults. Our findings have important practical implications: (1) they may allow major seismogenic sources to be singled out within large active thrust systems; (2) they suggest that reservoirs hosted in smaller anticlines are more likely to be intact; and (3) they also suggest that in order to minimize the hazard of triggering significant earthquakes, all new gas storage facilities should use exploited reservoirs rather than sterile hydrocarbon traps or aquifers.
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Cao, Cheng, Jianxing Liao, Zhengmeng Hou, Hongcheng Xu, Faisal Mehmood, and Xuning Wu. "Utilization of CO2 as Cushion Gas for Depleted Gas Reservoir Transformed Gas Storage Reservoir." Energies 13, no. 3 (January 25, 2020): 576. http://dx.doi.org/10.3390/en13030576.
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Underground gas storage reservoirs (UGSRs) are used to keep the natural gas supply smooth. Native natural gas is commonly used as cushion gas to maintain the reservoir pressure and cannot be extracted in the depleted gas reservoir transformed UGSR, which leads to wasting huge amounts of this natural energy resource. CO2 is an alternative gas to avoid this particular issue. However, the mixing of CO2 and CH4 in the UGSR challenges the application of CO2 as cushion gas. In this work, the Donghae gas reservoir is used to investigate the suitability of using CO2 as cushion gas in depleted gas reservoir transformed UGSR. The impact of the geological and engineering parameters, including the CO2 fraction for cushion gas, reservoir temperature, reservoir permeability, residual water and production rate, on the reservoir pressure, gas mixing behavior, and CO2 production are analyzed detailly based on the 15 years cyclic gas injection and production. The results showed that the maximum accepted CO2 concentration for cushion gas is 9% under the condition of production and injection for 120 d and 180 d in a production cycle at a rate of 4.05 kg/s and 2.7 kg/s, respectively. The typical curve of the mixing zone thickness can be divided into four stages, which include the increasing stage, the smooth stage, the suddenly increasing stage, and the periodic change stage. In the periodic change stage, the mixed zone increases with the increasing of CO2 fraction, temperature, production rate, and the decreasing of permeability and water saturation. The CO2 fraction in cushion gas, reservoir permeability, and production rate have a significant effect on the breakthrough of CO2 in the production well, while the effect of water saturation and temperature is limited.
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Mkpese, U. U., G. O. Emujakporue, and A. O. Sofolabo. "Reservoir Static Modelling towards Safe CO2 Storage in Depleted Oil Reservoirs of ‘CRK’ Field, Niger Delta, Nigeria." International Journal of Environment and Climate Change 14, no. 3 (March 11, 2024): 364–76. http://dx.doi.org/10.9734/ijecc/2024/v14i34048.
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Geological carbon storage (GCS) is gradually gaining acceptance as the technology of highest repute for the mitigation against greenhouse gas effect. This involves the injection and long-term or permanent storage of carbon dioxide (CO2) in subsurface geological formations. The development of a robust 3D reservoir model then becomes necessary to understand the facies changes and the petrophysical properties distribution of candidate CO2 storage reservoirs. This study attempts the use of static modelling technique to investigate the depleted oil and gas reservoirs of ‘CRK’ field in the Niger Delta sedimentary Basin as a potential CO2 storage site. Using an integrated approach of 3D seismic and a suit of well logs from the study area, two reservoir sands (D10C0 and D6200) were mapped. 3D static modelling of discrete and continuous property distribution of the reservoirs revealed the reservoirs are composed majorly of clean sands with water saturation ranging from 8 to 75%. The average porosity and permeability values are between 20 to 29% and 250 to 890mD respectively. A theoretical storage capacity of 24.85Mt is estimated for the two reservoirs combined, while the median effective storage capacity is 6.22Mt. Comparison of the results obtained in the study with recommended standard values show the reservoirs are suitable for CO2 storage. The property models constructed can serve as primary input for dynamic simulation of the oilfield in future studies.
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Cheng, Minhua, Wen Xue, Zhi Guo, Meifang Hou, and Chenhui Wang. "Development of Large-Scale Tight Gas Sandstone Reservoirs and Recommendations for Stable Production—The Example of the Sulige Gas Field in the Ordos Basin." Sustainability 15, no. 13 (June 21, 2023): 9933. http://dx.doi.org/10.3390/su15139933.
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The natural gas reserves and gas recovery rate of tight gas sandstone reservoirs in the Sulige gas field in the Ordos Basin play a crucial role in China’s natural gas industry. This study aims to enhance the stable production time of the gas field by summarizing the geological characteristics of the tight gas sandstone reservoirs in the Sulige gas field, discussing the challenges in the development of the gas field, and providing recommendations for the development of the reservoirs. The results show that the matrix reservoir properties, effective sand body size, and gas-bearing properties of tight sandstone gas reservoirs in the Sulige gas field exhibit strong heterogeneity characteristics, and the western and northern parts of the basin edge are gas-water mixed storage areas. There are obvious differences in gas well production, cumulative production, production decline rate, and single well dynamic control reserves in different regions. The recovery of gas reservoirs is primarily influenced by reservoir quality and development well pattern. Increasing the well density increases from 1.5/km2 to 4/km2 in the gas field enrichment area, can raise the corresponding recovery rate from 26.0% to about 50% under the existing economic and technical conditions. Therefore, ensuring a stable production of the tight gas sandstone reservoirs in this gas field is challenging. To achieve a long-term stable production of the gas field, it is necessary to promote the refined reservoir description technology and improve the production through various measures such as replenishing fractures in wells with depleted fractures, sidetracking horizontal wells, and re-fracturing, thereby improving the reserve utilization degree. Moreover, implementing the negative pressure gas recovery technology as soon as possible can restore the production capacity of near-depletion wells.
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Carpenter, Chris. "Three-Way Coupled Modeling Evaluates CO2 Sequestration in Depleted Reservoir." Journal of Petroleum Technology 75, no. 01 (January 1, 2023): 64–66. http://dx.doi.org/10.2118/0123-0064-jpt.
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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 206156, “Importance of Three-Way Coupled Modeling for Carbon-Dioxide Sequestration in a Depleted Reservoir,” by Prasanna Chidambaram, SPE, Pankaj K. Tiwari, SPE, and Parimal A. Patil, SPE, Petronas, et al. The paper has not been peer reviewed. _ Three major depleted gas reservoirs in the Central Luconia field offshore Sarawak, Malaysia, are being evaluated for future carbon-dioxide (CO2) storage. A three-way coupled modeling approach that integrates dynamic, geochemistry, and geomechanics models is used to obtain the cumulative effect of all three changes. This integrated model provides a more-accurate estimate of CO2 storage capacity, caprock-integrity evaluation, CO2-plume migration path, and volume of CO2 stored through different mechanisms. Background The CO2 storage sites being evaluated are depleted gas reservoirs that have been in production for a few decades. At the end of their producing life, they have the potential to be converted into CO2 storage sites. The Central Luconia sedimentary basin is in a seismic-free zone with limited faults and consists of shale interbedded with high-sand-content sediment, making it ideal for CO2 storage. These reservoirs provide the required geological characteristics and volume needed to ensure long-term CO2 storage in a safe and economical way. The depleted gas reservoirs have an in-place volume of approximately 1.5–3 Tscf. Their thickness ranges from 100 to 150 m, with a porosity of 15–32% and permeability of 10–1600 md. These fields are believed to be supported by a regional aquifer several thousand feet thick. Large seafloor subsidence has been observed in these reservoirs. Storage-Capacity Estimation Storage capacity of a depleted hydrocarbon reservoir is affected by several factors including voidage created; aquifer influx and efflux during the production and CO2-injection phases, respectively; maximum injection pressure; rock compressibility; and geochemical effects. Depending on which of these factors are prominent in the storage reservoir, CO2-storage capacity may be estimated using a simple material-balance model or may require a more-complex approach to capture these effects. Use of the Three-Way Coupled Model Injected CO2 is anticipated to react with reservoir rock, leading to either dissolution of reservoir rock or precipitation of solids that are products of the geochemical reactions, causing a net change in porosity and permeability. With regard to geomechanical effects, uplift is anticipated to occur during CO2 injection. The degree to which subsidence is reversed depends on whether compaction of the reservoir is fully elastic or if plastic deformation has occurred. During production, reduction in porosity and permeability has occurred because of subsidence. Conventional or stand-alone reservoir simulation does not capture geochemical and geomechanical effects. Hence, it is critical to use an integrated model that captures the effects of dynamic, geochemical, and geomechanical changes caused by CO2 injection in order to evaluate suitability of the reservoir for long-term CO2 storage. A three-way coupled modeling approach that integrates dynamic, geochemistry, and geomechanics models provides a more-accurate estimate of CO2 storage capacity, along with estimation of subsidence. In three-way coupled modeling, the dynamic model is at the center, which passes input parameters to the geochemical and geomechanical models. Once it receives updated porosity and permeability values back from the geochemical and geomechanical models, the dynamic model incorporates these changes before proceeding to the next simulation timestep.
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Hou, Qi, Jianguang Wei, Ping Qiu, Xiaofeng Zhou, and Abdumalik Gayubov. "Experimental Study on Sand Production Mechanism of Underground Gas Storage in Depleted Reservoir." Journal of Physics: Conference Series 2610, no. 1 (October 1, 2023): 012024. http://dx.doi.org/10.1088/1742-6596/2610/1/012024.
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Abstract The storage of gas in underground reservoirs is critical for meeting seasonal demands, as well as for emergency situations and strategic reserves. However, the prolonged period and high flow of gas storage can lead to sand production, which can cause complications. To address this issue, a physical simulation experiment was conducted to study sand production during injection and production in underground gas storage, with varying formation pressure and water content. The results of the study indicate that lower formation pressure results in more severe sand production, and increased water content intensifies sand production. However, the displacement of sand from rock pores can improve reservoir physical properties. These findings provide valuable guidance for selecting appropriate production pressure differences during gas storage operation, based on formation pressure and water content, to ensure the rational production of gas in depleted-reservoir underground gas storage.
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Yuan, Junliang, Jingen Deng, Yong Luo, Shisheng Guo, Haishan Zhang, Qiang Tan, Kai Zhao, and Lianbo Hu. "The Research on Borehole Stability in Depleted Reservoir and Caprock: Using the Geophysics Logging Data." Scientific World Journal 2013 (2013): 1–7. http://dx.doi.org/10.1155/2013/965754.
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Long-term oil and gas exploitation in reservoir will lead to pore pressure depletion. The pore pressure depletion will result in changes of horizontal in-situ stresses both in reservoirs and caprock formations. Using the geophysics logging data, the magnitude and orientation changes of horizontal stresses in caprock and reservoir are studied. Furthermore, the borehole stability can be affected by in-situ stresses changes. To address this issue, the dehydration from caprock to reservoir and roof effect of caprock are performed. Based on that, the influence scope and magnitude of horizontal stresses reduction in caprock above the depleted reservoirs are estimated. The effects of development on borehole stability in both reservoir and caprock are studied step by step with the above geomechanical model.
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Feyzullayev, A. A., and A. G. Gojayev. "Influence of geological reservoir heterogeneity on exploitation conditions of Garadagh field / underground gas storage (Azerbaijan)." Gornye nauki i tekhnologii = Mining Science and Technology (Russia) 6, no. 2 (July 14, 2021): 105–13. http://dx.doi.org/10.17073/2500-0632-2021-2-105-113.
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Underground oil and gas reservoirs (formations) are characterized by spatial variability of their structure, material composition and petrophysical properties of its constituent rocks: particle size distribution, porosity, permeability, structure and texture of the pore space, carbonate content, electrical resistivity, oil and water saturation and other properties. When assessing development and exploitation conditions for underground gas storages, created in depleted underground oil and gas reservoirs, the inherited nature of the reservoir development should be taken into account. Therefore, identifying the features of variations in well productivity is a crucial task, solution of which can contribute to the creation of more efficient system for underground gas storage exploitation. The paper presents the findings of comparative analysis of spatial variations in well productivity during the exploitation of the Garadagh underground gas storage (Azerbaijan), created in the depleted gas condensate reservoir. An uneven nature of the variations in well productivity was established, which was connected with the reservoir heterogeneity (variations in the reservoir lithological composition and poroperm properties). The research was based on the analysis of spatial variations of a number of reservoir parameters: the reservoir net thickness, lithological composition and poroperm properties. The analysis of variations in the net thickness and poroperm properties of the VII horizon of the Garadagh gas condensate field was carried out based on the data of geophysical logging of about 40 wells and studying more than 90 core samples. The data on of more than 90 wells formed the basis for the spacial productivity variation analysis. The analysis of productivity variation in the space of well technological characteristics (based on data from 18 wells) in the Garadagh underground gas storage (UGS) was carried out through the example of the volume of cyclic gas injection and withdrawal in 2020–2021 season. The studies allowed revealing non-uniform spacial variations in the volumes of injected and withdrawn gas at the Garadagh UGS, created in the corresponding depleted gas condensate reservoir. The features of the UGS exploitation conditions are in good agreement with the features of the reservoir development conditions (variations in the well productivity). The inherited nature of the reservoir development and the underground gas storage exploitation is substantiated by the reservoir heterogeneity caused by the spatial variability of the reservoir lithological composition and poroperm properties. Assessing and taking into account the reservoir heterogeneity when designing underground gas storage exploitation conditions should be an important prerequisite for increasing UGS exploitation efficiency.
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Alkan, Hakan, Johannes Fabian Bauer, Oleksandr Burachok, Patrick Kowollik, Michael Olbricht, and Mohd Amro. "Hydrogen from Depleted/Depleting Hydrocarbon Reservoirs: A Reservoir Engineering Perspective." Applied Sciences 14, no. 14 (July 17, 2024): 6217. http://dx.doi.org/10.3390/app14146217.
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In today’s industry, H2 is mostly produced from fossil fuels such as natural gas (NG), oil, and coal through various processes. However, all these processes produce both carbon dioxide (CO2) as well as H2, making them questionable in terms of climate change mitigation efforts. In addition to efforts to increase the conversion efficiency of green H2 technologies, work is also underway to make H2 production from fossil fuels more environmentally friendly by reducing/avoiding CO2 emissions. In this framework, these technologies are combined with geologic carbon storage. In a further step, the use of depleted hydrocarbon reservoirs for in situ H2 production is being investigated, with the co-generated CO2 remaining permanently in the reservoir. The objective of this paper is to provide a brief overview of the technologies that can be used to produce H2 from depleted and depleting hydrocarbon reservoirs (DHRs) in various ways. We evaluate the required processes from a reservoir engineering perspective, highlighting their potential for H2 generation and their technology readiness level (TRL) for applications. We also investigate the possibility of permanently storing the co-produced CO2 in the reservoir as a means of mitigating emissions. In addition, we provide a preliminary cost analysis to compare these methods with conventional hydrogen production techniques, as well as an assessment of operational risks and associated cost estimates.
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Worden, Richard H. "Carbon Dioxide Capture and Storage (CCS) in Saline Aquifers versus Depleted Gas Fields." Geosciences 14, no. 6 (May 28, 2024): 146. http://dx.doi.org/10.3390/geosciences14060146.
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Saline aquifers have been used for CO2 storage as a dedicated greenhouse gas mitigation strategy since 1996. Depleted gas fields are now being planned for large-scale CCS projects. Although basalt host reservoirs are also going to be used, saline aquifers and depleted gas fields will make up most of the global geological repositories for CO2. At present, depleted gas fields and saline aquifers seem to be treated as if they are a single entity, but they have distinct differences that are examined here. Depleted gas fields have far more pre-existing information about the reservoir, top-seal caprock, internal architecture of the site, and about fluid flow properties than saline aquifers due to the long history of hydrocarbon project development and fluid production. The fluid pressure evolution paths for saline aquifers and depleted gas fields are distinctly different because, unlike saline aquifers, depleted gas fields are likely to be below hydrostatic pressure before CO2 injection commences. Depressurised depleted gas fields may require an initial injection of gas-phase CO2 instead of dense-phase CO2 typical of saline aquifers, but the greater pressure difference may allow higher initial injection rates in depleted gas fields than saline aquifers. Depressurised depleted gas fields may lead to CO2-injection-related stress paths that are distinct from saline aquifers depending on the geomechanical properties of the reservoir. CO2 trapping in saline aquifers will be dominated by buoyancy processes with residual CO2 and dissolved CO2 developing over time whereas depleted gas fields will be dominated by a sinking body of CO2 that forms a cushion below the remaining methane. Saline aquifers tend to have a relatively limited ability to fill pores with CO2 (i.e., low storage efficiency factors between 2 and 20%) as the injected CO2 is controlled by buoyancy and viscosity differences with the saline brine. In contrast, depleted gas fields may have storage efficiency factors up to 80% as the reservoir will contain sub-hydrostatic pressure methane that is easy to displace. Saline aquifers have a greater risk of halite-scale and minor dissolution of reservoir minerals than depleted gas fields as the former contain vastly more of the aqueous medium needed for such processes compared to the latter. Depleted gas fields have some different leakage risks than saline aquifers mostly related to the different fluid pressure histories, depressurisation-related alteration of geomechanical properties, and the greater number of wells typical of depleted gas fields than saline aquifers. Depleted gas fields and saline aquifers also have some different monitoring opportunities. The high-density, electrically conductive brine replaced by CO2 in saline aquifers permits seismic and resistivity imaging, but these forms of imaging are less feasible in depleted gas fields. Monitoring boreholes are less likely to be used in saline aquifers than depleted gas fields as the latter typically have numerous pre-existing exploration and production well penetrations. The significance of this analysis is that saline aquifers and depleted gas fields must be treated differently although the ultimate objective is the same: to permanently store CO2 to mitigate greenhouse gas emissions and minimise global heating.
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Wang, Jianlin, Dan Gillam, Soubhagya Das, Tom Boyle, and Melanie Ryan. "Modelling CO2 storage in oil and gas reservoirs in the Gippsland Basin." Australian Energy Producers Journal 64, no. 2 (May 16, 2024): S210—S214. http://dx.doi.org/10.1071/ep23212.
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The Gippsland Basin has world class geology for carbon capture and storage (CCS) and a long history of oil and gas production. Depleted oil and gas fields within the Gippsland Basin that are candidates for carbon dioxide (CO2) storage are in close proximity to existing infrastructure that could be repurposed as part of a CCS project. Modelling of CO2 storage in the depleted Bream oil and gas reservoir is being progressed. Bream reservoir properties are very well understood due to extensive geological and geophysical data sets available from wells and seismic data. Additionally, the field has been through three key phases of development during its production history; oil production and gas re-injection in 1988, gas cap blowdown started in 2002, and seasonal gas storage and withdrawal started in 2012 through to field shut-in in 2020. This provides a wealth of dynamic data that is used to calibrate the reservoir models to improve our confidence in the CO2 plume prediction. However, there are also challenges in modelling CO2 storage in depleted fields. Unlike saline aquifers, CO2 can be injected into a three-phase depleted reservoir that contains residual oil and gas saturation. The key aspects of our workflow to evaluate the plume behaviour are presented in this paper.
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Moncorgé, Arthur, Martin Petitfrère, and Sylvain Thibeau. "Complete Equation of State Thermal Formulation for Simulation of CO2 Storage." SPE Journal 27, no. 01 (December 2, 2021): 914–28. http://dx.doi.org/10.2118/205447-pa.
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Summary Storage of carbon dioxide (CO2) in depleted gas reservoirs or large aquifers is one of the available solutions to reduce anthropogenic greenhouse gas emissions. Numerical modeling of these processes requires the use of large geological models with several orders of magnitude of variations in the porous media properties. Moreover, modeling the injection of highly concentrated and cold CO2 in large reservoirs with the correct physics introduces numerical challenges that conventional reservoir simulators cannot handle. We propose a thermal formulation based on a full equation of state (EoS) formalism to model pure CO2 and CO2 mixtures with the residual gas of depleted reservoirs. Most of the reservoir simulators model the phase equilibriums with a pressure-temperature-based formulation. With this usual framework, it is not possible to exhibit two phases with pure CO2 contents. Moreover, in this classical framework, the crossing of the phase envelope is associated with a large discontinuity in the enthalpy computation, which can prevent the convergence of the energy conservation equation. In this work, accurate and continuous phase properties are obtained, basing our formulation on enthalpy as a primary variable. We first implement a new phase-split algorithm with input variables as pressure and enthalpy instead of the usual pressure and temperature, and we validate it on several test cases. This algorithm can model situations in which the mixture can change rapidly from one phase to the other at constant pressure and temperature. Then, treating enthalpy instead of temperature as a primary variable in both the reservoir and the well modeling algorithms, our reservoir simulator can model situations with pure or near pure components, as well as crossing of the phase envelope that usual formulations implemented in reservoir simulators cannot handle. We first validate our new formulation against the usual formulation on a problem in which both formulations can correctly represent the physics. Then, we show situations in which the usual formulations fail to represent the correct physics and that are simulated well with our new formulation. Finally, we apply our new model for the simulation of pure and cold CO2 injection in a real depleted gas reservoir from the Netherlands.
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Ciotta, Mariana, and Colombo Celso Gaeta Tassinari. "Defining geological viability criteria for CO2 and hydrogen storage in depleted oil and gas fields." Research, Society and Development 13, no. 8 (August 15, 2024): e5513846130. http://dx.doi.org/10.33448/rsd-v13i8.46130.
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This study focuses on how depleted oil and gas fields can be used as geological reservoirs to support the shift towards decarbonization and sustainable, low-carbon energy systems. These reservoirs, integral to CO2 and hydrogen storage, are pivotal in harmonizing the dual objectives of environmental conservation and energy transition. We delve into the characteristics of these depleted fields, evaluating their suitability for both CO2 and hydrogen storage, each serving distinct yet complementary decarbonization roles. CO2 storage, facilitated through carbon capture and storage (CCS) technology, aims to diminish atmospheric CO2 levels, thereby mitigating climate change. In parallel, hydrogen storage in these depleted fields emerges as a strategic solution for managing the intermittency of renewable energy sources like wind and solar power. Our study starts from the premise of using depleted oil and gas fields, assessing their potential and challenges for CO2 and hydrogen storage. We define essential criteria for evaluating the feasibility of depleted reservoirs, considering the distinct nature of CO2 and hydrogen. The literature review supported the analysis developed in this research, leading to the creation of three categories of criteria — structural and tectonic, storage and containment, and impact and reactivity — which provide a comprehensive framework for evaluating the viability of these reservoirs for both gases. Through this perspective, this research aims to systematically assess how specific factors such as porosity and permeability impact the efficacy of gas storage, thereby identifying essential parameters for optimizing storage solutions for either CO2 or hydrogen.
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Denney, Dennis. "CO2 Injection Into Depleted Gas Reservoirs." Journal of Petroleum Technology 62, no. 07 (July 1, 2010): 76–79. http://dx.doi.org/10.2118/0710-0076-jpt.
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Muhammed, Nasiru Salahu, Bashirul Haq, Dhafer Al Shehri, Suaibu O. Badmus, Abdulrauf R. Adebayo, and Mohamed Mahmoud. "Hydrogen injection and withdrawal performance in depleted gas reservoirs." International Journal of Hydrogen Energy 96 (December 2024): 427–42. http://dx.doi.org/10.1016/j.ijhydene.2024.11.229.
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Aghakhanloo, Mahdi Naji, Mohsen Akef Ghalehni, and Ali Naji Aghakhanloo. "Simulation depleted natural gas reservoirs for compressed air storage." International Journal of Engineering and Technology 11, no. 4 (August 31, 2019): 869–77. http://dx.doi.org/10.21817/ijet/2019/v11i4/191104068.
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Zatsepina, Olga Ye, and Mehran Pooladi-Darvish. "Storage of CO2 as Hydrate in Depleted Gas Reservoirs." SPE Reservoir Evaluation & Engineering 15, no. 01 (February 1, 2012): 98–108. http://dx.doi.org/10.2118/137313-pa.
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Muhammed, Nasiru Salahu, Md Bashirul Haq, Dhafer Abdullah Al Shehri, Amir Al-Ahmed, Mohammad Mizanur Rahman, Ehsan Zaman, and Stefan Iglauer. "Hydrogen storage in depleted gas reservoirs: A comprehensive review." Fuel 337 (April 2023): 127032. http://dx.doi.org/10.1016/j.fuel.2022.127032.
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Ai, Xingbo, Ziyu Zhou, and ZhaoYang. "Integration of storage in depleted gas reservoirs evaluation of injection and extraction operation." Journal of Physics: Conference Series 2898, no. 1 (November 1, 2024): 012044. http://dx.doi.org/10.1088/1742-6596/2898/1/012044.
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Abstract In order to accurately evaluate the operation status of gas injection and production in reservoirs with depleted volcanic reservoirs and the injection and production capacity of a single well, an integrated model of the pore reservoir - wellbore - surface pipeline network was established for the Xushen gas field. Besides, the optimization algorithm of the integrated simulation was used to set up the optimization objective function according to the needs of the actual study, to build the optimization control variables at each level of the system, and to set up single-well production conditions under several additional constraints, including full production capacity, water/gas ratio, fluid-carrying capacity, and peak/valley production changes. The production conditions of a single well are set by the calculation of each sub-system and additional requirements in the field. Through the optimization calculation, the production distribution of a single well is obtained under the conditions of giving full play to the production capacity, taking into account the water/gas ratio, the liquid-carrying capacity, and the production changes during peak and valley periods. The study shows that the water intrusion volume of alternating injection and extraction exhibits cyclic changes of alternating increase and decrease, and the numerical simulation method of the gas reservoir predicts that the water intrusion volume of the scenario at the end of multi-cycle gas injection is 260-340×104 m^3, and that of the scenario at the end of multi-cycle gas extraction is 550-610×104 m^3; and that of the straight well scenario is larger, with a single-cycle volume of 289-338×104 m^3 at the late stage of the five rounds of injection and extraction cycles; The horizontal well program has a larger water intrusion amount, with a single-cycle water intrusion amount of 289-338×104 m^3 at the end of five injection and extraction cycles.
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Lin, Baicen, Yunsheng Wei, Shusheng Gao, Liyou Ye, Huaxun Liu, Wenqing Zhu, Jianzhong Zhang, and Donghuan Han. "Current Progress and Development Trend of Gas Injection to Enhance Gas Recovery in Gas Reservoirs." Energies 17, no. 7 (March 26, 2024): 1595. http://dx.doi.org/10.3390/en17071595.
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Conventional recovery enhancement techniques are aimed at reducing the abandonment pressure, but there is an upper limit for recovery enhancement due to the energy limitation of reservoirs. Gas injection for energy supplementation has become an effective way to enhance gas recovery by reducing hydrocarbon saturation in gas reservoirs. This review systematically investigates progress in gas injection for enhanced gas recovery in three aspects: experiments, numerical simulations and field examples. It summarizes and analyzes the current research results on gas injection for EGR and explores further prospects for future research. The research results show the following: (1) Based on the differences in the physical properties of CO2, N2 and natural gas, effective cushion gas can be formed in bottom reservoirs after gas injection to achieve the effects of pressurization, energy replenishment and gravity differentiation water resistance. However, further experimental evaluation is needed for the degree of increase in penetration ability. (2) It is more beneficial to inject N2 before CO2 or the mixture of N2 and CO2 in terms of EGR effect and cost. (3) According to numerical simulation studies, water drive and condensate gas reservoirs exhibit significant recovery effects, while CO2-EGR in depleted gas reservoirs is more advantageous for burial and storage; current numerical simulations only focus on mobility mass and saturation changes and lack a mixed-phase percolation model, which leads to insufficient analysis of injection strategies and a lack of distinction among different gas extraction effects. Therefore, a mixed-phase-driven percolation model that can characterize the fluid flow path is worth studying in depth. (4) The De Wijk and Budafa Szinfelleti projects have shown that gas injection into water drive and depleted reservoirs has a large advantage for EGR, as it can enhance recovery by more than 10%. More experiments, simulation studies and demonstration projects are needed to promote the development of gas injection technology for enhanced recovery in the future.
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Chamani, Amin, and Vamegh Rasouli. "3D numerical simulation of injection into a porous natural gas storage." APPEA Journal 51, no. 1 (2011): 653. http://dx.doi.org/10.1071/aj10046.
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The increasing demand for the consumption of natural gas has attracted the interest to store natural gas in depleted reservoirs. Natural gas is injected into the depleted reservoir and then produced once needed to be supplied to the consumers through pipelines. Changes of reservoir fluid pressure due to injection/ depletion will result in the local changes of stress regime inside the reservoir as well as the surrounding rocks. These stress fluctuations will primarily lead to the deformations and changes of the loads exerted on the wellbore. This can potentially trigger hazardous events such as considerable land surface movements, wellbore instability and casing collapse, fault reactivation, and cap rock failure. Therefore a good knowledge of reservoir geomechanics is required when planning storage of natural gas in a depleted reservoir. In this paper the concept of effective stress and pore pressure will be reviewed. A 3D finite element (FE) numerical modelling technique is developed to investigate the changes in stresses and displacements either during the injection or the depletion in a complete isotropic elastic media. The numerical code is used to simulate the injection-induced stress and displacement fields at a field scale for a hypothetical model with an embedded porous formation. The effect of formation rock mechanical properties such as Young’s modulus is also investigated through a series of sensitivity analysis. The results are presented and interpreted and various conclusions are made.
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Rui, Yiming, Bin Zhu, Qingsong Tang, Changcheng Yang, Dan Wang, Wanfen Pu, and Xiaodong Tang. "Experimental Study of the Feasibility of In-Situ Hydrogen Generation from Gas Reservoir." Energies 15, no. 21 (November 2, 2022): 8185. http://dx.doi.org/10.3390/en15218185.
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Due to there is no better way to exploit depleted gas reservoirs, and hydrogen can generate from natural gas combustion. In this paper, the possibility of in-situ hydrogen generation in air injected gas reservoirs was determined through pseudo dynamic experiments. The study indicated that higher temperature and steam/methane ratio can generate more hydrogen, and the temperature should not be lower than 600 °C within gas reservoirs. The debris has positive catalysis for hydrogen generation. The maximum mole fraction of hydrogen was 26.63% at 600 °C.
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Lyu, Xiaocong, Fang Cen, Rui Wang, Huiqing Liu, Jing Wang, Junxi Xiao, and Xudong Shen. "Density-Driven CO2 Dissolution in Depleted Gas Reservoirs with Bottom Aquifers." Energies 17, no. 14 (July 16, 2024): 3491. http://dx.doi.org/10.3390/en17143491.
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Depleted gas reservoirs with bottom water show significant potential for long-term CO2 storage. The residual gas influences mass-transfer dynamics, further affecting CO2 dissolution and convection in porous media. In this study, we conducted a series of numerical simulations to explore how residual-gas mixtures impact CO2 dissolution trapping. Moreover, we analyzed the CO2 dissolution rate at various stages and delineated the initiation and decline of convection in relation to gas composition, thereby quantifying the influence of residual-gas mixtures. The findings elucidate that the temporal evolution of the Sherwood number observed in the synthetic model incorporating CTZ closely parallels that of the single-phase model, but the order of magnitude is markedly higher. The introduction of CTZ serves to augment gravity-induced convection and expedites the dissolution of CO2, whereas the presence of residual-gas mixtures exerts a deleterious impact on mass transfer. The escalation of residual gas content concomitantly diminishes the partial pressure and solubility of CO2. Consequently, there is an alleviation of the concentration and density differentials between saturated water and fresh water, resulting in the attenuation of the driving force governing CO2 diffusion and convection. This leads to a substantial reduction in the rate of CO2 dissolution, primarily governed by gravity-induced fingering, thereby manifesting as a delay in the onset and decay time of convection, accompanied by a pronounced decrement in the maximum Sherwood number. In the field-scale simulation, the injected CO2 improves the reservoir pressure, further pushing more gas to the producers. However, due to the presence of CH4 in the post-injection process, the capacity for CO2 dissolution is reduced.
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Kolokolova, I. V., and I. N. Konovalova. "New methods for isolation and mapping of natural reservoirs for underground hydrogen storage in depleted hydrocarbon deposits." Actual Problems of Oil and Gas, no. 30 (December 21, 2020): 3–12. http://dx.doi.org/10.29222/ipng.2078-5712.2020-30.art1.
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The article proposes new methodological techniques for identifying and mapping true and false seals based on the data of geophysical methods, according to the main provisions of the theory of the three-layer structure of natural oil and gas reservoirs. Seismic exploration in combination with well logging makes it possible to control the storage volumes, determine the gas-water contact contour and obtain detailed models of the natural reservoir.
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Hamza, Ahmed, Ibnelwaleed A. Hussein, Mohammed J. Al-Marri, Mohamed Mahmoud, Reyad Shawabkeh, and Santiago Aparicio. "CO2 enhanced gas recovery and sequestration in depleted gas reservoirs: A review." Journal of Petroleum Science and Engineering 196 (January 2021): 107685. http://dx.doi.org/10.1016/j.petrol.2020.107685.
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Kondrat, R. М., and L. І. Khaidarova. "The Influence of the Characteristics of the Gas Reservoirs Perforation-Entering on the Well Production Capabilities." Prospecting and Development of Oil and Gas Fields, no. 4(73) (December 30, 2019): 46–53. http://dx.doi.org/10.31471/1993-9973-2019-4(73)-46-53.
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The main complications in the production of residual gas from depleted gas reservoirs are characterized. The deterioration of the formation pay zone in the depleted reservoirs occurs mainly due to the accumulation of liquid and particles and due to possible deformation of the rocks. One of the methods to reduce the effect of the for-mation bottom-hole zone contamination on the productive characteristics of wells is to create perforation tunnels in the bottomhole zone that can pass through the contaminated zone and improve the hydrodynamic connection of the gas-bearing reservoir with the well. The author studies the effect of the number and the size of perforation tun-nels (depending on the permeability of the reservoir at constant wellhead pressure) on the gas-well flow rate. The research results are presented in the form of graphical dependence of the ratio between the flow rate of the well with perforation channels and a hydrodynamically perfect well q/q0 on determining factors, as well as in the form of graphic relationships among individual determining factors. Using the research results, it is found that the ra-tional value of the diameter of the perforation channels should be at least 0,03 m, the channel lengths should not be shorter than 0,292-0,307 m and the number of channels per meter of the revealed reservoir thickness should be not less than 17-19 depending on the permeability of the formation. The number of perforation tunnels and their length de-crease with the growth of reservoir permeability according to the exponential law.