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Curtis M. Oldenburg - One of the best experts on this subject based on the ideXlab platform.
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Review of Quantitative Monitoring Methodologies for Emissions Verification and Accounting for Carbon Dioxide Capture and Storage for California’s Greenhouse Gas Cap-and-Trade and Low-Carbon Fuel Standard Programs
2014Co-Authors: Curtis M. Oldenburg, Jens BirkholzerAbstract:Author(s): Oldenburg, Curtis M.; Birkholzer, Jens T. | Abstract: The Cap-and-Trade and Low Carbon Fuel Standard (LCFS) programs being administered by the California Air Resources Board (CARB) include Carbon Dioxide Capture and Storage (CCS) as a potential means to reduce greenhouse Gas (GHG) emissions. However, there is currently no universal standard approach that quantifies GHG emissions reductions for CCS and that is suitable for the quantitative needs of the Cap-and-Trade and LCFS programs. CCS involves emissions related to the capture (e.g., arising from increased energy needed to separate carbon dioxide (CO2) from a flue Gas and compress it for transport), transport (e.g., by pipeline), and storage of CO2 (e.g., due to leakage to the atmosphere from geologic CO2 storage sites). In this project, we reviewed and compared monitoring, verification, and accounting (MVA) protocols for CCS from around the world by focusing on protocols specific to the geologic storage part of CCS. In addition to presenting the review of these protocols, we highlight in this report those storage-related MVA protocols that we believe are particularly appropriate for CCS in California. We find that none of the existing protocols is completely appropriate for California, but various elements of all of them could be adopted and/or augmented to develop a rigorous, defensible, and practical surface leakage MVA protocol for California. The key features of a suitable surface leakage MVA plan for California are that it: (1) informs and validates the leakage risk assessment, (2) specifies use of the most effective monitoring strategies while still being flexible enough to accommodate special or site-specific conditions, (3) allow quantification of stored CO2, and (4) offer defensible estimates of uncertainty in monitored properties. California’s surface leakage MVA protocol needs to be applicable to the main CO2 storage opportunities (in California and in other states with entities participating in California’s Cap-and-Trade or LCFS programs), specifically CO2-Enhanced oil Recovery (CO2-EOR), CO2 injection into depleted Gas reservoirs (with or without CO2-Enhanced Gas Recovery (CO2-EGR)), as well as deep saline storage. Regarding the elements of an effective surface leakage MVA protocol, our recommendations for California are that: (1) both CO2 and methane (CH4) surface leakage should be monitored, especially for Enhanced Recovery scenarios, (2) emissions from all sources not directly related to injection and geologic storage (e.g., from capture, pipeline transport, etc.) should be monitored and reported under a plan separate from the surface leakage MVA plan that is included as another component of the quantification methodology (QM), (3) the primary objective of the surface leakage MVA plan should be to quantify surface leakage of CO2 and CH4 and its uncertainty, with consideration of best-practices and state-of-the-art approaches to monitoring including attribution assessment, (4) effort should be made to monitor CO2 storage and migration in the subsurface to anticipate future surface leakage monitoring needs, (5) detailed descriptions of specific monitoring technologies and approaches should be provided in the MVA plan, (6) the main purpose of the CO2 injection project (CO2-EOR, CO2-EGR, or pure geologic carbon sequestration (GCS)) needs to be stated up front, (7) approaches to dealing with missing data and quantifying uncertainty need to be described, and (8) post-injection monitoring should go on for a period consistent with or longer than that prescribed by the U.S. EPA.
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joule thomson cooling due to co2 injection into natural Gas reservoirs
Energy Conversion and Management, 2007Co-Authors: Curtis M. OldenburgAbstract:Depleted natural Gas reservoirs are a promising target for Carbon Sequestration with Enhanced Gas Recovery (CSEGR). The focus of this study is on evaluating the importance of Joule-Thomson cooling during CO2 injection into depleted natural Gas reservoirs. Joule-Thomson cooling is the adiabatic cooling that accompanies the expansion of a real Gas. If Joule-Thomson cooling were extreme, injectivity and formation permeability could be altered by the freezing of residual water, formation of hydrates, and fracturing due to thermal stresses. The TOUGH2/EOS7C module for CO2-CH4-H2O mixtures is used as the simulation analysis tool. For verification of EOS7C, the classic Joule-Thomson expansion experiment is modeled for pure CO2 resulting
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joule thomson cooling due to co2 injection into natural Gas reservoirs
Lawrence Berkeley National Laboratory, 2006Co-Authors: Curtis M. OldenburgAbstract:Depleted natural Gas reservoirs are a promising target for Carbon Sequestration with Enhanced Gas Recovery (CSEGR). The focus of this study is on evaluating the importance of Joule-Thomson cooling during CO2 injection into depleted natural Gas reservoirs. Joule-Thomson cooling is the adiabatic cooling that accompanies the expansion of a real Gas. If Joule-Thomson cooling were extreme, injectivity and formation permeability could be altered by the freezing of residual water, formation of hydrates, and fracturing due to thermal stresses. The TOUGH2/EOS7C module for CO2-CH4-H2O mixtures is used as the simulation analysis tool. For verification of EOS7C, the classic Joule-Thomson expansion experiment is modeled for pure CO2 resulting in Joule-Thomson coefficients in agreement with standard references to within 5-7 percent. For demonstration purposes, CO2 injection at constant pressure and with a large pressure drop (~;50 bars) is presented in order to show that cooling by more than 20oC can occur by this effect. Two more-realistic constant-rate injection cases show that for typical systems in the Sacramento Valley, California, the Joule-Thomson cooling effect is minimal. This simulation study shows that for constant-rate injections into high-permeability reservoirs, the Joule-Thomson cooling effect is not expected to create significant problems for CSEGR.
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economic feasibility of carbon sequestration with Enhanced Gas Recovery csegr
Energy, 2004Co-Authors: Curtis M. Oldenburg, S H Stevens, Sally M BensonAbstract:Abstract Prior reservoir simulation and laboratory studies have suggested that injecting carbon dioxide into mature natural Gas reservoirs for carbon sequestration with Enhanced Gas Recovery (CSEGR) is technically feasible. Reservoir simulations show that the high density of carbon dioxide can be exploited to favor displacement of methane with limited Gas mixing by injecting carbon dioxide in low regions of a reservoir while producing from higher regions in the reservoir. Economic sensitivity analysis of a prototypical CSEGR application at a large depleting Gas field in California shows that the largest expense will be for carbon dioxide capture, purification, compression, and transport to the field. Other incremental costs for CSEGR include: (1) new or reconditioned wells for carbon dioxide injection, methane production, and monitoring; (2) carbon dioxide distribution within the field; and, (3) separation facilities to handle eventual carbon dioxide contamination of the methane. Economic feasibility is most sensitive to wellhead methane price, carbon dioxide supply costs, and the ratio of carbon dioxide injected to incremental methane produced. Our analysis suggests that CSEGR may be economically feasible at carbon dioxide supply costs of up to US$ 4–12/t (US$ 0.20–0.63/Mcf). Although this analysis is based on a particular Gas field, the approach is general and can be applied to other Gas fields. This economic analysis, along with reservoir simulation and laboratory studies that suggest the technical feasibility of CSEGR, demonstrates that CSEGR can be feasible and that a field pilot study of the process should be undertaken to test the concept further.
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carbon sequestration in natural Gas reservoirs Enhanced Gas Recovery and natural Gas storage
Lawrence Berkeley National Laboratory, 2003Co-Authors: Curtis M. OldenburgAbstract:Natural Gas reservoirs are obvious targets for carbon sequestration by direct carbon dioxide (CO2) injection by virtue of their proven record of Gas production and integrity against Gas escape. Carbon sequestration in depleted natural Gas reservoirs can be coupled with Enhanced Gas production by injecting CO2 into the reservoir as it is being produced, a process called Carbon Sequestration with Enhanced Gas Recovery (CSEGR). In this process, supercritical CO2 is injected deep in the reservoir while methane (CH4) is produced at wells some distance away. The active injection of CO2 causes repressurization and CH4 displacement to allow the control and enhancement of Gas Recovery relative to water-drive or depletion-drive reservoir operations. Carbon dioxide undergoes a large change in density as CO2 Gas passes through the critical pressure at temperatures near the critical temperature. This feature makes CO2 a potentially effective cushion Gas for Gas storage reservoirs. Thus at the end of the CSEGR process when the reservoir is filled with CO2, additional benefit of the reservoir may be obtained through its operation as a natural Gas storage reservoir. In this paper, we present discussion and simulation results from TOUGH2/EOS7C of Gas mixture property prediction, Gas injection, repressurization, migration, and mixing processes that occur in Gas reservoirs under active CO2 injection.
Reinhard Gaupp - One of the best experts on this subject based on the ideXlab platform.
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experimental and numerical investigations on co2 injection and Enhanced Gas Recovery effects in altmark Gas field central germany
Acta Geotechnica, 2014Co-Authors: Leonhard Ganzer, Viktor Reitenbach, Dieter Pudlo, Daniel Albrecht, Arron Tchouka Singhe, Kilian Nhungong Awemo, Joachim Wienand, Reinhard GauppAbstract:The feasibility of CO2 storage and Enhanced Gas Recovery (EGR) effects in the mature Altmark natural Gas field in Central Germany has been studied in this paper. The investigations were comprehensive and comprise the characterization of the litho- and diagenetic facies, mineral content, geochemical composition, the petrophysical properties of the reservoir rocks with respect to their potential reactivity to CO2 as well as reservoir simulation studies to evaluate the CO2 wellbore injectivity and displacement efficiency of the residual Gas by the injected CO2. The Rotliegend sediments of the Altmark pilot injection area exhibit distinct mineralogical, geochemical, and petrophysical features related to litho- and diagenetic facies types. The reservoir rock reactivity to CO2 has been studied in autoclave experiments and associated effects on two-phase transport properties have been examined by means of routine and special core analysis before and after the laboratory runs. Dissolution of calcite and anhydrite during the short-term treatments leading to the enhancements of permeability and porosity as well as stabilization of the water saturation relevant for CO2 injection have been observed. Numerical simulation of the injection process and EGR effects in a sector of the Altmark field coupled with a wellbore model revealed the possibility of injecting the CO2 Gas at temperatures as low as 10 °C and pressures around 40 bar achieving effective inflow in the reservoir without phase transition in the wellbore. The small ratio of injected CO2 volume versus reservoir volume indicated no significant EGR effects. However, the retention and storage capacity of CO2 will be maximized. The migration/extension of CO2 varies as a function of heterogeneity both in the layers and in the reservoir. The investigation of CO2 extension and pressure propagation suggested no breakthrough of CO2 at the prospective production well during the 3-year injection period studied.
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Experimental and numerical investigations on CO_2 injection and Enhanced Gas Recovery effects in Altmark Gas field (Central Germany)
Acta Geotechnica, 2014Co-Authors: Leonhard Ganzer, Viktor Reitenbach, Dieter Pudlo, Daniel Albrecht, Arron Tchouka Singhe, Kilian Nhungong Awemo, Joachim Wienand, Reinhard GauppAbstract:The feasibility of CO_2 storage and Enhanced Gas Recovery (EGR) effects in the mature Altmark natural Gas field in Central Germany has been studied in this paper. The investigations were comprehensive and comprise the characterization of the litho- and diagenetic facies, mineral content, geochemical composition, the petrophysical properties of the reservoir rocks with respect to their potential reactivity to CO_2 as well as reservoir simulation studies to evaluate the CO_2 wellbore injectivity and displacement efficiency of the residual Gas by the injected CO_2. The Rotliegend sediments of the Altmark pilot injection area exhibit distinct mineralogical, geochemical, and petrophysical features related to litho- and diagenetic facies types. The reservoir rock reactivity to CO_2 has been studied in autoclave experiments and associated effects on two-phase transport properties have been examined by means of routine and special core analysis before and after the laboratory runs. Dissolution of calcite and anhydrite during the short-term treatments leading to the enhancements of permeability and porosity as well as stabilization of the water saturation relevant for CO_2 injection have been observed. Numerical simulation of the injection process and EGR effects in a sector of the Altmark field coupled with a wellbore model revealed the possibility of injecting the CO_2 Gas at temperatures as low as 10 °C and pressures around 40 bar achieving effective inflow in the reservoir without phase transition in the wellbore. The small ratio of injected CO_2 volume versus reservoir volume indicated no significant EGR effects. However, the retention and storage capacity of CO_2 will be maximized. The migration/extension of CO_2 varies as a function of heterogeneity both in the layers and in the reservoir. The investigation of CO_2 extension and pressure propagation suggested no breakthrough of CO_2 at the prospective production well during the 3-year injection period studied.
Liang Huang - One of the best experts on this subject based on the ideXlab platform.
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kerogen deformation upon co2 ch4 competitive sorption implications for co2 sequestration and Enhanced ch4 Recovery
Journal of Petroleum Science and Engineering, 2019Co-Authors: Qing Wang, Liang Huang, Zhengfu Ning, Zhilin Cheng, Wentong Zhang, Huibo QinAbstract:Abstract The low permeability of kerogen governs the storage and production of shale Gas. The flexible kerogen constantly experiences mechanical deformation induced by reservoir environment and complex interplay with geofluids. However, the kerogen deformation associated with CH4/CO2 competitive sorption remains poorly understood. In this work, the effect of preloaded moisture on the deformation of kerogen with different organic types was investigated with molecular dynamics simulation. The kerogen deformation upon CH4/CO2 competitive sorption was quantified with the combination of grand canonical Monte Carlo simulations and poromechanics theory. The effects of various factors and their corresponding contributions were discussed in detail. The effects of kerogen deformation on CH4/CO2 diffusion were studied. Some implications for CO2 sequestration and Enhanced Gas Recovery (CS-EGR) were proposed. Our results verify the theoretical feasibility of CS-EGR in shale Gas reservoir. CO2 is observed to have a higher affinity with kerogen and a lower diffusion coefficient compared with CH4, facilitating it to replace CH4 and retain in the kerogen matrix. The rising CO2 composition can induce larger kerogen swelling, thus opening fluid flow pathways and increasing shale Gas production. There are optimum moisture content and reservoir pressure corresponding to the maximum effective pore size in kerogen. It could be feasible to enhance the efficiency of CS-EGR by manipulating the reservoir moisture and CO2 injection timing. Thermal stimulation in deep shale reservoir may not be efficient for CS-EGR. CH4/CO2 competitive sorption can induce significant swelling of kerogen. The flexible nature of kerogen should be considered to improve the evaluation on both Gas-in-place and CO2 storage capacity.
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molecular insight into competitive adsorption of methane and carbon dioxide in montmorillonite effect of clay structure and water content
Fuel, 2019Co-Authors: Qing Wang, Liang HuangAbstract:Abstract The microscopic competitive adsorption mechanism of methane (CH4) and carbon dioxide (CO2) is of fundamental significance for CO2 sequestration with Enhanced Gas Recovery (CS-EGR) in clay-rich shale Gas reservoirs, which is still in a preliminary research stage. In this study, the Na-montmorillonite models with various pore sizes and water densities were generated to gain insights into the CO2/CH4 competitive adsorption behaviors using the combined molecular dynamics and grand canonical Monte Carlo simulations. The effects and corresponding mechanisms of clay pore size, structure heterogeneity and water content on CO2/CH4 adsorption capacity, contribution of selectivity and isosteric adsorption heat were discussed in detail. Simulation results show that the Na-montmorillonite clay favors the preferential adsorption of CO2 over CH4, and the preferential adsorption of CO2 reduces with increasing clay pore size and pressure. Adsorbility factor is the major contribution for the CO2/CH4 adsorption selectivity in dry clay models, while the contribution of volumetric factor enhances with rising pore heterogeneity caused by increasing water content and decreasing pore size. The physical pore heterogeneity in the upper near-wall region resulted from Na+ distribution, associated with the difference of CO2/CH4 dynamic diameter is one reason for the asymmetrical CO2/CH4 density profiles, while the strong affinity between CO2/Na+ and substituted Al atoms in the upper tetrahedron is the other reason. Interestingly, a later increase of CO2/CH4 adsorption selectivity with further rising water density is observed, which is due to the solvation of Na+ in interlayer water phase, re-exposing some high energy adsorption sites for CO2 adsorption. This result provides implication that the CS-EGR efficiency can be potentially improved by increasing the water content in clay. This study gains deep insights into the CO2/CH4 competitive adsorption mechanism in montmorillonite clay at microscopic scale, and can open new potentials for tuning the application of CS-EGR in clay-rich shale Gas reservoirs.
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effect of organic type and moisture on co2 ch4 competitive adsorption in kerogen with implications for co2 sequestration and Enhanced ch4 Recovery
Applied Energy, 2018Co-Authors: Liang Huang, Qing Wang, Zhengfu Ning, Zhilin Cheng, Wentong Zhang, Huibo QinAbstract:Abstract Although research attentions for CO2 injection in Gas-bearing reservoirs have been drawn to CO2 sequestration with Enhanced Gas Recovery (CS-EGR), the microscopic competitive adsorption mechanism of methane (CH4) and carbon dioxide (CO2) considering the effect of organic type and moisture remains to be determined. In this work, we focus on the competitive adsorption behaviors of CH4 and CO2 on dry and moist realistic kerogen models of different organic types by performing combined molecular dynamics (MD) and grand canonical Monte Carlo (GCMC) simulations. The effects of organic type and moisture content on kerogen pore structures, moisture distribution and interaction between CH4/CO2 and kerogen surfaces are discussed in details. Simulation results show that CO2/CH4 adsorption capacity and adsorption selectivity are in the order of kerogen IA
Michael L Johns - One of the best experts on this subject based on the ideXlab platform.
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quantitative dependence of ch4 co2 dispersion on immobile water fraction
Aiche Journal, 2017Co-Authors: Marco Zecca, Sarah J. Vogt, Abdolvahab Honari, Gongkui Xiao, Einar O. Fridjonsson, Eric F. May, Michael L JohnsAbstract:Enhanced Gas Recovery (EGR) involves CO2 injection into natural Gas reservoirs to both increase Gas Recovery and trap CO2. EGR viability can be determined by reservoir simulations; however these require a description of fluid dispersion (mixing) between the supercritical CO2 and natural Gas. Here we quantify this dispersivity (α) in sandstone rock plugs as a function of residual water fraction. To ensure the accuracy of such data, we designed a novel core flooding experimental protocol that ensured an even spatial distribution of water, minimised erroneous entry/exit contributions to mixing, and minimised dissolution of the CO2 into the water phase. Dispersivity was found to increase significantly with water content, although the differences in α between sandstones were eliminated upon the inclusion of residual water. This enabled development of a correlation between α and water content and, hence, between the dispersion coefficient and Peclet number that is readily incorporable into reservoir simulations. This article is protected by copyright. All rights reserved.
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Inclusion of Connate Water in Enhanced Gas Recovery Reservoir Simulations
Energy, 2017Co-Authors: M.j. Patel, Eric F. May, Michael L JohnsAbstract:Abstract Enhanced natural Gas Recovery (EGR) with supercritical (sc)CO2 sequestration offers the prospect of increased natural Gas Recovery. High-fidelity reservoir simulations offer a method to quantify the risk of contamination of produced Gas by the injected scCO2. Simulations of scCO2 mixing with the reservoir Gas have been reported; however the effects of connate water on EGR have not been effectively explored. We extend a prior EGR simulation tool (Patel, May and Johns, 2016; Ref. [1]) to incorporate connate water accounting for its effect on dispersivity and permeability; chemical equilibrium is modelled using a novel, computationally efficient Lagrange multiplier-based approach. The code is applied to a ‘quarter five-spot’ benchmark scenario. The inclusion of connate water generally resulted in a reduction in breakthrough time and a decrease in methane Recovery. The connate water's largest effect was to change the scCO2 flow field, which sank towards the reservoir floor, flooded the lowermost accessible layers and entered the production well via a high throughput channel (‘coning’). The magnitude of these effects were, however, sensitive to well perforation depth, the influence of which was subsequently studied systematically. Well perforation depth was found to determine the duration of these sinking and coning events in a non-linear manner.
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Enhanced Gas Recovery with co2 sequestration the effect of medium heterogeneity on the dispersion of supercritical co2 ch4
International Journal of Greenhouse Gas Control, 2015Co-Authors: Abdolvahab Honari, Michael L Johns, Branko Bijeljic, Eric F. MayAbstract:Abstract Reinjection of CO 2 into producing natural Gas reservoirs is considered as a promising technology to improve Gas Recovery, mitigate atmospheric emissions and control climate change. However, natural Gas and CO 2 are miscible at reservoir conditions and could result in CO 2 contamination of produced natural Gas. This mixing process and consequently the viability of Enhanced Gas Recovery (EGR) projects can be quantitatively determined by reservoir simulations – such simulations require a description of Gas dispersion. Here we conduct fluid transport experiments through carbonate and sandstone rock cores at various reservoir conditions to evaluate the effect of medium heterogeneity on the dispersion between supercritical CO 2 and CH 4 , accounting for erroneous contributions from entrance/exit and gravitational effects. Early breakthrough and long-tailed profiles are observed for one of the carbonate cores (Ketton) which is attributed to the existence of intra-grain micro-pores, which results in a persistent pre-asymptotic transport regime. Thus a revised model (Mobile-Immobile Model) was successfully used for this core to obtain dispersion coefficients characteristic of the eventual asymptotic regime. Both heterogeneous carbonate rocks considered exhibit higher dispersion than that observed in previously-measured homogeneous sandstone cores (Honari et al., 2013). The power law describing the dependency of dispersion coefficient on Peclet number at comparatively high interstitial displacement velocities gave an exponent of 1.2 for sandstones and 1.4 for carbonates, consistent with literature predictions (Bijeljic and Blunt, 2006; Bijeljic et al., 2011) based on pore-scale simulations.
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co2 sequestration for Enhanced Gas Recovery new measurements of supercritical co2 ch4 dispersion in porous media and a review of recent research
International Journal of Greenhouse Gas Control, 2012Co-Authors: Thomas J Hughes, Abdolvahab Honari, Brendan F Graham, Aman S Chauhan, Michael L JohnsAbstract:Abstract The Enhanced Recovery of natural Gas by the injection and sequestration of CO 2 is an attractive scenario for certain prospective field developments if the risks of Gas contamination or early CO 2 breakthrough can be assessed reliably. Simulations of Enhanced Gas Recovery (EGR) scenarios require accurate dispersion parameters at reservoir conditions to quantify the size of the miscible CO 2 –CH 4 displacement front; several experimental studies using core-flooding equipment aimed at measuring such parameters have been reported over the last decade. However, such measurements are particularly challenging and the data produced are generally afflicted in their repeatability by limited experimental control and in their accuracy by systematic errors such as gravitational and core-entrance/exit effects. We review here the existing experimental data pertaining to EGR by CO 2 sequestration and also report new measurements of longitudinal CO 2 –CH 4 dispersion coefficients at temperatures of 40–80 °C, pressures of 8–12 MPa and interstitial velocities of 0.05–1.13 mm s −1 [14.2–320 ft day −1 ] in 5–10 cm long sandstone cores with permeabilities of 12 and 460 mD. The core-floods were conducted in both a horizontal and vertical orientation, with significant gravitational effects observed for low velocity floods in horizontal cores with high permeabilities. We also analyzed the effects of tubing and core entrance/exit effects on the measurements and found that the latter resulted in apparent dispersion coefficients up to 63% larger than would be due to the core alone. Our results indicate that dispersivities for CO 2 –CH 4 at these supercritical conditions are less than 0.001 m, which indicates that excessive mixing will not occur in EGR scenarios in the absence of conformance effects such as heterogeneity coupled with injection well pattern. Inclusion of such conformance effects is essential for detailed reservoir simulation.
Leonhard Ganzer - One of the best experts on this subject based on the ideXlab platform.
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experimental and numerical investigations on co2 injection and Enhanced Gas Recovery effects in altmark Gas field central germany
Acta Geotechnica, 2014Co-Authors: Leonhard Ganzer, Viktor Reitenbach, Dieter Pudlo, Daniel Albrecht, Arron Tchouka Singhe, Kilian Nhungong Awemo, Joachim Wienand, Reinhard GauppAbstract:The feasibility of CO2 storage and Enhanced Gas Recovery (EGR) effects in the mature Altmark natural Gas field in Central Germany has been studied in this paper. The investigations were comprehensive and comprise the characterization of the litho- and diagenetic facies, mineral content, geochemical composition, the petrophysical properties of the reservoir rocks with respect to their potential reactivity to CO2 as well as reservoir simulation studies to evaluate the CO2 wellbore injectivity and displacement efficiency of the residual Gas by the injected CO2. The Rotliegend sediments of the Altmark pilot injection area exhibit distinct mineralogical, geochemical, and petrophysical features related to litho- and diagenetic facies types. The reservoir rock reactivity to CO2 has been studied in autoclave experiments and associated effects on two-phase transport properties have been examined by means of routine and special core analysis before and after the laboratory runs. Dissolution of calcite and anhydrite during the short-term treatments leading to the enhancements of permeability and porosity as well as stabilization of the water saturation relevant for CO2 injection have been observed. Numerical simulation of the injection process and EGR effects in a sector of the Altmark field coupled with a wellbore model revealed the possibility of injecting the CO2 Gas at temperatures as low as 10 °C and pressures around 40 bar achieving effective inflow in the reservoir without phase transition in the wellbore. The small ratio of injected CO2 volume versus reservoir volume indicated no significant EGR effects. However, the retention and storage capacity of CO2 will be maximized. The migration/extension of CO2 varies as a function of heterogeneity both in the layers and in the reservoir. The investigation of CO2 extension and pressure propagation suggested no breakthrough of CO2 at the prospective production well during the 3-year injection period studied.
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Experimental and numerical investigations on CO_2 injection and Enhanced Gas Recovery effects in Altmark Gas field (Central Germany)
Acta Geotechnica, 2014Co-Authors: Leonhard Ganzer, Viktor Reitenbach, Dieter Pudlo, Daniel Albrecht, Arron Tchouka Singhe, Kilian Nhungong Awemo, Joachim Wienand, Reinhard GauppAbstract:The feasibility of CO_2 storage and Enhanced Gas Recovery (EGR) effects in the mature Altmark natural Gas field in Central Germany has been studied in this paper. The investigations were comprehensive and comprise the characterization of the litho- and diagenetic facies, mineral content, geochemical composition, the petrophysical properties of the reservoir rocks with respect to their potential reactivity to CO_2 as well as reservoir simulation studies to evaluate the CO_2 wellbore injectivity and displacement efficiency of the residual Gas by the injected CO_2. The Rotliegend sediments of the Altmark pilot injection area exhibit distinct mineralogical, geochemical, and petrophysical features related to litho- and diagenetic facies types. The reservoir rock reactivity to CO_2 has been studied in autoclave experiments and associated effects on two-phase transport properties have been examined by means of routine and special core analysis before and after the laboratory runs. Dissolution of calcite and anhydrite during the short-term treatments leading to the enhancements of permeability and porosity as well as stabilization of the water saturation relevant for CO_2 injection have been observed. Numerical simulation of the injection process and EGR effects in a sector of the Altmark field coupled with a wellbore model revealed the possibility of injecting the CO_2 Gas at temperatures as low as 10 °C and pressures around 40 bar achieving effective inflow in the reservoir without phase transition in the wellbore. The small ratio of injected CO_2 volume versus reservoir volume indicated no significant EGR effects. However, the retention and storage capacity of CO_2 will be maximized. The migration/extension of CO_2 varies as a function of heterogeneity both in the layers and in the reservoir. The investigation of CO_2 extension and pressure propagation suggested no breakthrough of CO_2 at the prospective production well during the 3-year injection period studied.