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1.
Long-term integrity of existing wells in a CO2-rich environment is essential for ensuring that geological sequestration of CO2 will be an effective technology for mitigating greenhouse gas-induced climate change. The potential for wellbore leakage depends in part on the quality of the original construction as well as geochemical and geomechanical stresses that occur over its life-cycle. Field data are essential for assessing the integrated effect of these factors and their impact on wellbore integrity, defined as the maintenance of isolation between subsurface intervals. In this report, we investigate a 30-year-old well from a natural CO2 production reservoir using a suite of downhole and laboratory tests to characterize isolation performance.These tests included mineralogical and hydrological characterization of 10 core samples of casing/cement/formation, wireline surveys to evaluate well conditions, fluid samples and an in situ permeability test. We find evidence for CO2 migration in the occurrence of carbonated cement and calculate that the effective permeability of an 11′-region of the wellbore barrier system was between 0.5 and 1 milliDarcy. Despite these observations, we find that the amount of fluid migration along the wellbore was probably small because of several factors: the amount of carbonation decreased with distance from the reservoir, cement permeability was low (0.3–30 microDarcy), the cement–casing and cement-formation interfaces were tight, the casing was not corroded, fluid samples lacked CO2, and the pressure gradient between reservoir and caprock was maintained. We conclude that the barrier system has ultimately performed well over the last 3 decades. These results will be used as part of a broader effort to develop a long-term predictive simulation tool to assess wellbore integrity performance in CO2 storage sites.  相似文献   

2.
Wellbore integrity is one of the key performance criteria in the geological storage of CO2. It is significant in any proposed storage site but may be critical to the suitability of depleted oil and gas reservoirs that may have 10’s to 1000’s of abandoned wells. Much previous work has focused on Portland cement which is the primary material used to seal wellbore systems. This work has emphasized the potential dissolution of Portland cement. However, an increasing number of field studies (e.g., Carey et al., 2007), experimental studies (e.g., Kutchko et al., 2006) and theoretical considerations indicate that the most significant leakage mechanism is likely to be flow of CO2 along the casing–cement microannulus, cement–cement fractures, or the cement–caprock interface.In this study, we investigate the casing–cement microannulus through core-flood experiments. The experiments were conducted on a synthetic wellbore system consisting of a 5-cm diameter sample of cement that was cured with an embedded rectangular length of steel casing that had grooves to accommodate fluid flow. The experiments were conducted at 40 ° C and 14 MPa pore pressure for 394 h. During the experiment, 6.2 l of a 50:50 mixture of supercritical CO2 and 30,000 ppm NaCl-rich brine flowed through 10-cm of limestone before flowing through the 6-cm length cement–casing wellbore system. Approximately 59,000 pore volumes of fluid moved through the casing–cement grooves. Scanning electron microscopy revealed that the CO2–brine mixture impacted both the casing and the cement. The Portland cement was carbonated to depths of 50–250 μm by a diffusion-dominated process. There was very little evidence for mass loss or erosion of the Portland cement. By contrast, the steel casing reacted to form abundant precipitates of mixed calcium and iron carbonate that lined the channels and in one case almost completely filled a channel. The depth of steel corroded was estimated at 25– 30μm and was similar in value to results obtained with a simplified corrosion model.The experimental results were applied to field observations of carbonated wellbore cement by Carey et al. (2007) and Crow et al. (2009) to show that carbonation of the field samples was not accompanied by significant CO2–brine flow at the casing–cement interface. The sensitivity of standard-grade steel casing to corrosion suggests that relatively straight-forward wireline logging of external casing corrosion could be used as a useful indicator of flow behind casing. These experiments also reinforce other studies that indicate rates of Portland cement deterioration are slow, even in the high-flux CO2–brine experiments reported here.  相似文献   

3.
Two sets of experiments on typical Class G well cement were carried out in the laboratory to understand better the potential processes involved in well leakage in the presence of CO2. In the first set, good-quality cement samples of permeability in the order of 0.1 μD (10?19 m2) were subjected to 90 days of flow through with CO2-saturated brine at conditions of pressure, temperature and water salinity characteristic of a typical geological sequestration zone. Cement permeability dropped rapidly at the beginning of the experiment and remained almost constant thereafter, most likely mainly as a result of CO2 exsolution from the saturated brine due to the pressure drop along the flow path which led to multi-phase flow, relative-permeability effects and the observed reduction in permeability. These processes are identical to those which would occur in the field as well if the cement sheath in the wellbore annulus is of good quality. The second set of experiments, carried out also at in situ conditions and using ethane rather than CO2 to eliminate any possible geochemical effects, assessed the effect of annular spaces between wellbore casing and cement, and of radial cracks in cement on the effective permeability of the casing-cement assemblage. The results show that, if both the cement and the bond are of good quality, the effective permeability of the assemblage is extremely low (in the order of 1 nD, or 10?21 m2). The presence of an annular gap and/or cracks in the order of 0.01–0.3 mm in aperture leads to a significant increase in effective permeability, which reaches values in the range of 0.1–1 mD (10?15 m2). The results of both sets of experiments suggest that good cement and good bonding with casing and the surrounding rock will likely constitute a good and reliable barrier to the upward flow of CO2 and/or CO2-saturated brine. The presence of mechanical defects such as gaps in bonding between the casing or the formation, or cracks in the cement annulus itself, leads to flow paths with significant effective permeability. This indicates that the external and internal interfaces of cements in wells would most probably constitute the main flow pathways for fluids leakage in wellbores, including both gaseous/supercritical phase CO2 and CO2-saturated brine.  相似文献   

4.
Capturing and storing carbon dioxide (CO2) underground for thousands of years is one way to reduce atmospheric greenhouse gases, often associated with global warming. Leakage through wells is one of the major issues when storing CO2 in depleted oil or gas reservoirs. CO2-injection candidates may be new wells, or old wells that are active, closed or abandoned. In all cases, it is critical to ensure that the long-term integrity of the storage wells is not compromised. The loss of well integrity may often be explained by the geochemical alteration of hydrated cement that is used to isolate the annulus across the producing/injection intervals in CO2-related wells. However, even before any chemical degradation, changes in downhole conditions due to supercritical CO2 injections can also be responsible for cement debonding from the casing and/or from the formation, leading to rapid CO2 leakage. A new cement with better CO2 resistance is compared with conventional cement using experimental procedure and methodology simulating the interaction of set cement with injected, supercritical CO2 under downhole conditions. Geochemical experimental data and a mechanical modeling approach are presented. The use of adding expanding property to this new cement to avoid microannulus development during the CO2 injection is discussed.  相似文献   

5.
6.
The cement industry is one of the most significant sources of anthropogenic emissions of CO2. It is connected with the specific character of the production processes, during which great quantities of CO2 are produced. Basic actions to reduce CO2 emissions recommended by the European Union's, Reference Document on Best Available Techniques in the Cement and Lime Manufacturing Industries, include: reduction of fuel consumption, selection of raw materials with low content of organic compounds and fuels with low coal contribution to heating value. All actions connected with the improvement of energy conversion efficiency of the cement production process cause CO2 emissions reduction. The use of at most acceptable by the valid standards amounts of waste as raw materials and additives for cement production, also brings about the reduction of significant part of CO2 emissions. These measures have been and continue to be pursued by the cement factories in Poland. This article describes the evolution of the cement industry in Poland over the period 1998–2008 and the resulting changes in CO2 emissions and explores the drivers for these changes. The sources of CO2 emissions in cement industry have been presented in this article as well as a discussion of potential ways to reduce Polish cement industry emissions even further.  相似文献   

7.
China has laid out an ambitious strategy for developing its vast shale gas reserves. This study developed an input–output based hybrid life-cycle inventory model to estimate the energy use, water consumption, and air emissions implications of shale gas infrastructure development in China over the period 2013–2020, including well drilling and operation, land rig and fracturing fleet manufacture, and pipeline construction. Multiple scenarios were analyzed based on different combinations of well development rates, well productivities, and success rates. Results suggest that 700–5100 petajoules (PJ) of primary energy will be required for shale gas infrastructure development, while the net primary energy yield of shale gas production over 2013–2020 was estimated at 1650–7150 PJ, suggesting a favorable energy balance. Associated emissions of CO2e were estimated at 80–580 million metric tons, and were primarily attributable to coal-fired electricity generation, fugitive methane, and flaring of methane during shale gas processing and transmission. Direct water consumption was estimated at 20–720 million metric tons. The largest sources of energy use and emissions for infrastructure development were the metals, mining, non-metal mineral products, and power sectors, which should be the focus of energy efficiency initiatives to reduce the impacts of shale gas infrastructure development moving forward.  相似文献   

8.
Carbon dioxide is the major greenhouse gas responsible for global warming. Man-made CO2 emissions contribute approximately 63% of greenhouse gases and the cement industry is responsible for approximately 5% of CO2 emissions emitting nearly 900 kg of CO2 per 1000 kg of cement. CO2 from a cement plant was captured and purified to 98% using the monoethanolamine (MEA) based absorption process. The capture cost was $51 per tonne of CO2 captured, representing approximately 90% of total cost. Steam was the main operating cost representing 39% of the total capture cost. Switching from coal to natural gas reduces CO2 emissions by about 18%. At normal load, about 36 MW of waste heat is available for recovery to satisfy the parasitic heat requirements of MEA process; however, it is very difficult to recover.  相似文献   

9.
Desires to enhance the energy security of the United States have spurred renewed interest in the development of abundant domestic heavy hydrocarbon resources including oil shale and coal to produce unconventional liquid fuels to supplement conventional oil supplies. However, the production processes for these unconventional fossil fuels create large quantities of carbon dioxide (CO2) and this remains one of the key arguments against such development. Carbon dioxide capture and storage (CCS) technologies could reduce these emissions and preliminary analysis of regional CO2 storage capacity in locations where such facilities might be sited within the U.S. indicates that there appears to be sufficient storage capacity, primarily in deep saline formations, to accommodate the CO2 from these industries. Nevertheless, even assuming wide-scale availability of cost-effective CO2 capture and geologic storage resources, the emergence of a domestic U.S. oil shale or coal-to-liquids (CTL) industry would be responsible for significant increases in CO2 emissions to the atmosphere. The authors present modeling results of two future hypothetical climate policy scenarios that indicate that the oil shale production facilities required to produce 3 MMB/d from the Eocene Green River Formation of the western U.S. using an in situ retorting process would result in net emissions to the atmosphere of between 3000 and 7000 MtCO2, in addition to storing potentially 900–5000 MtCO2 in regional deep geologic formations via CCS in the period up to 2050. A similarly sized, but geographically more dispersed domestic CTL industry could result in 4000–5000 MtCO2 emitted to the atmosphere in addition to potentially 21,000–22,000 MtCO2 stored in regional deep geologic formations over the same period. While this analysis shows that there is likely adequate CO2 storage capacity in the regions where these technologies are likely to deploy, the reliance by these industries on large-scale CCS could result in an accelerated rate of utilization of the nation's CO2 storage resource, leaving less high-quality storage capacity for other carbon-producing industries including electric power generation.  相似文献   

10.
Industrial-scale injection of CO2 into saline formations in sedimentary basins will cause large-scale fluid pressurization and migration of native brines, which may affect valuable groundwater resources overlying the deep sequestration aquifers. In this paper, we discuss how such basin-scale hydrogeologic impacts (1) may reduce current storage capacity estimates, and (2) can affect regulation of CO2 storage projects. Our assessment arises from a hypothetical future carbon sequestration scenario in the Illinois Basin, which involves twenty individual CO2 storage projects (sites) in a core injection area most suitable for long-term storage. Each project is assumed to inject five million tonnes of CO2 per year for 50 years. A regional-scale three-dimensional simulation model was developed for the Illinois Basin that captures both the local-scale CO2–brine flow processes and the large-scale groundwater flow patterns in response to CO2 storage. The far-field pressure buildup predicted for this selected sequestration scenario support recent studies in that environmental concerns related to near- and far-field pressure buildup may be a limiting factor on CO2 storage capacity. In other words, estimates of storage capacity, if solely based on the effective pore volume available for safe trapping of CO2, may have to be revised based on assessments of pressure perturbations and their potential impacts on caprock integrity and groundwater resources. Our results suggest that (1) the area that needs to be characterized in a permitting process may comprise a very large region within the basin if reservoir pressurization is considered, and (2) permits cannot be granted on a single-site basis alone because the near- and far-field hydrogeologic response may be affected by interference between individual storage sites. We also discuss some of the challenges in making reliable predictions of large-scale hydrogeologic impacts related to CO2 sequestration projects.  相似文献   

11.
Before implementing CO2 storage on a large scale its viability regarding injectivity, containment and long-term safety for both humans and environment is crucial. Assessing CO2–rock interactions is an important part of that as these potentially affect physical properties through highly coupled processes. Increased understanding of the physical impact of injected CO2 during recent years including buoyancy driven two-phase flow and convective mixing elucidated potential CO2 pathways and indicated where and when CO2–rock interactions are potentially occurring. Several areas of interactions can be defined: (1) interactions during the injection phase and in the near well environment, (2) long-term reservoir and cap rock interactions, (3) CO2–rock interactions along leakage pathways (well, cap rock and fault), (4) CO2–rock interactions causing potable aquifer contamination as a consequence of leakage, (5) water–rock interactions caused by aquifer contamination through the CO2 induced displacement of brines and finally engineered CO2–rock interactions (6). The driving processes of CO2–rock interactions are discussed as well as their potential impact in terms of changing physical parameters. This includes dissolution of CO2 in brines, acid induced reactions, reactions due to brine concentration, clay desiccation, pure CO2–rock interactions and reactions induced by other gases than CO2. Based on each interaction environment the main aspects that are possibly affecting the safety and/or feasibility of the CO2 storage scheme are reviewed and identified. Then the methodologies for assessing CO2–rock interactions are discussed. High priority research topics include the impact of other gaseous compounds in the CO2 stream on rock and cement materials, the reactivity of dry CO2 in the absence of water, how CO2 induced precipitation reactions affect the pore space evolution and thus the physical properties and the need for the development of coupled flow, geochemical and geomechanical models.  相似文献   

12.
To evaluate the risk of corrosion of cement by geosequestered CO2, samples are being retrieved from wells placed in natural CO2 deposits [e.g., Crow et al., 2009]. If the cement passing through the cap rock is carbonated, it may indicate that annular gaps or cracks have allowed carbonic acid to come into contact with the cement. However, it must be recognized that the pore water in the cap rock has become saturated with CO2 over geological time. After the well is placed, the CO2 will diffuse toward the cement and react with it. A simple analysis of the diffusion kinetics demonstrates that carbonation depths of millimeters to centimeters can be expected from this reaction within the lifetime of a well, in the absence of any cracks or gaps. Therefore, the occurrence of carbonation in cement sealing natural CO2 deposits must be interpreted with caution.  相似文献   

13.
This paper provides a preliminary assessment of the suitability of Tertiary sedimentary basins in Northern, Western and Eastern Greece in order to identify geological structures close to major CO2 emission sources with the potential for long-term storage of CO2. The term “emissions” refers to point source emissions as defined by the International Energy Agency, including power generation, the cement sector and other industrial processes. The Prinos oil field and saline aquifer, along with the saline formations of the Thessaloniki Basin and the Mesohellenic Trough have been identified as prospective CO2 geological storage sites. In addition, a carbonate deep saline aquifer occurring at appropriate depths beneath the Neogene-Quaternary sediments of Ptolemais-Kozani graben (NW Greece) is considered. The proximity of this geological formation to Greece's largest lignite-fired power plants suggests that it would be worthwhile undertaking further site-specific studies to quantify its storage capacity and assess its structural integrity.  相似文献   

14.
The In Salah Gas Joint Venture CO2 storage project has been in operation in Algeria since 2004 and is currently the world's largest onshore CO2 storage project. CO2 is injected into the saline aquifer of a gas reservoir several kilometres away from the gas producers. Current focus in the project is on implementing a comprehensive monitoring strategy and modelling the injection behaviour in order to ensure and verify safe long-term storage. A key part of this effort is the understanding of the processes involved in CO2 migration within relatively low-permeability sandstones and shales influenced by fractures and faults. We summarise our current understanding of the fault and fracture pattern at this site and show preliminary forecasts of the system performance using discrete fracture models and fluid flow simulations. Despite evidence of fractures at the reservoir/aquifer level, the thick mudstone caprock sequence is expected to provide an effective flow and mechanical seal for the storage system; however, quantification of the effects of fracture flow is essential to the site verification.  相似文献   

15.
The feasibility of monitoring CO2 migration in a saline aquifer at a depth of about 650 m with cross-hole and surface–downhole electrical resistivity tomography (ERT) is investigated at the CO2SINK test site close to Ketzin (Germany). The permanent vertical electrical resistivity array (VERA) consists of 45 electrodes (15 in the injection well Ktzi201 and 15 in each of the two observation wells Ktzi200 and Ktzi202), successfully placed on the electrically insulated casings, in the depth range of about 590–740 m with a spacing of about 10 m. The three Ketzin wells are arranged as perpendicular triangle with distances of 50 and 100 m.First synthetic modelling studies indicate an increase of the electrical resistivity of about 200% caused by CO2 injection, corresponding to a bulk CO2 saturation of 50%, which is in good agreement with laboratory studies. Finite difference inversion of field data delivers three-dimensional resistivity distributions between the wells which are consistent with the reservoir modelling studies.To increase the limited observation area provided by the cross-hole measurements, additional surface–downhole measurements were deployed. A main CO2 migration in SE–NW direction is deduced from surface to downhole resistivity experiments.The first cross-hole time-lapse results show that the resolution and the coverage of the electrode array in the Ketzin setting are sufficient to resolve the expected resistivity changes on the characteristic length scale of the electrode array. Significant resistivity changes could be measured, however, detailed information on the CO2 plume could not be resolved yet by VERA under the existing geological circumstances.  相似文献   

16.
The CO2SINK pilot project at Ketzin is aimed at a better understanding of geological CO2 storage operation in a saline aquifer. The reservoir consists of fluvial deposits with average permeability ranging between 50 and 100 mDarcy. The main focus of CO2SINK is developing and testing of monitoring and verification technologies. All wells, one for injection and two for observation, are equipped with smart casings (sensors behind casing, facing the rocks) containing a Distributed Temperature Sensing (DTS) and electrodes for Electrical Resistivity Tomography (ERT). The in-hole Gas Membrane Sensors (GMS) observed the arrival of tracers and CO2 with high temporal resolution. Geophysical monitoring includes Moving Source Profiling (MSP), Vertical Seismic Profiling (VSP), crosshole, star and 4-D seismic experiments. Numerical models are benchmarked via the monitoring results indicating a sufficient match between observation and prediction, at least for the arrival of CO2 at the first observation well. Downhole samples of brine showed changes in the fluid composition and biocenosis. First monitoring results indicate anisotropic flow of CO2 coinciding with the “on-time” arrival of CO2 at observation well one (Ktzi 200) and the later arrival at observation well two (Ktzi 202). A risk assessment was performed prior to the start of injection. After one year of operations about 18,000 t of CO2 were injected safely.  相似文献   

17.
This paper presents a study of cement replacement by sugar cane bagasse ash (SCBA) in industrial scale aiming to reduce the CO2 emissions into the atmosphere. SCBA is a by-product of the sugar/ethanol agro-industry abundantly available in some regions of the world and has cementitious properties indicating that it can be used together with cement. Recent comprehensive research developed at the Federal University of Rio de Janeiro/Brazil has demonstrated that SCBA maintains, or even improves, the mechanical and durability properties of cement-based materials such as mortars and concretes. Brazil is the world’s largest sugar cane producer and being a developing country can claim carbon credits. A simulation was carried out to estimate the potential of CO2 emission reductions and the viability to issue certified emission reduction (CER) credits. The simulation was developed within the framework of the methodology established by the United Nations Framework Convention on Climate Change (UNFCCC) for the Clean Development Mechanism (CDM). The State of São Paulo (Brazil) was chosen for this case study because it concentrates about 60% of the national sugar cane and ash production together with an important concentration of cement factories. Since one of the key variables to estimate the CO2 emissions is the average distance between sugar cane/ethanol factories and the cement plants, a genetic algorithm was developed to solve this optimization problem. The results indicated that SCBA blended cement reduces CO2 emissions, which qualifies this product for CDM projects.  相似文献   

18.
Carbon dioxide capture and storage (CCS) technology is gaining credibility as the best short to medium term solution for significantly reducing net carbon emissions into the atmosphere. From a capacity point of view, deep saline aquifers offer the greatest potential for CO2 storage. In this respect, well injectivity is considered a key technical and economical issue. Rock/fluid interactions – dissolution/precipitation of minerals, in particular carbonates – are currently considered as one of the principal reasons for wellbore injectivity changes in aquifers.This research investigated the mechanisms involved in injectivity losses through experimental and theoretical methods. The impact on injectivity of permeability changes occurring at various distances from the wellbore was studied using an idealised CO2 injection well flow model. A new experimental set-up was used to investigate the effect on dissolution/precipitation mechanisms of the pressure and temperature changes that the fluid is subjected to as it advances from the wellbore.Numerical modelling of the injection wellbore has shown that changes in the petrophysical properties of the reservoir several metres away from the wellbore can still have a significant impact on injectivity. As indicated by the experimental research carried out, pressure and temperature gradients that exist inside the reservoirs may lead to re-precipitation in the far field, however no significant permeability and porosity changes were detected to suggest major losses of injectivity due to these effects.  相似文献   

19.
Carbon dioxide (CO2) injection into saline aquifers is one of the promising options to sequester large amounts of CO2 in geological formations. During as well as after injection of CO2 into an aquifer, CO2 migrates towards the top of the formation due to density differences between the formation brine and the injected CO2. The time scales of CO2 migration towards the top of an aquifer and the fraction of CO2 that is trapped as residual gas depends strongly on the driving forces that are acting on the injected CO2.When CO2 migrates to the top of an aquifer, brine may be displaced downwards in a counter-current flow setting particularly during the injection period. A majority of the published work on counter-current flow settings have reported significant reductions in the associated relative permeability functions as compared to co-current measurements. However, this phenomenon has not yet been considered in the simulation of CO2 storage into saline aquifers.In this paper we study the impact of changes in mobility for the two-phase brine/CO2 system as a result of transitions between co- and counter-current flow settings. We have included this effect in a simulator and studied the impact of the related mobility reduction on the saturation distribution and residual saturation of CO2 in aquifers over relevant time scales. We demonstrate that the reduction in relative permeability in the vertical direction changes the plume migration pattern and has an impact on the amount of gas that is trapped as a function of time. This is to our best knowledge the first attempt to integrate counter-current relative permeability into the simulation of injection and subsequent migration of CO2 in aquifers. The results and analysis presented in this paper are directly relevant to all ongoing activities related to the design of large-scale CO2 storage in saline aquifers.  相似文献   

20.
Coalbeds are an attractive geological environment for storage of carbon dioxide (CO2) because CO2 is retained in the coal as an adsorbed phase and the cost of injection can be offset by enhanced coalbed methane (ECBM) production. This paper presents the findings of a CO2 storage feasibility study on coalbeds in the Wyodak-Anderson coal zone of the Powder River Basin, Wyoming, USA, using reservoir characterization and fluid flow simulations. A 3D numerical model of the Big George coal was constructed using geostatistical techniques, with values of cleat and matrix permeability and porosity constrained through history-matching of production data from coalbed methane (CBM) wells in the field area.Following history-matching, several ECBM and CO2 storage scenarios were investigated: shrinkage and swelling of the coal was either allowed or disallowed, a horizontal hydraulic fracture was either placed at the injection well or removed from the model, the number of model layers was varied between 1 and 24, and the permeability and porosity fields were constructed to be either homogeneous or heterogeneous in accordance with geostatistical models of regional variability. All simulations assumed that the injected gas was 100% CO2 and that the coalbed was overlain by an impermeable caprock. Depending on the scenario, the simulations predicted that after 13 years of CO2 injection, the cumulative methane production would be enhanced by a factor of 1.5–5. Including coal matrix shrinkage and swelling in the model predicted swelling near the injection well, which resulted in a slight reduction (10%) in injection rate. However, including a horizontal hydraulic fracture in the model at the base of the injection well helped mitigate the negative effect of swelling on injection rate. It was also found that six model layers were needed to have sufficient resolution in the vertical direction to account for the buoyancy effects between the gas and resident water, and that capturing the heterogeneous nature of the coal permeability and porosity fields predicted lower estimates of the storage capacity of the Wyodak-Anderson coal zone.After noting that gravity and buoyancy were the major driving forces behind gas flow within the Big George coal, several leakage scenarios were also investigated, in an effort to better understand the interplay between diffusion and flow properties on the transport and storage of CO2. The modeling predicted that the upward migration of gas due to the buoyancy effect was faster than the diffusion of CO2 and therefore the gas rapidly rose to the top of the coalbed and migrated into overlying strata when an impermeable caprock was not included in the model.  相似文献   

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