首页 | 本学科首页   官方微博 | 高级检索  
相似文献
 共查询到20条相似文献，搜索用时 625 毫秒
1.
Baseline monitoring at the proposed enhanced gas recovery site in Altmark (Germany) was carried out in combination with theoretical and laboratory investigations to describe and predict the principles of expected stable carbon isotope and dissolved inorganic carbon (DIC) trends during CO2 injection in reservoirs. This provides fundamental data for site-specific characterisation for monitoring purposes. Baseline ??13C values at the Altmark site ranged between ?1.8 and ?11.5??? and DIC values were about 2?mmol?L?1. These baseline values form the basis for a theoretical study on the influences of the ambient reservoir conditions on the state of geochemical and isotope equilibrium of the reservoir fluids. Transferring this theoretical study to the Altmark site enables predictions on geochemical trends during potential injection. Assuming that CO2 would be injected at the Altmark site to pCO2?=?100?bar and with a ??13C of ?30???, at isotopic and geochemical equilibrium, ??13CDIC values would approach this end-member, and DIC concentrations of 1,000?mmol L?1 would be expected. Laboratory experiments were conducted at low pCO2 levels (4?C35?bars) to mimic the approach of a CO2 plume at a monitoring well. These results support field investigations from other sites: that ??13CDIC is a sensitive tool for monitoring CO2 migration in the subsurface and simultaneously allows quantification of geochemical trapping of CO2.  相似文献   

2.
We present a two-step stochastic inversion approach for monitoring the distribution of CO2 injected into deep saline aquifers for the typical scenario of one single injection well and a database comprising a common suite of well logs as well as time-lapse vertical seismic profiling (VSP) data. In the first step, we compute several sets of stochastic models of the elastic properties using conventional sequential Gaussian co-simulations (SGCS) representing the considered reservoir before CO2 injection. All realizations within a set of models are then iteratively combined using a modified gradual deformation algorithm aiming at reducing the mismatch between the observed and simulated VSP data. In the second step, these optimal static models then serve as input for a history matching approach using the same modified gradual deformation algorithm for minimizing the mismatch between the observed and simulated VSP data following the injection of CO2. At each gradual deformation step, the injection and migration of CO2 is simulated and the corresponding seismic traces are computed and compared with the observed ones. The proposed stochastic inversion approach has been tested for a realistic, and arguably particularly challenging, synthetic case study mimicking the geological environment of a potential CO2 injection site in the Cambrian-Ordivician sedimentary sequence of the St. Lawrence platform in Southern Québec. The results demonstrate that the proposed two-step reservoir characterization approach is capable of adequately resolving and monitoring the distribution of the injected CO2. This finds its expression in optimized models of P- and S-wave velocities, density, and porosity, which, compared to conventional stochastic reservoir models, exhibit a significantly improved structural similarity with regard to the corresponding reference models. The proposed approach is therefore expected to allow for an optimal injection forecast by using a quantitative assimilation of all available data from the appraisal stage of a CO2 injection site.  相似文献   

3.
Sedimentary porous rocks can be used for long-term subsurface containment of CO2. Before injecting CO2 to sedimentary reservoirs, it is necessary to perform stability analysis of the reservoir and to estimate the maximum sustainable pore fluid pressures. In order to avoid the reservoir damage during the CO2 injection, the effective stresses in the reservoir should be evaluated. In this paper, numerical modeling techniques are used for the evaluation of stresses and deformations in a naturally fractured carbonate sedimentary reservoir. The developed numerical modeling scheme couples the behavior of the CO2 injection and the change in the geomechanical behavior of the sedimentary carbonate reservoir for a case study from Saudi Arabia. The present investigation extends the previous studies by considering the sorption-based deformation during the injection of the compressed CO2 fluid into the Arab-D naturally fractured carbonate reservoir. The change in permeability during the injection of CO2 is evaluated. The adopted CO2 injection scenario was shown to be within the safe maximum occupancy, and that the increase in the pore pressure does not result in the reservoir failure.  相似文献   

4.
Numerical models are essential tools in fully understanding the fate of injected CO2 for commercial-scale sequestration projects and should be included in the life cycle of a project. Common practice involves modeling the behavior of CO2 during and after injection using site-specific reservoir and caprock properties. Little has been done to systematically evaluate and compare the effects of a broad but realistic range of reservoir and caprock properties on potential CO2 leakage through caprocks. This effort requires sampling the physically measurable range of caprock and reservoir properties, and performing numerical simulations of CO2 migration and leakage. In this study, factors affecting CO2 leakage through intact caprocks are identified. Their physical ranges are determined from the literature from various field sites. A quasi-Monte Carlo sampling approach is used such that the full range of caprock and reservoir properties can be evaluated without bias and redundant simulations. For each set of sampled properties, the migration of injected CO2 is simulated for up to 200 years using the water–salt–CO2 operational mode of the STOMP simulator. Preliminary results show that critical factors determining CO2 leakage rate through caprocks are, in decreasing order of significance, the caprock thickness, caprock permeability, reservoir permeability, caprock porosity, and reservoir porosity. This study provides a function for prediction of potential CO2 leakage risk due to permeation of intact caprock and identifies a range of acceptable seal thicknesses and permeability for sequestration projects. The study includes an evaluation of the dependence of CO2 injectivity on reservoir properties.  相似文献   

5.
Approximately 300 kg/day of food-grade CO2 was injected through a perforated pipe placed horizontally 2–2.3 m deep during July 9–August 7, 2008 at the MSU-ZERT field test to evaluate atmospheric and near-surface monitoring and detection techniques applicable to the subsurface storage and potential leakage of CO2. As part of this multidisciplinary research project, 80 samples of water were collected from 10 shallow monitoring wells (1.5 or 3.0 m deep) installed 1–6 m from the injection pipe, at the southwestern end of the slotted section (zone VI), and from two distant monitoring wells. The samples were collected before, during, and following CO2 injection. The main objective of study was to investigate changes in the concentrations of major, minor, and trace inorganic and organic compounds during and following CO2 injection. The ultimate goals were (1) to better understand the potential of groundwater quality impacts related to CO2 leakage from deep storage operations, (2) to develop geochemical tools that could provide early detection of CO2 intrusion into underground sources of drinking water (USDW), and (3) to test the predictive capabilities of geochemical codes against field data. Field determinations showed rapid and systematic changes in pH (7.0–5.6), alkalinity (400–1,330 mg/l as HCO3), and electrical conductance (600–1,800 μS/cm) following CO2 injection in samples collected from the 1.5 m-deep wells. Laboratory results show major increases in the concentrations of Ca (90–240 mg/l), Mg (25–70 mg/l), Fe (5–1,200 ppb), and Mn (5–1,400 ppb) following CO2 injection. These chemical changes could provide early detection of CO2 leakage into shallow groundwater from deep storage operations. Dissolution of observed carbonate minerals and desorption-ion exchange resulting from lowered pH values following CO2 injection are the likely geochemical processes responsible for the observed increases in the concentrations of solutes; concentrations generally decreased temporarily following four significant precipitation events. The DOC values obtained are 5 ± 2 mg/l, and the variations do not correlate with CO2 injection. CO2 injection, however, is responsible for detection of BTEX (e.g. benzene, 0–0.8 ppb), mobilization of metals, the lowered pH values, and increases in the concentrations of other solutes in groundwater. The trace metal and BTEX concentrations are all significantly below the maximum contaminant levels (MCLs). Sequential leaching of core samples is being carried out to investigate the source of metals and other solutes.  相似文献   

6.
Geological sequestration of CO2 is an option for significantly reducing emissions into the atmosphere. Various hydrocarbon companies in western Canada are currently injecting acid-gas (CO2 and H2S) into deep subsurface formations. At West Stoddart, in northeast British Columbia, acid-gas has been injected since 1998 at 1600 m depth into sandstones of the Triassic Halfway Formation, which forms a regional aquifer. A comprehensive subsurface characterization was conducted of the regional and local-scale geology, reservoir characteristics, mineralogy, in situ fluid properties, and hydrogeology. Preliminary results from geochemical and numerical multi-phase flow modelling suggest that the majority of the injected acid-gas will dissolve in the formation water and remain within a radius of a few kilometres of the injection well. The experience with the acid-gas injection at West Stoddart and other operations in the Alberta Basin has shown that the process of large-scale CO2-injection into deep aquifers is technically feasible.  相似文献   

7.
Carbon dioxide (CO2) has been injected in the subsurface permeable formations as a means to cut atmospheric CO2 emissions and/or enhance oil recovery (EOR). It is important to constrain the boundaries of the CO2 plume in the target formation and/or other formations hosting the CO2 migrated from the target formation. Monitoring methods and technologies to assess the CO2 plume boundaries over time within a reservoir of interest are required. Previously introduced methods and technologies on pressure monitoring to detect the extent of the CO2 plume require at least two wells, i.e. pulser and observation wells. We introduce pressure transient technique requiring single well only. Single well pressure transient testing (drawdown/buildup/injection/falloff) is widely used to determine reservoir properties and wellbore conditions. Pressure diagnostic plots are used to identify different flow regimes and determine the reservoir/well characteristics. We propose a method to determine the plume extent for a constant rate pressure transient test at a single well outside the CO2 plume. Due to the significant contrast between mobility and storativity of the CO2 and native fluids (oil or brine), the CO2 boundary causes deviation in the pressure diagnostic response from that corresponding to previously identified heterogeneities. Using the superposition principle, we develop a relationship between the deviation time and the plume boundary. We demonstrate the applicability of the proposed method using numerically generated synthetic data corresponding to homogeneous, heterogeneous, and anisotropic cases to evaluate its potential and limitations. We discuss ways to identify and overcome the potential limitations for application of the method in the field.  相似文献   

8.
In order to detect hydraulic and geochemical impact on the groundwater directly above the CO2 storage reservoir at the Ketzin pilot site continuous monitoring using an observation well is carried out. The target depth (446 m below ground level, bgl.) of the well is the Exter formation (Upper Triassic, Rhaetian) which is the closest permeable stratigraphic overlying formation to the CO2 storage reservoir (630–636 m bgl. at well location). The monitoring concept comprises evaluation of hydraulic conditions, temperature, water chemistry, gas geochemistry and δ13C values. This is achieved by a tubing inserted inside the well with installed pressure sensors and a U-tube sampling system so that pumping tests or additional wireline logging can be carried out simultaneously with monitoring. The aquifer was examined using a pump test. The observation well is hydraulically connected to the regional aquifer system and the permeability of about 1.8 D is comparatively high. Between Sept. 2011 and Oct. 2012, a pressure increase of 7.4 kPa is observed during monitoring under environmental conditions. Drilling was carried out with drilling mud on carbonate basis. The concentration of residual drilling mud decreases during the pump test, but all samples show a residual concentration of drilling mud. The formation fluid composition is recalculated with PHREEQC and is comparable to the literature values for the Exter formation. The gas partial pressure is below saturation at standard conditions and the composition is dominated by N2 similar to the underlying storage reservoir prior to CO2 injection. The impact of residual drilling mud on dissolved inorganic carbon and the respective δ13C values decreases during the monitoring period. The pristine isotopic composition cannot be determined due to calcite precipitation. No conclusive results indicate a leakage from the underlying CO2 storage reservoir.  相似文献   

9.
Potential pathways in the subsurface may allow upwardly migrating gaseous CO2 from deep geological storage formations to be released into near surface aquifers. Consequently, the availability of adequate methods for monitoring potential CO2 releases in both deep geological formations and the shallow subsurface is a prerequisite for the deployment of Carbon Capture and Storage technology. Geoelectrical surveys are carried out for monitoring a small-scale and temporally limited CO2 injection experiment in a pristine shallow aquifer system. Additionally, the feasibility of multiphase modeling was tested in order to describe both complex non-linear multiphase flow processes and the electrical behavior of partially saturated heterogeneous porous media. The suitability of geoelectrical methods for monitoring injected CO2 and geochemically altered groundwater was proven. At the test site, geoelectrical measurements reveal significant variations in electrical conductivity in the order of 15?C30?%. However, site-specific conditions (e.g., geological settings, groundwater composition) significantly influence variations in subsurface electrical conductivity and consequently, the feasibility of geoelectrical monitoring. The monitoring results provided initial information concerning gaseous CO2 migration and accumulation processes. Geoelectrical monitoring, in combination with multiphase modeling, was identified as a useful tool for understanding gas phase migration and mass transfer processes that occur due to CO2 intrusions in shallow aquifer systems.  相似文献   

10.
During 2003–2006, a pilot project of alternating water and CO2 injection was performed on a limited part of the Upper Miocene sandstone oil reservoir of the Ivani? Field. During the test period oil and gas recovery was significantly increased. Additionally 4,440 m3 of oil and 2.26 × 106 m3 of gas were produced. It has initiated further modelling of sandstone reservoirs in the Ivani? Field in order to calculate volumes available for CO2 injection for the purpose of increasing hydrocarbon production from depleted sandstone reservoirs in the entire Croatian part of the Pannonian Basin System. In the first phase, modelling was based on results of laboratory testing on the core samples. It considered applying analogies with world-known projects of CO2 subsurface storage and its usage to enhance hydrocarbon production. In the second phase, reservoir variables were analysed by variograms and subsequently mapped in order to reach lithological heterogeneities and to determine reliable average values of reservoir volumes. Data on porosity, depth and reservoir thickness for the “Gamma 3” and the “Gamma 4” reservoirs, are mapped by the ordinary kriging technique. Calculated volume of CO2 expressed at standard condition which can be injected in the main reservoirs of the Ivani? Field at near miscible conditions is above 15.5 billion m3.  相似文献   

11.
《International Geology Review》2012,54(14):1792-1812
Abundant crude oil and CO2 gas coexist in the fourth member of the Upper Cretaceous Quantou reservoir in the Huazijing Step of the southern Songliao Basin, China. Here, we present results of a petrographic characterization of this reservoir based on polarizing microscope, X-ray diffraction, fluid inclusion, and carbon–oxygen isotopic data. These data were used to identify whether CO2 might be trapped in minerals after the termination of a CO2-enhanced oil recovery (EOR) project, and to determine what effects might the presence of CO2 have on the properties of crude oil in the reservoir. The crude oil reservoir in the study area, which coexists with mantle-derived CO2, is hosted by dawsonite-bearing lithic arkoses and feldspathic litharenites. These sediments are characterized by a paragenetic sequence of clay, quartz overgrowth, first-generation calcite, dawsonite, second-generation calcite, and ankerite. The dawsonite analysed during this study exhibits δ13 C (Peedee Belemnite, PDB) values of ?4.97‰ to 0.67‰, which is indicative for the formation of magmatic–mantle CO2. The paragenesis and compositions of fluid inclusions in the dawsonite-bearing sandstones record a sequence of two separate filling events, the first involving crude oil and the second involving magmatic–mantle CO2. The presence of prolate primary hydrocarbon inclusions within the dawsonite indicates that these minerals precipitated from oil-bearing pore fluids at temperatures of 94–97°C, in turn suggesting that CO2 could be stored as carbonate minerals after the termination of a CO2-EOR project. In addition, the crude oil in the basin would become less dense after deposition of bitumen by deasphalting the injection of CO2 gas into the oil pool.  相似文献   

12.
《Applied Geochemistry》2005,20(6):1131-1157
The Weyburn Oil Field is a carbonate reservoir in south central Saskatchewan, Canada and is the site of a large CO2 injection project for purposes of enhanced oil recovery. The Weyburn Field, in the Mississippian Midale Formation, was discovered in 1954 and was under primary production until secondary recovery by water flood began in 1964. The reservoir comprises two units, the Vuggy and the Marly, and primary and secondary recovery are thought to only have significantly depleted the Vuggy zone, leaving the Marly with higher oil saturations. In 2000, PanCanadian Resources (now EnCana), the operator of the field, began tertiary recovery by injection of CO2 and water, primarily into the Marly. The advent of this project was an opportunity to study the potential for geological storage of CO2.Using 43 Baseline samples collected in August 2000, before CO2 injection at Weyburn, and 44 monitoring samples collected in March 2001, changes in the fluid chemistry and isotope composition have been tracked. The initial fluid distribution showed water from discovery through water flood in the Midale Formation with Cl ranging from 25,000 to 60,000 mg/L, from the NW to the SE across the Phase 1A area. By the time of Baseline sampling the produced water had been diluted to Cl of 25,000–50,000 mg/L as a result of the addition of make up water from the low TDS Blairmore Formation, but the pattern of distribution was still present. The Cl distribution is mimicked by the distribution of other dissolved ions and variables, with Ca (1250–1500 mg/L) and NH3 (aq) increasing from NW to SE, and alkalinity (700–300 mg/L), resistivity, and H2S (300–100 mg/L) decreasing. Based on chemical and isotopic data, the H2S is interpreted to result from bacterial SO4 reduction. After 6 months of injection of CO2, the general patterns are changed very little, except that the pH has decreased by 0.5 units and alkalinity has increased, with values over 1400 mg/L in the NW, decreasing to 500 mg/L in the SE. Calcium has increased to range from 1250 to 1750 mg/L, but the pattern of NW–SE distribution is altered. Chemical and isotopic data suggest this change in distribution is caused by the dissolution of calcite due to water–rock reactions driven by CO2. The Baseline samples varied from −22 to −12‰ δ13C (V-PDB) for CO2 gas. The injected CO2 has an isotope ratio of −20‰. The Monitor-1 samples of produced CO2 ranged from −18 to −13‰, requiring a heavy source of C, most easily attributed to dissolution of carbonate minerals. Field measured pH had increased and alkalinity had decreased by the second monitoring trip (July 2001) to near Baseline values, suggesting continued reaction with reservoir minerals.Addition of CO2 to water–rock mixtures comprising carbonate minerals causes dissolution of carbonates and production of alkalinity. Geochemical modeling suggests dissolution is taking place, however more detail on water–oil–gas ratios needs to be gathered to obtain more accurate estimates of pH at the formation level. Geological storage of CO2 relies on the potential that, over the longer term, silicate minerals will buffer the pH, causing any added CO2 to be precipitated as calcite. Some initial modeling of water–rock reactions suggests that silica sources are available to the water resident in the Midale Formation, and that clay minerals may well be capable of acting as pH buffers, allowing injected CO2 to be stored as carbonate minerals. Further work is underway to document the mineralogy of the Midale Formation and associated units so as to define more accurately the potential for geological storage.  相似文献   

13.
The Ketzin pilot site, led by the GFZ German Research Centre for Geosciences, is Europe??s longest-operating on-shore CO2 storage site with the aim of increasing the understanding of geological storage of CO2 in saline aquifers. Located near Berlin, the Ketzin pilot site is an in situ laboratory for CO2 storage in an anticlinal structure in the Northeast German Basin. Starting research within the framework of the EU project CO2SINK in 2004, Ketzin is Germany??s first CO2 storage site and fully in use since the injection began in June 2008. After 39?months of operation, about 53,000 tonnes of CO2 have been stored in 630?C650?m deep sandstone units of the Upper Triassic Stuttgart Formation. An extensive monitoring program integrates geological, geophysical and geochemical investigations at Ketzin for a comprehensive characterization of the reservoir and the CO2 migration at various scales. Integrating a unique field and laboratory data set, both static geological modeling and dynamic simulations are regularly updated. The Ketzin project successfully demonstrates CO2 storage in a saline aquifer on a research scale. The results of monitoring and modeling can be summarized as follows: (1) Since the start of the CO2 injection in June 2008, the operation has been running reliably and safely. (2) Downhole pressure data prove correlation between the injection rate and the reservoir pressure and indicates the presence of an overall dynamic equilibrium within the reservoir. (3) The extensive geochemical and geophysical monitoring program is capable of detecting CO2 on different scales and gives no indication for any leakage. (4) Numerical simulations (history matching) are in good agreement with the monitoring results.  相似文献   

14.
Numerical simulations of CO2 migration for the period June 2008–December 2011 were performed based on a unique data set including a recently revised static geological 3D model of the reservoir formation of the Ketzin pilot site in Brandenburg, Germany. We applied the industrial standard ECLIPSE 100 and scientific TOUGH2-MP simulators for this task and implemented a workflow to allow for integration of complex model geometries from the Petrel software package into TOUGH2-MP. Definition of a near- and a far-field well area allowed us to apply suitable permeability modifiers, and thus to successfully match simulation results with pressure measurements and arrival times in observation wells. Coincidence was achieved for CO2 arrival times with deviations in the range of 5.5–15 % and pressure values in the injection well CO2 Ktzi 201/2007 and the observation well CO2 Ktzi 202/2007 with even smaller deviations. It is shown that the integration of unique operational and observation data in the workflow improves the setup of the geological model. Within such an iteration loop model uncertainties are reduced and enable advanced predictions for future reservoir behaviour with regard to pressure development and CO2 plume migration in the storage formation at the Ketzin pilot site supporting the implementation of monitoring campaigns and guiding site operation.  相似文献   

15.
Careful site characterization is critical for successful geologic storage of carbon dioxide (CO2) because of the many physical and chemical processes impacting CO2 movement and containment under field conditions. Traditional site characterization techniques such as geological mapping, geophysical imaging, well logging, core analyses, and hydraulic well testing provide the basis for judging whether or not a site is suitable for CO2 storage. However, only through the injection and monitoring of CO2 itself can the coupling between buoyancy flow, geologic heterogeneity, and history-dependent multi-phase flow effects be observed and quantified. CO2 injection and monitoring can therefore provide a valuable addition to the site-characterization process. Additionally, careful monitoring and verification of CO2 plume development during the early stages of commercial operation should be performed to assess storage potential and demonstrate permanence. The Frio brine pilot, a research project located in Dayton, Texas (USA) is used as a case study to illustrate the concept of an iterative sequence in which traditional site characterization is used to prepare for CO2 injection and then CO2 injection itself is used to further site-characterization efforts, constrain geologic storage potential, and validate understanding of geochemical and hydrological processes. At the Frio brine pilot, in addition to traditional site-characterization techniques, CO2 movement in the subsurface is monitored by sampling fluid at an observation well, running CO2-saturation-sensitive well logs periodically in both injection and observation wells, imaging with crosswell seismic in the plane between the injection and observation wells, and obtaining vertical seismic profiles to monitor the CO2 plume as it migrates beyond the immediate vicinity of the wells. Numerical modeling plays a central role in integrating geological, geophysical, and hydrological field observations.  相似文献   

16.
The injection of CO2 into depleted natural gas reservoirs has been proposed as a promising new technology for combining enhanced gas recovery and geological storage of CO2. During the injection, application of suitable techniques for monitoring of the induced changes in the subsurface is required. Observing the movement and the changes in saturation of the fluids contained in the reservoir and the confining strata is among the primary aims here. It is shown that under conditions similar to the Altmark site, Germany, pulsed neutron-gamma logging can be applied with limitations. The pulsed neutron-gamma method can be applied for detection and quantification of changes in brine saturation and water content, whereas changes in the gas composition are below the detection limit. A method to account for the effects of salt precipitation resulting from evaporation of residual brine is presented.  相似文献   

17.
A controlled field pilot has been developed in Bozeman, Montana, USA, to study near surface CO2 transport and detection technologies. A slotted horizontal well divided into six zones was installed in the shallow subsurface. The scale and CO2 release rates were chosen to be relevant to developing monitoring strategies for geological carbon storage. The field site was characterized before injection, and CO2 transport and concentrations in saturated soil and the vadose zone were modeled. Controlled releases of CO2 from the horizontal well were performed in the summers of 2007 and 2008, and collaborators from six national labs, three universities, and the U.S. Geological Survey investigated movement of CO2 through the soil, water, plants, and air with a wide range of near surface detection techniques. An overview of these results will be presented.  相似文献   

18.
李玮  师庆三  董海海  侯锐 《中国地质》2022,49(2):485-495
[研究目的]克拉玛依油田X区克下组低渗透油藏存在物性差、水驱开发采收率低等问题,影响了油田的可持续发展.CO2是全球变暖的主要成分,世界各国都在想方设法减少CO2的排放量,本文试图利用CO2驱油气方式提高该油藏的采收率,变害为利.[研究方法]文章选取研究区60余口取心井目标层位岩心样品,开展扫描电镜及压汞测试分析等研究...  相似文献   

19.
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.  相似文献   

20.
CO2 is now considered as a novel heat transmission fluid to extract geothermal energy. It can achieve the goal of energy exploitation and CO2 geological sequestration. Taking Zhacanggou as research area, a “Three-spot” well pattern (one injection with two production), “wellbore–reservoir” coupled model is built, and a constant injection rate is set up. A fully coupled wellbore–reservoir simulator—T2Well—is introduced to study the flow mechanism of CO2 working as heat transmission fluid, the variance pattern of each physical field, the influence of CO2 injection rate on heat extraction and the potential and sustainability of heat resource in Guide region. The density profile variance resulting from temperature differences of two wells can help the system achieve “self-circulation” by siphon phenomenon, which is more significant in higher injection rate cases. The density of CO2 is under the effect of both pressure and temperature; moreover, it has a counter effect on temperature and pressure. The feedback makes the flow process in wellbore more complex. In low injection rate scenarios, the temperature has a dominating impact on the fluid density, while in high rate scenario, pressure plays a more important role. In most scenarios, it basically keeps stable during 30-year operation. The decline of production temperature is <5 °C. However, for some high injection rate cases (75 and 100 kg/s), due to the heat depletion in reservoir, there is a dramatic decline for production temperature and heat extraction rate. Therefore, a 50-kg/s CO2 injection rate is more suitable for “Three-spot” well pattern in Guide region.  相似文献   

设为首页 | 免责声明 | 关于勤云 | 加入收藏

Copyright©北京勤云科技发展有限公司  京ICP备09084417号