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1.
The efficiency and sustainability of carbon dioxide (CO2) storage in deep geological formations crucially depends on the integrity of the overlying cap-rocks. Existing oil and gas wells, which penetrate the formations, are potential leakage pathways. This problem has been discussed in the literature, and a number of investigations using semi-analytical mathematical approaches have been carried out by other authors to quantify leakage rates. The semi-analytical results are based on a number of simplifying assumptions. Thus, it is of great interest to assess the influence of these assumptions. We use a numerical model to compare the results with those of the semi-analytical model. Then we ease the simplifying restrictions and include more complex thermodynamic processes including sub- and supercritical fluid properties of CO2 and non-isothermal as well as compositional effects. The aim is to set up problem-oriented benchmark examples that allow a comparison of different modeling approaches to the problem of CO2 leakage.  相似文献   

2.
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   

3.
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   

4.
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   

5.
CO2 pilot injection studies, with site-specific geologic assessment and engineering reservoir design, can be instrumental for demonstrating both incremental enhanced oil recovery and permanent geologic storage of greenhouse gases. The purpose of this paper is to present the geologic and reservoir analyses in support of a field pilot test that will evaluate the technical and economic feasibility of commercial-scale CO2-enhanced oil recovery to increase oil recovery and extend the productive life of the Citronelle Oil Field, the largest conventional oil field in Alabama (SE USA). Screening of reservoir depth, oil gravity, reservoir pressure, reservoir temperature, and oil composition indicates that the Cretaceous-age Donovan sand, which has produced more than 169 × 106 bbl in Citronelle Oil Field, is amenable to miscible CO2 flooding. The project team has selected an 81 ha (200 ac) 5-spot test site with one central gas injector, two producers, and two initially temporarily abandoned production wells that are now in production. Injection is planned in two separate phases, each consisting of 6,804 t (7,500 short tons) of food-grade CO2. The Citronelle Unit B-19-10 #2 well (Permit No. 3232) is the CO2 injector for the first injection test. The 14-1 and 16-2 sands of the upper Donovan are the target zones. These sandstone units consist of fine to medium-grained sandstone that is enveloped by variegated mudstone. Both of these sandstone units were selected based on the distribution of perforated zones in the test pattern, production history, and the ability to correlate individual sandstone units in geophysical well logs. The pilot injections will evaluate the applicability of tertiary oil recovery to Citronelle Field and will provide a large volume of information on the pressure response of the reservoirs, the mobility of fluids, time to breakthrough, and CO2 sweep efficiency. The results of the pilot injections will aid in the formulation of commercial-scale reservoir management strategies that can be applied to Citronelle Field and other geologically heterogeneous oil fields and the design of similar pilot injection projects.  相似文献   

6.
A long-term (up to 10 ka) geochemical change in saline aquifer CO2 storage was studied using the TOUGHREACT simulator, on a 2-dimensional, 2-layered model representing the underground geologic and hydrogeologic conditions of the Tokyo Bay area that is one of the areas of the largest CO2 emissions in the world. In the storage system characterized by low permeability of reservoir and cap rock, the dominant storage mechanism is found to be solubility trapping that includes the dissolution and dissociation of injected CO2 in the aqueous phase followed by geochemical reactions to dissolve minerals in the rocks. The CO2–water–rock interaction in the storage system (mainly in the reservoir) changes the properties of water in a mushroom-like CO2 plume, which eventually leads to convective mixing driven by gravitational instability. The geochemically evolved aqueous phase precipitates carbonates in the plume front due to a local rise in pH with mixing of unaffected reservoir water. The carbonate precipitation occurs extensively within the plume after the end of its enlargement, fixing injected CO2 in a long, geologic period.Dawsonite, a Na–Al carbonate, is initially formed throughout the plume from consumption of plagioclase in the reservoir rock, but is found to be a transient phase finally disappearing from most of the CO2-affected part of the system. The mineral is unstable relative to more common types of carbonates in the geochemical evolution of the CO2 storage system initially having formation water of relatively low salinity. The exception is the reservoir-cap rock boundary where CO2 saturation remains very high throughout the simulation period.  相似文献   

7.
This work was motivated by considerations of potential leakage pathways for CO2 injected into deep geological formations for the purpose of carbon sequestration. Because existing wells represent a potentially important leakage pathway, a spatial analysis of wells that penetrate a deep aquifer in the Alberta Basin was performed and various statistical measures to quantify the spatial distribution of these wells were presented. The data indicate spatial clustering of wells, due to oil and gas production activities. The data also indicate that the number of wells that could be impacted by CO2 injection, as defined by the spread of an injected CO2 plume, varies from several hundred in high well-density areas to about 20 in low-density areas. These results may be applied to other mature continental sedimentary basins in North America and elsewhere, where detailed information on well location and status may not be available.  相似文献   

8.
Documenting geographic distribution and spatial linkages between CO2 sources and potential sinks in areas with significant levels of CO2 emissions is important when considering carbon-management strategies such as geologic sequestration or enhanced oil recovery (EOR). For example, the US Gulf Coast overlies a thick succession (>6,000 m [>20,000 ft]) of highly porous and permeable sandstone formations separated by thick, regionally extensive shale aquitards. The Gulf Coast and Permian Basin also have a large potential for EOR, in which CO2 injected into suitable oil reservoirs could be followed by long-term storage of CO2 in nonproductive formations below reservoir intervals. For example, >6 billion barrels (Bbbl) of oil from 182 large reservoirs is technically recoverable in the Permian Basin as a result of miscible-CO2 flooding. The Gulf Coast also contains an additional 4.5 Bbbl of oil that could be produced by using miscible CO2. Although the CO2 pipeline infrastructure is well-developed in the Permian Basin, east Texas and the Texas Gulf Coast may have a greater long-term potential for deep, permanent storage of CO2 because of thick brine-bearing formations near both major subsurface and point sources of CO2.  相似文献   

9.
The utilization of anthropogenic CO2 for enhanced oil recovery (EOR) can significantly extend the production life of an oil field, and help in the reduction of atmospheric emission of anthropogenic CO2 if sequestration is considered. This work summarizes the prospect of EOR and sequestration using CO2 flooding from an Indian mature oil field at Cambay basin through numerical modelling, simulation and pressure study based on limited data provided by the operator. To get an insight into CO2-EOR and safe storage process in this oil field, a conceptual sector model is developed and screening standard is proposed keeping in mind the major pay zone of the producing reservoir. To construct the geomodel, depth maps, well positions and coordinates, well data and well logs, perforation depths and distribution of petrophysical properties as well as fluid properties provided by the operator, has been considered. Based on the results from the present study, we identified that the reservoir has the potential for safe and economic geological sequestration of 15.04×106 metric ton CO2 in conjunction with a substantial increase in oil recovery of 10.4% of original oil in place. CO2-EOR and storage in this mature field has a bright application prospect since the findings of the present work could be a better input to manage the reservoir productivity, and the pressure field for significant enhancement of oil recovery followed by safe storage.  相似文献   

10.
Pressure buildup limits CO2 injectivity and storage capacity and pressure loss limits the brine production capacity and security, particularly for closed and semi-closed formations. In this study, we conduct a multiwell model to examine the potential advantages of combined exhaustive brine production and complete CO2 storage in deep saline formations in the Jiangling Depression, Jianghan Basin of China. Simulation results show that the simultaneous brine extraction and CO2 storage in saline formation not only effectively regulate near-wellbore and regional pressure of storage formation, but also can significantly enhance brine production capacity and CO2 injectivity as well as storage capacity, thereby achieving maximum utilization of underground space. In addition, the combination of brine production and CO2 injection can effectively mitigate the leakage risk between the geological units. With regard to the scheme of brine production and CO2 injection, constant pressure injection is much superior to constant rate injection thanks to the mutual enhancement effect. The simultaneous brine production of nine wells and CO2 injection of four wells under the constant pressure injection scheme act best in all respects of pressure regulation, brine production efficiency, CO2 injectivity and storage capacity as well as leakage risk mitigation. Several ways to further optimize the combined strategy are investigated and the results show that increasing the injection pressure and adopting fully penetrating production wells can further significantly enhance the combined efficiency; however, there is no obvious promoting effect by shortening the well spacing and changing the well placement.  相似文献   

11.
This study examined the impacts of reservoir properties on carbon dioxide (CO2) migration after subsurface injection and evaluated the possibility of characterizing reservoir properties using CO2 monitoring data such as spatial–temporal distributions of gas pressure, which can be reasonably monitored in practice. The injection reservoir was assumed to be located 1,400–1,500 m below the ground surface such that CO2 remained in the supercritical state. The reservoir was assumed to contain layers with alternating conductive and resistive properties, which is analogous to actual geological formations such as the Mount Simon Sandstone unit. The CO2 injection simulation used a cylindrical grid setting in which the injection well was situated at the center of the domain, which extended out 8,000 m from the injection well. The CO2 migration was simulated using the latest version of the simulator, subsurface transport over multiple phases (the water–salt–CO2–energy module), developed by Pacific Northwest National Laboratory. A nonlinear parameter estimation and optimization modeling software package, Parameter ESTimation (PEST), is adopted for automated reservoir parameter estimation. The effects of data quality, data worth, and data redundancy were explored regarding the detectability of reservoir parameters using gas pressure monitoring data, by comparing PEST inversion results using data with different levels of noises, various numbers of monitoring wells and locations, and different data collection spacing and temporal sampling intervals. This study yielded insight into the use of CO2 monitoring data for reservoir characterization and how to design the monitoring system to optimize data worth and reduce data redundancy. The feasibility of using CO2 saturation data for improving reservoir characterization was also discussed.  相似文献   

12.
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   

13.
A numerical model was developed to investigate the potential to detect fluid migration in a (homogeneous, isotropic, with constant pressure lateral boundaries) porous and permeable interval overlying an imperfect primary seal of a geologic CO2 storage formation. The seal imperfection was modeled as a single higher-permeability zone in an otherwise low-permeability seal, with the center of that zone offset from the CO2 injection well by 1400 m. Pressure response resulting from fluid migration through the high-permeability zone was detectable up to 1650 m from the centroid of that zone at the base of the monitored interval after 30 years of CO2 injection (detection limit = 0.1 MPa pressure increase); no pressure response was detectable at the top of the monitored interval at the same point in time. CO2 saturation response could be up to 774 m from the center of the high-permeability zone at the bottom of the monitored interval, and 1103 m at the top (saturation detection limit = 0.01). More than 6% of the injected CO2, by mass, migrated out of primary containment after 130 years of site performance (including 30 years of active injection) in the case where the zone of seal imperfection had a moderately high permeability (10??17 m2 or 0.01 mD). Free-phase CO2 saturation monitoring at the top of the overlying interval provides favorable spatial coverage for detecting fluid migration across the primary seal. Improved sensitivity of detection for pressure perturbation will benefit time of detection above an imperfect seal.  相似文献   

14.
Carbon dioxide (CO2) sequestration in depleted sandstone hydrocarbon reservoirs could be complicated by a number of geomechanical problems associated with well drilling, completions, and CO2 injection. The initial production of hydrocarbons (gas or oil) and the resulting pressure depletion as well as associated reduction in horizontal stresses (e.g., fracture gradient) narrow the operational drilling mud weight window, which could exacerbate wellbore instabilities while infill drilling. Well completions (casing, liners, etc.) may experience solids flowback to the injector wells when injection is interrupted due to CO2 supply or during required system maintenance. CO2 injection alters the pressure and temperature in the near wellbore region, which could cause fault reactivation or thermal fracturing. In addition, the injection pressure may exceed the maximum sustainable storage pressure, and cause fracturing and fault reactivation within the reservoirs or bounding formations. A systematic approach has been developed for geomechanical assessments for CO2 storage in depleted reservoirs. The approach requires a robust field geomechanical model with its components derived from drilling and production data as well as from wireline logs of historical wells. This approach is described in detail in this paper together with a recent study on a depleted gas field in the North Sea considered for CO2 sequestration. The particular case study shows that there is a limitation on maximum allowable well inclinations, 45° if aligning with the maximum horizontal stress direction and 65° if aligning with the minimum horizontal stress direction, beyond which wellbore failure would become critical while drilling. Evaluation of sanding risks indicates no sand control installations would be needed for injector wells. Fracturing and faulting assessments confirm that the fracturing pressure of caprock is significantly higher than the planned CO2 injection and storage pressures for an ideal case, in which the total field horizontal stresses increase with the reservoir re-pressurization in a manner opposite to their reduction with the reservoir depletion. However, as the most pessimistic case of assuming the total horizontal stresses staying the same over the CO2 injection, faulting could be reactivated on a fault with the least favorable geometry once the reservoir pressure reaches approximately 7.7 MPa. In addition, the initial CO2 injection could lead to a high risk that a fault with a cohesion of less than 5.1 MPa could be activated due to the significant effect of reduced temperature on the field stresses around the injection site.  相似文献   

15.
Fluid inclusions have recorded the history of degassing in basalt. Some fluid inclusions in olivine and pyroxene phenocrysts of basalt were analyzed by micro-thermometry and Raman spectroscopy in this paper. The experimental results showed that many inclusions are present almost in a pure CO2 system. The densities of some CO2 inclusions were computed in terms of Raman spectroscopic characteristics of CO2 Fermi resonance at room temperature. Their densities change over a wide range, but mainly between 0.044 g/cm3 and 0.289 g/cm3. Their micro-thermometric measurements showed that the CO2 inclusions examined reached homogenization between 1145.5℃ and 1265℃ . The mean value of homogenization temperatures of CO2 inclusions in basalts is near 1210℃. The trap pressures (depths) of inclusions were computed with the equation of state and computer program. Distribution of the trap depths makes it know that the degassing of magma can happen over a wide pressure (depth) range, but mainly at the depth of 0.48 km to 3.85 km. This implicates that basalt magma experienced intensive degassing and the CO2 gas reservoir from the basalt magma also may be formed in this range of depths. The results of this study showed that the depth of basalt magma degassing can be forecasted from CO2 fluid inclusions, and it is meaningful for understanding the process of magma degassing and constraining the inorganogenic CO2 gas reservoir.  相似文献   

16.
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17.
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   

18.
Subsurface sequestration of CO2 in oil and gas provinces where permanence of hydrocarbon accumulations has proven the reliability of potential traps is rightly seen as a solid option for containment of CO2 atmospheric concentrations. However, one of the most promising provinces for carbon storage in North America, the Texas Gulf Coast, has also been heavily drilled for more than a century, puncturing many otherwise perfectly sound seals (>125,000 wells over ~50,000 km2). As a result, boreholes and, in particular, older abandoned wells could be major leakage pathways for sequestered CO2. This article presents statistics on well spatial and depth distribution that have been drawn from public domain sources and relates these data to historical plugging and abandonment regulations in the Texas Gulf Coast. Surface-well density averages of 2.4 wells/km2 can be locally much higher—but also much lower in larger areas. Average well penetration density drops to 0.27 and 0.05 well/km2 below a depth of 2,440 and 3,660 m, respectively. Natural mitigating factors such as thief zones and heaving “shales” could also play a role in limiting the impact of these direct conduits to the shallow subsurface and surface.  相似文献   

19.
This paper reports a preliminary investigation of CO2 sequestration and seal integrity at Teapot Dome oil field, Wyoming, USA, with the objective of predicting the potential risk of CO2 leakage along reservoir-bounding faults. CO2 injection into reservoirs creates anomalously high pore pressure at the top of the reservoir that could potentially hydraulically fracture the caprock or trigger slip on reservoir-bounding faults. The Tensleep Formation, a Pennsylvanian age eolian sandstone is evaluated as the target horizon for a pilot CO2 EOR-carbon storage experiment, in a three-way closure trap against a bounding fault, termed the S1 fault. A preliminary geomechanical model of the Tensleep Formation has been developed to evaluate the potential for CO2 injection inducing slip on the S1 fault and thus threatening seal integrity. Uncertainties in the stress tensor and fault geometry have been incorporated into the analysis using Monte Carlo simulation. The authors find that even the most pessimistic risk scenario would require ∼10 MPa of excess pressure to cause the S1 fault to reactivate and provide a potential leakage pathway. This would correspond to a CO2 column height of ∼1,500 m, whereas the structural closure of the Tensleep Formation in the pilot injection area does not exceed 100 m. It is therefore apparent that CO2 injection is not likely to compromise the S1 fault stability. Better constraint of the least principal stress is needed to establish a more reliable estimate of the maximum reservoir pressure required to hydrofracture the caprock.  相似文献   

20.
Seismic surveys successfully imaged a small scale CO2 injection (1,600 ton) conducted in a brine aquifer of the Frio Formation near Houston, Texas. These time-lapse borehole seismic surveys, crosswell and vertical seismic profile (VSP), were acquired to monitor the CO2 distribution using two boreholes (the new injection well and a pre-existing well used for monitoring) which are 30 m apart at a depth of 1,500 m. The crosswell survey provided a high-resolution image of the CO2 distribution between the wells via tomographic imaging of the P-wave velocity decrease (up to 500 m/s). The simultaneously acquired S-wave tomography showed little change in S-wave velocity, as expected for fluid substitution. A rock physics model was used to estimate CO2 saturations of 10–20% from the P-wave velocity change. The VSP survey resolved a large (∼70%) change in reflection amplitude for the Frio horizon. This CO2 induced reflection amplitude change allowed estimation of the CO2 extent beyond the monitor well and on three azimuths. The VSP result is compared with numerical modeling of CO2 saturations and is seismically modeled using the velocity change estimated in the crosswell survey.  相似文献   

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