Modeling the effects of completion techniques and formation heterogeneity on CO2 sequestration in shallow and deep saline aquifers

This work studied the effect of completion techniques and reservoir heterogeneity on CO₂ storage and injectivity in saline aquifers using a compositional reservoir simulator, CMG-GEM. Two reservoir models were built based on the published data to represent a deep saline aquifer and a shallow aquifer. The effect of various completion conditions on CO₂ storage was then discussed, including partial perforation of the reservoir net pay (partial completion), well geometry, orientation, location, and length. The heterogeneity effect was addressed by considering three parameters: mean permeability, the vertical to horizontal permeability ratio, and permeability variation. Sensitivity analysis was carried out using iSIGHT software (design of experiments) to determine the dominant factors affecting CO₂ storage capacity and injectivity. Simulation results show that the most favorable option is the perforation of all layers with horizontal wells 250–300 m long set in the upper layers. Mean permeability has the most effect on CO₂ storage capacity and injectivity; k _v/k _h affects CO₂ injectivity storage capacity more than permeability variation, V _k. More CO₂ can be stored in the heterogeneous reservoirs with low mean permeability; however, high injectivity can be achieved in the uniform reservoirs with high mean permeability.     

Exhaustive brine production and complete CO2 storage in Jianghan Basin of China

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.     

Modeling of coal bed methane (CBM) production and CO2 sequestration in coal seams

A mathematical model was developed to predict the coal bed methane (CBM) production and carbon dioxide (CO₂) sequestration in a coal seam accounting for the coal seam properties. The model predictions showed that, for a CBM production and dewatering process, the pressure could be reduced from 15.17 MPa to 1.56 MPa and the gas saturation increased up to 50% in 30 years for a 5.4 × 10⁵ m² of coal formation. For the CO₂ sequestration process, the model prediction showed that the CO₂ injection rate was first reduced and then slightly recovered over 3 to 13 years of injection, which was also evidenced by the actual in seam data. The model predictions indicated that the sweeping of the water in front of the CO₂ flood in the cleat porosity could be important on the loss of injectivity. Further model predictions suggested that the injection rate of CO₂ could be about 11 × 10³ m³ per day; the injected CO₂ would reach the production well, which was separated from the injection well by 826 m, in about 30 years. During this period, about 160 × 10⁶ m³ of CO₂ could be stored within a 21.4 × 10⁵ m² of coal seam with a thickness of 3 m.     

Small angle X-ray scattering mapping and kinetics study of sub-critical CO2 sorption by two Australian coals

Time- and position-resolved synchrotron small angle X-ray scattering data were acquired from samples of two Australian coal seams: Bulli seam (Bulli 4, R_o = 1.42%, Sydney Basin), which naturally contains CO₂ and Baralaba seam (R_o = 0.67%, Bowen Basin), a potential candidate for sequestering CO₂. This experimental approach has provided unique, pore-size-specific insights into the kinetics of CO₂ sorption in the micro- and small mesopores (diameter 5 to 175 Å) and the density of the sorbed CO₂ at reservoir-like conditions of temperature and hydrostatic pressure.For both samples, at pressures above 5 bar, the density of CO₂ confined in pores was found to be uniform, with no densification in near-wall regions. In the Bulli 4 sample, CO₂ first flooded the slit pores between polyaromatic sheets. In the pore-size range analysed, the confined CO₂ density was close to that of the free CO₂. The kinetics data are too noisy for reliable quantitative analysis, but qualitatively indicate faster kinetics in mineral-matter-rich regions.In the Baralaba sample, CO₂ preferentially invaded the smallest micropores and the confined CO₂ density was up to five times that of the free CO₂. Faster CO₂ sorption kinetics was found to be correlated with higher mineral matter content but, the mineral-matter-rich regions had lower-density CO₂ confined in their pores. Remarkably, the kinetics was pore-size dependent, being faster for smaller pores.These results suggest that injection into the permeable section of an interbedded coal-clastic sequence could provide a viable combination of reasonable injectivity and high sorption capacity.     

CO2 leakage impacts on shallow groundwater: Field-scale reactive-transport simulations informed by observations at a natural analog site

It is challenging to predict the degree to which shallow groundwater might be affected by leaks from a CO₂ sequestration reservoir, particularly over long time scales and large spatial scales. In this study observations at a CO₂ enriched shallow aquifer natural analog were used to develop a predictive model which is then used to simulate leakage scenarios. This natural analog provides the opportunity to make direct field observations of groundwater chemistry in the presence of elevated CO₂, to collect aquifer samples and expose them to CO₂ under controlled conditions in the laboratory, and to test the ability of multi-phase reactive transport models to reproduce measured geochemical trends at the field-scale. The field observations suggest that brackish water entrained with the upwelling CO₂ are a more significant source of trace metals than in situ mobilization of metals due to exposure to CO₂. The study focuses on a single trace metal of concern at this site: U. Experimental results indicate that cation exchange/adsorption and dissolution/precipitation of calcite containing trace amounts of U are important reactions controlling U in groundwater at this site, and that the amount of U associated with calcite is fairly well constrained. Simulations incorporating these results into a 3-D multi-phase reactive transport model are able to reproduce the measured ranges and trends between pH, pCO₂, Ca, total C, U and Cl⁻ at the field site. Although the true fluxes at the natural analog site are unknown, the cumulative CO₂ flux inferred from these simulations are approximately equivalent to 37.8E−3 MT, approximately corresponding to a .001% leak rate for injection at a large (750 MW) power plant. The leakage scenario simulations suggest that if the leak only persists for a short time the volume of aquifer contaminated by CO₂-induced mobilization of U will be relatively small, yet persistent over 100 a.     

Time-lapse crosswell seismic and VSP monitoring of injected CO<Subscript>2</Subscript> in a brine aquifer

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.     

Dynamics of CO<Subscript>2</Subscript> fluxes and concentrations during a shallow subsurface CO<Subscript>2</Subscript> release

A field facility located in Bozeman, Montana provides the opportunity to test methods to detect, locate, and quantify potential CO₂ leakage from geologic storage sites. From 9 July to 7 August 2008, 0.3 t CO₂ day⁻¹ were injected from a 100-m long, ~2.5-m deep horizontal well. Repeated measurements of soil CO₂ fluxes on a grid characterized the spatio-temporal evolution of the surface leakage signal and quantified the surface leakage rate. Infrared CO₂ concentration sensors installed in the soil at 30 cm depth at 0–10 m from the well and at 4 cm above the ground at 0 and 5 m from the well recorded surface breakthrough of CO₂ leakage and migration of CO₂ leakage through the soil. Temporal variations in CO₂ concentrations were correlated with atmospheric and soil temperature, wind speed, atmospheric pressure, rainfall, and CO₂ injection rate.     

Seal integrity and feasibility of CO<Subscript>2</Subscript> sequestration in the Teapot Dome EOR pilot: geomechanical site characterization

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.     

Numerical simulation of carbon dioxide migration in a sandstone aquifer considering the fluid–solid coupling

Very limited investigations have been done on the numerical simulation of carbon dioxide (CO₂) migration in sandstone aquifers taking consideration of the interactions between fluid flow and rock stress. Based on the poroelasticity theory and multiphase flow theory, this study establishes a mathematical model to describe CO₂ migration, coupling the flow and stress fields. Both finite difference method (FDM) and finite element method (FEM) were used to discretize the mathematical model and generate a numerical model. A case study was carried out using the numerical model on the Jiangling sandstone aquifer in the Jianghan basin, China. The rock mechanics parameters of reservoir and overlying strata of Jiangling depression were obtained by triaxial tests. A two-dimensional model was then built to simulate carbon dioxide migration in the sandstone aquifer. The numerical simulation analyzes the carbon dioxide migration distribution rule with and without considering capillary pressure. Time-dependent migration of CO₂ in the sandstone aquifer was analyzed, and the result from the coupled model was compared with that from a traditional non-coupled model. The calculation result indicates a good consistency between the coupled model and the non-coupled model. At the injection point, the CO₂ saturation given by the coupled model is 15.39 % higher than that given by the non-coupled model; while the pore pressure given by the coupled model is 4.8 % lower than that given by the non-coupled model. Therefore, it is necessary to consider the coupling of flow and stress fields while simulating CO₂ migration for CO₂ disposal in sandstone aquifers. The result from the coupled model was also sensitized to several parameters including reservoir permeability, porosity, and CO₂ injection rate. Sensitivity analyses show that CO₂ saturation is increased non-linearly with CO₂ injection rate and decreased non-linearly with reservoir porosity. Pore pressure is decreased non-linearly with reservoir porosity and permeability, and increased non-linearly with CO₂ injection rate. When the capillary pressure was considered, the computed gas saturation of carbon dioxide was increased by 10.75 % and the pore pressure was reduced by 0.615 %.     

Preliminary reservoir model of enhanced coalbed methane (ECBM) in a subbituminous coal seam,Huntly Coalfield,New Zealand

The Huntly coalfield has significant coal deposits that contain biogenically-sourced methane. The coals are subbituminous in rank and Eocene in age and have been previously characterised with relatively low to moderate measured gas (CH₄) contents (2–4 m³/ton). The CO₂ holding capacity is relatively high (18.0 m³/ton) compared with that of CH₄ (2.6 m³/ton) and N₂ (0.7 m³/ton) at the same pressure (4 MPa; all as received basis). The geothermal gradient is also quite high at 55 °C/km.A study has been conducted which simulates enhancement of methane recovery (ECBM) from these deposits using a new version of the TOUGH2 (version 2) reservoir simulator (ECBM-TOUGH2) that can handle non-isothermal, multi-phase flows of mixtures of water, CH₄, CO₂ and N₂. The initial phase of the simulation is CH₄ production for the first 5 years of the field history. The model indicates that methane production can be significantly improved (from less than 80% recovery to nearly 90%) through injection of CO₂. However, although an increase in the rate of CO₂ injection increases the amount of CO₂ sequestered, the methane recovery (because of earlier breakthrough with increasing injection rate) decreases. Modeling of pure N₂ injection produced little enhanced CH₄ production. The injection of a hypothetical flue gas mixture (CO₂ and N₂) also produced little increase in CH₄ production. This is related to the low adsorption capacity of the Huntly coal to N₂ which results in almost instantaneous breakthrough into the production well.     

Investigation of the geochemical impact of CO2 on shallow groundwater: design and implementation of a CO2 injection test in Northeast Germany

A small scale and temporally limited CO₂ injection test was performed in a shallow aquifer to investigate the geochemical impact of CO₂ upon such aquifers and to apply and verify different monitoring methods. Detailed site investigation coupled with multiphase simulations were necessary to design the injection experiment and to set up the monitoring network, before CO₂ was injected over a ten-day period at three injection wells, at a depth of 18?m below surface level into a quaternary sand aquifer located close to the town of Wittstock in Northeast Germany. Monitoring methods comprised groundwater sampling and standard analyses, as well as trace element analyses and isotope analyses; geoelectrical borehole monitoring; passive samplers to analyse temporally integrated for cations and multi-parameter probes that can measure continuously for dissolved CO₂, pH and electrical conductivity. Due to CO₂ injection, total inorganic carbon concentrations increased and pH decreased down to a level of 5.1. Associated reactions comprised the release of major cations and trace elements. Geoelectrical monitoring, as well as isotope analyses and multi-parameter probes proved to be suitable methods for monitoring injected CO₂ and/or the alteration of groundwater.     

Effect of NO2 in exhaust gas from an oxyfuel combustion system on the cap rock of a proposed CO2 injection site

A laboratory geochemical study was conducted using a drill core sample of cap rock from the Surat Basin, Australia, to investigate the effect of NO₂ contained in the CO₂ gas exhausted from the oxyfuel combustion process (oxyfuel combustion CO₂) on the cap rock. A gas (CO₂ containing NO₂) was prepared to simulate the exhaust gas produced from the oxyfuel combustion process. Two types of gases (pure CO₂ and CO₂ containing SO₂) were also prepared as reference gases. The effect of NO₂ on cap rock was studied experimentally using these gases. No differences in the amounts of leached ions and pH changes for CO₂ containing NO₂ (36 ppmv), pure CO₂, and CO₂ containing SO₂ (35 ppmv) existed. The pH values decreased immediately after CO₂ gas injection but increased with time as a result of mineral buffering. Leaching of Fe, Mg, Ca, and K was suggested to have occurred as the result of dissolution of Fe-chlorite, prehnite and illite-smectite mixed layer clay in the shale sample. The amounts of Ca, Fe, and Mg leached with CO₂ containing NO₂ (318 ppmv) were higher than those for pure CO₂. For the mixture containing 318 ppmv NO₂, the pH increased more than that for the other gas conditions immediately after the pH fall at the start of the experiment, because oxidation-reduction reactions occurred between Fe²⁺ and NO₃⁻. Moreover, the results indicated that some of the leached Ca and Fe were deposited on the shale sample because of the pH increase. Therefore, we concluded that the effects of NO₂ on mineral dissolution and pH changes of formation water are negligible when oxyfuel combustion CO₂ containing about 30 ppmv of NO₂ is injected into an underground aquifer. In addition, even if about 300 ppmv NO₂ is accidentally injected into the underground aquifer, mineral dissolution is suppressed due to the buffering of pH decrease after gas injection.     

Geologic assessment and injection design for a pilot CO<Subscript>2</Subscript>-enhanced oil recovery and sequestration demonstration in a heterogeneous oil reservoir: Citronelle Field,Alabama, USA

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.     

Impact of CO<Subscript>2</Subscript> injection rate on heat extraction at the HDR geothermal field of Zhacanggou,China

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.     

Characterization of deep saline aquifers in the Bécancour area,St. Lawrence Lowlands,Québec,Canada: implications for CO2 geological storage

The present paper provides a case study of the assessment of the potential for CO₂ storage in the deep saline aquifers of the Bécancour region in southern Québec. This assessment was based on a hydrogeological and petrophysical characterization using existing and newly acquired core and well log data from hydrocarbon exploration wells. Analyses of data obtained from different sources provide a good understanding of the reservoir hydrogeology and petrophysics. Profiles of formation pressure, temperature, density, viscosity, porosity, permeability, and net pay were established for Lower Paleozoic sedimentary aquifers. Lateral hydraulic continuity is dominant at the regional scale, whereas vertical discontinuities are apparent for most physical and chemical properties. The Covey Hill sandstone appears as the most suitable saline aquifer for CO₂ injection/storage. This unit is found at a depth of more than 1 km and has the following properties: fluid pressures exceed 14 MPa, temperature is above 35 °C, salinity is about 108,500 mg/l, matrix permeability is in the order of 3 × 10^?16 m² (0.3 mDarcy) with expected higher values of formation-scale permeability due to the presence of natural fractures, mean porosity is 6 %, net pay reaches 282 m, available pore volume per surface area is 17 m³/m², rock compressibility is 2 × 10^?9 Pa^?1 and capillary displacement pressure of brine by CO₂ is about 0.4 MPa. While the containment for CO₂ storage in the Bécancour saline aquifers can be ensured by appropriate reservoir characteristics, the injectivity of CO₂ and the storage capacity could be limiting factors due to the overall low permeability of aquifers. This characterization offers a solid basis for the subsequent development of a numerical hydrogeological model, which will be used for CO₂ injection capacity estimation, CO₂ injection scenarios and risk assessment.     

Estimate CO2 storage capacity of the Johansen formation: numerical investigations beyond the benchmarking exercise

In this paper, Shell’s in-house reservoir simulator MoReS is applied to a recently introduced CO₂ sequestration benchmark problem entitled “Estimation of the CO₂ Storage Capacity of a Geological Formation” (Class et al. 2008). The principal objective of this benchmark is the simulation of CO₂ distribution within a modeling region, and leakage of CO₂ outside of it, for a period of 50 years. This study goes beyond the benchmarking exercise to investigate additional factors with direct relevance to CO₂ storage capacity estimations: water and gas relative permeabilities, permeability anisotropy, presence of sub-seismic features (conductive fractures, thin shale layers), regional hydrodynamic gradient, CO₂-enriched brine convection (due to brine density differences), and injection rates. The effects of hydrodynamic gradients and gravitationally induced convection only become significant over 100 s of years. This study has thus extended simulation time to 1,000 years. It is shown that grid resolution significantly impacts results. Vertical-grid refinement results in larger and thinner CO₂ plumes. Lateral-grid refinement delays leakage out of the model domain and reduces injection pressure for a given injection rate. Sub-seismic geological features such as fractures/faults and shale layers are demonstrated to have impact on CO₂ sequestration. Fractures located up-dip from the injector may lead to more leakage while the opposite may happen in the presence of fractures perpendicular to the dip. Thin shale layers produce stacked CO₂ blankets. They should be explicitly represented instead of being upscaled using a reduced vertical to horizontal permeability ratio. Results are seen to be far more sensitive to gas relative permeability and hysteresis than to variations in the water relative permeability models used. For a multi-injectors project, there is scope to optimize the phasing of injections to avoid potential fracturing near injectors.     

Geochemical detection of carbon dioxide in dilute aquifers

Background  

Carbon storage in deep saline reservoirs has the potential to lower the amount of CO₂ emitted to the atmosphere and to mitigate global warming. Leakage back to the atmosphere through abandoned wells and along faults would reduce the efficiency of carbon storage, possibly leading to health and ecological hazards at the ground surface, and possibly impacting water quality of near-surface dilute aquifers. We use static equilibrium and reactive transport simulations to test the hypothesis that perturbations in water chemistry associated with a CO₂ gas leak into dilute groundwater are important measures for the potential release of CO₂ to the atmosphere. Simulation parameters are constrained by groundwater chemistry, flow, and lithology from the High Plains aquifer. The High Plains aquifer is used to represent a typical sedimentary aquifer overlying a deep CO₂ storage reservoir. Specifically, we address the relationships between CO₂ flux, groundwater flow, detection time and distance. The CO₂ flux ranges from 10³ to 2 × 10⁶ t/yr (0.63 to 1250 t/m²/yr) to assess chemical perturbations resulting from relatively small leaks that may compromise long-term storage, water quality, and surface ecology, and larger leaks characteristic of short-term well failure.     

深部咸水层二氧化碳封存的干化效应及选址启示

将二氧化碳注入到深部咸水层中,形成复杂的多组分、多相流系统。二氧化碳在压力梯度、浓度差作用下不断扩散,逐步带走盐溶液中的水分,导致各组分的相态变化,盐结晶析出,阻塞了咸水层孔隙通道,从而降低了二氧化碳的注入效率,研究该干化效应的影响因素并为工程选址提供依据具有重要意义。采用二维径向模型建立多相流体的流动方程,并结合相对渗透率和毛细压力方程探讨二氧化碳注入速率、咸水层含盐量、毛细压力的特征参数对干化效应的影响,干化效应可用固体饱和度值进行定量描述。结果表明：二氧化碳运移分3个区域：干涸区、气液相混合区及液相咸水区,干化效应主要发生在井周的干涸区。在毛细作用下固体饱和度随注入速率的减小而增大,随咸水层含盐量增大而增大,随毛细作用增大而增大。因此,提高二氧化碳的注入速率,向咸水层中注水稀释含盐量或选择粒径较大的均质咸水层减小毛细作用,均可降低盐结晶对孔隙通道的阻塞,提高注入效率。     

High-resolution stable carbon isotope monitoring indicates variable flow dynamic patterns in a deep saline aquifer at the Ketzin pilot site (Germany)

Stable isotopes of injected CO₂ act as useful tracers in carbon capture and storage (CCS) because the CO₂ itself is the carrier of the tracer signal and remains unaffected by sorption or partitioning effects. At the Ketzin pilot site (Germany), carbon stable isotope composition (δ¹³C) of injected CO₂ at the injection well was analyzed over a time period of 4 months. Occurring isotope variances resulted from the injection of CO₂ from two different sources (an oil refinery and a natural gas-reservoir). The two gases differed in their carbon isotope composition by more than 27‰. In order to find identifiable patterns of these variances in the reservoir, more than 250 CO₂-samples were collected and analyzed for their carbon isotope ratios at an observation well 100 m distant from the injection well. An isotope ratio mass spectrometer connected to a modified Thermo Gasbench system allowed quick and cost effective isotope analyses of a high number of CO₂ gas specimens. CO₂ gas from the oil refinery (δ¹³C = −30.9‰, source A) was most frequently injected and dominated the reservoir δ¹³C values at the injection site. Sporadic injection of the CO₂ from the natural gas-reservoir (δ¹³C = −3.5‰, source B) caused isotope shifts of up to +5‰ at the injection well. These variances provided a potential ideal tracer for CO₂ migration behavior. Based on these findings, tracer input signals that were injected during the last 2 years of injection could be reconstructed with the aid of an isotope mixing model and CO₂ delivery schedules. However, in contrast to the injection well, δ¹³C values at the observation well showed no variances and a constant value of −28.5‰ was measured at 600 m depth. This is in disagreement with signals that would be expected if the input signals from the injection would arrive at the observation well. The lack of isotope signals at the observation well suggests that parts of the reservoir are filled with CO₂ that is immobilized.     

Simulation of CO2 plume movement in multilayered saline formations through multilayer injection technology in the Ordos Basin,China

Deep saline aquifers still remain a significant option for the disposal of large amounts of CO₂ from the atmosphere as a means of mitigating global climate change. The small scale Carbon Capture and Sequestration demonstration project in Ordos Basin, China, operated by the Shenhua Group, is the only one of its kind in Asia, to put the multilayer injection technology into practice. This paper aims at studying the influence of temperature, injection rate and horizontal boundary effects on CO₂ plume transport in saline formation layers at different depths and thicknesses, focusing on the variations in CO₂ gas saturation and mass fraction of dissolved CO₂ in the formation of brine in the plume’s radial three-dimensional field around the injection point, and interlayer communication between the aquifer and its confining beds of relatively lower permeability. The study uses the ECO2N module of TOUGH2 to simulate flow and pressure configurations in response to small-scale CO₂ injection into multilayer saline aquifers. The modelling domain involves a complex multilayer reservoir–caprock system, comprising of a sequence of sandstone aquifers and sealing units of mudstone and siltstone layers extending from the Permian Shanxi to the Upper Triassic Liujiagou formation systems in the Ordos Basin. Simulation results indicate that CO₂ injected for storage into deep saline aquifers cause a significant pressure perturbation in the geological system that may require a long duration in the post-injection period to establish new pressure equilibrium. The multilayer simultaneous injection scheme exhibits mutual interference with the intervening sealing layers, especially when the injection layers are very close to each other and the corresponding sealing layers are thin. The study further reveals that injection rate and temperature are the most significant factors for determining the lateral and vertical extent that the CO₂ plume reaches and which phase and amount will exist at a particular time during and after the injection. In general, a large number of factors may influence the CO₂–water fluid flow system considering the complexity in the real geologic sequence and structural configurations. Therefore, optimization of a CO₂ injection scheme still requires pursuance of further studies.