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1.
Geological storage of CO2 in the offshore Gippsland Basin, Australia, is being investigated by the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) as a possible method for storing the very large volumes of CO2 emissions from the nearby Latrobe Valley area. A storage capacity of about 50 million tonnes of CO2 per annum for a 40-year injection period is required, which will necessitate several individual storage sites to be used both sequentially and simultaneously, but timed such that existing hydrocarbon assets will not be compromised. Detailed characterisation focussed on the Kingfish Field area as the first site to be potentially used, in the anticipation that this oil field will be depleted within the period 2015–2025. The potential injection targets are the interbedded sandstones of the Paleocene-Eocene upper Latrobe Group, regionally sealed by the Lakes Entrance Formation. The research identified several features to the offshore Gippsland Basin that make it particularly favourable for CO2 storage. These include: a complex stratigraphic architecture that provides baffles which slow vertical migration and increase residual gas trapping and dissolution; non-reactive reservoir units that have high injectivity; a thin, suitably reactive, lower permeability marginal reservoir just below the regional seal providing mineral trapping; several depleted oil fields that provide storage capacity coupled with a transient production-induced flow regime that enhances containment; and long migration pathways beneath a competent regional seal. This study has shown that the Gippsland Basin has sufficient capacity to store very large volumes of CO2. It may provide a solution to the problem of substantially reducing greenhouse gas emissions from future coal developments in the Latrobe Valley.  相似文献   

2.
Deep saline aquifers in sedimentary basins are considered to have the greatest potential for CO2 geological storage in order to reduce carbon emissions. CO2 injected into a saline sandstone aquifer tends to migrate upwards toward the caprock because the density of the supercritical CO2 phase is lower than that of formation water. The accumulated CO2 in the upper portions of the reservoir gradually dissolves into brine, lowers pH and changes the aqueous complexation, whereby induces mineral alteration. In turn, the mineralogical composition could impose significant effects on the evolution of solution, further on the mineralized CO2. The high density of aqueous phase will then move downward due to gravity, give rise to “convective mixing,” which facilitate the transformation of CO2 from the supercritical phase to the aqueous phase and then to the solid phase. In order to determine the impacts of mineralogical compositions on trapping amounts in different mechanisms for CO2 geological storage, a 2D radial model was developed. The mineralogical composition for the base case was taken from a deep saline formation of the Ordos Basin, China. Three additional models with varying mineralogical compositions were carried out. Results indicate that the mineralogical composition had very obvious effects on different CO2 trapping mechanisms. Specific to our cases, the dissolution of chlorite provided Mg2+ and Fe2+ for the formation of secondary carbonate minerals (ankerite, siderite and magnesite). When chlorite was absent in the saline aquifer, the dominant secondary carbon sequestration mineral was dawsonite, and the amount of CO2 mineral trapping increased with an increase in the concentration of chlorite. After 3000 years, 69.08, 76.93, 83.52 and 87.24 % of the injected CO2 can be trapped in the solid (mineral) phase, 16.05, 11.86, 8.82 and 6.99 % in the aqueous phase, and 14.87, 11.21, 7.66 and 5.77 % in the gas phase for Case 1 through 4, respectively.  相似文献   

3.
Mineral trapping is one of the safest ways to store CO2 underground as C will be immobilized in a solid phase. Carbon dioxide will be, therefore, sequestered for geological periods of time, helping to diminish greenhouse gas emissions and mitigate global warming. Although mineral trapping is considered a fairly long process, owing to the existence of kinetic barriers for mineral precipitation, it has been demonstrated both experimentally and by numerical modeling. Here the results of experimental and numerical modeling studies performed in sandstones of the saline aquifer of the Rio Bonito Formation, Paraná Basin, are presented. The Rio Bonito Formation consists of paralic sandstones deposited in the intracratonic Paraná Basin, southern Brazil, during the Permian (Artinskian–Kungurian). These rocks have the largest potential for CO2 storage because of their appropriated reservoir quality, depth and proximity to the most important stationary CO2 sources in Brazil. Here it is suggested that CO2 can be permanently stored as carbonates as CO2 reacts with rocks of the Rio Bonito Formation and forms CaCO3 at temperatures and pressures similar to those encountered for CO2 storage in geological formations. Results of this work will be useful for studies of partitioning mechanisms for C trapping in CO2 storage programs.  相似文献   

4.
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   

5.
One of the uncertainties in the field of carbon dioxide capture and storage (CCS) is caused by the parameterization of geochemical models. The application of geochemical models contributes significantly to calculate the fate of the CO2 after its injection. The choice of the thermodynamic database used, the selection of the secondary mineral assemblage as well as the option to calculate pressure dependent equilibrium constants influence the CO2 trapping potential and trapping mechanism. Scenario analyses were conducted applying a geochemical batch equilibrium model for a virtual CO2 injection into a saline Keuper aquifer. The amount of CO2 which could be trapped in the formation water and in the form of carbonates was calculated using the model code PHREEQC. Thereby, four thermodynamic datasets were used to calculate the thermodynamic equilibria. Furthermore, the equilibrium constants were re-calculated with the code SUPCRT92, which also applied a pressure correction to the equilibrium constants. Varying the thermodynamic database caused a range of 61% in the amount of trapped CO2 calculated. Simultaneously, the assemblage of secondary minerals was varied, and the potential secondary minerals dawsonite and K-mica were included in several scenarios. The selection of the secondary mineral assemblage caused a range of 74% in the calculated amount of trapped CO2. Correcting the equilibrium constants with respect to a pressure of 125 bars had an influence of 11% on the amount of trapped CO2. This illustrates the need for incorporating sensitivity analyses into reaction pathway modeling.  相似文献   

6.
鄂尔多斯盆地是我国CO2地下埋藏的潜在目标区,位于伊金霍洛旗附近的中神监X井与CO2地下注入井中神注1井相邻,两者钻遇地层系统和岩石组合一致。为对示范区储层的固碳潜力和泥岩改造状况做出预测,为CO2地质储存的数值模拟研究提供基础地质信息和相关数据,通过偏光显微镜、扫描电镜、X射线衍射、X射线荧光等多种技术手段,开展了中神监X井石千峰组的岩石学和地球化学特征研究。结果表明石千峰组的砂岩岩石类型主要为长石岩屑砂岩和岩屑长石砂岩;泥岩主要由石英、粘土矿物和长石组成,其中,粘土矿物主要为伊利石,其次为蒙皂石、高岭石和绿泥石。预测在CO2注入后的流体-砂岩长期相互作用过程中,石千峰组砂岩可以通过形成片钠铝石、方解石、铁白云石和菱铁矿等固碳矿物,形成对CO2泄露而言的矿物圈闭,进而实现CO2的长期和安全封存;红色泥岩夹层将发生金属离子活化,导致泥岩褪色。  相似文献   

7.
Capture and geological sequestration of CO2 from energy production is proposed to help mitigate climate change caused by anthropogenic emissions of CO2 and other greenhouse gases. Performance goals set by the US Department of Energy for CO2 storage permanence include retention of at least 99% of injected CO2 which requires detailed assessments of each potential storage site’s geologic system, including reservoir(s) and seal(s). The objective of this study was to review relevant basin-wide physical and chemical characteristics of geological seals considered for saline reservoir CO2 sequestration in the United States. Results showed that the seal strata can exhibit substantial heterogeneity in the composition, structural, and fluid transport characteristics on a basin scale. Analysis of available field and wellbore core data reveal several common inter-basin features of the seals, including the occurrence of quartz, dolomite, illite, calcite, and glauconite minerals along with structural features containing fractures, faults, and salt structures. In certain localities within the examined basins, some seal strata also serve as source rock for oil and gas production and can be subject to salt intrusions. The regional features identified in this study can help guide modeling, laboratory, and field studies needed to assess local seal performances within the examined basins.  相似文献   

8.
Capturing CO2 from point sources and storing it in geologic formations is a potential option for allaying the CO2 level in the atmosphere. In order to evaluate the effect of geological storage of CO2 on rock-water interaction, batch experiments were performed on sandstone samples taken from the Altmark reservoir, Germany, under in situ conditions of 125 °C and 50 bar CO2 partial pressure. Two sets of experiments were performed on pulverized sample material placed inside a closed batch reactor in (a) CO2 saturated and (b) CO2 free environment for 5, 9 and 14 days. A 3M NaCl brine was used in both cases to mimic the reservoir formation water. For the “CO2 free” environment, Ar was used as a pressure medium. The sandstone was mainly composed of quartz, feldspars, anhydrite, calcite, illite and chlorite minerals. Chemical analyses of the liquid phase suggested dissolution of both calcite and anhydrite in both cases. However, dissolution of calcite was more pronounced in the presence of CO2. In addition, the presence of CO2 enhanced dissolution of feldspar minerals. Solid phase analysis by X-ray diffraction and Mössbauer spectroscopy did not show any secondary mineral precipitation. Moreover, Mössbauer analysis did not show any evidence of significant changes in redox conditions. Calculations of total dissolved solids’ concentrations indicated that the extent of mineral dissolution was enhanced by a factor of approximately 1.5 during the injection of CO2, which might improve the injectivity and storage capacity of the targeted reservoir. The experimental data provide a basis for numerical simulations to evaluate the effect of injected CO2 on long-term geochemical alteration at reservoir scale.  相似文献   

9.
In this paper, we focus on the geological storage of CO2 in reservoirs with zones that are cold enough to facilitate CO2 hydrate formation at local pressures. A 2D hydro-chemical mechanical model which has five layers (three layers with aquifers and two layers with cap rock in which we introduced two fractures) is created. We apply a reactive transport reservoir simulator, RetrasoCodeBright (RCB), in which hydrate is treated as a pseudo mineral. Following the recent modifications to account for hydrate dynamics in the code through a kinetic approach (Kvamme et al., Proceedings of the 7th International Conference on Gas Hydrates (ICGH 2011), 2011b), we have further improved the simulator to implement the nonequilibrium thermodynamic calculations. In the present study, we spot the light on the hydrate formation effects on porosity in different regions, as well as on the flow pattern. These simulations are based on classical relationships between porosity and permeability, but the outline of ongoing modifications is presented as well. A critical question in such systems is whether hydrate formation can contribute to stabilizing the storage, given that hydrates are pore filling and cannot be stable toward mineral surfaces. The implications of hydrate formation on the geo-mechanical properties of the model reservoir are other aspects addressed in this study.  相似文献   

10.
To investigate the potential for the geologic storage of CO2 in saline sedimentary aquifers, 1600 ton of CO2 were injected at 1500 m depth into a 24-m sandstone section of the Frio Formation — a regional reservoir in the US Gulf Coast. Fluid samples obtained from the injection and observation wells before, during and after CO2 injection show a Na–Ca–Cl type brine with 93,000 mg/L TDS and near saturation of CH4 at reservoir conditions. As injected CO2 gas reached the observation well, results showed sharp drops in pH (6.5 to 5.7), pronounced increases in alkalinity (100 to 3000 mg/L as HCO3) and Fe (30 to 1100 mg/L), and significant shifts in the isotopic compositions of H2O and DIC. Geochemical modeling indicates that brine pH would have dropped lower, but for buffering by dissolution of calcite and Fe oxyhydroxides. Post-injection results show the brine gradually returning to its pre-injection composition.  相似文献   

11.
《Applied Geochemistry》2000,15(8):1085-1095
The pore space of deep saline aquifers in the Alberta (sedimentary) Basin offers a significant volume for waste storage by “hydrodynamic trapping”. Furthermore, given the slow regional fluid flow in these deep saline aquifers, ample time exists for waste-water/rock chemical reactions to take place. A geochemical computer model (PATHARC) was used to compute the interaction of industrial waste streams comprising CO2, H2SO4 and H2S with the minerals in typical carbonate and sandstone aquifers from the Alberta Basin. The results support the idea that these acids can be neutralized by such reactions and that new mineral products are formed, such as calcite, siderite, anhydrite/gypsum and pyrrhotite, thereby trapping the CO3, SO4 and S ions that are formed when the acid gases dissolve in the formation water. Siliciclastic aquifers appear to be a better host for “mineral trapping” than carbonate aquifers, especially with regard to CO2. Carbonate aquifers may be more prone to leakage due to high CO2 pressures generated by reaction with H2SO4 and H2S. Even though permeability decreases are expected due to this “mineral trapping”, they can be partially controlled so that plugging of the aquifer does not occur.  相似文献   

12.
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13.
Oxygen isotope microanalyses of authigenic quartz, in combination with temperatures of quartz precipitation constrained by fluid inclusion microthermometry and burial history modelling, are employed to trace the origin and evolution of pore waters in three distinct reservoirs of the Brae Formation in the Miller and Kingfisher Fields (North Sea). Oxygen isotope ratios of quartz cements were measured in situ in nine sandstone thin sections with a Cameca ims-4f ion microprobe. In conjunction with quartz cement paragenesis in the reservoirs, constrained from textural and cathodoluminescence (CL) microscopy studies, pore water evolution was reconstructed from the time of deposition of the sandstones in the Upper Jurassic until the present.CL photomicrographs of quartz overgrowths in the Brae Formation sandstones show three cement zones (A, B and C) which can be related to different oxygen isotope compositions: (1) the earliest, and thinnest, zone A (homogeneous CL pattern with probable δ18O values between +23‰ and +26‰—direct measurements were not possible) precipitated in the sandstones at temperatures <60 °C; (2) the second zone B (complex CL pattern and directly measured δ18O values between +15‰ and +18‰) precipitated in the sandstones most likely between 70 and 90 °C; (3) the third zone C (homogeneous CL pattern and directly measured δ18O values between +16‰ and +22‰) precipitated in the sandstones most likely at temperatures >90 °C. Calculated oxygen isotope compositions of pore waters show that zone A quartz cements, and enclosing concretionary calcite, precipitated from a meteoric-type fluid (∼−7‰) during shallow burial (<1.5 km). Zone B quartz cements precipitated from fluids which evolved in composition from a meteoric-type fluid (δ18O −7‰) to a more 18O-enriched fluid (δ18O −4‰) as burial continued to ∼3.0 km. Data from zone C quartz cements are consistent with further fluid evolution from δ18O −4‰ to basinal-type fluids with δ18O similar to the present-day formation water oxygen isotope composition (+0.6‰ at 4.0 km burial). A similar pore water evolution can be derived for all three reservoirs studied, indicating that hydrogeologic evolution was similar across sandstones of the whole Brae Formation.The quartz cement zones observed in the Brae Formation sandstones, and the pore water history derived for the area studied, is analogous to published petrographic and pore water evolution data from the nearby Brent Group reservoirs and from reservoirs located in the Haltenbanken area on the Atlantic margin offshore Norway. Considering quartz cement is a major porosity-occluding phase in many reservoir sandstones, and because pore waters both dissolve quartz and carry the dissolved silica to cementation sites, the data presented are valuable for improving the understanding and prediction of reservoir quality development in sandstones globally.  相似文献   

14.
对长岭凹陷深层天然气藏储层——营城组火山岩中发育的流体包裹体进行了详细研究,结果表明在火山岩发育的石英、方解石细网脉中均存在较多的碳质流体包裹体,单个包裹体激光拉曼光谱分析结果表明其主要为CO2及CH4两种类型的碳质包裹体。其中方解石细网脉体中发育有原生及次生CH4包裹体,而含CO2包裹体多以原生包裹体产于石英细网脉中。很多含CO2包裹体的石英细脉中发现了含CH4包裹体的方解石脉体的角砾,这就表明石英细脉形成晚于方解石细脉。营城组火山岩储层中CO2及CH4包裹体的产状特征研究表明,松辽盆地深层天然气藏的形成系火山岩成岩后CO2及CH4等气体不同期次充注的结果,CH4气的充注时间早于CO2气,火山岩中发育的原生孔隙及次生裂隙为上述气体的充注和聚集提供了重要通道。  相似文献   

15.
An experimental investigation has been carried on the solubility of CO2 in water and 1 M NaCl between 0.3 and 4 MPa, in order to test the validity of the results given by various modelling codes. In addition to experiments with pure fluids, the effect of a range of likely reservoir minerals on CO2–water interactions, including K-feldspar, kaolinite, calcite, Ca-montmorillonite and Na-montmorillonite were also investigated. In addition to measurements of CO2 solubility, the pH of the CO2-saturated suspensions was also measured directly at pressures of up to 1 MPa. The results demonstrate that predictions of CO2 solubility made with PHREEQC and Geochemist’s Workbench agree to within 20% with the experimental value, provided corrections are first made off-line for the fugacity coefficient of CO2, while predictions from standalone models are slightly more accurate. In the presence of mineral suspensions, PHREEQC and Geochemist’s Workbench give good results for calcite and kaolinite but underestimate the pH of montmorillonite-bearing assemblages while slightly overestimating the pH of K-feldspar suspensions. These results are significant because they indicate that CO2-charged fluids reacted with clays may be less acidic than indicated by the models, which will impact predictions of the potential for dissolution of reservoir and cap rock minerals, as well as the potential for leaching of toxic metals.  相似文献   

16.
A sedimentary formation perturbated by supercritical CO2 reacts by dissolving primary minerals and forming new secondary phases. In this process CO2 may be trapped in stable carbonate minerals and may thereby be immobilized for long time spans. The potential for mineral trapping can be estimated by solving kinetic expressions for the reservoir minerals and possible secondary phases. This is, however, not trivial as kinetic data are uncertain or even lacking for the minerals of interest. Here, the rate equations most commonly used for CO2 storage simulations have been solved, and the rate parameters varied, to obtain sensitivity on the total amount of CO2 stored as mineral carbonate. As various expressions are in use to estimate growth rates of secondary carbonates, three formulations were compared, including one taking into account mineral nucleation preceding growth. The sensitivity studies were done on two systems, the Utsira Sand being representative for a cold quartz-rich sand (37 °C, 100 bar CO2), and the Gulf Coast Sediment, being representative for a medium temperature quartz–plagioclase-rich system (75 °C, 300 bar CO2).The simulations showed that the total predicted CO2 mineral storage is especially sensitive to the choice of growth rate model and the reactive surface area. The largest sensitivity was found on α, fraction of total surface area available for reactions, with a reduction of one order of magnitude for all reacting phases leading to 3–4 times lower predicted CO2 mineral storage. Because the reactive surface area is highly uncertain for natural systems, the range in predicted results may be even larger. The short-term predictions (<100–1000 a), such as the onset of carbonate growth, were highly sensitive to nucleation and growth rates. Moreover, the type of carbonate minerals formed was shown to be model dependent, with the simplest model predicting an unlikely carbonate assemblage at low temperature (i.e., formation of dolomite at 37 °C). Therefore, to use kinetic models to upscale short-term (<months) laboratory experiments in time, to identify the past reactions and physical conditions of natural CO2 storage analogues, and finally to predict the potential for CO2 trapping in existing and future storage projects, more knowledge has to be collected, especially on the reactive surface area of CO2 storage reservoirs, and on the rate of secondary carbonate nucleation and growth.  相似文献   

17.
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   

18.
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   

19.
Carbon dioxide enhanced oil recovery (CO2-EOR) has been widely applied to the process of carbon capture, utilization, and storage (CCUS). Here, we investigate CO2–oil–water–rock interactions under reservoir conditions (100 °C and 24 MPa) in order to understand the fluid–rock interactions following termination of a CO2-EOR project. Our experimental results show that CO2-rich fluid remained the active fluid controlling the dissolution–precipitation processes in an oil-undersaturated sandstone reservoir; e.g., the dissolution of feldspar and calcite, and the precipitation of kaolinite as well as solid phases comprising O, Si, Al, Na, C, and Ti. Mineral dissolution rates were reduced in the case that mineral surfaces were coated by oil. Mineral wettability and composition, and oil saturation were the main controls on the exposed surface area of grains, and mineral wettability in particular led to selective dissolution. In addition, the permeability of the reservoir decreased substantially due to the precipitation of kaolinite and solid-phase particles, and due to the clogging of less soluble mineral particles released by the dissolution of K-feldspar and carbonate cement, whereas porosity increased. The results provide insight into potential formation damage resulting from CO2-EOR projects.  相似文献   

20.
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   

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