Pore pressure during metamorphism of carbonate rock: effect of volumetric properties of H<Subscript>2</Subscript>O–CO<Subscript>2</Subscript> mixtures

The molar volume of mixtures of CO₂ and H₂O is a strong function of the fluid composition. Both CO₂ and H₂O participate in the metamorphism of carbonate rocks, resulting in a change in the fluid composition during reaction. One of the effects of the change in composition is the increase in pore-fluid pressure with only small increases in extent of reaction, ;. Pressure calculated from the volumetric properties of CO₂-H₂O mixtures at 400 °C increases greatly with small increases of ; but drops at greater values because of the increase in pore volume as a result of (V_solid. The pore pressure increase at small values of ;, though, readily exceeds the reported tensile strength of carbonate rocks, and the rock cannot sustain significant reaction without fracturing. The result of a small amount of reaction is a fractured rock with increased permeability, which promotes fluid transport.     

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.     

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.     

Carbonate cements in Miller field of the UK North Sea: a natural analog for mineral trapping in CO<Subscript>2</Subscript> geological storage

Miller field of the North Sea has had high concentrations of natural CO₂ for ~70 Ma. It is an ideal analog for the long-term fate of CO₂ during engineered storage, particularly for formation of carbonate minerals that permanently lock up CO₂ in solid form. The Brae Formation reservoir sandstone contains an unusually high quantity of calcite concretions; however, C and O stable isotopic signatures suggest that these are not related to the present-day CO₂ charge. Margins of the concretions are corroded, probably because of reduced pH due to CO₂ influx. Dispersed calcite cements are also present, some of which postdate the CO₂ charge and, therefore, are the products of mineral trapping. It is calculated that only a minority of the reservoired CO₂ in Miller (6–24%) has been sequestrated in carbonates, even after 70 Ma of CO₂ emplacement. Most of the CO₂ accumulation is dissolved in pore fluids. Therefore, in a reservoir similar to the Brae Formation, engineered CO₂ storage must rely on physical retention mechanisms because mineral trapping is both incomplete and slow.     

A stochastic inversion workflow for monitoring the distribution of CO<Subscript>2</Subscript> injected into deep saline aquifers

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.     

Feasibility of CO<Subscript>2</Subscript> migration detection using pressure and CO<Subscript>2</Subscript> saturation monitoring above an imperfect primary seal of a geologic CO<Subscript>2</Subscript> storage formation: a numerical investigation

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.     

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.     

Study on Effects of Low Viscosity Fluid Pre-injection on Hydraulic Fracture Complexity in Tight Heterogeneous Glutenite Reservoirs

Tight heterogeneous glutenite reservoir is typically not easy to form complex hydraulic fracture (HF) due to its poor physical properties, poor matrix seepage capacity, and small limit discharge radius and undeveloped natural fracture system. To improve the HF complexity and the stimulated reservoir volume (SRV), a novel stimulation technology called CO₂ miscible fracturing has been introduced and its fracturing mechanism has been studied. The CO₂ miscible fracturing modifies the in situ stress field by injecting low viscosity fluid to increase the HF complexity and SRV. Therefore, a series of numerical simulations based on a hydro-mechanical-damage model were carried out to study the effects of low viscosity fluid pre-injection on pore pressure, stress field, and fracturing effect in tight heterogeneous glutenite reservoirs. The results indicate that the low viscosity fluid injection can effectively increase the pore pressure around the wellbore and reduce the effective stress of the glutenite. The FCI and SRV increase with the increase of the pre-injection amount of the low viscosity fluid. The HF complexity and SRV can be improved by pre-injecting low viscosity fluid to transform the in situ stress field. The field application of this technology in a well of Shengli Oilfield showed that low-viscosity fluid pre-injection can effectively increase the width of the fractured zone, improve the SRV, and optimize the fracturing effect.

     

Experimental and numerical study on the fracture of rocks during injection of CO<Subscript>2</Subscript>-saturated water

Geological sequestration of CO₂ into depleted hydrocarbon reserviors or saline aquifers presents the enormous potential to reduce greenhouse gas emission from fossil fuels. However, it may give rise to a complicated coupling physical and chemical process. One of the processes is the hydro-mechanical impact of CO₂ injection. During the injection project, the increase of pore pressures of storing formations can induce the instability, which finally results in a catastrophic failure of disposal sites. This paper focuses mainly on the role of CO₂-saturated water in the fracturing behavior of rocks. To investigate how much the dissolved CO₂ can influence the pore pressure change of rocks, acoustic emission (AE) experiments were performed on sandstone and granite samples under triaxial conditions. The main innovation of this paper is to propose a time dependent porosity method to simulate the abrupt failure process, which is observed in the laboratory and induced by the pore pressure change due to the volume dilatancy of rocks, using a finite element scheme associated with two-phase characteristics. The results successfully explained the phenomena obtained in the physical experiments.     

A shear‐dilation‐based model for evaluation of hydraulically stimulated naturally fractured reservoirs

The role of shear dilation as a mechanism of enhancing fluid flow permeability in naturally fractured reservoirs was mainly recognized in the context of hot dry rock (HDR) geothermal reservoir stimulation. Simplified models based on shear slippage only were developed and their applications to evaluate HDR geothermal reservoir stimulation were reported. Research attention is recently focused to adjust this stimulation mechanism for naturally fractured oil and gas reservoirs which reserve vast resources worldwide. This paper develops the overall framework and basic formulations of this stimulation model for oil and gas reservoirs. Major computational modules include: natural fracture simulation, response analysis of stimulated fractures, average permeability estimation for the stimulated reservoir and prediction of an average flow direction. Natural fractures are simulated stochastically by implementing ‘fractal dimension’ concept. Natural fracture propagation and shear displacements are formulated by following computationally efficient approximate approaches interrelating in situ stresses, natural fracture parameters and stimulation pressure developed by fluid injection inside fractures. The average permeability of the stimulated reservoir is formulated as a function of discretized gridblock permeabilities by applying cubic law of fluid flow. The average reservoir elongation, or the flow direction, is expressed as a function of reservoir aspect ratio induced by directional permeability contributions. The natural fracture simulation module is verified by comparing its results with observed microseismic clouds in actual naturally fractured reservoirs. Permeability enhancement and reservoir growth are characterized with respect to stimulation pressure, in situ stresses and natural fracture density applying the model to two example reservoirs. Copyright © 2002 John Wiley & Sons, Ltd.     

Interactions between basalts and oil source rocks in rift basins： CO2 generation

Basalts interbedded with oil source rocks are discovered frequently in rift basins of eastern China, where CO2 is found in reservoirs around or within basalts, for example in the Binnan reservoir of the Dongying Depression. In the reservoirs, CO2 with heavy carbon isotopic composition (δ13C>-10‰ PDB) is in most cases accounts for 40% of the total gas reserve, and is believed to have resulted from degassing of basaltic magma from the mantle. In their investigations of the Binnan reservoir, the authors suggested that the CO2 would result from interactions between the source rocks and basalts. As the source rocks around basalts are rich in carbonate minerals, volcanic minerals, transition metals and organic matter, during their burial history some of the transition metals were catalyzed on the thermal degradation of organic matter into hydrocarbons and on the decomposition of carbonate minerals into CO2, which was reproduced in thermal simulations of the source rocks with the transition metals (Ni and Co). This kind of CO2 accounts for 55%-85% of the total gas reserve generated in the process of thermal simulation, and its δ13C values range from -11‰- -7.2‰ PDB, which are very similar to those of CO2 found in the Binnan reservoir. The co-generation of CO2 and hydrocarbon gases makes it possible their accumulation together in one trap. In other words, if the CO2 resulted directly from degassing of basaltic magma or was derived from the mantle, it could not be accumulated with hydrocarbon gases because it came into the basin much earlier than hydrocarbon generation and much earlier than trap formation. Therefore, the source rocks around basalts generated hydrocarbons and CO2 simultaneously through catalysis of Co and Ni transition metals, which is useful for the explanation of co-accumulation of hydrocarbon gases and CO2 in rift basins in eastern China.     

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 %.     

A geochemical clogging model with carbonate precipitation rates under hydrothermal conditions

A step-wise numerical calculation method was developed to provide predictions of when and where carbonate deposits might be found through reservoirs during CO₂ sequestration. Flow experiments through porous media using a supersaturated carbonate fluid were also performed in order to observe flow rates. In order to evaluate precipitation rates and permeability change in the formation, calculated flow rates based on the proposed geochemical clogging model were compared with the experimentally observed data. Both high and low temperature cases were studied to understand how hydrothermal conditions can affect precipitation rates of carbonate. According to chemical kinetics, growth rates of minerals are generally proportional to the saturation index (S.I.) that depends on temperature. Thus, a supersaturated fluid has the advantage of improving the filtration and the amount of C fixation (σ). However, when the ratio of filtration coefficient (λ) to pore fluid velocity (u) increases, the permeability around the injection point tends to be significantly reduced by carbonate accumulation, and thus, this might result in insufficient injection of CO₂. Therefore, it is essential to understand how to control both λ and u so that the precipitation of carbonate can be located as far away from the inlet as possible.     

Geomechanical and geochemical effects on sandstones caused by the reaction with supercritical CO2: an experimental approach to in situ conditions in deep geological reservoirs

The geochemical and geomechanical behaviour of reservoir rocks from deep saline aquifers during the injection and geological storage of CO₂ is studied in laboratory experiments. A combination of geochemical and geomechanical studies was carried out on various sandstones from the North German Basin. After the mineralogical, geochemical and petrophysical characterization, a set of sandstone samples was exposed to supercritical (sc)CO₂ and brine for 2–4 weeks in an autoclave system. One sample was mineralogically and geochemically characterised and then loaded in a triaxial cell under in situ pressure and temperature conditions to study the changes of the geomechanical rock properties. After treatment in the autoclaves, geochemical alterations mainly in the carbonate, but also in the sheet silicate cements as well as in single minerals of the sandstones were observed, affecting the rocks granular structure. In addition to partial solution effects during the geochemical experiments, small grains of secondary carbonate and other mineral precipitations were observed within the pore space of the treated sandstones. Results of additional geomechanical experiments with untreated samples show that the rock strength is influenced by the saturation degree, the confining pressure, the pore fluid pressure and temperature. The exposure to pure scCO₂ in the autoclave system induces reduced strength parameters, modified elastic deformation behaviour and changes of the effective porosity in comparison to untreated sandstone samples. Experimental results show that the volume of pore fluid fluxing into the pore space of the sandstones clearly depends on the saturation level of the sample.     

Site characterization for CO<Subscript>2</Subscript> geologic storage and vice versa: the Frio brine pilot,Texas, USA as a case study

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.     

Dawsonite fixation of mantle CO2 in the cretaceous Songliao Basin,Northeast China: a natural analogue for CO2 mineral trapping in oilfields

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

Numerical simulation of CO2 disposal by mineral trapping in deep aquifers

Carbon dioxide disposal into deep aquifers is a potential means whereby atmospheric emissions of greenhouse gases may be reduced. However, our knowledge of the geohydrology, geochemistry, geophysics, and geomechanics of CO₂ disposal must be refined if this technology is to be implemented safely, efficiently, and predictably. As a prelude to a fully coupled treatment of physical and chemical effects of CO₂ injection, the authors have analyzed the impact of CO₂ immobilization through carbonate mineral precipitation. Batch reaction modeling of the geochemical evolution of 3 different aquifer mineral compositions in the presence of CO₂ at high pressure were performed. The modeling considered the following important factors affecting CO₂ sequestration: (1) the kinetics of chemical interactions between the host rock minerals and the aqueous phase, (2) CO₂ solubility dependence on pressure, temperature and salinity of the system, and (3) redox processes that could be important in deep subsurface environments. The geochemical evolution under CO₂ injection conditions was evaluated. In addition, changes in porosity were monitored during the simulations. Results indicate that CO₂ sequestration by matrix minerals varies considerably with rock type. Under favorable conditions the amount of CO₂ that may be sequestered by precipitation of secondary carbonates is comparable with and can be larger than the effect of CO₂ dissolution in pore waters. The precipitation of ankerite and siderite is sensitive to the rate of reduction of Fe(III) mineral precursors such as goethite or glauconite. The accumulation of carbonates in the rock matrix leads to a considerable decrease in porosity. This in turn adversely affects permeability and fluid flow in the aquifer. The numerical experiments described here provide useful insight into sequestration mechanisms, and their controlling geochemical conditions and parameters.     

低渗透油藏二氧化碳混相驱注采方式研究——以克拉玛依油田X区克下组低渗透油藏为例

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

Assessing the feasibility of CO<Subscript>2</Subscript>-enhanced oil recovery and storage in mature oil field: A case study from Cambay basin

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.