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.     

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.     

Impacts of mineralogical compositions on different trapping mechanisms during long-term CO<Subscript>2</Subscript> storage in deep saline aquifers

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.     

Site characterisation of a basin-scale CO<Subscript>2</Subscript> geological storage system: Gippsland Basin,southeast Australia

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.     

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.     

Geologic factors controlling CO2 storage capacity and permanence: case studies based on experience with heterogeneity in oil and gas reservoirs applied to CO2 storage

A variety of structural and stratigraphic factors control geological heterogeneity, inferred to influence both sequestration capacity and effectiveness, as well as seal capacity. Structural heterogeneity factors include faults, folds, and fracture intensity. Stratigraphic heterogeneity is primarily controlled by the geometry of depositional facies and sandbody continuity, which controls permeability structure. The permeability structure, in turn, has implications for CO₂ injectivity and near-term migration pathways, whereas the long-term sequestration capacity can be inferred from the production history. Examples of Gulf Coast oil and gas reservoirs with differing styles of stratigraphic heterogeneity demonstrate the impact of facies variability on fluid flow and CO₂ sequestration potential. Beach and barrier-island deposits in West Ranch field in southeast Texas are homogeneous and continuous. In contrast, Seeligson and Stratton fields in south Texas, examples of major heterogeneity in fluvial systems, are composed of discontinuous, channel-fill sandstones confined to narrow, sinuous belts. These heterogeneous deposits contain limited compartments for potential CO₂ storage, although CO₂ sequestration effectiveness may be enhanced by the high number of intraformational shale beds. These field examples demonstrate that areas for CO₂ storage can be optimized by assessing sites for enhanced oil and gas recovery in mature hydrocarbon provinces.     

Sealing efficiency analysis for shallow-layer caprocks in CO<Subscript>2</Subscript> geological storage

The CO₂ migrated from deeper to shallower layers may change its phase state from supercritical state to gaseous state (called phase transition). This phase transition makes both viscosity and density of CO₂ experience a sharp variation, which may induce the CO₂ further penetration into shallow layers. This is a critical and dangerous situation for the security of CO₂ geological storage. However, the assessment of caprock sealing efficiency with a fully coupled multi-physical model is still missing on this phase transition effect. This study extends our previous fully coupled multi-physical model to include this phase transition effect. The dramatic changes of CO₂ viscosity and density are incorporated into the model. The impacts of temperature and pressure on caprock sealing efficiency (expressed by CO₂ penetration depth) are then numerically investigated for a caprock layer at the depth of 800 m. The changes of CO₂ physical properties with gas partial pressure and formation temperature in the phase transition zone are explored. It is observed that phase transition revises the linear relationship of CO₂ penetration depth and time square root as well as penetration depth. The real physical properties of CO₂ in the phase transition zone are critical to the safety of CO₂ sequestration. Pressure and temperature have different impact mechanisms on the security of CO₂ geological storage.     

Screening and ranking of sedimentary basins for sequestration of CO<Subscript>2</Subscript> in geological media in response to climate change

Sedimentary basins are suitable to different degrees for CO ₂ geological sequestration as a result of various intrinsic and extrinsic characteristics, of which the geothermal regime is one of the most important. Warm basins are less favorable for CO ₂ sequestration than cold basins because of reduced capacity in terms of CO ₂ mass, and because of higher CO ₂ buoyancy, which drives the upward CO ₂ migration. A set of 15 criteria, with several classes each, has been developed for the assessment and ranking of sedimentary basins in terms of their suitability for CO ₂ sequestration. Using a parametric normalization procedure, a basin's individual scores are summed to a total score using weights that express the relative importance of different criteria. The total score is ranked to determine the most suitable basin or region thereof for the geological sequestration of CO ₂. The method is extremely flexible in that it allows changes in the functions that express the importance of various classes for any given criterion, and in the weights that express the relative importance of various criteria. Examples of application are given for Canada's case and for the Alberta basin in Canada.     

Robust simulation of sharp-interface models for fast estimation of CO<Subscript>2</Subscript> trapping capacity in large-scale aquifer systems

Modeling geological carbon storage represents a new and substantial challenge for the subsurface geosciences. To increase understanding and make good engineering decisions, containment processes and large-scale storage operations must be simulated in a thousand-year perspective. Large differences in spatial and temporal scales make it prohibitively expensive to compute the fate of injected CO₂ using traditional 3D simulators. Instead, accurate forecast can be computed using simplified models that are adapted to the specific setting of the bouyancy-driven migration of the light fluid phase. This paper presents a family of vertically integrated models for studying the combined large-scale and long-term effects of structural, residual, and solubility trapping of CO₂. The models are based on an assumption of a sharp interface separating CO₂ and brine and can provide a detailed inventory of the injected CO₂ volumes over periods of thousands of years within reasonable computational time. To be compatible with simulation tools used in industry, the models are formulated in a black-oil framework. The models are implemented in MRST-co2lab, which is an open community software developed especially to study and optimize large-scale, long-term geological storage of CO₂. The resulting simulators are fully implicit and handle input from standard geomodeling tools.     

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.     

Evaluating the impact of caprock and reservoir properties on potential risk of CO2 leakage after injection

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

Potential and Suitability Evaluation of CO2 Geological Storage in Major Sedimentary Basins of China, and the Demonstration Project in Ordos Basin

From 2010 to 2012, the China Geological Survey Center for Hydrogeology and Environmental Geology Survey (CHEGS) carried out the project “Potential evaluation and demonstration project of CO2 Geological Storage in China”. During this project, we developed an evaluation index system and technical methods for the potential and suitability of CO2 geological storage based on China’s geological conditions, and evaluated the potential and suitability of the primary basins for CO2 geological storage, in order to draw a series of regional scale maps (at a scale of 1:5000000) and develop an atlas of the main sedimentary basins in China. By using these tools, we delineated many potential targets for CO2 storage. We also built techniques and methods for site selection and the exploration and assessment of CO2 geological storage in deep saline aquifers. Furthermore, through cooperation with the China Shenhua Coal to Liquid and Chemical Co., Ltd., we successfully constructed the first coal-based demonstration project for CO2 geological storage in deep saline aquifers in the Yijinhuoluo Banner of Ordos in the Inner Mongolia Autonomous Region, which brought about the basic preliminary theories, techniques, and methods of geological CO2 storage in deep saline aquifers under China’s geological conditions.     

CO<Subscript>2</Subscript> source-sink matching in the lower 48 United States,with examples from the Texas Gulf Coast and Permian Basin

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.     

Dissolution sequestration mechanism of CO<Subscript>2</Subscript> at the Shiqianfeng saline aquifer in the Ordos Basin,northwestern China

This study focused on the target injection layers of deep saline aquifers in the Shiqianfeng Fm. in the Carbon Capture and Sequestration (CCS) Demonstration Projects in the Ordos Basin, northwestern China. The study employed a combination method of experiments and numerical simulation to investigate the dissolution mechanism and impact factors of CO₂ in these saline aquifers. The results showed (1) CO₂ solubility in different types of water chemistry were shown in ascending order: MgCl₂-type water < CaCl₂-type water < Na₂SO₄-type water < NaCl-type water < Na₂CO₃-type water < distilled water. These results were consistent with the calculated results undertaken by TOUGHREACT with about 5% margin of error. CO₂ solubility of Shiqianfeng Fm. saline was 1.05 mol/L; (2) compared with distilled water, the more complex the water’s chemical composition, the greater the increase in HCO₃ ^?concentration. While the water’s composition was relatively simple, the tested water’s HCO₃ ^?concentrations were in close accord with the calculated value undertaken by the TOUGHREACT code, and the more complex the water’s composition, the poorer the agreement was, probably due to the complex and unstable HCO₃ ^? complicating matters when in an aqueous solution system including both tested HCO₃ ^?concentration and calculated HCO₃ ^?concentration; (3) the CO₂ solubility in the saline at the temperature conditions of 55 °C and 70 °C were 1.17 and 1.02 mol/L. When compared with the calculated value of 1.20 and 1.05 mol/L, they were almost the same with only 1 and 3% margin of error; concentrations of HCO₃ ^? were 402.73 mg/L (0.007 mol/L) and 385.65 mg/L (0.006 mol/L), while the simulation results were 132.16 mg/L (0.002 mol/L) and 128.52 mg/L (0.002 mol/L). From the contrast between the tested data and the calculated data undertaken by the TOUGHREACT code, it was shown that TOUGHRACT code could better simulate the interaction between saline and CO₂ in the dissolution sequestration capacity. Therefore, TOUGHREACT code could be used for the inter-process prediction of CO₂ long-term geological storage of CO₂; (4) The Ca²⁺ concentration and SO₄ ^2?concentration in saline water had less effect on the solubility of CO₂ and HCO₃ ^?concentration. In addition, TDS and pH values of saline affected not only the solubility of CO₂, but also the conversion of CO₂ to HCO₃ ^? due to that they can affect the activity and acid-base balance. So in fact, we just need to consider that the TDS and pH values are main impact factors in the dissolution sequestration capacity of CO₂ geological sequestration in deep saline aquifers.     

3D seismic analysis of complex faulting patterns above the Snapper Field,Gippsland Basin: implications for CO2 storage

Mechanical damage (e.g. faults and fractures) related to tectonic forces and/or variations in formation pore pressures may enable the leakage of fluids through otherwise effective seal rocks. Characterisation of faults and fractures within seals is therefore essential for the assessment of long-term trap integrity in potential CO₂ storage sites. 3D seismic reflection data are used to describe a previously unrecognised network of extensive, small Miocene-age faults with displacement of generally <30 m and lengths that vary between ～300 and 2500 m above the Snapper Field, in the Gippsland Basin. The Snapper Field is a nearly depleted oil and gas field that presents an attractive site for potential CO₂ storage due its structural closure and because it has effectively retained significant natural hydrocarbon (including CO₂) columns over geological time-scales. Volume-based seismic attributes reveal that this fault system is located within the Oligocene Lakes Entrance Formation of the Seaspray Group, which acts as the regional seal to the Latrobe Group reservoirs in the Gippsland Basin. Detailed analysis of fault lengths and linkages suggests that the Miocene faults are non-tectonic, polygonal faults, although the displacement analysis of fault segments reveals strong correlations with the both the structure of the underlying Top Latrobe surface and normal faults that segment the Latrobe Group reservoirs, suggesting that the development of this fault system has been influenced by underlying structures. The geological evidence for long-term retention of hydrocarbons within the Snapper Field suggests that this fault system has not compromised the integrity of the Lakes Entrance Formation seal, although elevated pore pressures during CO₂ injection could potentially lead to reactivation of these structures.     

Sensitivity study of pulsed neutron-gamma saturation monitoring at the Altmark site in the context of CO2 storage

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

Factors affecting CO2 storage capacity and efficiency with water withdrawal in shallow saline aquifers

Carbon sequestration in shallow aquifers can be facilitated by water withdrawal. The factors that optimize the injection/withdrawal balance to minimize potential environmental impacts have been studied, including reservoir size, well pattern, injection rate, reservoir heterogeneity, anisotropy ratio, and permeability sequence. The effects of these factors on CO₂ storage capacity and efficiency were studied using a compositional simulator Computer Modeling Group-General Equation of State Model, which modeled features including residual gas trapping, CO₂ solubility, and mineralization reactions. Two terms, storage efficiency and CO₂ relative breakthrough time, were introduced to better describe the problem. The simulation results show that simultaneous water withdrawal during CO₂ injection greatly improves CO₂ storage capacity and efficiency. A certain degree of heterogeneity or anisotropy benefits CO₂ storage. A high injection rate favors storage capacity, but reduces the storage efficiency and CO₂ breakthrough time, which in turn limits the total amount of CO₂ injected.     

A survey of oil and gas wells in the Texas Gulf Coast,USA, and implications for geological sequestration of CO<Subscript>2</Subscript>

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