Investigating CO<Subscript>2</Subscript>-enhanced oil recovery potential for a mature oil field: a case study based on Ankleshwar oil field,Cambay Basin,India

CO₂-enhanced oil recovery (EOR) is an upcoming technology in India. At present, no Indian field is under CO₂-EOR and implementation of this technique to a mature oil field needs a rigorous study. In the present work, we made an attempt to investigate the CO₂-EOR potential of a mature oil field, situated in Cambay Basin, India. The field was put on production in 1961, and it has produced approximately 65.36 MMt oil during massive water flooding, leading to residual oil reserves of 6.49 MMt. The operator of the field is interested in incremental oil recovery from this field by injecting CO₂. This requires estimation of incremental oil recovery potential of the field by carrying out systematic study. We, therefore, developed a conceptual model inspired by Ankleshwar oil field of Cambay Basin using available information provided by the field operator and carried out systematic studies to establish an optimized strategy for CO₂ injection. To achieve this goal, we investigated the effect of various operational parameters on oil recovery efficiency of our conceptual model and selected optimum parameters for reservoir simulations. Simulation results clearly indicate that the field can be a good candidate for CO₂-EOR, and an additional oil recovery of 10.4% of hydrocarbon pore volume is feasible. Major outcome of the study is an optimized black-oil simulation model, which is in good agreement with the fine grid compositional model of high accuracy. The proposed black-oil model can easily be implemented and updated compared with compute intensive finer compositional simulation model.     

Quick-look assessments to identify optimal CO2 EOR storage sites

A newly developed, multistage quick-look methodology allows for the efficient screening of an unmanageably large number of reservoirs to generate a workable set of sites that closely match the requirements for optimal CO₂ enhanced oil recovery (EOR) storage. The objective of the study is to quickly identify miscible CO₂ EOR candidates in areas that contain thousands of reservoirs and to estimate additional oil recovery and sequestration capacities of selected top options through dimensionless modeling and reservoir characterization. Quick-look assessments indicate that the CO₂ EOR resource potential along the US Gulf Coast is 4.7 billion barrels, and CO₂ sequestration capacity is 2.6 billion metric tons. In the first stage, oil reservoirs are screened and ranked in terms of technical and practical feasibility for miscible CO₂ EOR. The second stage provides quick estimates of CO₂ EOR potential and sequestration capacities. In the third stage, a dimensionless group model is applied to a selected set of sites to improve the estimates of oil recovery and storage potential using appropriate inputs for rock and fluid properties, disregarding reservoir architecture and sweep design. The fourth stage validates and refines the results by simulating flow in a model that describes the internal architecture and fluid distribution in the reservoir. The stated approach both saves time and allows more resources to be applied to the best candidate sites.     

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.     

Physical and chemical characteristics of potential seal strata in regions considered for demonstrating geological saline CO<Subscript>2</Subscript> sequestration

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.     

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.     

Optimal aquifers and reservoirs for CCS and EOR in the Kingdom of Saudi Arabia: an overview

An overview on the tectono-stratigraphic framework of the Arabian plate indicates obvious differences between two distinct areas: the hydrocarbon-prolific sector and non-hydrocarbon-prolific sector. These differences resulted from the interplay of a variety of factors; some of which are related to the paleo-geographic configuration (eustatic sea level fluctuations, climatic conditions, and salt Basins), others to differential subsidence (burial) and structural inversions. During the Paleozoic, the regional compression was caused by far field effects of the Hercynian orogeny. This led to major folded structures in central and eastern Saudi Arabia (e.g. Ghawar anticline). During the Mesozoic, the most important tectonic factor was the stretching of the crust (extension), accompanied with the increase in temperature, resulting in an increase of the accommodation space, and thicker sedimentary successions. Regional unconformities are mostly found where folded structures are dominant, and they acted as a carrier systems for the accumulation of hydrocarbon and groundwater. A good understanding of the stratigraphy and tectonic evolution is, thus, required to develop carbon capture and storage (CCS) and to design efficiently enhanced oil recovery (EOR) in both sectors. Oil and gas reservoirs offer geologic storage potential as well as the economic opportunity of better production through CO₂-EOR. The world greatest hydrocarbon reservoirs mainly consist of Jurassic carbonate rocks, and are located around the Arabian Basin (including the eastern KSA and the Arabian Gulf). The Cretaceous reservoirs, which mainly consist of calcarenite and dolomite, are located around the Gotnia salt Basin (northeast of KSA). Depleted oil and gas fields, which generally have proven as geologic traps, reservoirs and seals, are ideal sites for storage of injected CO₂. Each potential site for CO₂-EOR or CCS should be evaluated for its potential storage with respect to the containment properties, and to ensure that conditions for safe and effective long term storage are present. The secured deep underground storage of CO₂ implies appropriate geologic rock formations with suitable reservoir rocks, traps, and impermeable caprocks. Proposed targets for CCS, in the non-hydrocarbon-prolific sector, are Kharij super-aquifer (Triassic), Az-Zulfi aquifer (Middle Jurassic), Layla aquifer (Late Jurassic), and Wasia aquifer (Middle Cretaceous). Proposed targets for EOR are Safaniya oil field (Middle Cretaceous) (Safaniya, Wara and Khafji reservoirs), Manifa oil field (Las, Safaniya and Khafji reservoirs) (Late Jurassic), and Khuff reservoir (Late Permian-Early Triassic) in central to eastern KSA.     

Pressure transient technique to constrain CO<Subscript>2</Subscript> plume boundaries

Carbon dioxide (CO₂) has been injected in the subsurface permeable formations as a means to cut atmospheric CO₂ emissions and/or enhance oil recovery (EOR). It is important to constrain the boundaries of the CO₂ plume in the target formation and/or other formations hosting the CO₂ migrated from the target formation. Monitoring methods and technologies to assess the CO₂ plume boundaries over time within a reservoir of interest are required. Previously introduced methods and technologies on pressure monitoring to detect the extent of the CO₂ plume require at least two wells, i.e. pulser and observation wells. We introduce pressure transient technique requiring single well only. Single well pressure transient testing (drawdown/buildup/injection/falloff) is widely used to determine reservoir properties and wellbore conditions. Pressure diagnostic plots are used to identify different flow regimes and determine the reservoir/well characteristics. We propose a method to determine the plume extent for a constant rate pressure transient test at a single well outside the CO₂ plume. Due to the significant contrast between mobility and storativity of the CO₂ and native fluids (oil or brine), the CO₂ boundary causes deviation in the pressure diagnostic response from that corresponding to previously identified heterogeneities. Using the superposition principle, we develop a relationship between the deviation time and the plume boundary. We demonstrate the applicability of the proposed method using numerically generated synthetic data corresponding to homogeneous, heterogeneous, and anisotropic cases to evaluate its potential and limitations. We discuss ways to identify and overcome the potential limitations for application of the method in the field.     

Experimental identification of CO2–oil–brine–rock interactions: Implications for CO2 sequestration after termination of a CO2-EOR project

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.     

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.     

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.     

Rate measurements and detection of gas microseepage to the atmosphere from an enhanced oil recovery/sequestration project,Rangely, Colorado,USA

One of the proposals for large-scale sequestration of fossil fuel-derived CO₂ is deep geologic disposal in depleted oil/gas reservoirs or deep aquifers. Previously published scenarios for this inadequately proven technology have either ignored or dismissed the possibility of vertical migration of gases caused by overpressure. Overpressuring of a reservoir or aquifer will be necessary in order to have acceptable rates for dispersal of injected CO₂. This research describes methodology and the results of measurement of microseepage of CO₂ and CH₄ at a large-scale CO₂-enhanced oil recovery (EOR) operation at Rangely, Colorado, USA. Shallow and deep soil gas concentrations, and direct transport of CO₂ and CH₄ into the atmosphere were measured. The interpretation of the measurements was complemented by both stable and radiogenic isotopic measurements of C. The results have demonstrated an estimated microseepage to the atmosphere of approximately 400 metric tonnes of CH₄/a from the 78 km² area of the Rangely field. Preliminary estimates of deep-sourced CO₂ losses are <3800 tonnes/a, based on stable isotope measurements of soil gases. Several holes up to 10 m deep were drilled on, and off the field for nested gas sampling of composition and stable C isotopic ratios for CO₂ and CH₄. Carbon-14 measurements on CO₂ from these holes indicate that deep-sourced CO₂ microseepage losses were approximately 170 tonnes/a.     

Computer modeling of methanotrophic oxidation of hydrocarbons in the unsaturated zone from an enhanced oil recovery/sequestration project, Rangely, Colorado, USA

One of the proposals for large-scale sequestration of fossil fuel-derived CO₂ is deep geologic disposal in depleted oil/gas reservoirs or deep aquifers. Previously published scenarios for this inadequately proven technology have either ignored or dismissed the possibility of vertical migration of gases caused by overpressure. Overpressuring of a reservoir or aquifer will be necessary in order to have acceptable rates for dispersal of injected CO₂. This research describes methodology and the results of measurement of microseepage of CO₂ and CH₄ at a large-scale CO₂-enhanced oil recovery (EOR) operation at Rangely, Colorado, USA. Shallow and deep soil gas concentrations, and direct transport of CO₂ and CH₄ into the atmosphere were measured. The interpretation of the measurements was complemented by both stable and radiogenic isotopic measurements of C. The results have demonstrated an estimated microseepage to the atmosphere of approximately 400 metric tonnes of CH₄/a from the 78 km² area of the Rangely field. Preliminary estimates of deep-sourced CO₂ losses are <3800 tonnes/a, based on stable isotope measurements of soil gases. Several holes up to 10 m deep were drilled on, and off the field for nested gas sampling of composition and stable C isotopic ratios for CO₂ and CH₄. Carbon-14 measurements on CO₂ from these holes indicate that deep-sourced CO₂ microseepage losses were approximately 170 tonnes/a.     

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.     

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.     

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.     

Geologic and infrastructure factors for delineating areas for clean coal: examples in Texas, USA

Texas has a wide variety of areas that can be targeted for new clean-coal facilities. These areas are delineated by mapping spatial linkages between coal- and lignite-bearing formations, groundwater and surface-water resources, and CO₂ sinks in brine formations for long-term CO₂ storage or in mature oil fields with potential for enhanced oil recovery (EOR). However, a variety of infrastructure factors make it feasible to also target numerous areas outside coal and lignite basins in Texas. These infrastructure factors include pipelines for delivery of CO₂ to subsurface sinks and delivery of coal-produced hydrogen to refineries, ease of connection to existing transmission lines, distribution of nonattainment areas where new clean-coal facilities could be constructed and be compliant with strict air-quality standards, and railroads that can transport coal and other feedstock to new clean-coal facilities. Primary regions in Texas where favorably co-located CO₂ source-sink factors related to coal and lignite trends include the Gulf Coast, the Eastern Shelf of the Permian Basin, and the Fort Worth Basin. However, areas outside coal and lignite basins, particularly the Permian Basin where a new clean-coal facility is being planned, also have clean-coal potential because of existing CO₂ pipelines and proximity to EOR fields that can economically sustain new clean-coal facilities.     

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.     

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.     

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.     

Role of Geomechanics in Assessing the Feasibility of CO2 Sequestration in Depleted Hydrocarbon Sandstone Reservoirs

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