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.     

Impact of multi-purpose aquifer utilisation on a variable-density groundwater flow system in the Gippsland Basin, Australia

The Latrobe aquifer in the Gippsland Basin in southeastern Australia is a prime example for emerging resource conflicts in Australian sedimentary basins. The Latrobe Group forms a major freshwater aquifer in the onshore Gippsland Basin, and is an important reservoir for oil and gas in both onshore and offshore parts of the basin. The Latrobe Group and overlying formations contain substantial coal resources that are being mined in the onshore part of the basin. These may have coal-seam-gas potential and, in addition, the basin is considered prospective for its geothermal energy and CO₂ storage potential. The impacts of groundwater extraction related to coal-mine dewatering, public water supply, and petroleum production on the flow of variable-density formation water has been assessed using freshwater hydraulic heads and impelling force vectors. Groundwater flows from the northern and western edges towards the central part of the basin. Groundwater discharge occurs mainly offshore along the southern margin. Post-stress hydraulic heads show significant declines near the petroleum fields and in the coal mining areas. A hydrodynamic model of the Latrobe aquifer was used to simulate groundwater recovery in the Latrobe aquifer from different scenarios of cessation of groundwater and other fluid extractions.     

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.     

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.     

Water–rock–CO2 interactions in saline aquifers aimed for carbon dioxide storage: Experimental and numerical modeling studies of the Rio Bonito Formation (Permian), southern Brazil

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

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.     

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.     

四川盆地理论CO_2地质利用与封存潜力评估

结合CO_2地质利用与封存技术机理,在国际权威潜力评估公式的基础上,系统地提出了适合中国地质背景的次盆地尺度CO_2封存潜力评估方法及关键参数取值。同时,以四川盆地为例,依次开展了枯竭油田地质封存与CO_2强化石油开采、枯竭气田与CO_2强化采气、不可采煤层地质封存与CO_2驱替煤层气,以及咸水层地质封存技术的CO_2地质封存潜力。结果表明,四川盆地利用深部咸水层与枯竭天然气田CO_2地质封存潜力最大,期望值分别达154.20×10~8t和53.73×10~8t。其中,枯竭天然气田因成藏条件好、勘探程度高、基础建设完善,为四川盆地及其周边利用枯竭气田CO_2地质封存技术实现低碳减排提供了早期示范机会。CO_2地质利用与封存潜力评估方法,对进一步开展全国次盆地尺度理论封存潜力评估与工程规划具有重要意义。     

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.     

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.     

A sensitivity analysis of factors affecting in geologic CO2 storage in the Ordos Basin and its contribution to carbon neutrality

To accelerate the achievement of China’s carbon neutrality goal and to study the factors affecting the geologic CO₂ storage in the Ordos Basin, China’s National Key R&D Programs propose to select the Chang 6 oil reservoir of the Yanchang Formation in the Ordos Basin as the target reservoir to conduct the geologic carbon capture and storage (CCS) of 100000 t per year. By applying the basic theories of disciplines such as seepage mechanics, multiphase fluid mechanics, and computational fluid mechanics and quantifying the amounts of CO₂ captured in gas and dissolved forms, this study investigated the effects of seven factors that influence the CO₂ storage capacity of reservoirs, namely reservoir porosity, horizontal permeability, temperature, formation stress, the ratio of vertical to horizontal permeability, capillary pressure, and residual gas saturation. The results show that the sensitivity of the factors affecting the gas capture capacity of CO₂ decreases in the order of formation stress, temperature, residual gas saturation, horizontal permeability, and porosity. Meanwhile, the sensitivity of the factors affecting the dissolution capture capacity of CO₂ decreases in the order of formation stress, residual gas saturation, temperature, horizontal permeability, and porosity. The sensitivity of the influencing factors can serve as the basis for carrying out a reasonable assessment of sites for future CO₂ storage areas and for optimizing the design of existing CO₂ storage areas. The sensitivity analysis of the influencing factors will provide basic data and technical support for implementing geologic CO₂ storage and will assist in improving geologic CO₂ storage technologies to achieve China’s carbon neutralization goal.©2022 China Geology Editorial Office.     

Interpretation of carbon dioxide diffusion behavior in coals

Storage of carbon dioxide in geological formations is for many countries one of the options to reduce greenhouse gas emissions and thus to satisfy the Kyoto agreements. The CO₂ storage in unminable coal seams has the advantage that it stores CO₂ emissions from industrial processes and can be used to enhance coalbed methane recovery (CO₂-ECBM). For this purpose, the storage capacity of coal is an important reservoir parameter. While the amount of CO₂ sorption data on various natural coals has increased in recent years, only few measurements have been performed to estimate the rate of CO₂ sorption under reservoir conditions. An understanding of gas transport is crucial for processes associated with CO₂ injection, storage and enhanced coalbed methane (ECBM) production.A volumetric experimental set-up has been used to determine the rate of sorption of carbon dioxide in coal particles at various pressures and various grain size fractions. The pressure history during each pressure step was measured. The measurements are interpreted in terms of temperature relaxation and transport/sorption processes within the coal particles. The characteristic times of sorption increase with increasing pressure. No clear dependence of the characteristic time with respect to the particle size was found. At low pressures (below 1 MPa) fast gas diffusion is the prevailing mechanism for sorption, whereas at higher pressures, the slow diffusion process controls the gas uptake by the coal.     

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.     

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.     

Uncertainties of geochemical modeling during CO<Subscript>2</Subscript> sequestration applying batch equilibrium calculations

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

Effects of in-situ conditions on relative permeability characteristics of CO2-brine systems

Carbon dioxide capture and geological storage (CCGS) is an emerging technology that is increasingly being considered for reducing greenhouse gas emissions to the atmosphere. Deep saline aquifers provide a very large capacity for CO₂ storage and, unlike hydrocarbon reservoirs and coal beds, are immediately accessible and are found in all sedimentary basins. Proper understanding of the displacement character of CO₂-brine systems at in-situ conditions is essential in ascertaining CO₂ injectivity, migration and trapping in the pore space as a residual gas or supercritical fluid, and in assessing the suitability and safety of prospective CO₂ storage sites. Because of lack of published data, the authors conducted a program of measuring the relative permeability and other displacement characteristics of CO₂-brine systems for sandstone, carbonate and shale formations in central Alberta in western Canada. The tested formations are representative of the in-situ characteristics of deep saline aquifers in compacted on-shore North American sedimentary basins. The results show that the capillary pressure, interfacial tension, relative permeability and other displacements characteristics of CO₂-brine systems depend on the in-situ conditions of pressure, temperature and water salinity, and on the pore size distribution of the sedimentary rock. This paper presents a synthesis and interpretation of the results.     

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.     

Increased hydrocarbon recovery and CO2 storage in Neogene sandstones,a Croatian example: part II

During 2003–2006, a pilot project of alternating water and CO₂ injection was performed on a limited part of the Upper Miocene sandstone oil reservoir of the Ivani? Field. During the test period oil and gas recovery was significantly increased. Additionally 4,440 m³ of oil and 2.26 × 10⁶ m³ of gas were produced. It has initiated further modelling of sandstone reservoirs in the Ivani? Field in order to calculate volumes available for CO₂ injection for the purpose of increasing hydrocarbon production from depleted sandstone reservoirs in the entire Croatian part of the Pannonian Basin System. In the first phase, modelling was based on results of laboratory testing on the core samples. It considered applying analogies with world-known projects of CO₂ subsurface storage and its usage to enhance hydrocarbon production. In the second phase, reservoir variables were analysed by variograms and subsequently mapped in order to reach lithological heterogeneities and to determine reliable average values of reservoir volumes. Data on porosity, depth and reservoir thickness for the “Gamma 3” and the “Gamma 4” reservoirs, are mapped by the ordinary kriging technique. Calculated volume of CO₂ expressed at standard condition which can be injected in the main reservoirs of the Ivani? Field at near miscible conditions is above 15.5 billion m³.     

Reactive transport simulation study of geochemical CO2 trapping on the Tokyo Bay model – With focus on the behavior of dawsonite

A long-term (up to 10 ka) geochemical change in saline aquifer CO₂ storage was studied using the TOUGHREACT simulator, on a 2-dimensional, 2-layered model representing the underground geologic and hydrogeologic conditions of the Tokyo Bay area that is one of the areas of the largest CO₂ emissions in the world. In the storage system characterized by low permeability of reservoir and cap rock, the dominant storage mechanism is found to be solubility trapping that includes the dissolution and dissociation of injected CO₂ in the aqueous phase followed by geochemical reactions to dissolve minerals in the rocks. The CO₂–water–rock interaction in the storage system (mainly in the reservoir) changes the properties of water in a mushroom-like CO₂ plume, which eventually leads to convective mixing driven by gravitational instability. The geochemically evolved aqueous phase precipitates carbonates in the plume front due to a local rise in pH with mixing of unaffected reservoir water. The carbonate precipitation occurs extensively within the plume after the end of its enlargement, fixing injected CO₂ in a long, geologic period.Dawsonite, a Na–Al carbonate, is initially formed throughout the plume from consumption of plagioclase in the reservoir rock, but is found to be a transient phase finally disappearing from most of the CO₂-affected part of the system. The mineral is unstable relative to more common types of carbonates in the geochemical evolution of the CO₂ storage system initially having formation water of relatively low salinity. The exception is the reservoir-cap rock boundary where CO₂ saturation remains very high throughout the simulation period.