How storage uncertainty will drive CCS infrastructure

Geological sequestration of CO2 is a crucial means of reducing CO2 emissions. China in CO2 sequestration have commenced relatively late, and both site selection criteria and evaluation methods require further refinement. Primary sequestration sites for CO2 include reservoirs, coal seams, and deep saline formations. Among these, reservoirs serve as sequestration sites due to their favorable geological conditions, high degree of exploration, and potential for economic benefits. Currently, China categorizes sequestration sites into five levels: regional, basin, target area, site, and injection. This paper proposes a site selection and evaluation methodology specifically for the injection level. Firstly, a prediction model for the geological sequestration potential of CO2 in reservoirs is established based on machine learning methods. Subsequently, an evaluation index system is constructed based on three categories of indicators: safety, potential, and economy, the evaluation thresholds for potential indicators were determined using a potential evaluation model, while the evaluation thresholds for safety and economic indicators were established through methods such as factor analysis. Finally, a comprehensive evaluation method for the effectiveness of CO2 sequestration in reservoirs is formulated using the Analytic Hierarchy Process (AHP).

Potential CO2 and brine leakage through wellbore pathways for geologic CO2 sequestration using the National Risk Assessment Partnership tools: Application to the Big Sky Regional Partnership

Realistic representation of subsurface heterogeneity is essential to better understand and effectively predict the migration and trapping patterns of carbon dioxide (CO 2 ) during geological carbon sequestration (GCS). Many candidate aquifers for GCS have sedimentary architectures which reflect fluvial deposition, where coarser-grained facies with higher-permeability (e.g., sandstone) are juxtaposed within finer-grained facies with lower-permeability (e.g., shale). Because the subsurface is difficult to access and sample, geostatistical methods are often used to model the spatial distribution of geological facies across different scales. We use a transition-probability based approach to simulate heterogeneous systems with binary facies distributions and the resulting petrophysical properties at the field scale. The approach produces heterogeneity fields which honor observable and physical facies attributes (e.g., volumetric proportions, mean lengths, and juxtapositional tendencies). Further, we use the associated facies-dependent properties for both relative permeability and capillary pressure relations and their hysteretic behavior. Heterogeneous facies models are used to investigate the sensitivity of different trapping mechanisms (i.e., dissolution, residual trapping) as well as CO 2 plume dynamics to variability in (1) the spatial organization and connectivity of sedimentary facies types; (2) aquifer temperature; (3) CO 2 injection period; (4) perforation length; and (5) the level of impurity, represented here as methane (CH 4 ) present in injected CO 2 streams. Model results show that the magnitudes of residual and solubility trapping are reduced by increasing the percentage and degree of connectivity of high-permeability facies. An increase in aquifer temperature leads to a decrease in residual trapping and an increase in solubility trapping. Results also reveal that for a given volume of injected CO 2 , shorter injection times yield higher total amounts of trapped CO 2 . Similarly, wells perforated over a shorter thickness of the aquifer contribute to an increase in both residual and solubility trapping. We also find that increased CH 4 concentrations in the injected CO 2 streams decrease residual trapping while increasing solubility trapping. This effect is more pronounced at shallower depths, where the pressure and temperature of the aquifer are lower. Cited as : Ershadnia, R., Wallace, C.D., Soltanian, M.R. CO 2 geological sequestration in heterogeneous binary media: Effects of geological and operational conditions. Advances in Geo-Energy Research, 2020, 4(4): 392-405, doi: 10.46690/ager.2020.04.05

Subsurface Property Rights: Implications for Geologic CO2 Sequestration

Saturation states dependence of feldspar dissolution rate: Sensitivity to the timescale of geochemical processes on CO2 geological sequestration

Geophysical technologies have been widely utilized and developed in the petroleum exploration and development for risk reduction and value maximization. In these days, for the transition to a carbo nneutral society, CO2 geological sequestration such as Carbon-dioxide Capture and Storage (CCS) is considered as an important component of the CO2 reduction. Geophysical technologies developed in petroleum industries have a great potential to characterize and monitor CCS sites with high precision and fidelity. This paper reviews geophysical methods for CO2 sequestration and introduces the results on the offshore demonstration CCS project in Japan that is dedicated to geologic storage in saline formations.

Gas geochemistry of natural analogues for the studies of geological CO2 sequestration

Deep saline aquifers are potential reservoirs for commercial scale CO2 geologic sequestration (GS) due to their large storage capacity and wide availability. These reservoirs are regional in scale with no conventional stratigraphic or structural traps. The fate of supercritical CO2 injected in saline aquifers depends on hydrodynamics and phase trapping. This paper examines hydrodynamic trapping, and the question of whether basinward flow of groundwater can counteract updip CO2 movement after injection ends, and render the gas immobile. After injection pressure dissipates, the important flow mechanisms are viscous flow of groundwater (imposed by compaction and gravity) and buoyant flow of CO2 (imposed by the density contrast between injected CO2 and the formation fluid). Hydrodynamic trapping theory is reviewed and its application to GS is discussed. The same methods developed for oil and gas can be used to identify possible hydrodynamic traps for pools of CO2 post injection. Examples are given of deep basin aquifer dynamics and regional groundwater flow gradients as they relate to GS. In a dipping aquifer, groundwater flow and buoyant CO2 flow may be in the same direction (immature compacting basin) or the opposite direction (mature basin). The mature basin scenario is optimum for GS, as long-term updip CO2 movement will be reduced by saline aquifer flow. Analytic expressions are used to investigate trapping potential, and to estimate the rate of buoyant CO2 movement after injection ends in a mature basin example with groundwater flow down the dip. Key inputs such as hydraulic gradient, dip, and density contrast were varied to assess their relative influence. The results demonstrate that, post injection, it is possible for pooled CO2 to be hydrodynamically trapped under field conditions. CO2 could also be displaced downdip in aquifers with high hydraulic gradients (~ 0.02) and low dips (~ 0.25 degrees). In the more likely case of a low to average hydraulic gradient (~ 0.0004 to 0.003), and dip greater than ~ 0.25 degrees, buoyancy dominates, and the CO2 is generally displaced in the updip direction at rates of approximately one to one hundred feet per year. This can lead to significant displacement over the long time scales desired for GS. Therefore, in a mature basin, groundwater flow alone will usually be insufficient to counteract buoyancy, and phase trapping or hydrodynamic trapping will be needed to ultimately immobilize the CO2.

The long-term geological sequestration of carbon dioxide (CO2) in underground formations (deep saline aquifers) is the most economically viable option to decrease the emissions of greenhouse gas in the atmosphere which are the main contributing factors for global warming. The injection of CO2 in carbonate aquifers dissolves some of the calcite rock due to the formation of carbonic acid as a result of the interaction between CO2 and brine. This rock dissolution may affect the rock integrity and in turn will affect the rock mechanical properties. The effect of CO2 on the rock mechanical properties is a key parameter to be studied to assess the aquifer performance in the process of geological sequestration and to get safe and effective long-term storage. The main objective of this study is to address the impact of geological sequestration of CO2 on the mechanical properties of carbonate aquifer and cap rocks. In addition, the effect of the storage time on these properties are investigated. Moreover, the effect of CO2 sequestration on rocks with different mechanical properties are studied, and the good candidate carbonate rocks for geologic sequestration are identified. In this study the CO2 was injected and soaked with the brine with the core at high pressure and high temperature (2000 psi and 100°C) to simulate the actual downhole conditions The carbonate cores were analyzed for mechanical properties using indirect tensile strength, unconfined compression, and acoustics testing machines. Results show that CO2 sequestration affected the mechanical properties of the carbonate rocks as well as the cap rocks. Long time soaking of CO2 in brine allowed for the formation of enough carbonic acid to react with the cores and this greatly impacted the rock mechanical and acoustic properties. The significant impact of CO2 storage was noted on Khuff limestone and the good candidate among the carbonate rocks studied here for geological sequestration of CO2 is found to be Indiana limestone.

Acetate is one of the most abundant organic compounds in many formation waters and is likely to be present in deep saline aquifers suitable for geologic CO2 sequestration (GCS). This work studied the effect of initially present acetate on the dissolution of anorthite (CaAl2Si2O8) and on subsequent secondary mineral precipitation under GCS conditions (35 °C and 74.8 atm). Anorthite was chosen as a model mineral because of the abundance of feldspar in clayey sandstones and the possibility of metal carbonation. In this study, acetate was found to decrease the cumulative aqueous concentrations of Al, Si, and Ca upon CO2 injection by inhibiting anorthite dissolution and increasing the amount of secondary mineral precipitates. The extent of the effect of acetate on metal concentration changes was element-specific (Al > Si > Ca), and the effect was found to be more significant in systems with lower salinity and lower pH. For anorthite dissolution, acetic acid inhibited the proton-mediated decomposition of the Al/Si-containing feldspar framework, while acetate anions may have facilitated the ion-exchange between interstitial Ca and aqueous cations. For secondary mineral precipitation, stoichiometry analysis of aqueous metal concentrations suggested the formation of Al-containing mineral(s). The presence of kaolinite as a secondary mineral was confirmed using high resolution transmission electron microscopy's electron diffraction data. An increase in the relative amount of precipitation due to the initial presence of acetate was suggested by mass balancing and verified on the cleaved anorthite surfaces by atomic force microscopy analysis. These results provide new insights for understanding and predicting GCS system evolution upon scCO2 injection in the initial presence of acetate.

CO2 injection strategies for enhanced oil recovery and geological sequestration in a tight reservoir: An experimental study

A critical component in the assessment of long-term risk from geologic sequestration of CO2 is the ability to predict mineralogical and geochemical changes within storage reservoirs due to rock-brine-CO2 reactions. Impurities and/or other constituents selected for co-sequestration can affect both the chemical and physical (e.g. density, viscosity, interfacial tension) behavior of CO2 in the deep subsurface. These impurities and concentrations are a function of both the industrial source(s) of the CO2, as well as the carbon capture technology used to extract the CO2 and produce a concentrated stream for geologic sequestration. This report summarizes the relative concentrations of CO2 and other constituents in exhaust gases from major non-energy related industrial sources of CO2. Assuming that carbon-capture technology would remove most of the incondensable gases N2, O2, and Ar, leaving SO2 and NOx as the main impurities, we selected four test fluid compositions for use in geochemical experiments. These included: 1) a pure CO2 stream representative of food grade CO2 used in most enhanced oil recovery projects: 2) a test fluid composition containing low concentrations (0.5 mole %) SO2 and NOx (representative of that generated from cement production), 3) a test fluid composition with higher concentrations (2.5 mole %) of SO2, and 4) and test fluid composition containing 3 mole % H2S.

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.

Thermochemistry of two calcium silicate carbonate minerals: scawtite, Ca7(Si6O18)(CO3)·2H2O, and spurrite, Ca5(SiO4)2(CO3)

API Class-G Portland cement commonly put in as zonal isolation material in oil and/or gas well. Corrosion against the well zonal isolation material could lead to potential leakage of formation fluid such oil, gas, or water. It is widely known that ordinary Portland cement is thermodinamically unstable in CO2 rich environment, which can be found in the CO2 geological sequestration. CO2 attack on API Class-G cement had been observed through experiments that simulate the down hole condition of Geological Sequestration of CO2. Some of the experiment reveal the detrimental effect of CO2 such as increase of porosity and permeability of cement sheath corroded by CO2 attack. The degradation of API Class-G cement by CO2 involves emergence and crystallization of CaCO3 from Ca(OH)2 which is formed during hydration of cement. In this experiment, we examine the role of addition of MgO swelling cement by weight fraction to mitigate the corrosion caused by CO2 against downhole hardened API Class-G cement thus inhibits the occurrence of leakage path of CO2. Observation for characterization and analysis by XRD, optical microscope, and cement paste uniaxial volumetric expansion presented in this paper. The conclusion will provide insights into design of carbonation resistant cement slurries using swelling cements admixtures.