Potential Chemical Impacts of Subsurface CO<sub>2</sub>: An Integrated Experimental and Numerical Assessment for a Case Study of the Ogallala Aquifer

Xiao, Ting; Jia, Wei; Esser, Richard; Dai, Zhenxue; McPherson, Brian

doi:10.1029/2020wr029274

Cited by 7 publications

(5 citation statements)

References 60 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…Like petroleum, the formation water and immiscible CO 2 gas also seems to be well confined within the Morrow B, as no evidence of significant seepage of Morrow B formation water into overlying stratigraphic units has been found through elevated CO 2 concentrations in the formation water of those units. 41,52,59,75 The risk of CO 2 migration into overlying strata is also reduced by the fact that gaseous CO 2 , the most mobile phase of CO 2 , is also the least abundant form of CO 2 in amounts 100's to 1000's of times less than the CO 2 that is dissolved in oil and water. 2 sequestration in the Morrow B is further helped by the fact that the amount of CO 2 stored as carbonate minerals, the most stable and secure mode of CO 2 sequestration, increases over time in the model simulations.…”

Section: Discussionmentioning

confidence: 99%

“…The second largest sink for the injected CO 2 is the Morrow B formation water. Like petroleum, the formation water and immiscible CO 2 gas also seems to be well confined within the Morrow B, as no evidence of significant seepage of Morrow B formation water into overlying stratigraphic units has been found through elevated CO 2 concentrations in the formation water of those units 41,52,59,75 . The risk of CO 2 migration into overlying strata is also reduced by the fact that gaseous CO 2 , the most mobile phase of CO 2 , is also the least abundant form of CO 2 in amounts 100's to 1000's of times less than the CO 2 that is dissolved in oil and water.…”

Section: Discussionmentioning

confidence: 99%

“…The injected CO 2 was originally derived from two major point source emitters, the Agrium fertilizer plant in northern Texas and the Arkalon ethanol plant in southwestern Kansas, 20 though since 2018 the CO 2 has only come from the Arkalon ethanol plant 21,22 . The southwest regional partnership on carbon sequestration (SWP), sponsored by the US Department of Energy (DOE), began a study on the FWU in 2012 involving laboratory experiments of CO 2 injection and transport, 23,24 characterization of the FWU pore fluids and geology, 25–29 numerical modeling of reservoir evolution resulting from CO 2 injection, 23,26,30–50 tracer studies, 41,51,52 and risk assessment and site monitoring 40,41,52–59 . Despite the extensive previous study, important knowledge gaps remain, especially with respect to larger‐scale chemical effects of the CO 2 injection beyond the vicinity of the injection and production wells.…”

Section: Introductionmentioning

confidence: 99%

See 2 more Smart Citations

Field‐scale reactive transport assessment of CO₂ storage in the Farnsworth unit through enhanced oil recovery practices

et al. 2023

View full text Add to dashboard Cite

The objective of this study was to investigate the transport and fate of CO2 injected into a sandstone reservoir in the western Farnsworth Unit, a hydrocarbon field in northern Texas. The study employed three‐dimensional multifluid‐phase numerical reactive solute and heat transport modeling. Model inputs were obtained from previous field characterization studies and calibrated to 8 years of historical production data. The CO2 in the models was injected through multiple wells for the first 25 years of the simulations according to a water‐alternating gas schedule. The simulations were carried out for a total of 1000 years in order to study the long‐term effects of CO2 injection. The results show that the largest fraction of the injected CO2 is stored in oil, followed by successively smaller amounts in the formation water, carbonate mineral phases, and as an immiscible gas phase. The small fraction of CO2 present as an immiscible gas, the most mobile phase for CO2, aids in the long‐term sequestration security of the injected CO2. The injected CO2 was found to migrate within a maximum radius of around 500 m of the injection wells. This means that changes in fluid pressure, temperature, composition, and reservoir mineralogy were also limited to occurring within this radius. This radius is very sensitive to model relative permeability and capillary pressure values, which were determined from history matching to the field production data. The models predicted dolomite to be the main mineral sink for the injected CO2. Quartz was another mineral predicted to precipitate, whereas calcite, albite, chlorite, illite, and kaolinite were predicted to dissolve. The changes in mineral abundance had minimal effect on porosity, implying that the permeability of the reservoir should also not change much because of CO2 injection. © 2023 Society of Chemical Industry and John Wiley & Sons, Ltd.

show abstract

Section: Discussionmentioning

confidence: 99%

Section: Discussionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

See 1 more Smart Citation

Field‐scale reactive transport assessment of CO₂ storage in the Farnsworth unit through enhanced oil recovery practices

et al. 2023

View full text Add to dashboard Cite

show abstract

“…At present, a large number of experimental and simulation studies on CO 2 /brine two-phase flow have been conducted. − Pore structure is one of the main factors, affecting flow behavior in porous media . CO 2 displacement of brine in real cores is carried out by the conventional high-temperature-high-pressure experimental system to study the effects of temperature, pressure, injection flow rate, and salinity of brine on the permeability and displacement efficiency. − However, the understanding of the transport mechanism is limited by the difficulty of monitoring fluid flow in opaque media .…”

Section: Introductionmentioning

confidence: 99%

Parameters Variation and Flow Characteristics When CO₂ Displacing Brine in Four Micromodels Simulating Carbon Sequestration in Saline Aquifers

et al. 2023

View full text Add to dashboard Cite

Two-phase flow of CO2/brine in porous media is critical to the capacity and safety of carbon sequestration into the brine aquifer. In order to provide valuable information and important theoretical basis for site selection and CO2 injection, the microscopic visualization technology was employed in this study to conduct displacement experiments of CO2/brine at the pore scale. Four micromodels with different sizes and structures, five injection rates of CO2, and six salinities of brine were used to study the effects of micromodel’s structure and displacement pattern on two-phase flow. Several parameters including the differential pressure, contact angle, permeability, velocity field, and force field were obtained by experimental measurement, image post-processing, and theoretical analysis, and then, these parameters’ variation was investigated. Phenomena such as thin film, corner flow, and Haines jump were also found during the displacement. Although brine could be completely displaced by CO2 in the capillary duct, the backflow of the wetting phase would occur at a low injection rate. Phenomena different from the theoretical analysis also occurred in pore doublet models: some brine was residual in the homogeneous pore doublet model at a low injection rate, while the heterogeneous pore doublet model was fully occupied by CO2 at a high injection rate. These phenomena are very useful for two-phase flow, and multiple factors need to be comprehensively considered to determine the operating conditions of CO2 storage into the brine aquifer.

show abstract

“…Moreover, CO 2 –rock geochemical reactions have been reported to contribute to the dissolution and precipitation of rock minerals that affect the CGS process. − When the injected CO 2 dissolves into formation brine and then acidifies (i.e., carbonated water), the CO 2 -dissolved water could then expose to and react with rock minerals, and hence, the rock pore size ( R ) changed accordingly . Following eqs –, CO 2 dissolution results in carbonic acid (H 2 CO 3 ), which further decomposes to be bicarbonate (HCO 3 – ) and carbonate (CO 3 2– ) ions…”

Section: Introductionmentioning

confidence: 99%

Relative CO₂Column Height for CO₂Geological Storage: A Non-Negligible Contribution from Reservoir Rock Characteristics

et al. 2022

View full text Add to dashboard Cite

As one of the solutions to tackle climate change caused by excess carbon dioxide (CO2) emission, CO2 geological storage has been increasingly implemented globally to store CO2 securely and permanently in the subsurface. In the current study, structural trapping, which shows the potential of initial CO2 containment and integrity of the subsurface structure, is experimentally investigated with CO2 leakage assessed. CO2 containment is quantified by CO2 column height, which describes the amount of CO2 accumulated in the formation underneath seal rock and is controlled by a balance between capillary and gravitational forces acting on formation brine and invading CO2. While previous studies considered only contributions from seal rock (i.e., “nonrelative”), the current study examines a concurrent contribution from reservoir rock as a seal–reservoir “relative” column height since CO2 storage as an analogy to petroleum reservoir is a structural trap consisting of the reservoir and impermeable seal covered. A distinctive discrepancy was found between the resultant relative and nonrelative column heights. The nonrelative column heights were positive (∼3000 m), implying a high potential for CO2 storage. On the contrary, with reservoir rock contribution considered, the relative column heights were negative (∼−1800 m), suggesting CO2 leakage through the structural trap. This was attributed to a relatively larger reservoir pore size (5.72 nm) than that of seal rock (4.04 nm). Hence, the contribution from reservoir rock characteristics is non-negligible when analyzing CO2 storage potential. Owing to CO2 dissolution in formation brine, CO2-induced effects including a geochemical reaction between acidic carbonated brine and rocks were also investigated. Rock dissolutions in both seal (claystone) and reservoir (limestone) rocks were observed with changes in the pore size, leading to lower storage potential. Further attempts to improve the column height were made by hydrophobizing seal rock via surfactant adsorption, although the changes were slight and could only facilitate a possible leakage (less negative height column).

show abstract

Potential Chemical Impacts of Subsurface CO₂: An Integrated Experimental and Numerical Assessment for a Case Study of the Ogallala Aquifer

Abstract: Geologic carbon dioxide sequestration (GCS) is considered a promising approach for mitigating CO 2 emissions from centralized (point) sources (

Cited by 7 publications

References 60 publications

Field‐scale reactive transport assessment of CO₂ storage in the Farnsworth unit through enhanced oil recovery practices

Field‐scale reactive transport assessment of CO₂ storage in the Farnsworth unit through enhanced oil recovery practices

Parameters Variation and Flow Characteristics When CO₂ Displacing Brine in Four Micromodels Simulating Carbon Sequestration in Saline Aquifers

Relative CO₂Column Height for CO₂Geological Storage: A Non-Negligible Contribution from Reservoir Rock Characteristics

Contact Info

Product

Resources

About

Potential Chemical Impacts of Subsurface CO2: An Integrated Experimental and Numerical Assessment for a Case Study of the Ogallala Aquifer

Abstract: Geologic carbon dioxide sequestration (GCS) is considered a promising approach for mitigating CO 2 emissions from centralized (point) sources (

Cited by 7 publications

References 60 publications

Field‐scale reactive transport assessment of CO2 storage in the Farnsworth unit through enhanced oil recovery practices

Field‐scale reactive transport assessment of CO2 storage in the Farnsworth unit through enhanced oil recovery practices

Parameters Variation and Flow Characteristics When CO2 Displacing Brine in Four Micromodels Simulating Carbon Sequestration in Saline Aquifers

Relative CO2Column Height for CO2Geological Storage: A Non-Negligible Contribution from Reservoir Rock Characteristics

Contact Info

Product

Resources

About

Potential Chemical Impacts of Subsurface CO₂: An Integrated Experimental and Numerical Assessment for a Case Study of the Ogallala Aquifer

Field‐scale reactive transport assessment of CO₂ storage in the Farnsworth unit through enhanced oil recovery practices

Field‐scale reactive transport assessment of CO₂ storage in the Farnsworth unit through enhanced oil recovery practices

Parameters Variation and Flow Characteristics When CO₂ Displacing Brine in Four Micromodels Simulating Carbon Sequestration in Saline Aquifers

Relative CO₂Column Height for CO₂Geological Storage: A Non-Negligible Contribution from Reservoir Rock Characteristics