This study reports the cradle-to-wheel life cycle greenhouse gas (GHG) emissions resulting from enhanced oil recovery (EOR) using CO2 sourced from direct air capture (DAC). A Monte Carlo simulation model representing variability in technology, location, and supply chain is used to model the possible range of carbon intensities (CI) of oil produced through DAC-EOR. Crude oil produced through DAC-EOR is expected to have a CI of 449 tCO2/mbbl. With 95% confidence, the CI is between 345 tCO2/mbbl to 553 tCO2/mbbl. Producing net-zero GHG emission oil through DAC-EOR is thus highly improbable. An example case of DAC-EOR in the U.S. Permian Basin shows that only in the unlikely instance of the most storage efficient sites using 100% renewable energy does DAC-EOR result in “carbon-negative” oil production.
{"title":"Putting the genie back in the bottle: Decarbonizing petroleum with direct air capture and enhanced oil recovery","authors":"Jayant Singh , Udayan Singh , Gonzalo Rodriguez Garcia , Vikram Vishal , Robert Anex","doi":"10.1016/j.ijggc.2024.104281","DOIUrl":"10.1016/j.ijggc.2024.104281","url":null,"abstract":"<div><div>This study reports the cradle-to-wheel life cycle greenhouse gas (GHG) emissions resulting from enhanced oil recovery (EOR) using CO<sub>2</sub> sourced from direct air capture (DAC). A Monte Carlo simulation model representing variability in technology, location, and supply chain is used to model the possible range of carbon intensities (CI) of oil produced through DAC-EOR. Crude oil produced through DAC-EOR is expected to have a CI of 449 tCO<sub>2</sub>/mbbl. With 95% confidence, the CI is between 345 tCO<sub>2</sub>/mbbl to 553 tCO<sub>2</sub>/mbbl. Producing net-zero GHG emission oil through DAC-EOR is thus highly improbable. An example case of DAC-EOR in the U.S. Permian Basin shows that only in the unlikely instance of the most storage efficient sites using 100% renewable energy does DAC-EOR result in “carbon-negative” oil production.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"139 ","pages":"Article 104281"},"PeriodicalIF":4.6,"publicationDate":"2024-11-14","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142660318","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-11-06DOI: 10.1016/j.ijggc.2024.104279
Markus Secomandi , Markku Nikku , Borja Arias , Jouni Ritvanen
Calcium looping (CaL), typically capable of reducing CO2 emissions by approximately 90%, is a technology well suited to capturing CO2 emissions from a wide array of industrial processes. An approach in which Ca(OH)2 is injected into the carbonator to increase the carbon capture efficiency of the CaL process to 99% was evaluated in this study using a one-and-a-half-dimensional reactor model. The effect of several key parameters was considered, including the injection flow rate, injection elevation, and the formation rate of CO2 in the freeboard of the carbonator due to the combustion of char particles elutriated from the calciner. The main finding was that capture rates of 99% appear attainable, given that enough Ca(OH)2 is injected and that the injection occurs at a suitable location, i.e., the sorbent is allowed sufficient residence time in the reactor.
{"title":"A conceptual evaluation of the use of Ca(OH)2 for attaining carbon capture rates of 99% in the calcium looping process","authors":"Markus Secomandi , Markku Nikku , Borja Arias , Jouni Ritvanen","doi":"10.1016/j.ijggc.2024.104279","DOIUrl":"10.1016/j.ijggc.2024.104279","url":null,"abstract":"<div><div>Calcium looping (CaL), typically capable of reducing CO<sub>2</sub> emissions by approximately 90%, is a technology well suited to capturing CO<sub>2</sub> emissions from a wide array of industrial processes. An approach in which Ca(OH)<sub>2</sub> is injected into the carbonator to increase the carbon capture efficiency of the CaL process to 99% was evaluated in this study using a one-and-a-half-dimensional reactor model. The effect of several key parameters was considered, including the injection flow rate, injection elevation, and the formation rate of CO<sub>2</sub> in the freeboard of the carbonator due to the combustion of char particles elutriated from the calciner. The main finding was that capture rates of 99% appear attainable, given that enough Ca(OH)<sub>2</sub> is injected and that the injection occurs at a suitable location, i.e., the sorbent is allowed sufficient residence time in the reactor.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"139 ","pages":"Article 104279"},"PeriodicalIF":4.6,"publicationDate":"2024-11-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142592839","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-11-06DOI: 10.1016/j.ijggc.2024.104265
Jeffrey D. Hyman , Alexander C. Murph , Lawrence Boampong , Alexis Navarre-Sitchler , James W. Carey , Phil Stauffer , Hari S. Viswanathan
One methodology to reduce CO in the atmosphere is inject it into subsurface systems where the ambient conditions are favorable for the carbon to precipitate/mineralize thereby permanently trapping it. Prospective host rocks are relatively impermeable when intact, so the flow of fluids and associated reactive transport therein primarily occurs within and through interconnected fracture networks that provide lower hydraulic resistance. Although critically important for the success of carbon mineralization, the characterization of the interplay between network geostructure, geochemical reactions, and hydrology on the total extent of mineralization is poorly understood. To this end, a set of reactive transport simulations modeling coupled dissolution and precipitation under a variety for hydrological and geochemical conditions are performed to characterize their impact on mineralization in three-dimensional fractured media. The generated data set is used to perform a robust sensitivity analysis and characterize how model parameters, as well as the network structure, affect the total amount of precipitated mineral. It is observed that the reaction rate constant of gypsum, the volume of the network, the incoming volumetric flow rate, and initial porosity showed the strongest impact on the maximum amount of mineralization in the system throughout the simulations.
{"title":"Determining the dominant factors controlling mineralization in three-dimensional fracture networks","authors":"Jeffrey D. Hyman , Alexander C. Murph , Lawrence Boampong , Alexis Navarre-Sitchler , James W. Carey , Phil Stauffer , Hari S. Viswanathan","doi":"10.1016/j.ijggc.2024.104265","DOIUrl":"10.1016/j.ijggc.2024.104265","url":null,"abstract":"<div><div>One methodology to reduce CO<span><math><msub><mrow></mrow><mrow><mn>2</mn></mrow></msub></math></span> in the atmosphere is inject it into subsurface systems where the ambient conditions are favorable for the carbon to precipitate/mineralize thereby permanently trapping it. Prospective host rocks are relatively impermeable when intact, so the flow of fluids and associated reactive transport therein primarily occurs within and through interconnected fracture networks that provide lower hydraulic resistance. Although critically important for the success of carbon mineralization, the characterization of the interplay between network geostructure, geochemical reactions, and hydrology on the total extent of mineralization is poorly understood. To this end, a set of reactive transport simulations modeling coupled dissolution and precipitation under a variety for hydrological and geochemical conditions are performed to characterize their impact on mineralization in three-dimensional fractured media. The generated data set is used to perform a robust sensitivity analysis and characterize how model parameters, as well as the network structure, affect the total amount of precipitated mineral. It is observed that the reaction rate constant of gypsum, the volume of the network, the incoming volumetric flow rate, and initial porosity showed the strongest impact on the maximum amount of mineralization in the system throughout the simulations.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"139 ","pages":"Article 104265"},"PeriodicalIF":4.6,"publicationDate":"2024-11-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142592847","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-11-02DOI: 10.1016/j.ijggc.2024.104266
Qin Zhang , Adedapo N. Awolayo , Patrick R. Phelps , Shafik Vadsariya , Christiaan T. Laureijs , Matthew D. Eisaman , Benjamin M. Tutolo
<div><div>Basalt-based CO<sub>2</sub> mineralization offers gigaton-scale capacity for sequestering anthropogenic CO<sub>2</sub>, but it faces challenges such as low cation productivity and formation of pore-clogging clays. A potential solution is to treat the basalt with aqueous acids such as HCl, a by-product of some electrochemical CO<sub>2</sub> removal processes. To date, our understanding of basalt-acid interactions is limited to extrapolations from higher pH environments, and therefore little is known about the mechanisms of the reaction at acidic conditions. To address this knowledge gap, far-from-equilibrium dissolution rates of basaltic glass and crystalline basalt were measured in mixed flow reactors at pH 0 to 9, and temperatures from 23 to 60 °C, with a specific focus on the low-pH region. Measured geometric surface area-normalized dissolution rates can be described according to: <span><span><span><math><mrow><mi>k</mi><mo>=</mo><mn>1</mn><msup><mrow><mn>0</mn></mrow><mrow><mo>−</mo><mrow><mo>(</mo><mn>5</mn><mo>.</mo><mn>6</mn><mo>±</mo><mn>0</mn><mo>.</mo><mn>5</mn><mo>)</mo></mrow></mrow></msup><mi>⋅</mi><mo>exp</mo><mfenced><mrow><mfenced><mrow><mfrac><mrow><mo>−</mo><mn>42</mn><mo>.</mo><mn>2</mn><mo>±</mo><mn>2</mn><mo>.</mo><mn>0</mn></mrow><mrow><mi>R</mi></mrow></mfrac></mrow></mfenced><mi>⋅</mi><mfenced><mrow><mfrac><mrow><mn>1</mn></mrow><mrow><mi>T</mi></mrow></mfrac><mo>−</mo><mfrac><mrow><mn>1</mn></mrow><mrow><msub><mrow><mi>T</mi></mrow><mrow><mi>r</mi></mrow></msub></mrow></mfrac></mrow></mfenced></mrow></mfenced><mi>⋅</mi><msubsup><mrow><mi>a</mi></mrow><mrow><msup><mrow><mi>H</mi></mrow><mrow><mo>+</mo></mrow></msup></mrow><mrow><mrow><mo>(</mo><mn>0</mn><mo>.</mo><mn>81</mn><mo>±</mo><mn>0</mn><mo>.</mo><mn>02</mn><mo>)</mo></mrow></mrow></msubsup><mo>+</mo><mn>1</mn><msup><mrow><mn>0</mn></mrow><mrow><mo>−</mo><mrow><mo>(</mo><mn>10</mn><mo>.</mo><mn>9</mn><mo>±</mo><mn>0</mn><mo>.</mo><mn>3</mn><mo>)</mo></mrow></mrow></msup><mi>⋅</mi><mo>exp</mo><mfenced><mrow><mfenced><mrow><mfrac><mrow><mo>−</mo><mn>32</mn><mo>.</mo><mn>5</mn><mo>±</mo><mn>1</mn><mo>.</mo><mn>1</mn></mrow><mrow><mi>R</mi></mrow></mfrac></mrow></mfenced><mi>⋅</mi><mfenced><mrow><mfrac><mrow><mn>1</mn></mrow><mrow><mi>T</mi></mrow></mfrac><mo>−</mo><mfrac><mrow><mn>1</mn></mrow><mrow><msub><mrow><mi>T</mi></mrow><mrow><mi>r</mi></mrow></msub></mrow></mfrac></mrow></mfenced></mrow></mfenced><mi>⋅</mi><msubsup><mrow><mi>a</mi></mrow><mrow><msup><mrow><mi>H</mi></mrow><mrow><mo>+</mo></mrow></msup></mrow><mrow><mo>−</mo><mrow><mo>(</mo><mn>0</mn><mo>.</mo><mn>15</mn><mo>±</mo><mn>0</mn><mo>.</mo><mn>01</mn><mo>)</mo></mrow></mrow></msubsup></mrow></math></span></span></span> where <span><math><mi>k</mi></math></span> is the rate constant (mol<!--> <!-->m<sup>−2</sup> <!-->s<sup>−1</sup>) at any temperature <span><math><mi>T</mi></math></span> (Kelvin) and <span><math><msup><mrow><mtext>H</mtext></mrow><mrow><mo>+</mo></mrow></msup></math></span> a
{"title":"Enhanced cation release via acid pretreatment for gigaton-scale geologic CO2 sequestration in basalt","authors":"Qin Zhang , Adedapo N. Awolayo , Patrick R. Phelps , Shafik Vadsariya , Christiaan T. Laureijs , Matthew D. Eisaman , Benjamin M. Tutolo","doi":"10.1016/j.ijggc.2024.104266","DOIUrl":"10.1016/j.ijggc.2024.104266","url":null,"abstract":"<div><div>Basalt-based CO<sub>2</sub> mineralization offers gigaton-scale capacity for sequestering anthropogenic CO<sub>2</sub>, but it faces challenges such as low cation productivity and formation of pore-clogging clays. A potential solution is to treat the basalt with aqueous acids such as HCl, a by-product of some electrochemical CO<sub>2</sub> removal processes. To date, our understanding of basalt-acid interactions is limited to extrapolations from higher pH environments, and therefore little is known about the mechanisms of the reaction at acidic conditions. To address this knowledge gap, far-from-equilibrium dissolution rates of basaltic glass and crystalline basalt were measured in mixed flow reactors at pH 0 to 9, and temperatures from 23 to 60 °C, with a specific focus on the low-pH region. Measured geometric surface area-normalized dissolution rates can be described according to: <span><span><span><math><mrow><mi>k</mi><mo>=</mo><mn>1</mn><msup><mrow><mn>0</mn></mrow><mrow><mo>−</mo><mrow><mo>(</mo><mn>5</mn><mo>.</mo><mn>6</mn><mo>±</mo><mn>0</mn><mo>.</mo><mn>5</mn><mo>)</mo></mrow></mrow></msup><mi>⋅</mi><mo>exp</mo><mfenced><mrow><mfenced><mrow><mfrac><mrow><mo>−</mo><mn>42</mn><mo>.</mo><mn>2</mn><mo>±</mo><mn>2</mn><mo>.</mo><mn>0</mn></mrow><mrow><mi>R</mi></mrow></mfrac></mrow></mfenced><mi>⋅</mi><mfenced><mrow><mfrac><mrow><mn>1</mn></mrow><mrow><mi>T</mi></mrow></mfrac><mo>−</mo><mfrac><mrow><mn>1</mn></mrow><mrow><msub><mrow><mi>T</mi></mrow><mrow><mi>r</mi></mrow></msub></mrow></mfrac></mrow></mfenced></mrow></mfenced><mi>⋅</mi><msubsup><mrow><mi>a</mi></mrow><mrow><msup><mrow><mi>H</mi></mrow><mrow><mo>+</mo></mrow></msup></mrow><mrow><mrow><mo>(</mo><mn>0</mn><mo>.</mo><mn>81</mn><mo>±</mo><mn>0</mn><mo>.</mo><mn>02</mn><mo>)</mo></mrow></mrow></msubsup><mo>+</mo><mn>1</mn><msup><mrow><mn>0</mn></mrow><mrow><mo>−</mo><mrow><mo>(</mo><mn>10</mn><mo>.</mo><mn>9</mn><mo>±</mo><mn>0</mn><mo>.</mo><mn>3</mn><mo>)</mo></mrow></mrow></msup><mi>⋅</mi><mo>exp</mo><mfenced><mrow><mfenced><mrow><mfrac><mrow><mo>−</mo><mn>32</mn><mo>.</mo><mn>5</mn><mo>±</mo><mn>1</mn><mo>.</mo><mn>1</mn></mrow><mrow><mi>R</mi></mrow></mfrac></mrow></mfenced><mi>⋅</mi><mfenced><mrow><mfrac><mrow><mn>1</mn></mrow><mrow><mi>T</mi></mrow></mfrac><mo>−</mo><mfrac><mrow><mn>1</mn></mrow><mrow><msub><mrow><mi>T</mi></mrow><mrow><mi>r</mi></mrow></msub></mrow></mfrac></mrow></mfenced></mrow></mfenced><mi>⋅</mi><msubsup><mrow><mi>a</mi></mrow><mrow><msup><mrow><mi>H</mi></mrow><mrow><mo>+</mo></mrow></msup></mrow><mrow><mo>−</mo><mrow><mo>(</mo><mn>0</mn><mo>.</mo><mn>15</mn><mo>±</mo><mn>0</mn><mo>.</mo><mn>01</mn><mo>)</mo></mrow></mrow></msubsup></mrow></math></span></span></span> where <span><math><mi>k</mi></math></span> is the rate constant (mol<!--> <!-->m<sup>−2</sup> <!-->s<sup>−1</sup>) at any temperature <span><math><mi>T</mi></math></span> (Kelvin) and <span><math><msup><mrow><mtext>H</mtext></mrow><mrow><mo>+</mo></mrow></msup></math></span> a","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"139 ","pages":"Article 104266"},"PeriodicalIF":4.6,"publicationDate":"2024-11-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142572780","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-11-02DOI: 10.1016/j.ijggc.2024.104278
Hyunshin Lee , Wonsuk Chung , Kosan Roh
Anion exchange membrane (AEM)-based electrolysis for CO2 reduction reaction (CO2RR) has garnered attention as a promising carbon dioxide utilization technology due to its superior energy efficiency at high current densities. The major drawback of AEM-based electrolysis for CO2RR is CO2 crossover, which leads to the loss of introduced CO2 feedstock and thus detrimentally affects the process's overall economic and environmental viability. We design a 3-stage membrane-based CO2 recovery unit to capture CO2 from the mixture of CO2 and O2 discharged from the anode side of AEM-based CO2 electrolyzers. The membrane area is optimized via a hybrid of genetic algorithm and ‘fmincon’ in MATLAB. The estimated CO2 capture cost ranges from 43.3 to 109.3 USD/tCO2, which is economically comparable to piperazine-based amine scrubbing units when recovering CO2 at a purity of up to 99.5 mol.% under a CO2/O2 molar ratio of 1.5∼2. The carbon footprint of the designed process ranges from −0.936 to −0.838 tCO2eq/tCO2-captured, indicating superior environmental performance compared to those of the piperazine-based amine scrubbing units.
{"title":"Conceptual design and evaluation of membrane gas separation-based CO2 recovery unit for CO2 electrolyzers employing anion exchange membranes","authors":"Hyunshin Lee , Wonsuk Chung , Kosan Roh","doi":"10.1016/j.ijggc.2024.104278","DOIUrl":"10.1016/j.ijggc.2024.104278","url":null,"abstract":"<div><div>Anion exchange membrane (AEM)-based electrolysis for CO<sub>2</sub> reduction reaction (CO<sub>2</sub>RR) has garnered attention as a promising carbon dioxide utilization technology due to its superior energy efficiency at high current densities. The major drawback of AEM-based electrolysis for CO<sub>2</sub>RR is CO<sub>2</sub> crossover, which leads to the loss of introduced CO<sub>2</sub> feedstock and thus detrimentally affects the process's overall economic and environmental viability. We design a 3-stage membrane-based CO<sub>2</sub> recovery unit to capture CO<sub>2</sub> from the mixture of CO<sub>2</sub> and O<sub>2</sub> discharged from the anode side of AEM-based CO<sub>2</sub> electrolyzers. The membrane area is optimized via a hybrid of genetic algorithm and ‘fmincon’ in MATLAB. The estimated CO<sub>2</sub> capture cost ranges from 43.3 to 109.3 USD/tCO<sub>2</sub>, which is economically comparable to piperazine-based amine scrubbing units when recovering CO<sub>2</sub> at a purity of up to 99.5 mol.% under a CO<sub>2</sub>/O<sub>2</sub> molar ratio of 1.5∼2. The carbon footprint of the designed process ranges from −0.936 to −0.838 tCO<sub>2</sub>eq/tCO<sub>2</sub>-captured, indicating superior environmental performance compared to those of the piperazine-based amine scrubbing units.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"139 ","pages":"Article 104278"},"PeriodicalIF":4.6,"publicationDate":"2024-11-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142572778","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-11-01DOI: 10.1016/j.ijggc.2024.104277
Mrinal Sinha , Erdinc Saygin , Andrew S. Ross , Ludovic Ricard
Carbon capture and storage (CCS) is forecast to play a significant role towards CO emissions reduction. Cost-effective and simplified monitoring will be essential for rapid adoption and growth of CCS. Seismic imaging methods are regularly utilized to monitor low-velocity anomalies generated by injection of CO in the subsurface. In this study we generate active and passive synthetic seismic datasets at different stages of CO injection in the subsurface based on geologically constrained subsurface models of the Pelican storage site in the Gippsland Basin, Australia. We apply full waveform inversion (FWI) and wave-equation dispersion (WD) inversion to seafloor deployed distributed acoustic sensing (DAS) data to reconstruct the low-velocity anomalies. We model both strain (DAS) and displacement datasets for the active data component of the study and show that they result in similar reconstruction of the CO anomaly. FWI based time-lapse imaging of active data yields the most accurate results. However, this approach is expensive and also suffers from complex issues because of the near-onshore location of the storage site. Alternatively inverting passive data results in only minor differences, but can still effectively monitor changes in the subsurface, and assist in monitoring the CO plume at the reservoir depth. Furthermore, we demonstrate the capability of WD for inverting Scholte-waves derived from ambient noise for shallow detection of CO in the unlikely event of a leakage. Therefore, we propose a mixed mode monitoring strategy where passive data is utilized for routine monitoring while active surveys are deployed only when further investigation is required.
{"title":"Seismic monitoring of CCS with active and passive data: A synthetic feasibility study based on Pelican site, Australia","authors":"Mrinal Sinha , Erdinc Saygin , Andrew S. Ross , Ludovic Ricard","doi":"10.1016/j.ijggc.2024.104277","DOIUrl":"10.1016/j.ijggc.2024.104277","url":null,"abstract":"<div><div>Carbon capture and storage (CCS) is forecast to play a significant role towards CO<span><math><msub><mrow></mrow><mrow><mn>2</mn></mrow></msub></math></span> emissions reduction. Cost-effective and simplified monitoring will be essential for rapid adoption and growth of CCS. Seismic imaging methods are regularly utilized to monitor low-velocity anomalies generated by injection of CO<span><math><msub><mrow></mrow><mrow><mn>2</mn></mrow></msub></math></span> in the subsurface. In this study we generate active and passive synthetic seismic datasets at different stages of CO<span><math><msub><mrow></mrow><mrow><mn>2</mn></mrow></msub></math></span> injection in the subsurface based on geologically constrained subsurface models of the Pelican storage site in the Gippsland Basin, Australia. We apply full waveform inversion (FWI) and wave-equation dispersion (WD) inversion to seafloor deployed distributed acoustic sensing (DAS) data to reconstruct the low-velocity anomalies. We model both strain (DAS) and displacement datasets for the active data component of the study and show that they result in similar reconstruction of the CO<span><math><msub><mrow></mrow><mrow><mn>2</mn></mrow></msub></math></span> anomaly. FWI based time-lapse imaging of active data yields the most accurate results. However, this approach is expensive and also suffers from complex issues because of the near-onshore location of the storage site. Alternatively inverting passive data results in only minor differences, but can still effectively monitor changes in the subsurface, and assist in monitoring the CO<span><math><msub><mrow></mrow><mrow><mn>2</mn></mrow></msub></math></span> plume at the reservoir depth. Furthermore, we demonstrate the capability of WD for inverting Scholte-waves derived from ambient noise for shallow detection of CO<span><math><msub><mrow></mrow><mrow><mn>2</mn></mrow></msub></math></span> in the unlikely event of a leakage. Therefore, we propose a mixed mode monitoring strategy where passive data is utilized for routine monitoring while active surveys are deployed only when further investigation is required.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"139 ","pages":"Article 104277"},"PeriodicalIF":4.6,"publicationDate":"2024-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142572779","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-10-30DOI: 10.1016/j.ijggc.2024.104267
Manguang Gan , Liwei Zhang , Yan Wang , Qinglong Qin , Ting Xiao , Yue Yin , Hanwen Wang
In the scenario of geologic CO2 storage, the injection of CO2 can create a carbonic acid-rich environment in the reservoir, and Cl-- and SO42--rich low-pH environments may form in the reservoir if the reservoir brine contains high concentrations of Cl- and SO42-. The analysis of morphological changes in wellbore cement containing leakage channels before and after the reaction in different acidic environments is crucial for assessing the risk of CO2 leakage along the internal cracks of wellbore cement. This study characterizes the morphological and structural changes of wellbore cement with a leaking channel before and after the flow of CO2-saturated brine and then compares the results with the structural changes of channels after exposure to HCl and H2SO4 solutions. The results indicate that the cement around the leaking channel dissolves, and the channel volume increases when exposed to CO2-saturated brine. The reaction is more intense at the inlet end than at the outlet end, and some cracks form around the channel. As the HCl solution flows through the channel, a hydrate precipitate that contains calcium and aluminum forms from the inlet to the middle of the channel. This is due to the aqueous phase cations (Ca2+ and Al3+ released from the hydrated cement phases) mixing with the high pH pore fluid ahead of the acid front. Upon flow of the H2SO4 solution through the channel, a thin layer of precipitation forms on both the inlet and outlet ends of the channel. XRD analysis indicates that the precipitation comprises gypsum (CaSO4·2H2O), which forms due to the reaction between SO42- in the H2SO4 solution and Ca2+ in the cement hydration product. The volume of the channel decreased after exposure to HCl and H2SO4 solutions, indicating that secondary precipitation resulting from the reaction between the cement and acid exceeded the cement dissolution, and the hydrochloric and sulfuric acidic environments had a limited effect on the expansion of the wellbore cement's internal channel. The experimental results of this study also indicate that in an acidic environment with the same pH, the CO2-saturated brine is the most corrosive to wellbore cement, followed by hydrochloric acid, and sulfuric acid is the least corrosive.
{"title":"Experimental study on the corrosion behavior of wellbore cement with a leaking channel under different acidic environments","authors":"Manguang Gan , Liwei Zhang , Yan Wang , Qinglong Qin , Ting Xiao , Yue Yin , Hanwen Wang","doi":"10.1016/j.ijggc.2024.104267","DOIUrl":"10.1016/j.ijggc.2024.104267","url":null,"abstract":"<div><div>In the scenario of geologic CO<sub>2</sub> storage, the injection of CO<sub>2</sub> can create a carbonic acid-rich environment in the reservoir, and Cl<sup>-</sup>- and SO<sub>4</sub><sup>2-</sup>-rich low-pH environments may form in the reservoir if the reservoir brine contains high concentrations of Cl<sup>-</sup> and SO<sub>4</sub><sup>2-</sup>. The analysis of morphological changes in wellbore cement containing leakage channels before and after the reaction in different acidic environments is crucial for assessing the risk of CO<sub>2</sub> leakage along the internal cracks of wellbore cement. This study characterizes the morphological and structural changes of wellbore cement with a leaking channel before and after the flow of CO<sub>2</sub>-saturated brine and then compares the results with the structural changes of channels after exposure to HCl and H<sub>2</sub>SO<sub>4</sub> solutions. The results indicate that the cement around the leaking channel dissolves, and the channel volume increases when exposed to CO<sub>2</sub>-saturated brine. The reaction is more intense at the inlet end than at the outlet end, and some cracks form around the channel. As the HCl solution flows through the channel, a hydrate precipitate that contains calcium and aluminum forms from the inlet to the middle of the channel. This is due to the aqueous phase cations (Ca<sup>2+</sup> and Al<sup>3+</sup> released from the hydrated cement phases) mixing with the high pH pore fluid ahead of the acid front. Upon flow of the H<sub>2</sub>SO<sub>4</sub> solution through the channel, a thin layer of precipitation forms on both the inlet and outlet ends of the channel. XRD analysis indicates that the precipitation comprises gypsum (CaSO<sub>4</sub>·2H<sub>2</sub>O), which forms due to the reaction between SO<sub>4</sub><sup>2-</sup> in the H<sub>2</sub>SO<sub>4</sub> solution and Ca<sup>2+</sup> in the cement hydration product. The volume of the channel decreased after exposure to HCl and H<sub>2</sub>SO<sub>4</sub> solutions, indicating that secondary precipitation resulting from the reaction between the cement and acid exceeded the cement dissolution, and the hydrochloric and sulfuric acidic environments had a limited effect on the expansion of the wellbore cement's internal channel. The experimental results of this study also indicate that in an acidic environment with the same pH, the CO<sub>2</sub>-saturated brine is the most corrosive to wellbore cement, followed by hydrochloric acid, and sulfuric acid is the least corrosive.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"139 ","pages":"Article 104267"},"PeriodicalIF":4.6,"publicationDate":"2024-10-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142553021","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-10-28DOI: 10.1016/j.ijggc.2024.104276
Greg Lackey , Scott Pantaleone , John K. Montgomery , Kristen Busse , Adam W. Aylor , Tracy J. Moffett
Federal offshore waters in the Gulf of Mexico are of interest for large-scale geologic carbon storage (GCS). However, more than 80,000 offshore oil and gas wells exist in the region, which could impact the integrity of sealing intervals. In this study, we propose a screening methodology for ranking offshore legacy wells based on the challenge they may present to GCS. The methodology relies on the review of well regulatory records to 1) identify leakage pathways and assess the potential hazards that wells pose to planned GCS operations, 2) evaluate well features that impact the accessibility of wells to determine the feasibility of potential corrective actions, and 3) rank wells based on the overall challenge they may pose for GCS. We demonstrate our framework by evaluating the construction and abandonment of 156 wells across eight areas of interest (AOIs) in shallow federal waters along the Texas Gulf Coast. The majority (99.3 %) of wells considered were constructed and plugged in a manner that did not isolate prospective GCS targets in the Upper and Lower Miocene formations and may potentially require a challenging or uncertain corrective action prior to GCS. Dataset trends suggest that the observed well construction and plugging designs may be common in shallow offshore federal waters along the Texas Gulf Coast. Consequently, operators pursuing offshore GCS projects in the region may consider selecting areas that avoid challenging wells or performing robust evaluations of legacy well leakage risks to plan corrective action prior to CO2 injection.
{"title":"Evaluating offshore legacy wells for geologic carbon storage: A case study from the Galveston and Brazos areas in the Gulf of Mexico","authors":"Greg Lackey , Scott Pantaleone , John K. Montgomery , Kristen Busse , Adam W. Aylor , Tracy J. Moffett","doi":"10.1016/j.ijggc.2024.104276","DOIUrl":"10.1016/j.ijggc.2024.104276","url":null,"abstract":"<div><div>Federal offshore waters in the Gulf of Mexico are of interest for large-scale geologic carbon storage (GCS). However, more than 80,000 offshore oil and gas wells exist in the region, which could impact the integrity of sealing intervals. In this study, we propose a screening methodology for ranking offshore legacy wells based on the challenge they may present to GCS. The methodology relies on the review of well regulatory records to 1) identify leakage pathways and assess the potential hazards that wells pose to planned GCS operations, 2) evaluate well features that impact the accessibility of wells to determine the feasibility of potential corrective actions, and 3) rank wells based on the overall challenge they may pose for GCS. We demonstrate our framework by evaluating the construction and abandonment of 156 wells across eight areas of interest (AOIs) in shallow federal waters along the Texas Gulf Coast. The majority (99.3 %) of wells considered were constructed and plugged in a manner that did not isolate prospective GCS targets in the Upper and Lower Miocene formations and may potentially require a challenging or uncertain corrective action prior to GCS. Dataset trends suggest that the observed well construction and plugging designs may be common in shallow offshore federal waters along the Texas Gulf Coast. Consequently, operators pursuing offshore GCS projects in the region may consider selecting areas that avoid challenging wells or performing robust evaluations of legacy well leakage risks to plan corrective action prior to CO<sub>2</sub> injection.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"139 ","pages":"Article 104276"},"PeriodicalIF":4.6,"publicationDate":"2024-10-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142531712","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-10-01DOI: 10.1016/j.ijggc.2024.104237
Jinyan Lin , Rui Liu , Niklas Heinemann , Johannes M. Miocic , Jinqiang Tian , Zengyu Chen , Lin Hu , Yazhen Zhang , Julien Amalberti , Lichao Wang
Global industry drillings targeted at deep-burial hydrocarbons have renewed the record of maximum sustainable overpressure in sedimentary basins. However, the influence of extremely high overpressure on natural fluid accumulation and artificial waste sequestration is not yet completely understood. To better understand the motion characteristics of the highly overpressured CO2-rich fluid, the CO2 retention capacity was quantified, and the CO2-rich fluid motion trails were evaluated in an ideal natural laboratory in the Yinggehai Basin. The hydraulic sealing capacity was higher than the capillary sealing capacity in the highly overpressured stratum. Relative to the situations of no breach or solely breached by capillary failure, the superposition of capillary and hydraulic failures resulted in the caprock integrity breakage by faults (or fractures), diapirs, and pipes. Meanwhile, the high expulsion flux of CO2-rich fluid caused the consumption of chlorite to generate illite in the caprock of dual-breached fields. The CO2-rich fluid flux of capillary invasion was limited by the inherently low permeability of caprock, which may be insufficient for a dramatic change of hydrogen ions or electron activities to induce remarkable chlorite dissolution in the caprock of the sole-breached field.
{"title":"CO2 retention in high-pressure/high-temperature reservoirs of the Yinggehai Basin, northwestern South China Sea","authors":"Jinyan Lin , Rui Liu , Niklas Heinemann , Johannes M. Miocic , Jinqiang Tian , Zengyu Chen , Lin Hu , Yazhen Zhang , Julien Amalberti , Lichao Wang","doi":"10.1016/j.ijggc.2024.104237","DOIUrl":"10.1016/j.ijggc.2024.104237","url":null,"abstract":"<div><div>Global industry drillings targeted at deep-burial hydrocarbons have renewed the record of maximum sustainable overpressure in sedimentary basins. However, the influence of extremely high overpressure on natural fluid accumulation and artificial waste sequestration is not yet completely understood. To better understand the motion characteristics of the highly overpressured CO<sub>2</sub>-rich fluid, the CO<sub>2</sub> retention capacity was quantified, and the CO<sub>2</sub>-rich fluid motion trails were evaluated in an ideal natural laboratory in the Yinggehai Basin. The hydraulic sealing capacity was higher than the capillary sealing capacity in the highly overpressured stratum. Relative to the situations of no breach or solely breached by capillary failure, the superposition of capillary and hydraulic failures resulted in the caprock integrity breakage by faults (or fractures), diapirs, and pipes. Meanwhile, the high expulsion flux of CO<sub>2</sub>-rich fluid caused the consumption of chlorite to generate illite in the caprock of dual-breached fields. The CO<sub>2</sub>-rich fluid flux of capillary invasion was limited by the inherently low permeability of caprock, which may be insufficient for a dramatic change of hydrogen ions or electron activities to induce remarkable chlorite dissolution in the caprock of the sole-breached field.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"138 ","pages":"Article 104237"},"PeriodicalIF":4.6,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142529132","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This study investigates the feasibility of storing the acid gas produced from the oil and gas facilities in Southern Saskatchewan into the Basal Sand aquifer using a coupled wellbore-aquifer-compositional reservoir model. The simulations investigate the pressure change around the fault in proximity of the primary storage location incorporating the influence of reservoir permeability, fault transmissibility, and wellbore configuration, on the factors critical to safe and efficient storage, such as plume migration, pressure changes, and CO2 storage capacity. A compositional fluid model created using an equation of state was integrated into the reservoir model. Simultaneous incorporation of fault transmissibility, phase solubility, water salinity, temporal in-situ hysteresis and structural trapping, and in-situ compositional tracking of individual gas components is considered as the main novelty of this work. The main challenge of the study was the lack of available data to characterize the aquifer. To this end, a comprehensive workflow of reservoir studies and modeling was applied to reduce the uncertainties and evaluate the site selection. The Basal sand scoping models reveal that the aquifer is expected to handle the required disposal volume given its extent. The injected acid gas plume migrates laterally and preferentially towards the northwest, away from the fault, owing to the aquifer's geological structure. CO2 remains entirely in the supercritical state, offering storage advantages due to its lower volume. The reservoir permeability significantly impacts the pressure patterns with lower permeability formations triggering higher wellhead injection pressures. Substantial pressure increases around the sealing fault can be observed. Pressure changes of 110 kPa (16 psi) to over 400 kPa (58 psi) were observed at the fault segment after 20 years of continuous gas injection for the expected range of reservoir properties. Mitigation strategies to minimize the increase in fault pressure entail relocating the injection site away from the fault or utilizing a horizontal well trajectory and using an observation well near the fault for monitoring any pressure buildup and slippage.
{"title":"An integrated dynamic modeling workflow for acid gas and CO2 geologic storage screening in saline aquifers with faults: A case study in Western Canada","authors":"Alireza Qazvini Firouz , Benyamin Yadali Jamaloei , Alejandro Duvan Lopez Rojas","doi":"10.1016/j.ijggc.2024.104258","DOIUrl":"10.1016/j.ijggc.2024.104258","url":null,"abstract":"<div><div>This study investigates the feasibility of storing the acid gas produced from the oil and gas facilities in Southern Saskatchewan into the Basal Sand aquifer using a coupled wellbore-aquifer-compositional reservoir model. The simulations investigate the pressure change around the fault in proximity of the primary storage location incorporating the influence of reservoir permeability, fault transmissibility, and wellbore configuration, on the factors critical to safe and efficient storage, such as plume migration, pressure changes, and CO<sub>2</sub> storage capacity. A compositional fluid model created using an equation of state was integrated into the reservoir model. Simultaneous incorporation of fault transmissibility, phase solubility, water salinity, temporal in-situ hysteresis and structural trapping, and in-situ compositional tracking of individual gas components is considered as the main novelty of this work. The main challenge of the study was the lack of available data to characterize the aquifer. To this end, a comprehensive workflow of reservoir studies and modeling was applied to reduce the uncertainties and evaluate the site selection. The Basal sand scoping models reveal that the aquifer is expected to handle the required disposal volume given its extent. The injected acid gas plume migrates laterally and preferentially towards the northwest, away from the fault, owing to the aquifer's geological structure. CO<sub>2</sub> remains entirely in the supercritical state, offering storage advantages due to its lower volume. The reservoir permeability significantly impacts the pressure patterns with lower permeability formations triggering higher wellhead injection pressures. Substantial pressure increases around the sealing fault can be observed. Pressure changes of 110 kPa (16 psi) to over 400 kPa (58 psi) were observed at the fault segment after 20 years of continuous gas injection for the expected range of reservoir properties. Mitigation strategies to minimize the increase in fault pressure entail relocating the injection site away from the fault or utilizing a horizontal well trajectory and using an observation well near the fault for monitoring any pressure buildup and slippage.</div></div>","PeriodicalId":334,"journal":{"name":"International Journal of Greenhouse Gas Control","volume":"138 ","pages":"Article 104258"},"PeriodicalIF":4.6,"publicationDate":"2024-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142423988","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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