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Статті в журналах з теми "CO2 geosequestration"

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Автор: Grafiati

Опубліковано: 7 вересня 2023

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1

Taggart, Ian. "Extraction of Dissolved Methane in Brines by CO2 Injection: Implication for CO2 Sequestration." SPE Reservoir Evaluation & Engineering 13, no. 05 (October 11, 2010): 791–804. http://dx.doi.org/10.2118/124630-pa.

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Summary The solubility of carbon dioxide (CO2) in underground saline formations is considered to offer significant long-term storage capability to effectively sequester large amounts of anthropogenic CO2. Unlike enhanced oil recovery (EOR), geosequestration relies on longer time scales and involves significantly greater volumes of CO2. Many geosequestration studies assume that the initial brine state is one containing no dissolved hydrocarbons and, therefore, apply simplistic two-component solubility models starting from a zero dissolved-gas state. Many brine formations near hydrocarbons, however, tend to be close to saturation by methane (CH4). The introduction of excess CO2 in such systems results in an extraction of the CH4 into the CO2-rich phase, which, in turn, has implications for monitoring of any sequestration project and offers the possibly additional CH4 mobilization and recovery.

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2

Sarkarfarshi, Mirhamed, Farshad A. Malekzadeh, Robert Gracie, and Maurice B. Dusseault. "Parametric sensitivity analysis for CO2 geosequestration." International Journal of Greenhouse Gas Control 23 (April 2014): 61–71. http://dx.doi.org/10.1016/j.ijggc.2014.02.003.

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3

Sharma, S., P. Cook, T. Berly, and C. Anderson. "AUSTRALIA’S FIRST GEOSEQUESTRATION DEMONSTRATION PROJECT—THE CO2CRC OTWAY BASIN PILOT PROJECT." APPEA Journal 47, no. 1 (2007): 259. http://dx.doi.org/10.1071/aj06017.

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Geological sequestration is a promising technology for reducing atmospheric emissions of carbon dioxide (CO2) with the potential to geologically store a significant proportion Australia of Australia’s stationary CO2 emissions. Stationary emissions comprise almost 50% (or about 280 million tonnes of CO2 per annum) of Australia’s total greenhouse gas emissions. Australia has abundant coal and gas resources and extensive geological storage opportunities; it is therefore well positioned to include geosequestration as an important part of its portfolio of greenhouse gas emission mitigation technologies.The Cooperative Research Centre for Greenhouse Gas Technologies is undertaking a geosequestration demonstration project in the Otway Basin of southwest Victoria, with injection of CO2 planned to commence around mid 2007. The project will extract natural gas containing a high percentage of CO2 from an existing gas well and inject it into a nearby depleted natural gas field for long-term storage. The suitability of the storage site has been assessed through a comprehensive risk assessment process. About 100,000 tonnes of CO2 is expected to be injected through a new injection well during a one- to two-year period. The injection of CO2 will be accompanied by a comprehensive monitoring and verification program to understand the behaviour of the CO2 in the subsurface and determine if the injected carbon dioxide has migrated out of the storage reservoir into overlying formations. This project will be the first storage project in Australia and the first in the world to test monitoring for storage in a depleted gas reservoir. Baseline data pertinent to geosequestration is already being acquired through the project and the research will enable a better understanding of long-term reactive transport and trapping mechanisms.This project is being authorised under the Petroleum Act 1998 (Victoria) and research, development and demonstration provisions administered by the Environment Protection Authority (EPA) Victoria in the absence of geosequestration- specific legislation. This highlights the need for such legislation to enable commercial-scale projects to proceed. Community acceptance is a key objective for the project and a consultation plan based on social research has been put in place to gauge public understanding and build support for the technology as a viable mitigation mechanism.

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4

LEUNING, R., D. ETHERIDGE, A. LUHAR, and B. DUNSE. "Atmospheric monitoring and verification technologies for CO2 geosequestration." International Journal of Greenhouse Gas Control 2, no. 3 (July 2008): 401–14. http://dx.doi.org/10.1016/j.ijggc.2008.01.002.

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5

Sharma, Sandeep, Peter Cook, and Charles Jenkins. "Demonstrating geosequestration in Australia: the CO2CRC Otway Project." APPEA Journal 49, no. 2 (2009): 601. http://dx.doi.org/10.1071/aj08074.

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The CO2CRC has a demonstration storage project underway in the Otway Basin of southwest Victoria. The aim of the project is to demonstrate that carbon capture and storage (CCS) can be performed under Australian conditions. The project involves extracting CO2 rich gas from an existing field and injecting it into a nearby depleted natural gas field for long-term storage. Injection commenced in April 2008, and approximately 100,000 tonnes of CO2 are planned to be injected through a new injection well drilled in 2007. A multi-disciplinary monitoring and verification (M&V) program has been in place from late 2005 and a baseline state of the subsurface, near surface and atmospheric conditions has been comprehensively defined prior to the commencement of injection. The project has also been instrumental in unravelling the legislative overlaps between jurisdictions and has helped shape the regulatory regime being developed by the Victorian Government. At the present time over 35,000 tonnes of CO2 has been injected and a variety of monitoring data collected. This paper aims to provide an update on the holistic project and how some of the findings may lead to expediting commercial uptake of CCS in Australia.

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6

Myers, Matthew, Linda Stalker, Bobby Pejcic, and Andrew Ross. "Tracers – Past, present and future applications in CO2 geosequestration." Applied Geochemistry 30 (March 2013): 125–35. http://dx.doi.org/10.1016/j.apgeochem.2012.06.001.

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7

Urosevic, M., R. Pevzner, B. Gurevich, V. Shulakova, A. Kepic, and S. Sharma. "Seismic monitoring of CO2 geosequestration: CO2CRC Otway project case study." ASEG Extended Abstracts 2010, no. 1 (December 2010): 1. http://dx.doi.org/10.1081/22020586.2010.12042023.

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8

Liang, Yunfeng, Shinya Tsuji, Jihui Jia, Takeshi Tsuji, and Toshifumi Matsuoka. "Modeling CO2–Water–Mineral Wettability and Mineralization for Carbon Geosequestration." Accounts of Chemical Research 50, no. 7 (June 29, 2017): 1530–40. http://dx.doi.org/10.1021/acs.accounts.7b00049.

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9

Damico, James R., Robert W. Ritzi, Naum I. Gershenzon, and Roland T. Okwen. "Challenging Geostatistical Methods To Represent Heterogeneity in CO2 Reservoirs Under Residual Trapping." Environmental and Engineering Geoscience 24, no. 4 (December 21, 2018): 357–73. http://dx.doi.org/10.2113/eeg-2116.

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Abstract Geostatistical methods based on two-point spatial-bivariate statistics have been used to model heterogeneity within computational studies of the dispersion of contaminants in groundwater reservoirs and the trapping of CO2 in geosequestration reservoirs. The ability of these methods to represent fluvial architecture, commonly occurring in such reservoirs, has been questioned. We challenged a widely used two-point spatial-bivariate statistical method to represent fluvial heterogeneity in the context of representing how reservoir heterogeneity affects residual trapping of CO2 injected for geosequestration. A more rigorous model for fluvial architecture was used as the benchmark in these studies. Both the geostatistically generated model and the benchmark model were interrogated, and metrics for the connectivity of high-permeability preferential flow pathways were quantified. Computational simulations of CO2 injection were performed, and metrics for CO2 dynamics and trapping were quantified. All metrics were similar between the two models. The percentage of high-permeability cells in spanning connected clusters (percolating clusters) was similar because percolation is strongly dependent upon proportions, and the same proportion of higher permeability cross-strata was specified in generating both models. The CO2 plume dynamics and residual trapping metrics were similar because they are largely controlled by the occurrence of percolating clusters. The benchmark model represented more features of the fluvial architecture and, depending on context, representing those features may be quite important, but the simpler geostatistical model was able to adequately represent fluvial reservoir architecture within the context and within the scope of the parameters represented here.

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10

Faiz, M. M., S. A. Barclay, N. Sherwood, L. Stalker, A. Saghafi, and D. J. Whitford. "NATURAL ACCUMULATION OF CO2 IN COALS FROM THE SOUTHERN SYDNEY BASIN—IMPLICATIONS FOR GEOSEQUESTRATION." APPEA Journal 46, no. 1 (2006): 455. http://dx.doi.org/10.1071/aj05027.

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The southern Sydney Basin is an ideal natural analogue for CO2 geosequestration because of the widespread CO2 occurrence, extensive data sets available and general knowledge of gas distribution. The CO2 mainly occurs adsorbed in coal, incorporated into carbonate minerals and dissolved in formation water. On this basis, an area of ~900 km2 has been chosen for detailed examination.Gas in the coal seams of this area contain mainly CH4 and CO2, the CO2 content ranging from Calculations indicate that about 78 x 106 tonnes of CO2 are presently stored in coaly intervals in the study area. Assuming a storage capacity of 20 m3/t for these coal seams, the total CO2 storage capacity for the coaly intervals is ~880 x 106 tonnes. Using the study area as an analogue for enhanced coal seam methane production, 175 x 106 tonnes of CO2 could be stored, assuming a 50% CH4 recovery factor and an average CO2 sorption capacity 1.5 times that for CH4.

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11

Godoi, José Maria Alves, and Patrícia Helena Lara dos Santos Matai. "Enhanced oil recovery with carbon dioxide geosequestration: first steps at Pre-salt in Brazil." Journal of Petroleum Exploration and Production Technology 11, no. 3 (February 15, 2021): 1429–41. http://dx.doi.org/10.1007/s13202-021-01102-8.

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AbstractThis paper revisits the intense using of energy in the world and the role of the fossil fuels with predominance of the oil in the global primary energy supply and their effects to climate change. It also presents a new reading on the thermodynamic conditions and characteristics of CO2 and CO2-EOR together with oil industry advancement in the world and Brazil. The interface with chemical EOR processes involving nanoparticles (NPs), their application inside the reservoirs for EOR and understanding of fines migration reducing, among other physical phenomena is also studied. Carbon capture and storage (CCS) is a worldwide strategy for mitigating climate change. CO2 geosequestration is also analyzed on the leakage of CO2 and brine from aquifers and their implication to the security of the storage and environment. Recent studies show that, globally, CO2-EOR can extract up to 375 billion of additional oil barrels and geological storage up to 360 Gt of CO2 in the next 50 years. Pre-salt is a complex of microbial carbonate reservoirs with stromatolite framework in ultra-deep waters (1500–3000) m depth, underneath by thick salt layer (2000–2500) m. Its reservoirs are in the depth up to (5500–6500) m TVDSS and approximately (200–300) km offshore. It presents light oils and high (GOR) ranging (200–400) Sm3/Sm3 and huge CO2 contamination (8–15)%. Due to the large CO2 content of oil, this work investigated CO2-EOR and CO2 geosequestration within the reservoirs. Pilot test demonstrated that miscible CO2-EOR with WAG is feasible and beneficial to this hydrocarbon Province. This study also calculated and validated the potential of CO2-EOR to the CCS. It concludes that Pre-salt can contribute to recovery factor (RF) increasing about 5.7 billion of additional oil barrels, and to CCS with about 266 Mt CO2 to be geological stored, for the next 20 years. In this context, this work also analyses the recent changes on the Brazilian oil and gas regulation to encourage new international Companies to enter in Brazil and Pre-salt for petroleum exploring. In Pre-salt, CO2-EOR also connects the petroleum energy system to CCS, transforming the oil reservoir in a carbon sink. These results represent a substantial role of Pre-salt to the energy efficiency of energy resources recovering from the biosphere and a high contribution to the climate change mitigation.

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12

Gibson-Poole, C. M., L. Svendsen, J. Underschultz, M. N. Watson, J. Ennis-King, P. J. van Ruth, E. J. Nelson, R. F. Daniel, and Y. Cinar. "GIPPSLAND BASIN GEOSEQUESTRATION: A POTENTIAL SOLUTION FOR THE LATROBE VALLEY BROWN COAL CO2 EMISSIONS." APPEA Journal 46, no. 1 (2006): 413. http://dx.doi.org/10.1071/aj05024.

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Geosequestration of CO2 in the offshore Gippsland Basin is being investigated by the CO2CRC as a possible method for storing the very large volumes of CO2 emissions from the Latrobe Valley area. A storage capacity of about 50 million tonnes of CO2 per year for a 40-year injection period is required, which will necessitate several individual storage sites to be used both sequentially and simultaneously, but timed such that existing hydrocarbon assets are not compromised. Detailed characterisation focussed on the Kingfish Field area as the first site to be potentially used, in the anticipation that this oil field will be depleted within the period 2015–25. The potential injection targets are the interbedded sandstones, shales and coals of the Paleocene-Eocene upper Latrobe Group, regionally sealed by the Lakes Entrance Formation. The research identified several features to the offshore Gippsland Basin that make it particularly favourable for CO2 storage. These include: a complex stratigraphic architecture that provides baffles which slow vertical migration and increase residual gas trapping; non-reactive reservoir units that have high injectivity; a thin, suitably reactive, low permeability marginal reservoir just below the regional seal providing additional mineral trapping; several depleted oil fields that provide storage capacity coupled with a transient flow regime arising from production that enhances containment; and, long migration pathways beneath a competent regional seal. This study has shown that the Gippsland Basin has sufficient capacity to store very large volumes of CO2. It may provide a solution to the problem of substantially reducing greenhouse gas emissions from the use of new coal developments in the Latrobe Valley.

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13

Masoudian, Mohsen S., David W. Airey, and Abbas El-Zein. "Mechanical and flow behaviours and their interactions in coalbed geosequestration of CO2." Geomechanics and Geoengineering 8, no. 4 (December 2013): 229–43. http://dx.doi.org/10.1080/17486025.2013.805252.

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14

Hnottavange-Telleen, Ken, Ethan Chabora, Robert J. Finley, Sallie E. Greenberg, and Scott Marsteller. "Risk management in a large-scale CO2 geosequestration pilot project, Illinois, USA." Energy Procedia 4 (2011): 4044–51. http://dx.doi.org/10.1016/j.egypro.2011.02.346.

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15

MA, Denglong, Jianqiang DENG, and Zaoxiao ZHANG. "CO2 Leakage Identification in Geosequestration Based on Real Time Correlation Analysis Between Atmospheric O2 and CO2." Chinese Journal of Chemical Engineering 22, no. 6 (June 2014): 634–42. http://dx.doi.org/10.1016/s1004-9541(14)60094-x.

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16

Peter, Ameh, Dongmin Yang, Kenneth Imo-Imo Israel Eshiet, and Yong Sheng. "A Review of the Studies on CO2–Brine–Rock Interaction in Geological Storage Process." Geosciences 12, no. 4 (April 12, 2022): 168. http://dx.doi.org/10.3390/geosciences12040168.

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CO2–brine–rock interaction impacts the behavior and efficiency of CO2 geological storage; a thorough understanding of these impacts is important. A lot of research in the past has considered the nature and impact of CO2–brine–rock interaction and much has been learned. Given that the solubility and rate of mineralization of CO2 in brine under reservoir conditions is slow, free and mobile, CO2 will be contained in the reservoir for a long time until the phase of CO2 evolves. A review of independent research indicates that the phase of CO2 affects the nature of CO2–brine–rock interaction. It is important to understand how different phases of CO2 that can be present in a reservoir affects CO2–brine–rock interaction. However, the impact of the phase of CO2 in a CO2–brine–rock interaction has not been given proper attention. This paper is a systematic review of relevant research on the impact of the phase of CO2 on the behavior and efficiency of CO2 geological storage, extending to long-term changes in CO2, brine, and rock properties; it articulates new knowledge on the effect of the phase of CO2 on CO2–brine–rock behavior in geosequestration sites and highlights areas for further development.

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17

Seyyedi, Mojtaba, Ausama Giwelli, Cameron White, Lionel Esteban, Michael Verrall, and Ben Clennell. "Changes in multi-phase flow properties of carbonate porous media during CO2 injection." APPEA Journal 60, no. 2 (2020): 672. http://dx.doi.org/10.1071/aj19061.

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Impacts of fluid–rock geochemical reactions occurring during CO2 injection into underground formations, including CO2 geosequestration, on porosity and single-phase permeability are well documented. However, their impacts on pore structure and multi-phase flow behaviour of porous media and, therefore, on CO2 injectivity and residual trapping potential, are yet unknown. We found that CO2-saturated brine–rock interactions in a carbonate rock led to a decrease in the sweep efficiency of the non-wetting phase (gas) during primary drainage. Furthermore, they led to an increase in the relative permeability of the non-wetting phase, a decrease in the relative permeability of the wetting phase (brine) and a reduction in the residual trapping potential of the non-wetting phase. The impacts of reactions on pore structure shifted the relative permeability cross-point towards more water-wet condition. Finally, calcite dissolution caused a reduction in capillary pressure of the used carbonate rock. For CO2 underground injection applications, such changes in relative permeabilities, residual trapping potential of the non-wetting phase (CO2) and capillary pressure would reduce the CO2 storage capacity and increase the risk of CO2 leakage.

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18

NAKO, Masao, and Masaji FUJIOKA. "Multi Well Pilot Test for JCOP-Japan CO2 Geosequestration in Coal Seams Project-." Shigen-to-Sozai 121, no. 9 (2005): 461–64. http://dx.doi.org/10.2473/shigentosozai.121.461.

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19

Wang, G. X., P. Massarotto, and V. Rudolph. "An improved permeability model of coal for coalbed methane recovery and CO2 geosequestration." International Journal of Coal Geology 77, no. 1-2 (January 2009): 127–36. http://dx.doi.org/10.1016/j.coal.2008.10.007.

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20

Loh, Zoë, Ray Leuning, Steve Zegelin, David Etheridge, Mei Bai, Travis Naylor, and David Griffith. "Testing Lagrangian atmospheric dispersion modelling to monitor CO2 and CH4 leakage from geosequestration." Atmospheric Environment 43, no. 16 (May 2009): 2602–11. http://dx.doi.org/10.1016/j.atmosenv.2009.01.053.

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21

Zhang, Kaizhong, Wei Li, Yuanping Cheng, Jun Dong, Qingyi Tu, and Rong Zhang. "Microscale Research on Effective Geosequestration of CO2 in Coal Reservoir: A Natural Analogue Study in Haishiwan Coalfield, China." Geofluids 2018 (2018): 1–12. http://dx.doi.org/10.1155/2018/3015038.

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A natural analogue study in CO2-rich coalfield (Haishiwan, China) provides a strong support for safe, reliable, and long-term storage by analyzing the mechanism of CO2 migration, entrapment, and storage in coal reservoir. Thus, effects of geological tectonism on reservoir properties were investigated. Simultaneously, coal and oil shale samples before and after supercritical CO2 (SCCO2) treatment via geochemical reactor were collected to analyze changes in pore structure, functional group distributions, and SCCO2 extraction. Observations from in situ properties of coal seam indicate that there is a positive relationship with CH4 contents and F19 fault whereas CO2 and carbonate contents decrease as the distance from F19 increases. Analysis of pore properties reveals that SCCO2 enlarges the development of coal pore and facilitates the diffusion and seepage channel of coal reservoir, while no changes in larger pores are found in oil shale, which may restrain fluids from passing through. Then, oxygen-containing functional groups are mobilized by SCCO2 from oil shale, associated with a decrease in sorption sites. The sealing capacity of cap rock (oil shale) and geological tectonism (F19 fault), as the major contributors to CO2 enrichment and accumulation, provides insights into the suitable selection of CCGS site for long geological time.

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22

Sun, Jingyue, Haopo Xu, Cong Chen, Tonglai Li, Weizhong Li, and Yan Qin. "CO2 Adhesion Characteristics on Solid Surfaces under CO2 Geologic Sequestration Environment." Geofluids 2022 (February 25, 2022): 1–14. http://dx.doi.org/10.1155/2022/9275688.

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Wettability at mineral-CO2 interface in CGS (carbon geosequestration) is a key parameter for risk assessments and storage capacity estimations. Many studies of wettability achieved inconsistent results, while adhesion could be a potential mechanism causing huge wettability alteration. CO2 adhesion characteristics have been revealed for CO2/brine/mica system under a wide range of pressures, temperatures, and salinities by analyzing static and dynamic contact angles. Under all experiment conditions, the average static CA ranges from 19.5° to 32.1°. In 8 MPa experiments, CA decreases from 26.0° to 19.5° with the increasing salinity. Similar trends were also observed under 12 MPa condition. However, CA does not show clear dependence on pressure. A concentric probe was designed by which vertical position of the probe can be changed by rotating the screw of the probe holder while horizontal degrees of freedom are restricted. With this concentric probe, contact angles were obtained at different positions of the same sample to investigate the effect of heterogeneity of sample surface. Uncertainty and large hysteresis of dynamic contact angles were found which related with measurement positions. These large hystereses as obvious sign of adhesion had good repeatability at specific surface positions. Further electron microscope test demonstrated the correlation between large hysteresis and smoother surfaces which is consistent with the DLVO theory-based water film thickness hypothesis on adhesion. This study enriched the data on the wettability of mica and may shed light on CO2 adhesion on solid surfaces for better understanding the fate of CO2 during sequestration.

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23

Hajiabadi, Seyed Hasan, Pavel Bedrikovetsky, Sara Borazjani, and Hassan Mahani. "Well Injectivity during CO2 Geosequestration: A Review of Hydro-Physical, Chemical, and Geomechanical Effects." Energy & Fuels 35, no. 11 (May 17, 2021): 9240–67. http://dx.doi.org/10.1021/acs.energyfuels.1c00931.

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24

Wei, Xiao Chen, Qi Li, Xia-Ying Li, Yan-Kun Sun, and Xue Hao Liu. "Uncertainty analysis of impact indicators for the integrity of combined caprock during CO2 geosequestration." Engineering Geology 196 (September 2015): 37–46. http://dx.doi.org/10.1016/j.enggeo.2015.06.023.

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25

Sun, Yankun, Qi Li, Duoxing Yang, and Xuehao Liu. "Laboratory core flooding experimental systems for CO2 geosequestration: An updated review over the past decade." Journal of Rock Mechanics and Geotechnical Engineering 8, no. 1 (February 2016): 113–26. http://dx.doi.org/10.1016/j.jrmge.2015.12.001.

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26

Zuo-tang, Wang, Wang Guo-xiong, Rudolph V., Diniz da Costa J. C., Huang Pei-ming, and Xin Lin. "Simulation of CO2-geosequestration enhanced coal bed methane recovery with a deformation-flow coupled model." Procedia Earth and Planetary Science 1, no. 1 (September 2009): 81–89. http://dx.doi.org/10.1016/j.proeps.2009.09.015.

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27

Wei, Xiaochen, Qi Li, Xiaying Li, and Yankun Sun. "Impact indicators for caprock integrity and induced seismicity in CO2 geosequestration: insights from uncertainty analyses." Natural Hazards 81, no. 1 (November 2, 2015): 1–21. http://dx.doi.org/10.1007/s11069-015-2063-5.

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28

Arzanfudi, Mehdi Musivand, Sanaz Saeid, Rafid Al-Khoury, and L. J. Sluys. "Multidomain-staggered coupling technique for Darcy–Navier Stokes multiphase flow: An application to CO2 geosequestration." Finite Elements in Analysis and Design 121 (November 2016): 52–63. http://dx.doi.org/10.1016/j.finel.2016.07.011.

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29

Hooper, B., B. Koppe, and L. Murray. "COMMERCIAL AND TECHNICAL ISSUES FOR LARGE-SCALE CARBON CAPTURE AND STORAGE PROJECTS—A GIPPSLAND BASIN STUDY." APPEA Journal 46, no. 1 (2006): 435. http://dx.doi.org/10.1071/aj05025.

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The Latrobe Valley in Victoria’s Gippsland Basin is the location of one of Australia’s most important energy resources—extremely thick, shallow brown coal seams constituting total useable reserves of more than 50,000 million tonnes. Brown coal has a higher moisture content than black coal and generates more CO2 emissions per unit of useful energy when combusted. Consequently, while the Latrobe Valley’s power stations provide Australia’s lowest- cost bulk electricity, they are also responsible for over 60 million tonnes of CO2 emissions per year—over half of the Victorian total. In an increasingly carbon constrained world the ongoing development of the Latrobe Valley brown coal resource is likely to require a drastic reduction in the CO2 emissions from new coal use projects—and carbon capture and storage (CCS) has the potential to meet such deep cuts. The offshore Gippsland Basin, the site of major producing oil and gas fields, has the essential geological characteristics to provide a high-volume, low-cost site for CCS. The importance of this potential to assist the continuing use of the nation’s lowest-cost energy source prompted the Australian Government to fund the Latrobe Valley CO2 Storage Assessment (LVCSA).The LVCSA proposal was initiated by Monash Energy (formerly APEL, and now a 100% subsidiary of Anglo American)—the proponent of a major brown coal-to-liquids plant in the Latrobe Valley. Monash Energy’s plans for the 60,000 BBL per day plant include CCS to store about 13 million tonnes of CO2 per year. The LVCSA, undertaken for Monash Energy by the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC), provides a medium to high-level technical and economic characterisation of the volume and cost potential for secure geosequestration of CO2 produced by the use of Latrobe Valley brown coal (Hooper et al, 2005a). The assessment’s scope includes consideration of the interaction between CO2 injection and oil and gas production, and its findings have been publicly released for use by CCS proponents, oil and gas producers and all other interested parties as an executive summary, (Hooper et al, 2005b), a fact sheet (Hooper et al, 2005c) and a presentation (Hooper et al, 2005d)).The LVCSA identifies the key issues and challenges for implementing CCS in the Latrobe Valley and provides a reference framework for the engagement of stakeholders. In effect the LVCSA constitutes a pre-feasibility study for the implementation of geosequestration in support of the continuing development of Victoria’s brown coal resources.The LVCSA findings indicate that the Gippsland Basin has sufficient capacity to safely and securely store large volumes of CO2 and may provide a viable means of substantially reducing greenhouse gas emissions from coal-fired power plants and other projects using brown coal in the Latrobe Valley. The assessment also indicates that CO2 injection could well be designed to avoid any adverse impact on adjacent oil and gas production, so that CO2 injection can begin near fields that have not yet come to the end of their productive lives. However, CCS proposals involving adjacent injection and production will require more detailed risk management strategies and continuing cooperation between prospective injectors and existing producers.

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Zhang, Xiang, Bing Wei, Jing Shang, Ke Gao, Wanfen Pu, Xingguang Xu, Colin Wood, and Lin Sun. "Alterations of geochemical properties of a tight sandstone reservoir caused by supercritical CO2-brine-rock interactions in CO2-EOR and geosequestration." Journal of CO2 Utilization 28 (December 2018): 408–18. http://dx.doi.org/10.1016/j.jcou.2018.11.002.

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Schädle, Thomas, Bobby Pejcic, Matthew Myers, and Boris Mizaikoff. "Portable Mid-Infrared Sensor System for Monitoring CO2 and CH4 at High Pressure in Geosequestration Scenarios." ACS Sensors 1, no. 4 (March 2016): 413–19. http://dx.doi.org/10.1021/acssensors.5b00246.

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Kou, Zuhao, Dongxu Zhang, Zhuoting Chen, and Yaxi Xie. "Quantitatively determine CO2 geosequestration capacity in depleted shale reservoir: A model considering viscous flow, diffusion, and adsorption." Fuel 309 (February 2022): 122191. http://dx.doi.org/10.1016/j.fuel.2021.122191.

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Hoffman, Nick, and Natt Arian. "The Latrobe Group and the 90-million-year beach." APPEA Journal 53, no. 2 (2013): 460. http://dx.doi.org/10.1071/aj12071.

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Carbon dioxide geosequestration requires a detailed understanding of the whole sedimentary section, with particular emphasis on topseals and intraformational seals. Hydrocarbon exploration is more focused on reservoirs but requires a similar basin understanding. This extended abstract reviews the knowledge gained from petroleum exploration in the Gippsland Basin to The CarbonNet Project’s exploration program for CO2 storage. The Ninety Mile Beach on the Gippsland coast is a prominent modern-day sand fairway where longshore drift transports sediments north-eastwards along a barrier-bar system, trapping lake systems behind the coastal strip. This beach is only 10,000 years old (dating to the last glacial rise of sea level) but is built on a platform of earlier beaches that can be traced back almost 90 million years to the initiation of Latrobe Group deposition in the Gippsland Basin. Using a recently compiled and open-file volume of merged 3D seismic surveys, the authors show the evolution of the Latrobe shoreline can be mapped continuously from the Upper Cretaceous to the present day. Sand fairways accumulate as a barrier-bar system at the edge of a steadily subsiding marine embayment, with distinct retrogradational geometries. Behind the barrier system, a series of trapped lakes and lagoons are mapped. In these, coal swamps, extensive shales, and tidal sediments were deposited at different stages of the sea-level curve, while fluvial systems prograded through these lowlands. Detailed 3D seismic extractions show the geometry, orientation and extent of coals, sealing shales, fluvial channels, and bayhead deltas. Detailed understanding of these reservoir and seal systems outlines multi-storey play fairways for hydrocarbon exploration and geosequestration. Use of modern basin resource needs careful coordination of activity and benefits greatly from established data-sharing practices.

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Northrop, P. Scott, and Jaime A. Valencia. "The CFZ™ process: A cryogenic method for handling high- CO2 and H2S gas reserves and facilitating geosequestration of CO2 and acid gases." Energy Procedia 1, no. 1 (February 2009): 171–77. http://dx.doi.org/10.1016/j.egypro.2009.01.025.

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Yurikov, Alexey, Konstantin Tertyshnikov, Sinem Yavuz, Pavel Shashkin, Roman Isaenkov, Evgenii Sidenko, Stanislav Glubokovskikh, Paul Barraclough, and Roman Pevzner. "Seismic monitoring of CO2 geosequestration using multi-well 4D DAS VSP: Stage 3 of the CO2CRC Otway project." International Journal of Greenhouse Gas Control 119 (September 2022): 103726. http://dx.doi.org/10.1016/j.ijggc.2022.103726.

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Varma, Sunil, Jim Underschultz, Tess Dance, Robert Langford, Joan Esterle, Kevin Dodds, and Dominique van Gent. "Regional study on potential CO2 geosequestration in the Collie Basin and the Southern Perth Basin of Western Australia." Marine and Petroleum Geology 26, no. 7 (August 2009): 1255–73. http://dx.doi.org/10.1016/j.marpetgeo.2008.05.001.

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Sminchak, J. R., Mark Moody, Andrew Theodos, Glenn Larsen, and Neeraj Gupta. "Investigation of Wellbore Integrity Factors in Historical Oil and gas Wells for CO2 Geosequestration in the Midwestern U.S." Energy Procedia 63 (2014): 5787–97. http://dx.doi.org/10.1016/j.egypro.2014.11.611.

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38

Chu, Hongyang, Xinwei Liao, Zhiming Chen, Wenyuan Liu, Lingyu Mu, and Hui Liu. "A new methodology to assess the maximum CO2 geosequestration capacity of shale reservoirs with SRV based on wellbore pressure." Journal of CO2 Utilization 34 (December 2019): 239–55. http://dx.doi.org/10.1016/j.jcou.2019.06.010.

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39

Gonçalves, Luís Carlos, Pedro Sebastião, Nuno Souto, and Américo Correia. "One Step Greener: Reducing 5G and Beyond Networks’ Carbon Footprint by 2-Tiering Energy Efficiency with CO2 Offsetting." Electronics 9, no. 3 (March 10, 2020): 464. http://dx.doi.org/10.3390/electronics9030464.

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Fifth generation (5G) and Beyond-5G (B5G) will be characterized by highly dense deployments, both on network plane and user plane. Internet of Things, massive sensor deployments and base stations will drive even more energy consumption. User behavior towards mobile service usage is witnessing a paradigm shift with heavy capacity, demanding services resulting in an increase of both screen time and data transfers, which leads to additional power consumption. Mobile network operators will face additional energetic challenges, mainly related to power consumption and network sustainability, starting right in the planning phase with concepts like energy efficiency and greenness by design coming into play. The main contribution of this work is a two-tier method to address such challenges leading to positively-offset carbon dioxide emissions related to mobile networks using a novel approach. The first tier contributes to overall power reduction and optimization based on energy efficient methods applied to 5G and B5G networks. The second tier aims to offset the remaining operational power usage by completely offsetting its carbon footprint through geosequestration. This way, we show that the objective of minimizing overall networks’ carbon footprint is achievable. Conclusions are drawn and it is shown that carbon sequestration initiatives or program adherence represent a negligible cost impact on overall network cost, with the added value of greener and more environmentally friendly network operation. This can also relieve the pressure on mobile network operators in order to maximize compliance with environmentally neutral activity.

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Boreham, Chris, Jim Underschultz, Linda Stalker, Barry Freifeld, Dirk Kirste, Ulrike Schacht, Ernie Perkins, Jonathan Ennis-King, Peter Dumesny, and Sandeep Sharma. "Geochemistry monitoring of CO2 storage at the CO2CRC Otway Project, Victoria: operational mode." APPEA Journal 49, no. 2 (2009): 602. http://dx.doi.org/10.1071/aj08075.

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The CO2CRC Otway Project is an Australian-first, demonstration-scale CO2 geosequestration experiment. It incorporates a wide-ranging monitoring and verification operation, including the injection of chemical tracers and the geochemical characterisation of the subsurface fluids sampled from the Naylor—1 monitoring well multi-zone U-tube system. Following the successful collection of baseline gas and fluid samples, injection began in April 2008 and by September 2008 over 20,000 tonnes of the projected total of ∼100,000 tonnes of supercritical CO2 has been injected into the depleted Waarre C unit of the Naylor gas reservoir in the Otway Basin. Critical operational issues revolved around the timing of the chemical tracer injection at the CRC—1 injection well and the on-going maintenance and modifications to the U-tube sampling assembly. The latter resulted from two things:a hazard and operability study (HAZOP), which specifically addressed the continued integrity of the U-tube assembly and the safe collection and disposal of pressurised gases and formation waters, and the need for an innovative solution to mitigate against hydrocarbon wax precipitaton inside the U-tubes that would have jeopardise retrieval of sub-surface samples. A solvent delivery and retrieval system involving Solvesso—100TM was deployed following a mini-HAZOP. Breakthrough was initially confirmed by tracer detection at Naylor—1 approximately four months after injection began, whereas changes in the inorganic geochemical signatures were observed a few weeks later. This has validated the sub-surface monitoring strategy and resulted in refinements to fluid flow models and expanded our understanding of geochemical processes. Furthermore, supercritical CO2 injection has resulted in the lowering of the gas-water contact at Naylor—1 and the progressive gassing out of the deeper U-tubes. Weekly to fortnightly U-tube sampling will continue until supercritical CO2 is established at Naylor—1 following which the frequency of sampling will be reviewed for the rest of the injection period.

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Van Gent, Dominique, Martin Burke, and Sandeep Sharma. "South West Hub Project, Western Australia: appraising ‘migration-assisted' containment for carbon storage in sandstone strata." APPEA Journal 57, no. 2 (2017): 669. http://dx.doi.org/10.1071/aj16024.

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The South West Hub project (SW Hub) managed by the Department of Mines and Petroleum (DMP) Carbon Strategy Branch, is continuing to build confidence in storage associated with migration assisted trapping (MAT) in unconfined saline aquifers. The area of interest is in the Harvey and Waroona Shires near large CO2 emission sources in the industrial centres of Kwinana and Collie. The injection target is the Lower Lesueur sandstone, a 1500 m thick reservoir with varying permeability layers that should support residual and solubility trapping. The storage complex has no regional shale layer and depends on MAT for primary containment, with the 600 m thick Upper Lesueur with its numerous paleosol baffles as the lower confining layer and the basal shale part of the Eneabba Formation as the upper confining layer. Detailed models have been built based on new 2D/3D seismic surveys and core/log data from the drilling of four wells over a five year period. The results, which include extensive sensitivity analysis, indicate that commercial quantities of CO2 may be injected safely with the plume remaining within the injection reservoir. Uncertainties do remain and the next stage of the program is aimed at reducing these. Significant technical work has also been done through research projects executed by the National Geosequestration Laboratory (NGL) and funded by the Australian National Low Emissions Coal research and development program (ANLEC R&D). This paper will summarise the geological setting, the technical workflow/activities and assurance processes together with the significant community and stakeholder management efforts undertaken.

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42

Yekeen, Nurudeen, Javed Akbar Khan, Muhammad Ali, Khaled Abdalla Elraies, Oluwagade Adenike Okunade, Syahrir Ridha, and Ahmed Al-Yaseri. "Impact of nanoparticles–surfactant solutions on carbon dioxide and methane wettabilities of organic-rich shale and CO2/brine interfacial tension: Implication for carbon geosequestration." Energy Reports 8 (November 2022): 15669–85. http://dx.doi.org/10.1016/j.egyr.2022.10.377.

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43

Isaenkov, Roman, Roman Pevzner, Stanislav Glubokovskikh, Sinem Yavuz, Alexey Yurikov, Konstantin Tertyshnikov, Boris Gurevich, et al. "An automated system for continuous monitoring of CO2 geosequestration using multi-well offset VSP with permanent seismic sources and receivers: Stage 3 of the CO2CRC Otway Project." International Journal of Greenhouse Gas Control 108 (June 2021): 103317. http://dx.doi.org/10.1016/j.ijggc.2021.103317.

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Whitford, D. J., and J. Pullar. "AUSTRALIA’S GAS FUTURE—A RESEARCH AND DEVELOPMENT PERSPECTIVE." APPEA Journal 47, no. 1 (2007): 251. http://dx.doi.org/10.1071/aj06016.

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Australia’s large natural gas resource offers the prospect of a secure and competitive supply of transport, domestic and industrial fuels, lower emissions and an opportunity for significant wealth generation. Although the use of gas is growing fast, there remain significant technological hurdles that must be overcome before its full potential is realised. Many of the technical issues have a distinctive Australian dimension that demand local solutions—we cannot necessarily rely on imported technology.In consultation with industry, government and other research and development providers, CSIRO has developed a gas technology roadmap that provides the basis for an integrated research program in support of the Australian gas industry. The roadmap addresses the needs of both the conventional and unconventional gas industries and covers the value chain from exploration, production and processing, to utilisation and end use.In the context of ensuring a reliable and secure supply of competitively priced gas, two research streams have been identified, focussing on accessing remote conventional gas that is economically stranded, and unlocking Australia’s large unconventional gas resources to supply the southeast quadrant. Gas is an intrinsically cleaner fuel than oil or coal in terms of CO2 emissions and specific research opportunities in geosequestration, gas-based alternative fuels and distributed energy have been identified.Gas in the form of LNG is a fast-growing export industry enhancing Australia’s position as a leading energy exporter. There are opportunities for research and development to contribute to LNG, gas-to-liquids (GTL) fuel conversion as well as the greater use of gas for large-scale resource developments. Given the diversity and range of research opportunities, Australia has the potential to become a global leader in gas technologies with the chance to grow knowledge-based exports in addition to the export of rawfuels and embedded-energy products.

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45

Mu, Andre, and John W. Moreau. "The geomicrobiology of CO2 geosequestration: a focused review on prokaryotic community responses to field-scale CO2 injection." Frontiers in Microbiology 6 (April 9, 2015). http://dx.doi.org/10.3389/fmicb.2015.00263.

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46

Ofori, Kofi, Chi M. Phan, Ahmed Barifcani, and Stefan Iglauer. "Some Interfacial Properties of Water and CO2/H2S at Quasireservoir Conditions: A Molecular Dynamics Study." SPE Journal, November 1, 2022, 1–13. http://dx.doi.org/10.2118/212843-pa.

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Summary Interfacial properties are important in the process of geosequestering acid gases in the presence of formation water. However, to a considerable extent, the information from molecular interactions is not obtainable experimentally. Theoretically, this limitation is due to a dearth of data at reservoir conditions (i.e., high pressures and elevated temperatures). Hence, molecular dynamics (MD) is used to study interfacial interactions such as interfacial tension (IFT) as a function of temperature and pressure through the mechanical pressure tensor method, acid gas adsorption onto water and absorption into water, pair correlation functions, and density profiles. Simulations were carried out isothermally at 77°C with pressures ranging from 0.5 to 15.6 MPa. The predicted water densities, ρ, and acid gas [CO2/H2S, with the NERD (Nath, Escobedo and de Pablo) H2S potential] densities matched the experimental values well. The two force fields used to simulate water-acid gas IFTs, γ, both overpredict the experimental values, especially at the higher pressures, but the water-OPLS (optimized potentials for liquid simulations) H2S acid gas combination’s γ is closer to the experimental ideal. The overpredictions are primarily due to the supercritical nature of the fluids and the force fields used. Radial distribution functions (RDFs) of the various combinations were also examined, and they were found to demonstrate the supercritical nature of the fluids and the molecular interaction between the constituent components of the acid gas and water. The interfacial thickness, δ, revealed further insights into the molecular structure and was found to be typically in the 4.0–7.5 Å range and is influenced by mainly the acid gas adsorption onto the water surface and to a lesser extent absorption into the bulk water. It was found that CO2 is more dominant than H2S at the water interfacial layer and that CO2-water interactions contributed more toward the overall interfacial properties. Our findings further suggest that the predomination of interactions by CO2 in the system, coupled with the weak interactivity between CO2 and H2S, means that CO2 geosequestration, at least in the 70 mol%CO2 and 30 mol%H2S used in this work, and by extension for higher CO2 mole percentages, does not face any meaningful impediment from the H2S presence during the process. In the absence of nigh impossible to achieve experiments at these extreme temperature and pressure conditions, the findings of this MD study thus offer a better understanding of some of the geological interactions of fluid-fluid mixtures in the presence of formation water and the application of this information during geosequestration.

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Mu, Andre, Chris Boreham, Henrietta X. Leong, Ralf R. Haese, and John W. Moreau. "Changes in the deep subsurface microbial biosphere resulting from a field-scale CO2 geosequestration experiment." Frontiers in Microbiology 5 (May 14, 2014). http://dx.doi.org/10.3389/fmicb.2014.00209.

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Sidenko, Evgenii, Konstantin Tertyshnikov, Andrej Bona, and Roman Pevzner. "DAS-VSP interferometric imaging: CO2CRC Otway Project feasibility study." Interpretation, August 31, 2021, 1–71. http://dx.doi.org/10.1190/int-2021-0038.1.

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Recent advancements in DAS technology open new ways for borehole-based seismic monitoring of CO2 geosequestration. Compared to 4D surface seismic monitoring, repeated VSP surveys with DAS receivers reduce the cost and invasiveness of time-lapse CO2 monitoring considerably. However, standard borehole imaging techniques cannot provide the same level of reservoir illumination as 3D surface seismic. The performance of VSP imaging can be significantly improved with interferometric utilization of free-surface multiples. We present results of a feasibility study of interferometric imaging with a synthetic walkaway VSP dataset, followed by its application to field walkaway VSP data recorded by conventional borehole geophones and two types of DAS (standard and engineered fibers). Both experiments (synthetic and field) demonstrate that interferometric imaging is a viable method to extend the subsurface image beyond the coverage of standard VSP imaging. Specifically, the interferometry approach provides a more detailed upper section of the subsurface, while standard migration of primary reflections provides a more detailed bottom part of the image. Comparison of the standard and engineered fibers shows that both fibers are sensitive to free-surface multiples, but the engineered fiber provides much higher signal to noise ratio, and thus is preferable for interferometric imaging with multiples. The result obtained with the engineered DAS cable shows that in the depth range suitable for both methods, the VSP interferometric image of reflectors is comparable to the surface seismic image. The experiment on the field DAS data proves that DAS is sensitive enough to record the non-primary wavefield for imaging and monitoring of the subsurface.

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