Groundwater Anomaly Related to CCS-CO2 Injection and the 2018 Hokkaido Eastern Iburi Earthquake in Japan

Carbon capture and storage (CCS) is considered a key technology for reducing CO2 emissions into the atmosphere. Nonetheless, there are concerns that if injected CO2 migrates in the crust, it may trigger slip of pre-existing faults. In order to test if this is the case, covariations of carbon, hydrogen, and oxygen isotopes of groundwater measured from Uenae well, southern Hokkaido, Japan are reported. This well is located 13 km away from the injection point of the Tomakomai CCS project and 21 km from the epicenter of September 6th, 2018 Hokkaido Eastern Iburi earthquake (M 6.7). Carbon isotope composition was constant from June 2015 to February 2018, and decreased significantly from April 2018 to November 2019, while total dissolved inorganic carbon (TDIC) content showed a corresponding increase. A decrease in radiocarbon and δ13C values suggests aquifer contamination by anthropogenic carbon, which could possibly be attributable to CCS-injected CO2. If such is the case, the CO2 enriched fluid may have initially migrated through permeable channels, blocking the fluid flow from the source region, increasing pore pressure in the focal region and triggering the natural earthquake where the brittle crust is already critically stressed.

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COMMERCIAL AND TECHNICAL ISSUES FOR LARGE-SCALE CARBON CAPTURE AND STORAGE PROJECTS—A GIPPSLAND BASIN STUDY

The APPEA Journal ◽

10.1071/aj05025 ◽

2006 ◽

Vol 46 (1) ◽

pp. 435

Author(s):

B. Hooper ◽

B. Koppe ◽

L. Murray

Keyword(s):

Co2 Emissions ◽

Brown Coal ◽

Carbon Capture ◽

Oil And Gas ◽

Carbon Capture And Storage ◽

Gas Production ◽

Co2 Injection ◽

Oil And Gas Production ◽

Gippsland Basin ◽

And Storage

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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Assessing Potential Thermo-Mechanical Impacts on Caprock Due to CO2 Injection—A Case Study from Northern Lights CCS

Energies ◽

10.3390/en14165054 ◽

2021 ◽

Vol 14 (16) ◽

pp. 5054

Author(s):

Nicholas Thompson ◽

Jamie Stuart Andrews ◽

Tore Ingvald Bjørnarå

Keyword(s):

Effective Stress ◽

Carbon Capture ◽

Storage System ◽

Carbon Capture And Storage ◽

Development Planning ◽

Co2 Injection ◽

Field Development ◽

Stress Changes ◽

Pressure Changes ◽

And Storage

Due to significant temperature differences between the injected medium and in situ formation, injection of CO2 (as with water or other cold fluids) at depth induces thermal changes that must be accounted for a complete understanding of the mechanical integrity of the injection/storage system. Based on evaluations for the Northern Lights Carbon Capture and Storage (CCS) project, we focus on thermal effects induced on the caprock via conduction from cooling in the storage sands below. We investigate, using both analytical and numerical approaches, how undrained effects within the low permeability caprock can lead to volumetric contraction differences between the rock framework and the pore fluid which induce both stress and pore pressure changes that must be properly quantified. We show that such undrained effects, while inducing a more complicated response in the stress changes in the caprock, do not necessarily lead to unfavourable tensile conditions, and may, in fact, lead to increases in effective stress. These observations build confidence in the integrity of the caprock/seal system. We also show, through conservative assumptions, that pressure communication between the caprock and storage sands may lead to a localised negative effective stress condition, challenging stability of the base caprock, which will be mitigated for in field development planning.

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Periodic CO2 Injection for Improved Storage Capacity and Pressure Management under Intermittent CO2 Supply

Energies ◽

10.3390/en15020566 ◽

2022 ◽

Vol 15 (2) ◽

pp. 566

Author(s):

Anton Shchipanov ◽

Lars Kollbotn ◽

Mauro Encinas ◽

Ingebret Fjelde ◽

Roman Berenblyum

Keyword(s):

Feasibility Study ◽

Carbon Capture ◽

Storage Capacity ◽

Carbon Capture And Storage ◽

Geological Structure ◽

Co2 Injection ◽

Storage Site ◽

Pressure Management ◽

Field Scale ◽

And Storage

Storing CO2 in geological formations is an important component of reducing greenhouse gases emissions. The Carbon Capture and Storage (CCS) industry is now in its establishing phase, and if successful, massive storage volumes would be needed. It will hence be important to utilize each storage site to its maximum, without challenging the formation integrity. For different reasons, supply of CO2 to the injection sites may be periodical or unstable, often considered as a risk element reducing the overall efficiency and economics of CCS projects. In this paper we present outcomes of investigations focusing on a variety of positive aspects of periodic CO2 injection, including pressure management and storage capacity, also highlighting reservoir monitoring opportunities. A feasibility study of periodic injection into an infinite saline aquifer using a mechanistic reservoir model has indicated significant improvement in storage capacity compared to continuous injection. The reservoir pressure and CO2 plume behavior were further studied revealing a ‘CO2 expansion squeeze’ effect that governs the improved storage capacity observed in the feasibility study. Finally, the improved pressure measurement and storage capacity by periodic injection was confirmed by field-scale simulations based on a real geological set-up. The field-scale simulations have confirmed that ‘CO2 expansion squeeze’ governs the positive effect, which is also influenced by well location in the geological structure and aquifer size, while CO2 dissolution in water showed minor influence. Additional reservoir effects and risks not covered in this paper are then highlighted as a scope for further studies. The value of the periodic injection with intermittent CO2 supply is finally discussed in the context of deployment and integration of this technology in the establishing CCS industry.

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Why CCS? Milestone on Research and Regulation Coverages

KnE Energy ◽

10.18502/ken.v1i1.346 ◽

2015 ◽

Vol 1 (1) ◽

pp. 13

Author(s):

Aisyah Kusuma ◽

Eko Widianto ◽

Rachmat Sule ◽

Wawan Gunawan A. Kadir ◽

Mega S. Gemilang

Keyword(s):

Oil Recovery ◽

Carbon Capture ◽

Carbon Emission ◽

Fossil Fuels ◽

Co2 Storage ◽

Carbon Capture And Storage ◽

Point Sources ◽

Co2 Injection ◽

Road Map ◽

And Storage

Further to Kyoto Protocol, again in 2009 G-20 Pittsburg Summit, Indonesia delivered the commitment on reducing 26% on its emission level. Moreover, as non-annex 1 country, Indonesia shows strong and bold commitment in supporting reduction on increased concentrations of greenhouse gases produced by human activities such as burning the fossil fuels and deforestation. From the energy sector, Carbon Capture and Storage (CCS) is known as a process of capturing waste carbon dioxide (CO2) from large point sources and depositing it normally at an underground geological formation. CCS becomes now as one of the possible supports to the country commitment. In Indonesia, the potential of CCS applications could be conducted in the gas fields with high content of CO2 and in almost depleted oil fields (by applying CO2-Enchanced Oil Recovery (EOR) The CCS approach could also be conducted in order to increase hydrocarbon production, and at the same time the produced CO2 will be injected and storage it back to the earth. Thus, CCS is a mitigation process in enhancing carbon emission reduction caused by green house effect from production hydrocarbon fields.This paper will show a proposed milestone on CCS Research roadmap, as steps to be taken in reaching the objective. The milestone consists of the study for identifying potential CO2 sources, evaluating CO2 storage sites, detail study related to CO2 storage selection, CO2 injection, and CO2 injection monitoring. Through these five steps, one can expect to be able to comprehend road map of CCS Research. Through this research milestone, applications of CCS should also be conducted based on the regulatory coverage milestone. From this paper, it is hoped that one can understand the upstream activities starting with research milestone to the very end downstream activities regarding to the regulation coverage bound. Keywords: CCS, reduction of carbon emission, regulation umbrella

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Evaluating Reservoir Risks and Their Influencing Factors during CO2 Injection into Multilayered Reservoirs

Geofluids ◽

10.1155/2017/6059142 ◽

2017 ◽

Vol 2017 ◽

pp. 1-14 ◽

Cited By ~ 1

Author(s):

Lu Shi ◽

Bing Bai ◽

Haiqing Wu ◽

Xiaochun Li

Keyword(s):

Flow Rate ◽

Risk Evaluation ◽

Carbon Capture ◽

Lower Layer ◽

Carbon Capture And Storage ◽

Injection Pressure ◽

Co2 Injection ◽

Rate Distribution ◽

Injection Flow ◽

And Storage

Wellbore and site safety must be ensured during CO2 injection into multiple reservoirs during carbon capture and storage projects. This study focuses on multireservoir injection and investigates the characteristics of the flow-rate distribution and reservoir-risk evaluation as well as their unique influences on multireservoir injection. The results show that more CO2 enters the upper layers than the lower layers. With the increase in injection pressure, the risks of the upper reservoirs increase more dramatically than those of the low reservoirs, which can cause the critical reservoir (CR) to shift. The CO2 injection temperature has a similar effect on the injection flow rate but no effect on the CR’s location. Despite having no effect on the flow-rate distribution, the formation-fracturing pressures in the reservoirs determine which layer becomes the CR. As the thickness or permeability of a layer increases, the inflows exhibit upward and downward trends in this layer and the lower layers, respectively, whereas the inflows of the upper layers remain unchanged; meanwhile, the risks of the lower layer and those of the others decrease and remain constant, respectively. Compared to other parameters, the reservoir porosities have a negligible effect on the reservoir risks and flow-rate distributions.

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Geoengineering and Economic Assessment of a Potential Carbon Capture and Storage Site in Southeast Queensland, Australia

SPE Reservoir Evaluation & Engineering ◽

10.2118/108924-pa ◽

2009 ◽

Vol 12 (05) ◽

pp. 660-670 ◽

Cited By ~ 6

Author(s):

Yildiray Cinar ◽

Peter R. Neal ◽

William G. Allinson ◽

Jacques Sayers

Keyword(s):

Carbon Capture ◽

Carbon Capture And Storage ◽

Injection Well ◽

Reservoir Engineering ◽

Co2 Injection ◽

Storage Site ◽

Fracture Gradient ◽

And Storage ◽

Southeast Queensland ◽

Injection Rates

Summary This paper presents geoengineering and economic sensitivity analyses and assessments of the Wunger Ridge flank carbon capture and storage (CCS) site. Both geoengineering and economics are needed to derive the number of wells required to inject a certain amount of CO2 for a given period. A numerical reservoir simulation examines injection rates ranging from 0.5 to 1.5 million tonnes of CO2 year for 25 years of injection. Primary factors affecting the ability to inject CO2 include permeability, formation fracture gradient, aquifer strength, and multiphase flow functions. Secondary factors include the solubility of CO2 in the formation brine, injection well location with respect to the flow barriers/low-permeability aquifers, model geometry including faults, grid size and refinement, and injection well type. Less significant factors include hydrodynamic effects. The economics are assessed using an internally developed technoeconomic model. The model optimizes the CO2 injection cost on the basis of geoengineering data and recent equipment costs. The overall costs depend on the initial costs of CO2 separation and source-to-sink distances and their associated pipeline costs. Secondary cost variations are highly dependent on fracture gradient, permeability, and CO2 injection rates. Depending on the injection characteristics, the specific cost of CO2 avoided is between AUS 62 and 80 per tonne. Introduction Australia's fossil-fuel fired power plants emit 194 million tonnes of CO2 each year (Mt CO2/yr), and approximately 26 Mt/yr of this comes from southeast Queensland. A multidisciplinary study has recently identified the onshore Bowen basin as having potential for geological storage of CO2 (Sayers et al. 2006a). In that paper, geological containment and injectivity and reservoir engineering simulation sensitivities showed that a target injection rate of 1.2 Mt CO2/yr over a 25-year project life span could be achieved (i.e., equivalent to injecting the emissions from a 400 MW gas based power station). This study further examines reservoir engineering and economics sensitivities.

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Performance Analysis of Cold Energy Recovery from CO2 Injection in Ship-Based Carbon Capture and Storage (CCS)

Energies ◽

10.3390/en7117266 ◽

2014 ◽

Vol 7 (11) ◽

pp. 7266-7281 ◽

Cited By ~ 6

Author(s):

Hwalong You ◽

Youngkyun Seo ◽

Cheol Huh ◽

Daejun Chang

Keyword(s):

Performance Analysis ◽

Energy Recovery ◽

Carbon Capture ◽

Carbon Capture And Storage ◽

Co2 Injection ◽

Cold Energy ◽

And Storage

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Simulasi difusi dan adsorpsi matriks pada proses enhanced coalbed methane

Jurnal Teknik Kimia Indonesia ◽

10.5614/jtki.2013.12.1.1 ◽

2018 ◽

Vol 12 (1) ◽

pp. 173

Author(s):

Ade Nurisman ◽

Retno Gumilang Dewi ◽

Ucok W.R. Siagian

Keyword(s):

Mathematical Model ◽

Co2 Emissions ◽

Coalbed Methane ◽

Carbon Capture ◽

Co2 Storage ◽

Carbon Capture And Storage ◽

Co2 Injection ◽

The Matrix ◽

Enhanced Coalbed Methane ◽

And Storage

Diffusion and matrix adsorption simulations in enhanced coalbed methane process. Carbon capture and storage (CCS) can be considered as one of climate change mitigation efforts, through capturing and injecting of CO2 in underground formations for reducing CO2 emissions. CO2 injection in coalbed methane (CBM) reservoir has potentially attracted for reducing CO2 emissions and enhancing coalbed methane (ECBM) recovery. Diffusion and sorption are phenomenon of gas in the matrix on CO2 injection in CBM reservoir. The objectives of the research are focused on understanding of diffusion and sorption of gas in the coal matrix with mathematical model and estimating of CO2 storage in coalbed and CH4 recovery. In this research, mathematical model is developed to describe the mechanism in the matrix on ECBM process. Mathematical model, which have been valid, is simulated in various variables, i.e. macroprosity (0.001, 0.005, and 0,01), pressure (1, 3, and 6 MPa), temperature (305, 423, and 573 K), and initial fraction of CO2 (0.05, 0.1, 0.3, and 0.5). The results of this research show that preferential sequestration of CO2 and preferential recovery of CH4 in the surface of micropore on macroporosity 0.001, pressure 1 MPa, temperature 305 K, and inital fraction CO2 0,5 conditions are 0.9936 and 0.0064.Keywords: carbon capture and storage (CCS), coalbed methane (CBM), ECBM, diffusion, adsorption Abstrak Carbon capture and storage (CCS) dapat dipertimbangkan sebagai salah satu upaya mitigasi perubahan iklim, yaitu dengan menangkap CO2 dan menginjeksikannya ke dalam formasi bawah permukaan. Injeksi CO2 pada lapangan coalbed methane (CBM) berpotensi mengurangi emisi CO2 dan meningkatkan produksi CBM (ECBM). Pada proses injeksi CO2 di lapangan CBM, fenomena yang terjadi di dalam matriks lapisan batubara (coalbed) adalah difusi dan adsorpsi. Penelitian ini bertujuan memahami fenomena difusi dan adsorpsi pada proses injeksi CO2 untuk ECBM melalui model matematika, dan memperkirakan potensi penyimpanan CO2 di dalam lapangan CBM dan potensi recovery CH4. Pada penelitian dilakukan pengembangan model matematika untuk menjelaskan fenomena di dalam matriks pada proses ECBM. Model matematika, yang telah valid, disimulasikan dengan memvariasikan beberapa variabel, yaitu makroporositas (0,001, 0,005, dan 0,01), tekanan (1, 3, dan 6 MPa), suhu (305, 423, dan 573 K), dan fraksi CO2 awal (0,05, 0,1, 0,3, dan 0,5). Hasil penelitian menunjukkan pada makroporositas 0,001, tekanan 1 Pa, suhu 305 K, dan fraksi CO2 awal 0,5, fraksi CO2 yang teradsorpsi pada permukaan mikropori bernilai 0,9936 dan sisa fraksi CH4 yang teradsorpsi pada permukaan mikropori bernilai 0,0064. Kata kunci: carbon capture and storage (CCS), coalbed methane (CBM), ECBM, difusi, adsorpsi

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