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

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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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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Geo-engineering and Economic Assessment of a Potential Carbon Capture and Storage Site in Southeast Queensland, Australia

10.2118/108924-ms ◽

2007 ◽

Cited By ~ 1

Author(s):

Yildiray Cinar ◽

Jacques Sayers ◽

Peter Ross Neal ◽

William Guy Allinson

Keyword(s):

Carbon Capture ◽

Carbon Capture And Storage ◽

Economic Assessment ◽

Storage Site ◽

And Storage ◽

Southeast Queensland ◽

Potential Carbon

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Assessing the Effect of Velocity Model Accuracy on Microseismic Interpretation at the In Salah Carbon Capture and Storage Site

Energy Procedia ◽

10.1016/j.egypro.2014.11.473 ◽

2014 ◽

Vol 63 ◽

pp. 4385-4393 ◽

Cited By ~ 7

Author(s):

Anna L. Stork ◽

James P. Verdon ◽

J.-Michael Kendall

Keyword(s):

Carbon Capture ◽

Carbon Capture And Storage ◽

Velocity Model ◽

Storage Site ◽

Model Accuracy ◽

And Storage

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

Frontiers in Earth Science ◽

10.3389/feart.2020.611010 ◽

2020 ◽

Vol 8 ◽

Author(s):

Yuji Sano ◽

Takanori Kagoshima ◽

Naoto Takahata ◽

Kotaro Shirai ◽

Jin-Oh Park ◽

...

Keyword(s):

Carbon Capture ◽

Dissolved Inorganic Carbon ◽

Isotope Composition ◽

Source Region ◽

Carbon Capture And Storage ◽

Co2 Injection ◽

Focal Region ◽

Injection Point ◽

Anthropogenic Carbon ◽

And Storage

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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The Endurance CO2 storage site, Blocks 42/25 and 43/21, UK North Sea

Geological Society London Memoirs ◽

10.1144/m52-2019-47 ◽

2020 ◽

Vol 52 (1) ◽

pp. 163-171 ◽

Cited By ~ 1

Author(s):

Jon G. Gluyas ◽

Usman Bagudu

Keyword(s):

Carbon Capture ◽

Co2 Storage ◽

Carbon Capture And Storage ◽

Lower Triassic ◽

Injection Rate ◽

Government Support ◽

Storage Site ◽

Sandstone Formation ◽

The Uk ◽

And Storage

AbstractThe Endurance, four-way, dip-closed structure in UK Blocks 42/25 and 43/21 occurs over a salt swell diapir and within Triassic and younger strata. The Lower Triassic Bunter Sandstone Formation reservoir within the structure was tested twice for natural gas (in 1970 and 1990) but both wells were dry. The reservoir is both thick and high quality and, as such, an excellent candidate site for subsurface CO2 storage.In 2013 a consortium led by National Grid Carbon drilled an appraisal well on the structure and undertook an injection test ahead of a planned development of Endurance as the first bespoke storage site on the UK Continental Shelf with an expected injection rate of 2.68 × 106 t of dense phase CO2 each year for 20 years. The site was not developed following the UK Government's removal of financial support for carbon capture and storage (CCS) demonstration projects, but it is hoped with the recent March 2020 Budget that government support for CCS may now be back on track.

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Uncertainty in regional estimates of capacity for carbon capture and storage

Solid Earth ◽

10.5194/se-10-1707-2019 ◽

2019 ◽

Vol 10 (5) ◽

pp. 1707-1715 ◽

Cited By ~ 1

Author(s):

Mark Wilkinson ◽

Debbie Polson

Keyword(s):

Carbon Capture ◽

Storage Capacity ◽

Significant Proportion ◽

Carbon Capture And Storage ◽

Saline Aquifers ◽

Storage Site ◽

Limited Data ◽

Wide Range ◽

Regional Estimates ◽

And Storage

Abstract. Carbon capture and storage (CCS) is a potentially important technology for the mitigation of industrial CO2 emissions. However, the majority of the subsurface storage capacity is in saline aquifers, for which there is relatively little information. Published estimates of the potential storage capacity of such formations, based on limited data, often give no indication of the uncertainty, despite there being substantial uncertainty associated with the data used to calculate such estimates. Here, we test the hypothesis that the uncertainty in such estimates is a significant proportion of the estimated storage capacity, and should hence be evaluated as a part of any assessment. Using only publicly available data, a group of 13 experts independently estimated the storage capacity of seven regional saline aquifers. The experts produced a wide range of estimates for each aquifer due to a combination of using different published values for some variables and differences in their judgements of the aquifer properties such as area and thickness. The range of storage estimates produced by the experts shows that there is significant uncertainty in such estimates; in particular, the experts' range does not capture the highest possible capacity estimates. This means that by not accounting for uncertainty, such regional estimates may underestimate the true storage capacity. The result is applicable to single values of storage capacity of regional potential but not to detailed studies of a single storage site.

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USING SEISMIC ATTRIBUTES TO EVALUATE LOWER PALEOZOIC AND PRECAMBRIAN STRUCTURE BENEATH A CARBON CAPTURE AND STORAGE SITE, ILLINOIS BASIN

10.1130/abs/2018am-321364 ◽

2018 ◽

Author(s):

R. William Keach ◽

◽

John H. McBride ◽

Hannes E. Leetaru

Keyword(s):

Carbon Capture ◽

Carbon Capture And Storage ◽

Seismic Attributes ◽

Illinois Basin ◽

Storage Site ◽

Lower Paleozoic ◽

And Storage

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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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