list-projects

Delimara CCS

Indira Mann — 2012-01-12T19:55:00Z

Norway's Sargas is proposing to build a 180MW or 360MW power plant in Delimara, Malta, which would include carbon capture and storage technology and aim to capture around 95% of its CO2 emissions.

The plant, which will be fuelled by coal and biomass - though gas feedstock has also been mentioned - will be assembled in the Republic of Korea, and eventually installed alongside the existing Delimara power station. The plan is to then ship the captured CO2 to Denmark, where it will be stored in depleted oil reservoirs.

Financing

Sargas aims to secure a power purchase agreement with national utility, Enemalta, with no investment and no capital expenditure required from the Maltese government. The plant is expected to cost €800 million to build.

Timing

As of November 2011, Enemalta was carrying out a technical evaluation of issues resulting from Sargas’s pre-feasibility study. After this evaluation is complete, a decision will be made on commissioning a feasibility study.

More information and press releases

Sargas controversy, Malta News portal, December 2011

Sargas controversy, Sunday Times of Malta, December 2011

Bellona article, November 2011

Malta Independent article, November 2011

Times of Malta article, November 2011

Alstom Datang

Indira Mann — 2011-11-20T21:19:17Z

China Datang Corporation and Alstom have joined forces to build and operate two CCS demonstration projects in China.

The two projects are located near China’s two biggest oilfields – Daqing in Heilongjiang province and Dongying in Shandong province, which will provide a cost-effective solution to transport and storage by using captured CO2 for enhanced oil recovery.

The 350 MW coal-fired Daqing power plant will use Alstom’s oxy-firing capture technology, while the partners are yet to decide on either oxy-firing, chilled ammonia or advanced amines for the 1000 MW Dongying coal-fired power plant.

The Daqing CCS demonstration project could be the first large-scale CCS demonstration project in China and Asia, and both projects will have the capacity to capture 1 million tonnes of CO2 per annum.

The project also aims to develop the most cost-effective CCS demo plant.

Timing

Both CCS projects are scheduled for operation in 2015. The partners signed a Memorandum of Understanding for the two projects in September 2011 and, in November, signed a feasibility study agreement for the Daqing project.

More information and press releases

Alstom press release, 10 November 2011

Alstom press release, 21 September 2011

Alstom (China) website

China Datang Corporation website

Contact

Philippe Kasse, Alstom, + 33 1 41 49 29 82

Shute Creek

Indira Mann — 2011-11-20T22:07:47Z

ExxonMobil's Shute Creek gas processing plant near LaBarge, Wyoming, is currently capturing around 7 million tonnes per annum of CO2. It is one of just eight CCS projects worldwide to have begun operating.

The CO2 is transported via Exxon, ChevronTexaco and Anadarko pipelines to several oilfields in the state for use in enhanced oil recovery operations. ChevronTexaco’s Rangely Weber oilfield is utilising captured CO2 at a rate of 1Mtpa, with Anadarko’s Salt Creek oilfield storing around 2.4Mtpa. A 400-kilometre pipeline connecting Shute Creek gas plant to the Salt Creek oilfield was completed in 2006.

Timing

ExxonMobil expanded the capacity of the capture plant using Controlled Freeze Zone capture technology in 2010, at a cost of $86 million. The installation of compressors led to a 50% higher capture rate.

The Rangely oilfield has already stored around 25 million tonnes of CO2 since EOR began in 1986. Salt Creek, which began storing CO2 in 2004, is one of the largest EOR projects in the US.

More information and press releases

Wyoming Energy News, plant expansion, December 2010

Project origins, 2008

Val Verde natural gas plants

Indira Mann — 2011-11-28T17:18:35Z

These five separate gas processing facilities in the Val Verde area of Texas, USA, capture around 1.3 million tonnes of CO2 annually for use in EOR operations at the Sharon Ridge oilfield. The dehydrated and compressed gas is transported via the Val Verde and CRC pipelines.

The five facilities are the Mitchell, Gray Ranch, Puckett, Pikes Peak and Terrell gas plants. EOR is believed to have been used at the Sharon Ridge field since 1972. The projects were formerly known as Sharon Ridge.

Companies involved include refiner Pennzoil, and Altura - one of the largest oil producers in Texas and industry leader in the EOR operations using CO2 flooding. It also has access to extensive seismic data. Altura E&P was formed by Shell and BP Amoco, and sold to Occidental in 2000. No further details are available.

Maritsa TPP

Indira Mann — 2011-11-29T13:15:00Z

Bulgaria is planning to retrofit carbon capture technology at the Maritsa Thermal Power Plant in the Stara Zagora area of the country. The project intends to eventually capture around 2.5 million tonnes per annum of CO2 at the 120MW lignite-fired power plant for storage in an onshore deep saline formation. The captured gas will be transported via new pipeline built for the project.

The project is being led by Bulgaria’s Ministry for Economy, Energy and Tourism, with Toshiba Corporation currently carrying out the feasibility study.

The Maritsa power complex
The Maritsa Iztok complex of three lignite-fired thermal power stations is the largest energy complex in south eastern Europe. It sources its entire feedstock from the area's large lignite coal basin. Maritsa Iztok-2, which is wholly owned by state energy company Bulgarian Energy Holding EAD, generates 30% of Bulgaria's electricity. Maritsa Iztok-1 is owned by AES Corporation of the US, which unveiled a new power plant in June 2011. Maritsa Iztok-3 is owned and operated by Energiina Kompaniya Maritsa Iztok 3 AD, which had been a joint venture between Italy's Enel and NEK. Enel had planned a new power plant at the site but, in June 2011, it sold its share of the existing facility to ContourGlobal LP.

Financing

Japan’s New Energy and Industrial Technology Development Organisation is sponsoring the project’s feasibility study, and funding has also been supplied by the Spanish Fund for Sustainable Development through the European Bank for Reconstruction and Development.

Timing

The feasibility study is expected to be completed in 2012, with the plant scheduled to be fully operational by 2020. The project is currently working on pipeline design and exploring potential storage sites, which have already been identified.

Naturkraft Kårstø

Audun Rødningsby — 2009-09-11T12:05:00Z

In 2006, the Norwegian Government began planning of a full-scale CO₂ capture facility from Naturkraft’s gas-fired power plant at Kårstø. The plans included a solution for transportation and secure storage of CO₂. Since then, a significant amount of preparatory work has been done, on all aspects of construction of the full-scale CCS facility.

The backdrop of the CCS project at Kårstø is to reduce emissions from one of Norway’s largest sources of CO₂. Naturkraft’s gas-fired power plant at Kårstø was commissioned the 14th of December 2007. It has an annual production capacity of up to 3.5 TWh, with CO₂ emissions of approximately 1.2 million tons of CO₂ per year at full production without carbon capture and storage. Since it was commissioned, the gas-fired power plant has had an irregular operational pattern. The power plant has been out of operation for extensive periods, resulting in reduced CO₂ emissions in comparison to a facility in continuous operation. Irregular operation of the power plant in the years to come will limit the environmental benefit of a CO₂ capture facility.

The Norwegian Government has therefore decided to halt the procurement process for the assignment of contracts to construct the CO₂ capture and storage (CCS) facility at Kårstø, until the gas-fired power plant’s operational pattern becomes clearer or other solutions that ensure regularity of production and emissions of CO₂ from the power plant become evident. At the same time, the Government will consider an integration of energy systems between the power plant and the gas processing facility at Kårstø, which may contribute to a reduction of total emissions. During the last two years the plant has been in countinious opperation exept for a few days of maintenance and there should therefore be no reasons for further postponing of this project.

The goal for the work on CCS at Kårstø is to reduce emissions from one of Norway’s largest sources of CO₂. An integration of energy systems at Kårstø involves the usage of electricity and heat from the gas-fired power plant at the gas processing facility, thereby replacing existing gas-fired compressors and boilers. The Government will consider technical and commercial aspects of an integration of this type. The results of this will be an important contribution to further work on CCS at Kårstø.

In march 2010 Gassco and Gassnova presented an Kårstø Integration pre-feasibility study. The objective of this Kårstø Integration Pre-feasibility Study was to describe potential integration opportunities at Kårstø including technical, environmental, safety, commercial issues and arrangements.

In the National Budget for 2011, presented in October 2010, were there no grants to continue the process on Kårstø. The government stated then that they will consider the future of the project during their work on the new climate policy this year.

Timing:

Original timing: Powerplant opened Nov 2007, electricity production without carbon capture and storage (2007), investment decision (2008), and commissioning (2011-2012). Delayed 2009.

Other Sources and Press Release:

ESA approved CCS project at Kårstø (March 2009)
Naturkraft’s opens November 2007
Naturkraft Karsto expected to come on stream end 2007 Electricity profile
Power technology’s overview on 420 MW Karsto power plant
Technical, economic and scheduling aspects of a CCS facility at Kårstø [PDF] (Dec 2006)
Building new power plants in a CO₂ constrained world: A Case Study from Norway on Gas-Fired Power Plants, Carbon Sequestration, and Politics [PDF] (May 2001)

European CO2 Technology Centre Mongstad

Audun Rødningsby — 2009-10-06T15:40:00Z

The CCS project at Mongstad is based on the implementation agreement between the Norwegian State and Statoil , and the Ministry of the Environment’s emission permit of October 12, 2006. The planning of the TCM project began immediately after the emission permit was granted and the implementation agreement signed. The Ministry of Petroleum and Energy signed in June 2007 an agreement on cooperation with industrial participants in the planning and preparation of TCM. The Norwegian State’s interests in the agreement were transferred in October 2007 to the state enterprise Gassnova.

The Norwegian Government presented in January 2009 a proposition to the Storting (St.prp. nr. 38 (2008-2009)) regarding investment in TCM, and on May 7, 2009 the Storting authorised the Ministry of Petroleum and Energy to invest in TCM. Based on this, StatoilHydro, Shell and the State (through Gassnova) decided to establish a technology company and commence construction of TCM. The construction time for TCM is estimated to be approximately 30 months.

To ensure that the experiences from the Technology Centre have the broadest relevance, the Technology Centre will test CO₂ capture on two types of flue gases using two capture technologies. One source of emissions is the existing catalytic cracker facility at the Mongstad Refinery and the other is emissions from the gas fired combined heat and power plant (CHP), which is under construction. Two technologies will be tested in parallel, amine technology and chilled ammonia technology. The choices of technologies were made by the TCM project on the basis of assessments of the technologies’ potential for improvements, possibilities of implementation as retrofit solutions, possibilities of full-scale application, technical maturity, environmental burden, and the possibilities of capture from sources such as coal, natural gas, and refining.

No known technologies for carbon capture from exhaust gases are fully matured, and although some technologies are more mature than others, years of development is needed. The technology centre at Mongstad will be a significant Norwegian contribution to international development of technology through the establishment of such a testing arena.

TCM will include both amine- and chilled ammonia based technologies. Access to different flue gas sources will enable testing that is relevant to both gas and coal fired power plants as well as flue gases from the industry activities.

Amine technology is considered to have a moderate technical risk, since this technology has been used in similar applications for decades. However, there is still a potential for improvements, and a need to qualify certain components of the process for a scale of at least one million t CO₂ per year. Improvements to be evaluated at TCM include process design, construction methods and cost efficiency.

The other method is the chilled ammonia technology, which has a potential for lower energy consumption per ton of CO₂ captured. This process has not been tested earlier at such a large scale, and thus represents a higher technical risk.

Timing:

Phase 1: Start-up of the cogeneration facility and pilot plant (2011/12) and Phase 2: operation of full scale plant (2018)

Other Sources and Press Release:

Video from the construction of the chilled ammonia plant by Alstom at TCM (Des 2010)

StatoilHydro submits plans to Government (February 2009)
Norwegian Government to invest in Mongstad (July 2008)
Carbon cooperation agreement at Mongstad (June 2007)
An important step towards CO₂ capture at Mongstad (June 2007)
Technology development in Norway to reduce CO₂ emissions (June 2007)
Carbon Dioxide Capture and Storage in Norway [PDF] (April 2007)
The Norwegian government and Statoil to develop a world class environmental power project at Mongstad (October 2006)

In Salah

Audun Rødningsby — 2009-10-07T10:30:00Z

The In Salah gas project in central Algeria is a joint venture between national energy company Sonatrach, BP and Statoil to produce 9 billion cubic metres of market-ready gas, a major source of gas exports to southern Europe.

The project focuses on three gas fields in the Ahnet-Timimoun Basin, where CO2 content ranges between 1% and 9%. Rather than venting the CO2 − an established practice on other similar projects − it is compressed and re-injected into the aquifer zone of one of the shallow gas reservoirs. About 1.2 million tonnes of CO2 is injected every year.

Gas produced from the Tegentour and Reg fields is dehydrated then transported 120 kilometres to a central processing facility at Krechba, where about 1.4 million cubic metres of CO2 are produced per day using amine capture technology. The CO2 is then re-injected at high pressure into the Krechba reservoir.

The venture partners have submitted a proposal to include carbon capture and storage (CCS) technologies in the Kyoto Protocol’s Clean Development Mechanism (CDM), drawing on their experience at In Salah. Their proposed approach forms part of the ongoing debate over CCS and CDM.

Other Sources and Press Release:

Monitoring CO2 storage
BP In Salah project website
Statoil In Salah project website

Bluewaters Power Station

Audun Rødningsby — 2009-10-07T10:00:00Z

Griffin Energy plans to expand its Bluewaters power station near Collie in Western Australia from two to four generating units, increasing its capacity to around 830MW. Its first two units – Bluewaters I and II – are now online, and plans for two new coal-fired, base-load generators, each capable of producing 208MW, are at the public consultation and environmental approval stage.

In its greenhouse gas management plan (July 2009) for the plant’s expansion, Griffin gave a commitment to research options for CCS. The company also said it would design the generating units to be carbon capture ready, although it has not outlined specific plans for CCS at the plant. However, it said it was likely to be a joint facility with other CO2 emitters in the Collie region.

The company aims to complete Bluewaters III and IV by 2013 and 2015, respectively. Its preferred fuel for the two new units is subcritical pulverized coal.

The Environmental Protection Agency’s (EPA) report in March 2010 on the plant expansion expressed concern that Griffin had not adequately secured land for a carbon capture plant in the future, and that it had not confirmed that the Lower Lesueur Formation and the Gage Sandstone geological formations could be used to store all CO2 from the entire lifespan of the expansion. It believes more research is needed into these potential storage sites.

At present, emission trading is being considered as a key mechanism for trying to achieve reductions in emissions.

Financing

No information available

Timing

Not yet defined for any CCS technology

More information and press releases:

Australia's EPA March 2010 report

Study into geosequestration in Collie and Perth basins 2007

Contact

Energyenquiries@thegriffingroup.com.au, or call 0061-89261 2800

Callide Oxyfuel Project

Audun Rødningsby — 2009-10-07T11:45:00Z

CS Energy’s demonstration project at Callide A power station in Biloela, in Central Queensland, is a world-first of its type. It will test the potential for low-emission electricity generation by retrofitting oxyfuel combustion technology, with a 30MW-capacity carbon capture unit, to an existing coal-fired plant.

The first stage will develop CO2 capture, and stage two will include the transport, injection and storage of captured and liquefied CO2. Results from the project will be used to inform how the technology can be applied at new power stations. The venture has identified potential storage sites to the west of Biloela, including a geological area known as the Denison Trough about 300km from the plant. It is estimated that the project could store up to 60,000 tonnes of CO2 over five years - the expected duration of the project.

The first major plant components were delivered to the site in May 2010, and work is underway on the oxygen and CO2 capture components. The demonstration is expected to start up in late 2011 and will initially run for two years.

The project is headed by CS Energy in partnership with Japan’s IHI Corporation, J-Power – which will provide project management support and expertise in low emission coal technology – and Mitsui & Co, along with Schlumberger Oilfields Australia and Xstrata Coal. It will also be supported the Australian Coal Association and the Australian and Queensland governments.

The Asia-Pacific Partnership on Clean Development and Climate considers the Callide Oxyfuel demonstration to be a flagship project.

Financing

The total estimated cost of the project is about A$206 million. Funding is being provided by the project partners along with A$50 million from Australia’s Low Emissions Technology Demonstration Fund (LETDF), and financial support from the Australian Coal Association’s COAL 21 fund and the Queensland government.

Timing

The project contract between CS Energy and Australia’s Ministry for Resources and Energy was signed in March 2008. Power generation using the oxyfuel technology is scheduled to begin in late 2011 with CO2 geo-sequestration beginning in 2012.

More information and press releases

Link to project information

Link to project press releases

Contact

Email energyinfo@csenergy.com.au or call 0061-73222 9838

Coolimba Oxy-fuel Project

Audun Rødningsby — 2009-10-07T12:15:00Z

The Coolimba Power Project, being developed by Aviva Corporation and AES, aims to build a new 2x200 MW oxyfuel-ready power station near Eneabba in the mid west of Western Australia. The project is designed with the potential to capture and store up to 90 per cent of its CO2 emissions, and incorporates plans to phase in up to 2.9 million tonnes a year of CCS – for up to 30 years – as a separate project, when feasible.

Coolimba could become one of the first commercial-scale CCS projects in Australia. It is well placed within the region’s energy hub, close to two major gas pipelines and the Perth Basin gas fields. Fuel would be sourced from the Central West coal deposit 15 kilometres south of Eneabba. The project would be a third major energy source for the region’s electricity grid. As well as the coal-fired plant, approval is being sought for up to 360MW of gas-fired power generation.

In July 2010, Australia’s Environment Ministry approved the project in part after assessing environmental approval appeals. Although the decision does not allow it to go ahead as an independent project, Aviva can now seek other interested partners. The Environmental Protection Authority (EPA) had already recommended approval in March, subject to strict conditions.

Financing

The Coolimba Power Project is estimated to cost around A$1 billion.

Timing

The project is awaiting the final report from CO2CRC on potential carbon storage sites. The recent EPA and government approvals should allow further progress. However, no further details are currently available.

More information and press releases

Link to Coolimba overview on project website

Link to Coolimba factsheet on CCS

Link to 14 July 2010 Aviva press release on approvals

Contact info

Call Coolimba project on 0061-8 9367 2344

Gorgon CO2 Injection Project

Audun Rødningsby — 2009-10-08T08:40:00Z

The Gorgon LNG Project off the north-west coast of Western Australia will include what could be the world’s largest carbon capture and storage project. Operator Chevron and its partners ExxonMobil and Shell received state approvals and licences for the overall project – which has an estimated lifespan of at least 40 years – in September 2009.

The commercial-scale CCS demonstration project will capture and store between 3.4 and 4 million tonnes of CO2 per year – a total of 120 million tonnes over the project’s lifetime, and 40 per cent of its emissions.

The CO2 will be captured directly from the gas field before being liquefied and transported by pipeline to the injection site, the Dupuy saline aquifer 2.3 km beneath Barrow Island. The project includes long-term monitoring of the stored CO2 via a number of surveillance wells and repeated seismic surveying. Chevron has a 50 per cent interest in the project, with ExxonMobil and Shell each holding a 25 per cent share.

In October 2010, the Gorgon project was formally recognised by international agency, the Carbon Sequestration Leadership Forum, at its annual meeting in Warsaw, Poland. It is one of just six CCS projects worldwide currently under construction, and satisfies the seven criteria established by the G8 nations to assess whether the goal of having 20 CCS projects in operation by 2020 is achievable.

2011 project update

Since the financial investment decision in 2009, work has continued on refining the project’s geological and dynamic simulation models and
planning for drilling injection and pressure management wells in late 2012. The design of the wells is almost complete and contracts are being negotiated for necessary equipment. One of the first contracts to be awarded was for the detailed design, construction and assurance
testing of six CO2 injection compressor trains at a cost of AU$415 million. The first compressor module is due to arrive on Barrow
Island in the second half of 2013.

Financing

The overall cost of the first phase of Gorgon LNG is A$43 billion. The Gorgon Carbon Dioxide Injection Project represents an investment of about A$2 billion. In November 2006, the Australian government announced funding support of A$60 million from its Low Emissions Technology Demonstration Fund (LETDF) for the CCS part of the project. The FID was made in September 2009.

Since 2003, the venture has invested over AU$150 million in storage appraisal. This included drilling a data well, extensive well testing and acquisition of a new 3D seismic survey.

Timing

Data wells have been drilled and a major sub-surface study has been carried out. Work is currently under way on the project infrastructure, and Gorgon is expected to begin operating by 2015.

More information and press releases

Chevron press release 9 October 2010

May 2010 project update

Project factsheet

Chevron project overview, YouTube

Chevron press release on funding decision 13 Sept 2009

ExxonMobil press release on funding decision 13 Sept 2009

Contact

Chevron Australia, 0061-9216 4000, email gorgon.info@chevron.com
ExxonMobil Australia, contact Richard Ellis on 0061-8 9320 5436

Hazelwood Carbon Capture Project

Audun Rødningsby — 2009-10-08T08:50:00Z

International Power’s post-combustion CO2 capture pilot plant at Hazelwood power station in Latrobe Valley began operating in July 2009. It has been capturing around 25 tonnes of CO2 a day, or 10,000 tonnes per year, from one 200MW unit.

The 1675MW facility burns brown coal from the adjacent Hazelwood mine, a source that produces comparatively higher amounts of CO2. The capture plant has been retrofitted to one of the power station’s eight 200MW units. The captured CO2 is removed from flue gases using ammonia absorption technology. It is then mixed with ash water to form calcium carbonate, which can be used by various industries, including the building trade. Excess CO2 is processed for industrial gas markets.

The capture plant was designed and built by Process Group, and project partner CO2CRC has provided technological support. CO2CRC is also working with the operator at Hazelwood to test three different types of CO2 capture technology as part of the CO2CRC H3 Capture project and the wider goals of the Latrobe Valley Post Combustion Capture Project.

Latrobe Valley Post Combustion Capture Project

This research project, focused mainly on Latrobe Valley in Victoria, is exploring commercially-viable methods of reducing CO2 emissions at brown coal-fired plants. CO2CRC, with researchers from Melbourne and Monash universities, are working with Loy Yang Power, International Power and national science agency CSIRO on seven linked research, plant-testing and evaluation studies. Funding of A$2.5 million towards the A$5.6 million project has come from Victoria’s ETIS fund. The project is based at two power plants - Loy Yang A and Hazelwood - and other work is taking place at CSIRO and both universities.

Financing

The total cost of the Hazelwood pilot project is A$369 million. The Australian government has contributed A$50 million through its Low Emissions Technology Demonstration Fund (LETDF), and the Victorian government’s Energy Technology Innovation Strategy (ETIS) has given A$30 million.

Timing

The capture plant started up in July 2009. No information is available on the expected duration of the pilot project.

More information and press releases

International Power press release 8 July 2009

Contact

Email corporateaffairs@ipplc.com.au

Munmorah PCC

Audun Rødningsby — 2009-10-08T10:05:00Z

Australia’s national science agency CSIRO is working with Delta Electricity to test post-combustion carbon capture at a pilot plant at Munmorah Power Station on the New South Wales (NSW) Central Coast.

The A$5-million pilot became operational in February 2009, and evaluation of the capture technology and suitable CO2 absorbents will continue until 2013. In particular, the project is looking at adapting the ammonia absorption process for Australian coal-fired power plants.

Munmorah PCC is one of two Australian pilots being run by CSIRO as part of the Asia Pacific Partnership (APP) on Clean Development and Climate’s project CFE-06-06, which is testing post-combustion capture for coal-fired power plants. The second pilot is Tarong PCC. [hyperlink to this proj].

Financing

Part-funding for the pilot scheme has been provided by the Australian Coal Association’s COAL21 Fund – administered by ACALET – which has allocated A$50 million to pilot and demonstration projects in NSW. There is also support through the APP.

Timing

The current pilot project runs until 2013 and the planned larger-scale demonstration plant is expected to be operational by 2015. In August 2010, the project reported on the completion of further trials with knowledge gained from previous testing successfully applied to the pilot plant.

More information and press releases

NewGenCoal webpage on Munmorah pilot
COAL21 handout showing funding allocations
Delta commitment to reducing GHGs
APP project roster with links to project update

ZeroGen

Audun Rødningsby — 2009-10-08T11:55:00Z

In December 2010, Queensland Government announced that the anticipated large-scale CCS demonstration project ZeroGen would not go ahead as planned.

The joint venture between state, Commonwealth and industry had intended to build and operate, by 2015, a new 530MW power coal-fired power plant that combined integrated coal gasification open cycle (IGCC) technology with carbon capture and storage, and might have been the world’s first facility of its type.

However, it has since been cancelled as a large-scale integrated project and is now considered a storage-only initiative. The government now intends to work with the coal industry over the next three years to identify suitable storage in Queensland. This focus will be industry-led and the restructured venture will now see ZeroGen become an independent entity, owned and run by industry.

The plant would have initially captured up to 65% of its emissions, with the potential to capture and store up to 90% – or 2 million tonnes of CO2 – in deep underground sandstone formations. Suitable sites for the plant and CO2 sequestration had been identified as part of the pre-feasibility study. However, the state government has said further research has failed to prove the current commercial viability of the proposals.

Mitsubishi Heavy Industries and Mitsubishi Corporation would have been providing the technologies for both the IGCC and the CCS units. Queensland Government’s other partners in the project were Australian Coal Association’s COAL21 Fund and Shell.

Prior to the December announcement, the Carbon Sequestration Leadership Forum had recognised the project as one of the world’s most important CCS projects.

Storage

Shell supported the project’s injection-testing programme. Investigative drilling of geological sites in the Northern Denison Trough, onshore Central Queensland, has been carried out, and more than 400 tonnes of CO2 injected, to test suitability for the secure storage of CO2. ZeroGen had applied for additional storage sites in the Surat and Galilee basins. The drilling programme had recently moved to its second stage, to identify specific reservoirs with enough capacity and monitor test injections of CO2.

Financing

The project was expected to cost A$4.3 billion. Queensland Government has already invested $102 million in research, with $90 million having come from the coal industry and the Commonwealth. In June 2010, ZeroGen applied for funding to Australia’s CCS Flagship Program.impact study will also be completed and all studies are due to be completed by September 2011.

More information and press releases

Queensland Government press release, 19 December 2010

Project overview

ZeroGen press release 8 December 2009

Contact info

Email info@zerogen.com.au or call 0061-7 3551 1200