2.2 Detailed project breakdown

LSIPs by region and number

North America and Europe contain most of the listed LSIPs (Figure 9). Specifically, the United States and Europe account for 25 and 21 projects respectively, or 62 per cent of all LSIPs, followed by Canada (nine projects), Australia (six projects) and China (six projects). Within Europe, the United Kingdom has the largest number of projects (seven) followed by the Netherlands (four) and Norway (three). There are currently no LSIPs identified in other key emitting countries such as Japan, India or Russia.

Figure 9 LSIPs by region and year

The amount of CO2 that is intended to be stored in any given year from the 74 LSIPs provides another indicator of the level of potential activity across location and asset lifecycle stage.

The United States is the most active area not only with regard to project numbers but also the amount of CO2 captured (Figure 10). Six countries – the United States, the United Kingdom, the Netherlands, Australia, Canada and China – combined account for 86 per cent of CCS activity on the basis of potentially stored CO2 each year.

Figure 10 Volume of CO2 potentially stored by region or country

The 74 listed LSIPs are shown in maps in Figure 11 with Figure 12 and Figure 13 focusing on North America and Europe respectively. These maps also identify the industry sector and storage types of the project. In these figures, the projects are identified by a reference number that corresponds to the detailed project listing in Appendix C.

Figure 11 World map of LSIPs by industry

United States

The United States is the most dynamic market as it is characterised by the following:

  • the highest number of projects in operation (four), in construction (three) and in development planning (18);
  • three projects indicating they will be in a position to decide on whether to take a final investment decision in the next 12 months;
  • the largest number of projects being put on-hold (five) or cancelled (three) over the past year; and
  • significant government funding for demonstration projects.

This current level of project activity is underpinned by the opportunities provided by CO2 EOR systems as described earlier in this chapter and by the United States having allocated the highest amount of government grants to specific projects (section 4.2). This is in contrast to many other jurisdictions around the world which are still occupied with funding allocation processes and have less mature EOR opportunities.

In the US there is momentum in industries where CO2 is already ‘captured’ as part of the industrial process, such as gas processing and fertiliser production, and where an opportunity is found to use that CO2. With a high purity stream of CO2 at hand, the effort in these industries is centred on compression, transport and storage. In the US, where EOR opportunities are strongest, there is a strong incentive for deals to be done among these CO2 capture sources, pipeline and oil field operators.

However, where the cost of capture is relatively high, such as power generation and SNG, developing a strong business case for CCS is a challenge. There may be exceptions to this, such as coal-based plants that yield multiple premium products in a poly-generation mode, as represented by the Texas Clean Energy project. Such multiple products can include electricity, high value chemicals and CO2.

One United States power project to date–Kemper County–has developed a viable business case and moved into the Execute stage. Other projects, like the Antelope Valley and AEP’s Mountaineer projects, have not been able to progress to Execute and have been placed on-hold, even with substantial government funding allocated. In the absence of national carbon legislation (and given the higher relative capture costs), the evidence suggests that for CCS to be applied to a power project a suite of incentives may be required to make the business case. This suite may include all or some of the following:

  1. Continuation of significant federal government grants (in the order of hundreds of millions of dollars or more) and often with tax concessions for qualifying project owners as early movers.
  2. States that are prepared to offer electricity rate recovery (in part or full) to help cover the higher operating costs of the capture plant or to meet a low carbon portfolio state mandate (for example, California’s Climate Legislation AB32).
  3. Incentives such as loan guarantees and tax credits to help offset the higher capital and operating cost of the project with CCS.
  4. Off-take agreements to generate revenue through the sale of other valued products, including CO2 for EOR.

A significant development in 2011 is the exit of Rio Tinto and BP from the Hydrogen Energy California project, with expectations that a deal can be closed with prospective new owner SCS Energy LLC. This company intends to reconfigure the project as a poly-generation plant similar to the Texas Clean Energy project.

It is important to note the work being undertaken by the seven Regional Carbon Sequestration Partnerships (RCSP) in the United States. The Partnerships form a nationwide network that is investigating the comparative merits of numerous CCS approaches to determine those best suited for different regions of the country and to develop a set of ‘best practices’ for CCS in North America that could be broadly applicable to other regions globally. NETL manages the Partnership program.

One Partnership project–the Midwest Geological Sequestration Consortium’s (MGSC) Illinois Basin-Decatur Test Injection–is expected to commence injection in the second half of 2011. The CO2 will be captured from the Archer Daniels Midland (ADM) ethanol plant in Decatur, Illinois, compressed and then injected into a nearby deep saline formation. The planned capture and injection rate, at 1000 tonnes of CO2 per day or 365000 tonnes per year, is significant and very close to the Institute’s LSIP scale criteria for an industrial facility. This test injection project is expected to operate for three years, for a total CO2 injected of around one million tonnes. A second project at larger scale – the Illinois-ICCS project with 1Mtpa of CO2 captured from the ADM plant – is included in the Institute’s LSIP listing, in the Execute stage.

Figure 12 North American map of LSIPs by industry


CCS continues to play a major role in Canada’s carbon emission reduction strategy, and significant strides have been made at the provincial level in advancing the policy regime and financial support base for projects. The possibility for CO2 EOR and oil sands continues to motivate CCS project development.

Major factors which have affected project development in the past 12 months include:

  • In May 2011, Shell filed for its Carbon Sequestration Lease for the Quest project under the Alberta Carbon Sequestration Tenure Regulation. Shell has indicated that a FID may be possible in 2012 subject to financial, permitting and community approval issues being satisfactorily progressed.
  • In April 2011, SaskPower received approval from the Saskatchewan Government to proceed with the CCS component of Boundary Dam.
  • In March 2011, the Alberta Government launched its Regulatory Framework Assessment process, an ambitious project to develop world class regulations for all elements of CCS.
  • In February 2011, the Alberta Government finalised its C$495 million grant agreement with Enhance Energy for the Alberta Carbon Trunk Line (ACTL). This decision is reinforced by approval from the Alberta Energy Resources Conservation Board to construct the pipeline.
  • In November 2010, the Alberta Government introduced the Carbon Capture and Storage Statutes Amendment Act to address some significant barriers to demonstrating CCS. In particular, this Act amends existing legislation and provides the mechanisms for companies that will be seeking access to pore space for storing CO2, and the associated requirements for monitoring and closure plans. In the legislation, the province will assume the long-term liability for the stored CO2, after certain conditions have been met; these conditions are being developed though Regulatory Framework Assessment. In April 2011, the Carbon Sequestration Tenure Regulation was published which sets the conditions for a pore space tenure application.

Canada continues with a robust large-scale CCS demonstration program, including:

  • the Great Plains/Weyburn-Midale project continuing to inject around 3Mtpa of CO2;
  • two projects that are in the Execute stage – Agrium CO2 Capture with ACTL and Boundary Dam; and
  • three projects which may be in a position to decide whether to progress to a FID in 2012: Swan Hills Synfuels which has finalised a funding agreement for C$285 million in government grant support; Quest which has finalised a funding agreement for C$865 million; and Project Pioneer which is in advanced negotiations for C$779 million in grant support.

Figure 13 European map of LSIPs by industry


Since the 2010 report, the most material development in Europe has been Member States of the European Union (EU) making CCS project submissions to the European Commission (EC) for the first round of the NER300 funding program. A total of 65 renewable and 13 CCS project proposals were submitted to the EC in May 2011 for assessment by the European Investment Bank (EIB). The EC intends to provide clarity on the outcomes of the first round of the NER300 funding program in the second half of 2012. Funding from the total NER300 program could probably support four to six large-scale CCS projects, though this is dependent on the quality of applications and the value of the allowances auctioned. The expectation is that these supported projects would be operating within four years of being informed of a funding award. Table 2 below summarises the 13 CCS submissions.

Table 2 CCS project submissions for NER300 to the European Commission

CCS project categories Projects submitted by name No. of projects
Power generation (pre-combustion)
  • C.GEN North Killingholme (United Kingdom)
  • Don Valley (United Kingdom)
  • Eston Grange CCS (United Kingdom)
Power generation (post-combustion)
  • Getica CCS Demonstration (Romania)
  • Bełchatów (Poland)
  • Porto Tolle (Italy)
  • Longannet (United Kingdom)
  • Peel Energy CCS (United Kingdom)
  • Peterhead Gas CCS (United Kingdom)
Power generation (oxyfuel)
  • UK Oxy CCS Demonstration (United Kingdom)
  • Vattenfall Jänschwalde (Germany)
Industrial applications
  • ULCOS – Blast Furnace (France) – steel production
  • Green Hydrogen (Netherlands) – hydrogen production

From the CCS related submissions, a number of observations can be made:

  • seven countries made project submissions to the EC to compete for funds available under the NER300 funding program;
  • seven project proposals were submitted by the Government of the United Kingdom across all three power generation categories;
  • only the Government of the United Kingdom has submitted applications for the power generation pre-combustion category;
  • the large majority of projects are related to power generation, and in general, the capture elements of these projects exhibit greater maturity than their storage elements;
  • there is a growing realisation in Europe that finding and licensing offshore storage sites of ‘strategic significance’ for captured CO2 will be the key to a winning submission – at least for the nine projects which propose offshore storage;
  • growing interest in possible application of EOR based models in the North Sea, in particular as a possible financial underpinning for Don Valley;
  • the Dutch Government submitted only the Green Hydrogen project by Air Liquide out of four projects put forward by industry for consideration. This non-power project will also receive €90 million of funding from the Dutch Government if successful in the NER300 funding program;
  • four projects have already received funding through the European Energy Programme for Recovery (EEPR), including Bełchatów (Poland), Porto Tolle (Italy), Don Valley Power Project (United Kingdom; formerly known as Hatfield) and Jänschwalde (Germany). The Norwegian Government has also announced an additional €137 million in funding for the Bełchatów project; and
  • the Porto Tolle project in Italy was submitted to the EC for consideration but suffered a setback over permitting approvals for the base power plant earlier in 2011. The Institute understands that ENEL has requested the Ministry for the Environment to re-examine the objections to the project raised in the earlier ruling issued by the Council of State.

The EIB will assess the NER300 submissions against a number of criteria, including importantly the cost of CO2 abatement and the financial viability of the project. Separately, the EC will confer with Member States as to what financial support they will give to the project, as well as assess the ability of the submissions (and available funding) to demonstrate the different technologies specified in the funding call.

Other developments include:

  • the ROAD project in the Netherlands plans to use the €180 million received through the EEPR (and an additional €150 million from the Dutch Government) to be in a position to decide on whether to progress to a FID early in 2012 and has not provided a submission to the NER300 program;
  • the United Kingdom continues to move to finalise negotiations in relation to program support for Longannet, with final decisions expected by the end of 2011. In addition, the government has announced support from general revenue for two to four projects with competition arrangements to be announced in early 2012; and
  • the Compostilla Project in Spain also received €180 million of EEPR funding. However, the Spanish authorities did not submit the project developer’s proposal for funding under the NER300 program to the EC.


Near-term storage options are not readily available in Australia, which does not have significant (nor near-term access to) EOR potential or depleted oil and gas fields. Because of this, the search for suitable saline formation storage is a requirement for all large-scale CCS projects. Saline formation storage is being used in the only Australian project in the Execute stage – the Gorgon Carbon Dioxide Injection Project. A detailed case study on this project is provided at the end of this chapter.

Against this background, in June 2011 the Australian Government announced AU$60.9 million in funding for a National CO2 Infrastructure Plan to study potentially suitable sites to store captured CO2 and speed up the development of transport infrastructure near major CO2 emission sources. The plan includes the development of a national CO2 drilling rig deployment strategy and an assessment of infrastructure needs.

The Australian Government also announced that it had selected the Collie Hub project for funding under the AU$1.68bn CCS Flagships Program. The ‘base case’ for the Collie Hub project aims to capture around 2.5Mtpa of CO2 from an industrial source south of Perth in Western Australia. The Australian Government is to provide up to AU$52 million to support the studies required to move the project to the next phase of decision making. A key aspect of the next phase of project development is the completion of a detailed storage viability study. Initial studies have identified the Lesueur formation in the Southern Perth Basin as the best potential CO2 storage site.

The Australian Government also announced that it will continue to progress other large-scale Australian CCS projects, including the CarbonNet project in Victoria and the Wandoan project in Queensland. As with the Collie Hub project, these two projects will initially focus on the development of CO2 storage reservoirs and associated community engagement.


China continues to be one of the most important and challenging markets for CCS deployment. The high cost and energy penalty and the immaturity of CCS technologies at large scale are commonly cited as the major concerns to Chinese stakeholders. The current measures for reducing China’s GHG emissions are focused on improving energy efficiency, energy conservation and increasing the share of non-fossil fuel energy sources. However, there is growing recognition by the Chinese central government that while these technological options remain important, they will only go so far and CCS will also need to play a key role in China’s climate change abatement strategies, particularly in the medium to long term. This recognition, coupled with the desire to foster indigenous low carbon technologies, will continue to drive CCS development in China.

The Institute identified six LSIPs in China that are largely in the planning stages. These projects are generally being undertaken by China’s large state-owned power utilities and oil and gas companies. Some of the most prominent projects are the Greengen IGCC project and the Shenhua Coal-to-Liquids (CTL) Plant (Ordos City). These projects have the support of government agencies such as the National Development and Reform Commission (NDRC), as well as involvement from international partners such as development banks, non-government organisations (NGOs) and industry.

CO2 utilisation is considered to be critical to making CCS a commercially viable option. A number of companies in China are already capturing and using CO2, including in the production of food and beverages, fertiliser, algae and for EOR. China’s focus in the near term in this regard is likely to be unchanged. For example, Sinopec is currently operating an integrated pilot plant that captures 0.04Mtpa of CO2 for EOR. Based on this experience, Sinopec has started a program to expand the capacity of this facility up to 1Mtpa CO2 capture (Phase II). A series of research programs will be conducted on petroleum geology investigation, environment impact and other areas concerning CO2 EOR. Phase II of this EOR facility is expected to be completed in 2014.


The Japanese Government is committed to reducing its CO2 emissions. Since the March 2011 earthquake and tsunami, the Government has revised its Basic Energy Plan, which will likely include an increased reliance on fossil fuels, at least in the short term. The revision of the plan is being considered in line with the emissions reduction target, and could include the adoption of CCS.

The Ministry of Economy, Trade and Industry (METI) is currently funding the development of a demonstration project in Hokkaido. The project aims to capture more than 100000 tonnes per year of CO2 for storage in an offshore deep saline formation more than 1000 metres under the seabed in the North of Japan. In support of this project, Japan CCS Co. Ltd is undertaking a 3D seismic survey and drilling a test borehole to identify and explore suitable formations for CO2 storage. The budget to develop the project is approximately ¥5.9bn in Japanese Fiscal Year (JFY) 2010 and ¥4.9bn in JFY 2011.


Korea aims to achieve commercial deployment of CCS plants and global technology competitiveness by 2020. Two LSIPs are currently under development:

  • Korea-CCS 1 proposes to use post-combustion technology to capture up to 1.2Mtpa of CO2 from a 300MW coal-fired power plant and store in a deep saline formation by 2017; and
  • Korea-CCS 2 proposes to use oxyfuel combustion or IGCC with pre-combustion technology to capture 1.2Mtpa of CO2 and store in a deep saline formation by 2019.

The Korean Government has commenced a storage capacity assessment and geological survey of the offshore Ulleung basin and is exploring shipping transport.

Middle East

The Middle East is a region of strong promise for CCS. This region possesses a range of drivers and natural advantages for CCS, including:

  • significant EOR and deep saline storage potential, accompanied by a wealth of geological data;
  • strong and growing demand for power that is unlikely to be satisfied by natural gas and will require use of other fuels, especially coal;
  • a rapidly expanding industrial base, especially in a number of high CO2 emission sectors, such as gas processing, refining, steel making, chemical processing, and fertilisers;
  • significant overlap between the location of existing CO2 sources and potential CO2 sinks; and
  • growing awareness and action to address climate change.

While there is large potential, the demonstration of CCS in the region is seen as an important precursor to deployment. The key initiative designed to contribute towards the regional demonstration of CCS is Abu Dhabi’s Masdar program. As a whole this program is a clean-energy initiative designed to explore a range of renewable and alternative fuel options for the United Arab Emirates. Through Masdar, three CCS projects are being supported, all focusing on using CO2 for EOR:

  • Emirates Steel Industries – iron and steel;
  • Emirates Aluminium CCS – power generation (post-combustion); and
  • Hydrogen Power Abu Dhabi (a joint venture between Masdar and BP) – power generation (pre-combustion).

For several years the region has actively advocated for the inclusion of CCS in the UNFCCC’s Clean Development Mechanism (CDM). Such an inclusion could further fuel CCS development in the Middle East by tipping near commercial projects into viable business opportunities.

Developing Countries

The absence of LSIPs in developing countries is noticeable. If projects struggle to build a business case in developed countries, developing countries will have an even greater challenge, especially in the face of other priorities.

In the current context, a key avenue for support of CCS demonstration projects in developing countries is the expected inclusion of CCS into the CDM (or any future mechanism post the Kyoto Protocol). Key decision text was adopted in late 2010 at the COP 16 climate change talks in Cancun, Mexico that legitimises the merit of CCS as a mitigation option within the context of the UNFCCC objectives, as well as its capacity to be able to systematically generate tradable credits under the CDM. This decision will ultimately see a framework established that could provide for the institutional arrangements of CCS under any future UNFCCC mechanism (including Technology; Financial; and Future Markets) and/or adopted within national government policy settings.

The inclusion of CCS in future UNFCCC mechanisms could assist the mobilisation of funds to CCS projects. Access to capital would help encourage a greater level of interest by both developing and developed countries in CCS demonstration projects in the developing world.

Using the CO2 is expected to be a key component of large-scale CCS demonstration projects in emerging and developing economies, where there is strong demand for energy and construction materials and less likelihood of the early adoption of carbon pricing. The main focus is likely to be EOR due to its technical maturity and potential CO2 utilisation capacity but other technologies may also be of interest such as carbonate mineralisation, concrete curing, bauxite residue carbonation, enhanced coal bed methane, urea yield boosting and renewable methanol.

Capacity development

A key factor that will constrain CCS demonstration in developing countries is human resource capacity. In order to deploy CCS a technical and expert workforce will be required to facilitate project operation. Developing the existing technical expertise of the oil and gas sector represents an early opportunity to develop CCS expertise within a country, as they may already be familiar with related processes. As developing countries move further along the CCS lifecycle the need for technology based capacity development activities will increase.

LSIPs by industry sector

There has been little change over the past three years in the distribution of LSIPs by industry sector (Figure 14). Power generation projects dominate (42 LSIPs) because they represent high levels of stationary source emissions and consequently have attracted the largest proportion of government funding for abatement. The number of gas processing projects has also remained reasonably stable and in some cases the drivers for deployment in this sector are well advanced.

Figure 14 LSIPs by industry sector and year

Since the 2010 report, there has been an overall increase in the volume of CO2 being stripped out through natural gas processing as well as a major shift from volumes in the Execute stage to Operate (Figure 15). The former reflects the addition of the Riley Ridge project to the list (2.5Mtpa, Evaluate stage) and an increase in CO2 capture capacity at the Shute Creek facility (from 4Mtpa to 7Mtpa). This increase in capacity at Shute Creek, together with the start-up of the first phase of Century Plant in late 2010, accounts for the large increase in CO2 capture capacity in the Operate stage.

Figure 15 Volume of CO2 captured by industry sector and year

As noted earlier, it is a positive development that there are now two projects in the power industry in the Execute stage with a number indicating that a decision on whether to proceed to a FID is likely within the next 12 months.

The status of CCS demonstration in other industries currently lacks significant funding and hence momentum. Though there are some projects in operation, these occur in the fertiliser and synfuels sectors where CO2 is stripped out as part of the process, and has been for decades. While there is interest in CCS deployment in these other sectors, from a volume perspective the level of activity is minimal. There are very few or even no projects in high emitting sectors such as iron and steel, cement and pulp and paper production. Since large-scale demonstration projects can take considerable time to move from identification to reach operation, lack of momentum in these other industries may prove problematic for future abatement. Without dedicated funding to these other industries, it is unlikely that CCS will be demonstrated in these sectors by 2020.

LSIPs by capture technology

Pre-combustion capture is the most frequently chosen capture technology by LSIPs in the Operate and Execute stages (Figure 16). Pre-combustion capture has a long history in gas processing, synfuels and fertiliser production but its application in power generation is more recent. For example, Kemper County is the first pre-combustion power project with CCS that has entered construction and intends to capture 3.5Mtpa of CO2.

Post-combustion capture technologies in the power sector have also recently moved into construction with Boundary Dam aiming to capture 1Mtpa of CO2. Beyond this project, the application of post-combustion capture in other sectors and large-scale operations is yet to be widely tested.

Most CCS projects in development planning are proposing to use pre-combustion or post-combustion capture technology, representing 55 per cent and 27 per cent respectively of the number of all planned projects. Although oxyfuel combustion capture is not as widely planned, it is maturing with five projects utilising this technology in the Define or Evaluate stage. Further details regarding the maturity levels of CO2 capture technologies can be found in section 3.1 of this report.

Figure 16 Volume of CO2 captured by capture type and capture asset lifecycle stage

Pre-combustion capture is the most frequently chosen CO2 capture technology in North America and China (88 per cent of all projects in the United States, 67 per cent in Canada and 83 per cent in China), while post-combustion capture is the most widely pursued in Europe, representing 48 per cent of all CCS projects (Figure 17). This pattern is reflective of government grant allocation differences between North America and Europe, and the large number of gas processing and SNG projects in the United States.

Figure 17 LSIPs by capture type and region

LSIPs by transport type

Almost 95 per cent of all LSIPs use or propose to use pipelines to transport CO2 to the storage site. Transportation appears to remain a lower order priority for proponents as the integration challenges are assumed to be well understood. This understanding is exemplified by the numerous CO2 capture projects that outsource their transportation and storage needs through existing EOR pipelines and fields. While such an approach streamlines these aspects of the CCS chain, the creation of new pipeline routes, especially in non-industrial areas, to tap into geological storage options is not as straightforward. This will most likely require detailed planning and public consultation in the associated land acquisition and permitting.

Shipping is still marginal with only four LSIPs currently pursuing this option. Nevertheless shipping is increasingly being investigated as a more flexible option for matching CO2 sources and sinks, for example in situations where offshore storage is preferred and where the capture facilities are not in the immediate vicinity of a pipeline entry point. Transport by truck is still limited to smaller scale injection testing projects, and could well be included in large-scale projects to deliver CO2 to industrial customers as a niche revenue source.

LSIPs by storage type

In the United States and Canada, almost 80 per cent of LSIPs in each country are either using or intend to use CO2 for EOR purposes (Figure 18). Similarly, all LSIPs being developed in the Middle East are EOR-driven and China is strongly focused on EOR and other industrial uses of CO2. On the other hand, CO2 storage in deep saline formations and depleted oil and gas reservoirs is prevalent in Europe and Australia.

Figure 18 Volume of CO2 by storage type and region

Full project integration with aligned capture and storage lifecycle stages is easier to achieve for EOR-driven projects than for those intending to use geologic storage solutions. This is important because it is unlikely that EOR/depleted oil and gas fields have the required capacity to be a major long-term contributor to CO2 abatement. Current assessments strongly suggest deep saline formations will provide the bulk of storage potential.

Two-thirds of projects with EOR, whose capture component is in the Define stage, have a commercial agreement in place for CO2 off-take or are in advanced negotiations with potential EOR customers (Figure 19). As CO2 EOR systems have been in operation in the United States for around four decades, new projects can feed into existing pipeline and EOR networks (or planned extensions to those) and permitting and contractual arrangements are well known. This considerably shortens the development timeframes for the storage end of the CCS chain. The capture element becomes the key risk to project progression in conventional EOR operations.

In comparison, where deep saline formations or depleted oil/gas reservoirs are to be used, only one-third of projects, whose capture component is in the Define stage, have the same level of storage definition (undertaking detailed site characterisation).

This dynamic of synchronising capture and storage definition becomes much more complex when applied to greenfield geologic storage solutions. Here the challenges for optimising limited budgets across capture desktop studies and potentially more expensive and lengthy storage exploration/appraisal/testing work scopes are magnified, particularly under timing constraints. This is especially true if the project is part of a competitive process and there is no history of exploration management in the managing organisation. Where there is considerable uncertainty as to whether a compelling business case can be made in support of the capture of CO2, there is little incentive for project proponents to expend potentially large sums of capital on storage exploration or appraisal activities, especially if there is a significant chance of failure.

Project proponents may seek to delay potentially large expenditures on storage characterisation until uncertainties on the capture business case are addressed, and then in turn mitigate storage risk through several years of site assessment, characterisation and modelling. Such a strategy may however significantly delay project implementation. Early storage data acquisition would also better inform regulatory and public engagement activities by project proponents.

The role for government may well extend beyond financial support for capture facilities to include supporting the timely provision of storage (and transportation) infrastructure. The hub models being developed in Australia with CarbonNet and the Collie Hub projects involve state governments supporting the development of the necessary storage infrastructure to support capture project proponents. Likewise, as mentioned previously, the Australian Government has recently announced funding for a National CO2 Infrastructure Plan.

Figure 19 Comparison of capture asset lifecycle with the progress of EOR and storage in deep saline formations or depleted oil and gas reservoirs

Portfolio distribution of LSIPs

A portfolio distribution mapping the key industries, technologies and regions where current LSIPs are being considered is a useful mechanism to summarise much of the previous discussion in this chapter (Table 3). Many of the salient points have been made previously, including the geographical dominance of a few regions, the dominance of power generation projects and pipeline systems within these regions, and geographical differences in the type of storage options being pursued.

Table 3 LSIPs by region, by technology and by industry

      North America Europe Asia Australia - New Zealand MENA Sub-total
Capture Power Pre-combustion 9 3 3 1 1 17
Post-combustion 4 10 2   1 17
Oxyfuel combustion 1 4       5
Various/other     1 2   3
Other Gas processing 6 2   2 1 11
Iron and steel   1     1 2
Cement           0
Various/other 14 1 2 2 19
Transport   Point-to-point onshore pipeline 14 6 5 4 1 30
Point-to-point offshore pipeline 1 8 1     10
Network pipeline 19 5   2 3 29
Other pipeline       1   1
Ship/tanker   2 2     4
Storage Geology Onshore deep saline formations 6 6 1 4 1 18
Offshore deep saline formations 1 6 2 1   10
Onshore depleted oil and gas reservoirs           0
Offshore depleted oil and gas reservoirs   5 1     6
Other Enhanced oil recovery 26 3 2   3 34
Enhanced gas recovery           0
Other reuse           0
Combination/ TBD 1 1 2 2   6


Case study - Gorgon Carbon Dioxide Injection Project

Significant progress is being made on the AU$2bn Gorgon Carbon Dioxide Injection Project since the Chevron-operated project passed its FID in September 2009, a milestone that represented the culmination of almost two decades of studies and a significant pre-investment.

Initial consideration of managing the Gorgon Project’s reservoir CO2 started in 1992, before the commissioning in 1998 of regional desktop studies seeking to identify potential storage sites within 300km of the proposed project site. This work culminated in 2003 with the publication of the Environmental, Social and Economic Review of the Gorgon Gas Development on Barrow Island (ESE Review), which voluntarily proposed that reservoir CO2 be injected into the Dupuy Formation below Barrow Island and provided ongoing studies confirmed it was technically feasible and not cost prohibitive. The Dupuy Formation was favoured as some 27 nearby well penetrations and existing 3D seismic coverage indicated suitable geology to permanently trap the injected CO2.

The Gorgon Project is operated by Chevron Australia and is a joint venture of the Australian subsidiaries of Chevron (approximately 47 per cent), ExxonMobil (25 per cent), Shell (25 per cent), Osaka Gas (1.25 per cent), Tokyo Gas (one per cent) and Chubu Electric Power (0.417 per cent).

Legislative development

Shortly after publication of the ESE Review it was recognised that there was no legislation to enable government to approve the proposed injection operations. To address this gap, the Barrow Island Act 2003 (WA) was passed by the Western Australian Parliament in late 2003. The Act contains provisions dealing with the conveyance and underground disposal of CO2 and is believed to be the world’s first GHG storage legislation. The provisions in the Act are brief but enable the Minister to place conditions on the approval. In effect, the Ministerial conditions establish the regulatory framework under which the project must operate. This was done intentionally, as in 2003 it was not fully understood what issues would require regulation. Barrow Island Act 2003 approvals for the underground disposal of reservoir CO2 were obtained at the same time as the Gorgon Joint Venture made its FID in 2009. A key component of the approvals imposed by the Minister is the requirement for a Site Management Plan. This document outlines how all aspects of the project will be undertaken. The concept of a site management plan has been subsequently adopted in the Australian Offshore Petroleum and Greenhouse Gas Storage Act 2006 (Commonwealth).

Environmental approvals

Prior to FID, environmental approvals were required under the Environmental Protection Act 1986 (WA) and the Environmental Protection and Biodiversity Conservation Act 1999 (Commonwealth). In September 2005, the Gorgon Joint Venture published its Environment Impact Statement and Environmental Review and Management Plan (EIS/ERMP) for a 10Mtpa liquefied natural gas (LNG) project on Barrow Island. Importantly, this document represented the first publication of an environmental impact assessment for a major GHG storage project. This document detailed the nature of the geology below Barrow Island, how GHG storage works and how the injected CO2 becomes trapped. It also outlined risks and potential impacts on environmental receptors. An important aim was producing a document with sufficient background data for the general public, as well as scientific community, to have confidence in the project’s assessment of the environmental risk associated with the injection and storage of CO2. Following public submissions to the EIS/ERMP, both Federal and Western Australian environmental approvals were granted in October 2007.

Shortly after receiving these environmental approvals, the Gorgon Joint Venture made the decision that they wished to expand the scope of the project from 10Mtpa LNG to 15Mtpa LNG. This required the original environmental impact assessment process to be revisited, including a revision to the risks study published previously. Federal and WA approvals for the expanded project were obtained in August 2009.

Throughout this process it was recognised that, despite the existing well penetrations and 3D seismic, significant additional data collection was required in order to improve the geological understanding of the proposed injection location. Indeed, the data required was comparable to the field appraisal activities that would be undertaken to appraise an oil and gas discovery.

Since 2003 the Gorgon Joint Venture has invested over AU$150 million in storage appraisal. This included the drilling of a data well in which the entire 300 metre reservoir section and overlying seals were cored, conducting extensive well testing and a series of seismic acquisition pilots including the acquisition of a new 3D seismic survey.

Throughout this period the Western Australian Government undertook a series of independent expert reviews to assure the quality of the technical work being undertaken by the Gorgon Joint Venture. These assurance (or due diligence) reviews were timed to provide independent advice to government at the time it was making important decisions about the project.

Since FID, work has continued on refining the project’s geological and dynamic simulation models and planning for the commencement of the drilling of the injection and pressure management wells in late 2012. The design of the wells is largely complete and contracts are currently being negotiated for the drilling rig and associated equipment to drill these wells.

Following FID, 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 compressors represent a significant piece of equipment with two compressors coupling together to form a module more than five stories high (Figure 20). Each compressor will be equipped with a four stage compressor comprising two compressor casings (each casing comprising two compressor stages) coupled through gearboxes on either side of a double-ended variable frequency drive electric drive motor. Intercoolers/aftercoolers will be installed after each compression stage. Factors requiring consideration in designing the compressors include:

  • ergonomic design focusing on improving maintenance and operational access;
  • equations of state for the CO2 rich gas stream;
  • the presence of incidental associated substances in the CO2 stream;
  • compressor aerodynamics, rotodynamics, material selection, drive technologies, system integration and maintenance factors;
  • each compressor train is designed to be modularised and must meet very stringent space constraints;
  • the ability to control the 3rd stage discharge pressure to within the range of 50 to 65 bar to allow the maximum dropout of liquid water as part of measures to manage corrosion downstream of the compressors; and
  • the need to minimise fugitive emissions around the compressor seals.

Figure 20 Layout of Gorgon CO2 compressor train. Image courtesy of Chevron Australia

Once the first compressor train has been constructed it undergoes a full speed full load validation test in a purpose designed and built test loop using CO2 as the test gas. The main focus of these tests is to validate the expected mechanical performance (torsional response, vibration, bearing temperature, and so on) and thermodynamic performances in terms of developed differential pressure, efficiency and absorbed power for each state. The test will maximise the use of the actual contract components including lubrication oil systems, electric motor controls and the compressor seal equipment. The full-speed, full-load, string testing commenced validation testing in June 2011.

Each compressor is then integrated into a module including all necessary pipe work and intercoolers before shipping to the project site on Barrow Island. The first compressor module is due to arrive on Barrow Island in the second half of 2013.

The lead time to undertaking the detailed design, construction and full speed, full load testing of the CO2 compressors is significant and reinforces the long lead times and investment requirement to successfully execute a GHG storage project of this scale.

The Australian Government has committed $60 million to the Gorgon Project as part of the Low Emissions Technology Demonstration Fund (LETDF).