Appendix 3: CO2 Injection Projects in Saline Aquifers

In this Appendix various projects are reviewed that currently inject CO2 into aquifers; either for a combination of socio-economic reasons or for research purposes. In the current political environment, a multitude of CO2 injection projects are proposed and are in various planning stages, but it is difficult to determine the likelihood of the actual implementation of specific projects. For example, projects that appeared to have a high probability of going ahead and had numerous associated research activities, e.g., FutureGen (Mattoon) or Schweinrich (CO2STORE/Europe), were cancelled due to the re-allocation of funding or change in site operators. Nevertheless, some projects that are in an “advanced” planning stage are included in the review if they provide detailed information related to site characterisation, reservoir properties, regulatory issues, costing and/or well completion. It should be noted that due to confidentiality issues and rapid changes in the CCS political environment, the availability of data for some injection operations may be limited.

Commercial Operations

Sleipner, Norway

The first commercial geological CO2 storage project within a saline aquifer was the Statoil operated Sleipner Project in Norway. More than 10 Mt of CO2 have been stored in the Utsira formation since the Sleipner project was started in October, 1996 (Carbon Capture Journal, 2008). Each day, approximately 2.7 kt of CO2 are removed from natural gas produced from the Sleipner West field in the North Sea. Capture of CO2 is done with a conventional amine process on an offshore platform in the North Sea, 250 km from land. The CO2 is piped over to the Sleipner East Gas Field, where it is reinjected into the Utsira Sand, a saline formation above the methane production interval (Baklid et al., 1996). The formation is a 50 m to 250m thick sandstone unit located at a depth of approximately 1,000 m directly below the Sleipner field (Figure 26) which extends over a large area in the Norwegian sector of the North Sea. With a thickness of 250 m, the formation can store 600 Gt of CO2 (Statoil, 2000). The injected CO2 is extracted from natural gas, which contains approximately 9% CO2. It is expected that 25 Mt of CO2 will be injected into the aquifer over the life of the project. Before injection, CO2 is brought to a supercritical state, requiring compression to 80 bars and cooling to 40 degrees Celsius. This is achieved using a compressor train, consisting of 4 units, each with a fluid knockout drum to remove water, compressor, cooler and gas turbine driver. One horizontal injection well is used to inject CO2 into the storage reservoir. The 3,752 m long well was drilled to a vertical depth of 1,163 m, with a terminal inclination of 83 degrees, and completed with 25 % chromium duplex steel tubing.

Figure 26. Simplified diagram of the Sleipner CO2 Storage Project. Inset: location and extent of the Utsira Formation (IPCC, 2005).


Prior to injection, the site was characterised with the help of 3D seismic surveys, well logging and coring the Utsira sandstone and sealing shales, from 1993 to 1994. Reservoir simulations predicted CO2 behaviour within the formation. The Saline Aquifer CO2 Storage (SACS/CO2STORE) Project was an R&D program (Kårstad, 2002), established in 1998 to monitor CO2 behaviour after injection at Sleipner. Monitoring of the injected CO2 has been underway since 1999. Statoil’s review of monitoring options at Sleipner suggested that observation wells and well seismic would be too complicated and to expensive. Repeat seismic surveys were therefore considered to be the most promising option. Four seismic surveys have now been completed at Sleipner (Figure 27). The injected CO2 has had a significant impact on the seismic signal, causing large increases in the seismic reflectivity, clearly demonstrating the position of the injected CO2 within the Utsira Sand (Arts et al., 2004). Seismic surveys have also demonstrated that the CO2 is still successfully contained within the Utsira Sand (Arts et al., 2004). By 2005, the CO2 plume had extended over an area of approximately 5 km2 around the injection point, and over time it is predicted to be completely dissolved within the formation water (IPCC, 2005). Even with the CO2 in a supercritical, rather than a gaseous, state it has been shown that CO2 accumulations with a thickness as little as about one metre can be detected, which is significantly less than the conventional seismic resolution limit of approximately 7 m. Even these thin accumulations cause significant, observable and measurable changes in the seismic signal, both in amplitude and in travel time due to the high porosity of the weakly consolidated Utsira sand.

Time lapse gravity surveying offers a lower cost complementary technique to seismic surveying. A baseline gravity survey was completed at Sleipner in 2002 and a repeat survey was completed in 2005. It is possible to measure gravity on the seafloor with uncertainties of <5 μGal, even in a relatively shallow water, high noise environment. Additionally, is has been shown that by simultaneously measuring water pressure, seafloor depth can be determined to sub-centimeter accuracy, relative to a ‘fixed’ point on the seafloor. These depth measurements are very important for correcting the gravity measurements for anomalous changes in benchmark height, such as from sediment scouring. In the future at shallow high-current environments such as Sleipner, more care should be taken in designing and deploying benchmarks, in order to reduce the effects of scouring and biological disturbances. Techniques such as laying gravel or carpet down prior to benchmark emplacement, or anchoring the benchmarks to the seabed could be employed.

Figure 27. Geophysical monitoring at Sleipner: a) timing of time-lapse seismic and gravity surveys, and b) time-lapse dataset visualising the spread of the injected CO2 in the Utsira Formation.

The Utsira Formation is highly permeable with an enormous pore volume compared to the planned injection volume of CO2 and the cap rock has shallow dome structures that allow free gas columns of only 15–25 m. Because of these features, it has been concluded that monitoring of the storage reservoir pressure is not a key issue as the shape and size of the storage reservoir cap and spill points will only lead to minor pressure build up. Therefore, the pressure increase in the aquifer due to CO2 injection is expected to be in the sub-one bar range, i.e. far below estimated limits to avoid mechanical failure or gas penetration through undisturbed cap rock.

The time-lapse gravity results and modelling support evidence from heatflow measurements and other temperature measurements in the vicinity of Sleipner which suggest that the Utsira formation is warmer than previously thought. This is only a beginning step in characterising the aquifer using time-lapse geophysical measurements. Additional gravity and seismic measurements are needed to further constrain this reservoir property by putting tighter bounds on the in situ CO2 density. Ideally, future 3D seismic measurements and gravity measurements will be made within a few months of each other, so that the geometry of the CO2 plume determined from seismic can be directly related to observed changes in gravity.

Time-lapse gravimetric reservoir monitoring may play a role in future CO2 sequestration efforts, however, this detection technique relies on the density contrast between injected CO2 and the aquifer fluids, limiting its applicability to fluid-filled reservoirs and excluding formations such as depleted coal beds. The best results will be obtained when monitoring shallow reservoirs less than 1000 m deep, where the density of CO2 is much less than that of the reservoir fluids. In order to slow CO2 emissions, as is needed to mitigate anthropogenic climate change, hundreds of sites such as Sleipner will be needed along with many other carbon reduction strategies. Undoubtedly, gravity will be a useful tool for monitoring injected CO2 for a number of these sites.


Capital costs for the Sleipner Project cannot be determined exactly as it is an integral part of the overall Sleipner field development. However, (Torp and Brown, 2005) have developed estimates for these costs (in terms of 1996 US dollars) Torp and Brown (2005) estimate that the total cost of site characterisation was US$1.9 million, the cost of designing and installing the compressor train to be US$79 million and the cost of the well is estimated to be US$15 million. The operating costs identified by Torp and Brown (2005) consist of the fuel required to run the gas turbines for compression (approximately 4,000 standard cubic metres per tonne CO2) and US$40 per tonne CO2 offshore emissions tax, labour and maintenance costs. The total costs amount to approximately US$7 million per year. The breakdown of cost components is shown in Table 19.

Table 19. Sleipner site characterisation costs.

Procedure Cost (US$ million)
3D seismic survey 0.4
Coring “Utsira” sand and well logs 0.9
Coring cap rock shales 0.5
Reservoir simulations 0.1
Total cost 1.9

Source: Torp and Brown (2005)

The Saline Aquifer CO2 Storage (SACS/CO2STORE) Project was a US$4.5 million R&D programme (Kårstad, 2002), established in 1998 to monitor CO2 behaviour after injection at Sleipner. (Torp and Gale, 2004) describe the project and state that the cost of a monitoring well, up to €45 million (US$54.7million) according to Statoil estimates, would be too high. The European Commission (2004) estimates that the cost of monitoring at Sleipner is €2.1million/yr.

Snøhvit, Norway

At the Statoil operated Snøhvit LNG project, CO2 is currently being injected into a deep saline formation in the Barents Sea. The Snøhvit project is the first LNG development in Europe. Production from the Askeladd, Albatross and Snøhvit fields began in September 2007 and the project is expected to have a 30-year lifetime. The CO2 content of the field gas must be decreased from 5-8% to less than 50 ppm prior to conversion to LNG. The 0.75 Mt/yr CO2 removed from the natural gas, using amine technology, is injected into the Tubåsen Formation situated below the Stø formation (Figure 28), a Jurassic gas reservoir (Maldal and Tappel, 2004). Injection of CO2 at Snøhvit commenced in May, 2008.

Figure 28. Simplified cross section through the Snøhvit field (from Maldal and Tappel, 2004).


Kårstad (2002) provides estimates of the capital costs of storage in terms of 2001 US dollars. Kårstad estimates the total capital cost to be US$191 million, a figure which covers the cost of a deviated, offshore injection well completed with 7 inch injection tubing, a 160km, 8 inch internal diameter pipeline to transport CO2 from the LNG plant to the Snøhvit field, a sub-sea control umbilical, a sub-sea well frame and a compressor train for the compression and dehydration of CO2. Table 20 shows a breakdown of these costs.

Table 20: Snøhvit capital costs

Item Cost (2001 US$ million)
Drilling injection well 16
Well completion and other well related 9
Pipeline, 160km 73
Sub-sea control umbilical 11
Sub-sea well frame 12
Compressor train 70
Total 191

Source: Kårstad (2002)

In Salah, Algeria

The In-Salah Gas Project, a Sonatrach, BP and Statoil joint venture, exploits the natural gas resources found within Algeria’s Ahnet-Timimoun Basin. The In Salah Project is one of BP’s two major gas projects in Algeria and is the largest dry gas joint-venture project in the country. The venture involves the development of seven proven gas fields in the southern Sahara, 1,200 km south of Algiers. The field gas, containing up to 10% CO2, requires a decrease in CO2 content to 0.3% prior to export to European markets (Riddiford et al., 2005; Riddiford et al., 2003). From July 2004, 1.2 Mt/yr CO2 have been injected into the aquifer section of the Krechba field, the Carboniferous Tournaisian sandstone reservoir at 1,800 metres depth. The project is expected to store up to 17 Mt CO2 over its lifetime, decreasing CO2 emissions of the project by 60%. Following separation from the natural gas stream at the Krechba processing plant, the CO2 is compressed in four stages up to 200bar and dehydrated. It is then injected using three injection wells into the storage formation (Wright, 2007a, b). Unfortunately, technical information from the In Salah project is largely limited to conference presentations and the company webpages of Statoil and BP.


The In Salah CO2 Assurance R&D Programme was established to ensure that CO2 is being safely sequestered and to assess various monitoring options. Techniques used include 4D seismic surveys, 4D gravity surveys, 4D electrical/electromagnetic techniques, dynamic modelling, tracers, analysing formation fluids, soil gas sampling and injection monitoring (Espie 2006, Wright 2007a).

The following monitoring plan was proposed for In Salah:

  • Soil gas depth testing, lineament analysis, microseismic testing, tiltmeters, surface flux monitoring, hydrogeology, microbiology, gravity test (4th quarter 2007);
  • Full soil gas survey, microseismic array, gravity survey, shallow observation well(s), further data acquisition from new production wells, hydrogeology/microbiology (early 2008)
  • 3D seismic survey, surface flux, gravity measurements, logging (early to mid 2008)


The total cost of CO2 storage is estimated to be US$100million (Wright, 2007a, b).

Regulations (Europe/Africa)

The Sleipner, Snøhvit, and In Salah projects are being regulated primarily under the petroleum regulations in the host country. There are no generic regulations in either Norway or Algeria for regulating the geological storage of carbon dioxide. Although Algeria and Norway are not member states of the European Parliament, the proponent companies have complied with the requirements for management of geological storage of CO2 that are set out in the proposed Directive of the European Parliament and Council on the geological storage of carbon dioxide and amending Council Directives 85/337/EEC, 96/61/EC, Directives 2000/60/EC, 2001/80/EC, 2004/35/EC, 2006/12/EC and Regulation (EC) No 1013/2006.

This proposed Directive sets out details on requirements relating to site selection, exploration permits, storage permits, requirements for environmental impact assessment and public consultation, operational matters including closure and post-closure obligations, monitoring and reporting obligations, inspections, measures in case of irregularities and/or leakage, and provision of a financial security. The Directive also addresses related matters including access to transport and storage, transboundary co-operation, and the required amendments to other legislation, including the necessary adaptations to the water and waste legislation.

The proposed Directive builds on recent decisions in other international forums to allow geological storage of carbon dioxide under the sea-bed. Legal barriers to the geological storage of CO2 in sub-seabed geological formations have been removed through the adoption of related risk management frameworks both under the Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other Matter (1972 London Convention) and under the Convention for the Protection of the Marine Environment of the North-East Atlantic (OSPAR Convention).

Gorgon, Australia (planned)

The Gorgon Joint Venture (ChevronTexaco, Shell and ExxonMobil) exploits the large natural gas resources of the Greater Gorgon area, offshore Western Australia. The natural gas in Gorgon contains up to 14 % CO2. The CO2 will be separated from the produced gas at the gas-processing facility on the island, compressed to a supercritical state, and then transported by a 12 km pipeline to the injection site for storage. If feasible, the project will involve the reinjection of 2.7-3.2 Mt/yr CO2 extracted from the field gas into the Dupuy Saline Formation 2,300 m below Barrow Island (Figure 29). A total of 125 Mt CO2 is expected to be stored over the life of the project.

Figure 29. Diagrammatic geological cross-section showing the target injection horizon of the Gorgon Project (Chevron, 2005).

Seven injection wells are currently planned. These will be drilled directionally from 2 or 3 locations. A monitoring programme is currently being developed to keep track of CO2 behaviour after injection. The programme will include a number of observation wells for monitoring injection rates and pressures, seismic monitoring of CO2 migration, wireline logging, geochemical analyses of Dupuy Formation waters and installation of CO2 detection devices to detect leakages. Three water production wells are planned to manage reservoir pressures and brine displacement (Chevron, 2005).

Costs & Regulations

According to the IEA (2008), the total capital cost for CO2 compression, pipelines and injection wells is A$300-400 million (US$265-350 million).

As the geological sequestration component of the Gorgon project is located onshore, the regulatory framework is primarily that of the Western Australian Government through the Petroleum Act 1986 (WA), the Environment Protection Act (WA) and the Barrow Island Act 2003 (WA). Approval was also required under the federal Environment Protection and Biodiversity Conservation Act because of the location of the facilities in conservation reserves which include a number of matters of national environmental significance. Bilateral agreements between the Australian Government and Western Australian Government have led to an integration of the assessment and approval processes.

No generic legislation currently exists in WA for regulating geosequestration. However, the Barrow Island Act 2003 (WA) has provisions that allow the Minister to approve CO2 disposal on Barrow Island. The function of this Act is to, inter alia, ratify and authorise the implementation of an agreement between the State and the Gorgon Joint Ventures (GJV) relating to the offshore production of natural gas and other petroleum, and a gas processing and infrastructure project on Barrow Island. The Act also makes provisions for the transport and underground disposal of carbon dioxide recovered during gas processing on Barrow Island. Specifically, the Act requires the GJV to seek approval to dispose of CO2 on Barrow Island. The application for approval must include information on the methods to be used; the capacity and capability of the underground target reservoir; the rate of disposal; the volume/composition of the CO2 to be disposed; and the expected duration of the disposal. Under Schedule 1 of the Act the GJV is also required to submit a closure plan that addresses the long term management of injected CO2. Approvals under the Barrow Island Act 2003 (WA) and its Schedule 1 are subject to environmental approval under the Environmental Protection Act 1986 (WA). The CO2 disposal component along with all other aspects of the Gorgon Project must also comply with any imposed Ministerial environmental conditions. The draft of the Environmental Impact Statement (EIS) including a detailed risk assessment was submitted by Chevron in 2005 (Chevron, 2005). In late 2007 the GJV obtained State and Commonwealth environmental approvals for a 10 Mt/yr LNG development on Barrow Island. The State (Statement No. 748) and Commonwealth (EPBC Ref: 2003/1294) environmental approvals contain specific conditions relating the to the proposed CO2 injection project. Currently, the GJV is working on an update of the EIS document to reflect the increase of the project to 15 Mt/yr.

Acid-Gas Injection (Alberta & British Columbia, Canada)

Over the past two decades, oil and gas producers in the Alberta basin in western Canada (Alberta and British Columbia) have been faced with a growing challenge to reduce atmospheric emissions of hydrogen sulphide (H2S), which is produced from “sour” hydrocarbon pools. Since surface desulphurization is uneconomic and the surface storage of the produced sulphur constitutes a liability, increasingly more operators are turning to the disposal of acid gas (H2S and CO2 with minor traces of hydrocarbons) by injection into deep geological formations. The first acid-gas injection operation in Alberta was approved in 1989 and started injecting in 1990 into a depleted gas reservoir. Injection into the first aquifer commenced in 1994. By 2007, 48 operations for injection of acid gas had been approved in western Canada (41 in Alberta and 7 in British Columbia), of which 27 operations currently inject into aquifers. By the end of 2007, approximately 4 Mt CO2 and 3 Mt H2S had been injected into deep hydrocarbon reservoirs and saline aquifers in western Canada. The contents of CO2 in the injection stream of operations disposing of acid gas into saline aquifers ranges between 17 and 88 % and approximately 2 Mt CO2 were injected into aquifers. General as well as some site specific information with respect to acid-gas injection in Western Canada can be found in (Bachu and Gunter, 2004; Bachu et al., 2005); (Buschkuehle and Michael, 2006); (Michael and Buschkuehle, 2006; Michael and Haug, 2004).

The average injection depth in saline aquifers varies between 950 and 2814 m (Table 21). The relatively shallower injection zones (i.e., between 800 and 1100 m depth) correspond mostly to injection of acid gas dissolved in or mixed with water. The thickness of the injection formation, as defined geologically, varies between 15 and 343 m; however, the actual net pay, defined by layers with porosity and permeability adequate for injection, reaches only a maximum of 100 m. At 9 operations, acid gas is injected into sandstone aquifers and at 18 operations injection occurs into carbonates. In most cases shales and shaly siliciclastics constitute the overlying confining unit (top seal); the remainders of the injection zones are confined by tight limestones, evaporites and anhydrites. The caprock thickness varies between 15 and 218 m, which only refers to the top seal directly overlying the injection unit. In many cases additional lowpermeability formations contribute to a larger overall aquitard thickness. The porosity of the injection zone varies between 4% and 26%, the carbonate rocks generally having lower porosity. Only the porosity in sandstones displays a general trend of decreasing porosity with increasing depth. Rock permeability varies from as low as 1 mD to as high as 413 mD.

The original formation pressure is generally sub-hydrostatic with respect to freshwater, which is characteristic of the Alberta Basin, and varies between 5915 kPa at 950 m depth and 27,000 kPa at 2814 m depth. Formation temperature varies between 26oC and 103oC. The widespread variation of temperature with depth for the acid-gas injection zones is due to the variability in geothermal gradients across the Alberta Basin, which exhibits a trend of increasing gradients from the south, where they are as low as 20oC/km, to the north, where they reach more than 50oC/km. Generally, formation waters are very saline, with salinity varying in a very wide range, from ~20,000 mg/l–~341,000 mg/l.

Table 21. Characteristics of acid-gas injection operations injecting into saline aquifers in western Canada.

Characteristic Minimum Value Maximum Value
Injection depth (m) 950 2814
Formation thickness (m) 15 343
Net pay (m) 4 100
Porosity (%) 4 26
Permeability (mD) 1 413
Caprock thickness (m) 15 218
Formation pressure (kPa) 6,000 27,000
Formation temperature (°C) 26 103
Water salinity (mg/l) 23,742 341,430
CO2 in injection stream (%) 17 88
Injection rate (m3/day) 2,000 150,000


Pressure, temperature and gas composition are monitored at the wellhead and generally no subsurface monitoring requirements are imposed on the operators. As a result, there is very limited information on the subsurface spread and reactions of the injected acid gas.


The application and permitting process is regulated in Alberta by the Energy Resources Conservation Board (ERCB) under the Oil and Gas Conservation and the Coal Conservation acts and associated regulations. Directives related to the petroleum industry can be downloaded from the ERCB webpage ( These are reviewed and discussed in detail by (Bachu, 2008), and the following is an excerpt of that document. Most relevant to future CCS projects is the section in ERCB Directive 65 (ERCB, 2007) on acid-gas disposal, which requires the applicant to prove that:

  • It has the right to dispose in the respective geological formation;
  • Disposal will not impact hydrocarbon production;
  • The disposal fluid will be confined to the injection horizon;
  • The owners of neighbouring wells within a certain distance of the disposal well have been consulted and have no objections; and
  • Containment and isolation requirements, including well construction, are being met.

Acid-gas disposal wells usually fall within Class III in Directive 51 (ERCB, 1994) on well classification, completion, logging and testing requirements, which covers: a) injection of hydrocarbons, inert or other gases for the purpose of storage or enhanced recovery; b) solvent or other hydrocarbon products for enhanced recovery, c) sweet natural gas for storage, d) CO2, N2, O2, air or other gases for storage or enhanced recovery; and e) sour or acid gases for disposal, storage or cycling. The construction and operating requirements for Class III wells are:

  • Hydraulic isolation of the host zone and hydrocarbon-producing zones (all wells – exploration, production or injection – require isolation through surface casing of potable groundwater defined as water with salinity less than 4000 mg/l);
  • Annulus filled with corrosion-inhibiting fluid;
  • Installation of safety devices (e.g., valves against backflow);
  • Cementing across the potable-groundwater zone;
  • Logging for cement top, hydraulic isolation and casing inspection;
  • Initial casing/annulus pressure test;
  • Annual packer isolation test;
  • Wellhead pressure limitation; and
  • Injection through tubing.

Additional general regulations about well construction regarding Surface Casing and Cementing are found in ERCB Directives 8 and 9 (ERCB, 1990, 1997), respectively.

In the context of current efforts to reduce anthropogenic emissions of CO2, these acid-gas injection operations represent a commercial-scale analogue to geological storage of CO2. The technology and experience developed in the engineering aspects of acid-gas injection operations (i.e., design, materials, leakage prevention and safety) can be adopted for large-scale operations for CO2 geological storage, since a CO2 stream with no H2S is less corrosive and less hazardous. Although the fate of the injected acid gas has not been monitored to date, the subsurface information about aquifer, and reservoir rocks and fluids provides a wealth of information as to what characterises a good CO2-storage site. This information can be used for the screening and identification of future sites for geological sequestration and storage of CO2.

Pilot Sites (Research)


The Frio Brine Pilot Experiment began in 2002, funded by the U.S. DOE National Energy Technology Laboratory. The site for this experiment is in the South Liberty oilfield, northeast of Houston. Before injection, extensive monitoring, including baseline aqueous geochemistry, wireline logging and vertical seismic profiling, and modelling was conducted. Injection began on October 4, 2004, and over 10 days 1,600 tonnes of CO2 was injected 1500 m below the surface into a high permeability brine-bearing 24 m thick interval of sandstone of the Frio Formation.


The Frio test has a dedicated monitoring well that is offset 30-m updip (Figure 30). The project was monitored before, during and after the injection. Techniques used include RST logging, cross-well seismic, vertical seismic profiling, fluid sampling, measuring soil gas fluxes and concentrations and introduced tracers (Hovorka et al., 2006; Hovorka and Knox, 2003). The Frio project can be divided into two phases: Frio-1 (October, 2004 –January, 2006) and Frio-2 (September, 2006 – December, 2007). The main purposes of first stage were:

Subsurface Characterization:

  • High-quality geologic characterization prior to injection, and
  • Numerical modelling integrated with all phases of the project,

Monitoring and Verification:

  • Integration of multiple types of measurements, and
  • Use of wireline logs for monitoring plume movement.

Following the Frio-1 test, planning began for a second small-scale injection of about 300 tons of CO2 in the 17-m-thick Blue sand reservoir at 1650-m depth at the Frio site. The Blue sand has similar porosity (about 25%) and permeability (>2 Darcies) as the Frio-1 sand. A description of the Frio site and Frio-1 results is given in Hovorka et al. (2006).

During the second stage, 320 tonnes of CO2 were injected. The main objectives were:

  • To focus on storage permanence—quantifying residual saturation and dissolution.
  • Post-injection monitoring under stable conditions.
  • Establishing the effectiveness of buoyancy in moving CO2 through pore networks.
  • To observe arrival time and to capture associated geochemical changes.
  • Quantification of residual saturation trapping mechanism.
  • Quantification of dissolution during plume evolution.
  • To field test new tools (U-Tube, continuous X-well seismic).
  • To integrate chemistry and geophysics for model verification.

Time-lapse cross-well tomographic imaging of the Frio-1 CO2 plume demonstrated that large changes in seismic velocity (a 500 m/s decrease within the plume) were caused by the injection of supercritical CO2 into the brine reservoir (Ajo-Franklin et al., 2007; (Daley et al., 2006; Hovorka et al., 2006).

Figure 30. Monitoring set up at the Frio pilot project (Source:

An innovative geochemical sampling tool, the U-Tube, was installed in both the injection and the observation well 30 m updip of the injector to support in-zone fluid chemistry sampling. Formation fluid that was collected in the U-Tube was driven at reservoir pressure into evacuated sample cylinders at the surface by high pressure ultra-pure nitrogen. Samples were collected hourly to facilitate accurate delineation of CO2 breakthrough and recover uncontaminated and representative samples of two-phase fluids. Initial CO2 breakthrough occurred 51 hours after initiation of injection, resulting in an increase from 100 to 3,000 mg/l bicarbonate and decrease in pH from 6.7 to 5.7 in the analysed brine due to mineral dissolution (Kharaka et al., 2006).

Monitoring at the surface for a leakage signal was not effective because the natural and induced noise was large and the pre-perturbation period was shot. Examples of natural variability include a variably high water table , which resulted in little or no soil gas, and high natural CO2 flux because of the swampy forest setting (Klusman, 2004).

Costs & Regulations

The operators of the Frio Pilot project applied for a Class V experimental permit to the Texas Commission on Environmental Quality to inject CO2 into a saline aquifer as opposed to a Class I non-hazardous waste injection permit for a variety of reasons (Hovorka et al., 2003):

  • The injection period will be brief and concluded within a few months;
  • The volume injected will be small (3,000 tons);
  • The substance to be injected is benign (food-grade CO2);
  • The purpose of the experiment involves extremely close monitoring;
  • The area selected for the study is not suitable for a normal Class I injection well because it is faulted and penetrated by many oil wells; and
  • It is of benefit to all stakeholders to quickly, safely, and economically obtain information that will be useful in moving to a larger scale test, which is likely to be undertaken within the next few years. Information and experience obtained during this federally-funded experiment should be of substantive use in designing permit and monitoring strategies for that test.


In 2000, a project was begun in Japan at the Iwanohara base near Nagaoka, Niigata Prefecture, to inject CO2 underground. The METI-funded project was conducted by the Research Institute of Innovative Technology for the Earth (RITE). From July 2003 to January 2005, 10,400 tons of CO2 were injected (Figure 31) 1,100 m underground into a saline aquifer that is about 60 m thick. The caprock is a pelitic rock layer about 140 m thick. For the purposes of the test, purchased CO2 (a by-product of ammonia production) was delivered by road in liquid form to the injection site. A 1,230 m deep injection well was then used to inject the CO2 into the aquifer. The injection facilities included a liquefied CO2 vessel with an evaporator, booster, three main pumps controlling the injection pressure and volume and a heater to control the temperature. Carbon dioxide was injected at a rate of 20 t/day beginning in July 2003. Then, following a fifty-day intermission, it was injected at 40 t/day (Kikuta et al., 2005). During the injection period there were two planned breaks and an additional interruption due to an earthquake; nonetheless all of the CO2 was injected according to schedule. The magnitude-6.8 earthquake occurred about 20 km from the field site but other than causing a black-out that halted the operation of the aboveground facilities, no major abnormality occurred and operations resumed once safety was confirmed (Xue et al., 2006a).

Figure 31. Time-line of Nagaoka CO2 injection project.


For monitoring tests, three monitoring wells were installed around the injection well to monitor the CO2 and predict long-term CO2 movements through simulation. Three observation wells were drilled to depths of 1,319 m (OB-2), 1,270 m (OB-3) and 1,322 m (OB-4). The various methods that were employed for the monitoring process include geophysical logging (including induction, gamma ray, neutron and sonic logging), cross-hole seismic tomography, pressure and temperature measurement, induced seismicity monitoring sampling of fluids from the aquifer and observation of microseismicity (Xue, 2007). Sound waves that were used for observation confirmed that CO2 had respectively reached the observation wells located 40 m and 60 m from the injection well when 3 kt and 5 kt of CO2 had been injected (Xue at al., 2006b). Observations using cross-hole seismic tomography allowed visualisation of how the CO2 was spreading between the two observation wells sandwiching the injection well (Figure 32). Cross-well data were acquired before and after injection (6 times) (Figure 33). The cross-well seismic tomography detected a P-wave velocity decrease (CO2 invaded zone). An area of P-wave velocity decrease appeared near the injection well and the injected CO2 was found to be migrating along the formation in an up-dip direction. The results confirmed the usefulness of cross-well seismic tomography (Saito et al., 2006).

Figure 32. The source and receiver well geometry and the reference velocity field at the Nagaoka pilot site (Spetzler et al., 2008). The solid circle indicates the point of CO2 injection.

One of the improvements of monitoring techniques by applying differential analysis to cross-well seismic tomography was described by Onishi et al. (2007). Advanced well-logging was repeated 31 times during the experiment. Observed changes include decreases in P-wave velocity, and neutron porosity and an increase in resistivity. Repeat surveys allow mapping of breakthrough with time. This can be combined with fluid sampling to calibrate logging responses to provide estimates of CO2 saturation. Repeat borehole logging also allows comparison between estimates of porosity between different techniques (neutron and NMR) (Xue et al., 2006c). Spinner tests monitored flow within the borehole.

Figure 33. Seismic tomography monitoring results from the Nagaoka pilot site (Saito et al., 2006).

The geochemical analyses confirmed that the CO2 was dissolving into the saline aquifer water and that the CO2 would react with the rock to become mineralised and fixed in place. These data were used with simulation technology (GEM-GHG) to predict CO2 behaviour, indicating that after 1,000 years the CO2 will still be in almost the same place and that there is little possibility of it spreading in a wider area (Murai, 2007).


An analysis of the costs of CCS was carried out for four different types of CCS systems. For example, the total storage cost, assuming that power was supplied by a new coal-fired power plant, at a cost of 5yen/kWh, is estimated to be approximately 4,230 yen/t CO2 avoided (US$35.87/t CO2 avoided). This includes the costs of compressing 1 Mt/yr CO2 to 10 MPa, transport over 20 km and injecting by extended reach drilling (ERD) at a rate of 0.1 Mt/yr per well. The analysis found that geological storage costs in Japan were greater than the average costs stated in the IPCC SRCCS (2005). Transport costs are influenced by Japan’s dense population, while injection costs reflect the fact that the storage formations have low permeabilities. Figure 34 shows the estimates for each CCS component of the four systems.

Figure 34. Cost analysis based on model site survey (RITE, 2007)

Using data for storage costs obtained from the Nagaoka injection tests, (Akimoto et al., 2007) estimated the costs of CO2 aquifer storage in Japan. They found costs to be highly dependent on the scale of the operations, as well as the characteristics of the storage formation, transport distance and rate of injection.

Akimoto et al (2007) estimated injection costs for a range of scenarios based on an injection rate of 1 Mt CO2/yr. These are onshore injection into an inland reservoir and an offshore formation (by ERD), over a range of depths, and injection to a depth of 1,000 m using an offshore platform and subsea wellhead, for varying distances from the shore. For example, the cost of injecting 0.1 Mt CO2/yr/well to a depth of 1,000 m is estimated to be approximately 1,300 yen/t CO2 (US$11.18/t CO2) using an onshore well, 2,000 yen/t CO2 (US$17.20/t CO2) using ERD, 2,200yen/t CO2 (US$18.92/t CO2) using an offshore platform 10 km from the shore and 3,000 yen/t CO2 (US$25.80/t CO2) using a sub-sea wellhead 10 km from the shore (Table 22).

Table 22. Costs for injecting 1Mt/yr CO2, 0.1Mt/yr/well to a depth of 1,000 m.

Injection system Cost (JPY/t CO2) Cost (US$/t CO2)
Onshore well 1,300 11.18
ERD 2,000 17.20
Offshore platform (10km from shore) 2,200 18.92
Sub-sea well head (10km from shore) 3,000 25.80

Source: Akimoto et al (2007)

Transport costs were estimated for onshore pipelines, offshore pipelines and tankers as a function of transport distance, and also for onshore pipelines based on transport capacity. For example, Akimoto et al (2006) estimate that transporting 1 Mt CO2/yr over a distance of 100 km would cost approximately 3,300yen/t CO2 (US$28.37/t CO2) for an onshore pipeline and 1,800 yen/t CO2 (US$15.48/t CO2) using an offshore pipeline. It would cost over 3,800 yen/t (US$32.67/t) to transport CO2 in liquid form using a tanker for distances greater than 500km. Again, because of the high population density in Japan, the authors found that transport using onshore pipelines was more costly than using offshore pipelines. Furthermore, taking into account the influence of economies of scale, the cost of onshore pipelines is estimated to be as much as 5 to 10 times the average cost quoted in the IPCC SRCCS.

Ketzin (CO2SINK)

The CO2SINK project officially started in April 2004 and is aimed at developing an in-situ laboratory for the investigation of onshore CO2 storage (Förster et al., 2006). The target for the storage of CO2 is a sandstone aquifer in the Upper Triassic Stuttgart Formation in the Ketzin anticline in northern Germany (Figure 35). The migration of salt has formed several of these anticlinal structures in this part of Germany, which could act as traps for hydrocarbons. Approximately 30,000 tons per year are anticipated to be injected over 3 years and injection started in June 2008. The injection target is located at depths between 500 – 700 m and as a result, part of the CO2 will be in a gaseous state at the prevalent subsurface pressure and temperature conditions. The Stuttgart Formation sandstone aquifer is capped by an aquitard consisting of clay and gypsum of the Weser and Arnstadt formations. One injection well is used, with a true vertical depth of approximately 800m. The well was completed with 5.5 inch outer diameter production casing and

3.5 inch injection string.

Figure 35. Monitoring set-up of the CO2SINK project at Ketzin (Source:


The CO2SINK project incorporates a comprehensive monitoring program. Two observation wells were drilled 50 and 100 m away from the injection well, also with 800 m true vertical depth (Figure 35) and 5.5 inch outer diameter production casing. These wells allow borehole-based seismic and electrical measurements as well as extensive logging. A total of 200 m of core, covering the reservoir rock as well as the caprock formation, were collected and analysed.

Seismic monitoring methods that will be applied include cross-well, vertical seismic profile (VSP), moving source profiling (MSP), 2D and 3D time lapse techniques. A 3D 25-fold seismic survey with a 12 by 12 m resolution and about 12 km2 of subsurface coverage was acquired in 2005 to verify earlier geologic interpretations and to obtain a baseline for future seismic surveys (Juhlin et al., 2007; Jullien et al., 2005). During the autumn of 2007, baseline cross-well, VSP and MSP data were acquired at the injection site. Cross-well seismics will be repeated several times in the early stages of the injection process to map the time evolution of the CO2 plume in the vicinity of the injection well. Acquisition of VSP and MSP will be repeated twice during the injection period to map migration of the CO2 away from the injection well. The 2D seismic will be at the end of the injection period and will allow mapping of possible migration of the CO2 up towards the top of the anticline. Continuous Wavelet Decomposition (CWT) was successfully used as a valuable aid in enhancing the ability to map thin beds in seismic data. The CWT method can be used as a quick indicator of gas (hydrocarbon) and is an important technique in the monitoring phase of the CO2SINK project. Electrical Resistivity Tomography (ERT) will be used to complement seismic methods.

Risk Assessment

The Ketzin project will develop an integrated, cross-discipline methodology for risk assessment and management (Figure 36). In practice, this means the combining of individual risk issues identified at the specialist level into a common, comprehensive decision model and framework that will help project leaders to reduce risks to levels that are as low as reasonably practicable (ALARP). The top-level risks include all aspects of safety, cost, schedule and system performance, i.e., that the storage facility will retain the injected CO2 for the very long time required to mitigate climate change as illustrated in Figure xx.

The goals of the risk management work process for the CO2SINK project are to identify specifically for this CO2 storage site:

  • All potential sources of risk, including those to the local community,
  • Project decisions related to those risk sources, and
  • Alternative, mitigating actions to reduce risks to ALARP.

Figure 36. Illustration of top-level risks for the Ketzin Pilot project (CO2SINK project website).

Costs & Regulations

The total cost of the project is estimated to be €14 million (US$19 million) (CO2SINK 2007).

US Regional Carbon Sequestration Partnership Program

The US Department of Energy (DOE) has established seven regional carbon sequestration partnerships (RCSPs) to study CCS technologies. These are (NETL 2005):

  • Big Sky Regional Carbon Sequestration Partnership (BSCSP), led by Montana State University – covering Montana, Wyoming, South Dakota, Idaho, eastern Washington and Oregon
  • Midwest Geological Sequestration Consortium (MGSC), led by the Illinois State Geological Survey, in conjunction with the Indiana Geological Survey and the Kentucky Geological Survey – covering Illinois, south-western Indiana and western Kentucky;
  • Midwest Regional Carbon Sequestration Partnership (MRCSP), led by the Battelle Memorial Institute – covering Indiana, Kentucky, Ohio, Pennsylvania, New York and West Virginia
  • Southeast Regional Carbon Sequestration Partnership (SECARB), led by the Southern States Energy Board – covering Georgia, Florida, South Carolina, North Carolina, Virginia, Tennessee, Alabama, Mississippi, Arkansas, Louisiana and southeast Texas
  • Southwest Regional Partnership for Carbon Sequestration (SWP), coordinated by the New Mexico Institute of Mining and Technology – covering New Mexico, Oklahoma, Kansas, Colorado, Utah and portions of Texas, Wyoming and Arizona
  • Plains CO2 Reduction Partnership (PCO2R), led by the Energy & Environmental Research Centre at the University of North Dakota – covering North Dakota, South Dakota, Minnesota, Montana, Wyoming, Nebraska, Iowa, Missouri and Wisconsin and the Canadian provinces, Alberta, Saskatchewan and Manitoba
  • West Coast Regional Carbon Sequestration Partnership (WESTCARB), led by the California Energy Commission – covering California, Oregon, Washington, Alaska, Nevada, west Arizona, Hawaii and the Canadian province, British Columbia

The Programme consists of three phases (Battelle 2005):

  • Phase I, Characterisation phase (October 2003 to September 2005) – assessing storage options in the region, including characterising sources and sinks, assessing costs, risks and regulations and raising public awareness of CCS
  • Phase II, Validation Phase (October 2005 to September 2009) – conducting pilot projects to demonstrate and gather data on CO2 storage; and
  • Phase III, Deployment Phase (October 2009 to September 2017) – implementing large-scale pre-commercial geologic storage projects

Details of the CO2 storage projects being conducted by the RCSPs are described in a series of factsheets and presentations prepared for the Regional Carbon Sequestration Partnerships Annual Project Review Meeting, held 12-13 December 2007. The projects that inject or plan to inject into saline aquifers are listed in Table 23. Additional information can be found at the various RCSPs webpages accessible through the NETL website ( and in Litynski et al. (2008).

Table 23. Pilot and demonstration projects injecting or planning to inject CO2 into saline aquifers in the US Regional Partnership program.

RCSP Project Injection Start Project Status CO2 Storage Injection Unit Project Cost
BSCSP Moxa Arch Injection 2008 unknown 2 Mt Nugget Fm. $110,443,505
MGSC Decatur 2009 Well to be drilled January2009 1 Mt Mt Simon Sandstone $91,826,766
MRCSP Michigan Basin 2008 Injection complete & monitoring underway 10 kt Bass Islands Dolomite/Bois Blanc  
MRCSP Cincinnati Arch 2009 Injection due to start June 2009 1-3 kt Mt. Simon Sandstone $23,745,399 total for 3 projects
MRCSP Appalachian Basin 2008 Injection due to start October 2008 3 kt Oriskany, Clinton, and Rose Run Sandstone  
MRCSP Phase III 2010 Funded 1 Mt Mt Simon Sandstone $93,000,000
PCOR Fort Nelson 2010 Funded 10.8 Mt Unidentified Devonian carbonate $135,586,059
SECARB Mississippi 2008 Injection due to start late-2008 3 kt L. Tuscaloosa Fm $20,344,442 for all Phase II tests
SECARB Early Test Saline 2009 Funded 1.5 Mt L. Tuscaloosa Fm $98,689,241
SECARB Anthropogenic Test Saline 2010 Funded 1.0 Mt L. Tuscaloosa Fm
SWP Farnham Dome 2008 Site Characterisation underway 3 Mt Two Jurassic Sandstones $88,845,571
WESTCARB Salt River 2009 Permit applications underway 2 kt Martin Formation $5,500,000
WESTCARB Rosetta-Calpine Saline 2009 Site Characterisation completed 2 kt McCormick sand $5,925,223
WESTCARB Kimberlina 2010 Funded 1 Mt Olcese and Vedder Sandstones $90,719,100


The regulatory framework in the United States of America with respect to CO2 geological storage is discussed in detail by (Wilson and Gerard, 2007). The core premise of the Underground Injection Control (UIC) regulations is the containment of the injected material and protection of underground sources of drinking water. Operators must obtain a permit from the state agency or the Environmental Protection Agency (EPA) regional office before beginning injection operations. A detailed description of information required for the permitting process is set out in the Drinking water Academy (2002) document and includes comprehensive information on well sighting and construction, planned operation and monitoring, and plugging and abandonment.

Under the current regulatory regime in the US, injection of CO2 for geological storage would be permitted through Class I or Class II wells (Wilson and Gerard, 2007). Class I regulations cover hazardous and industrial wastes, whereas Class II wells are used for wastes associated with hydrocarbon production. Therefore, CO2 injected into saline aquifers originating from industry sources like power plants, refineries, and cement factories would require a Class I permit. Class II wells include CO2 used for EOR and CO2 produced in upstream gas operations. Neither regulation explicitly addresses storage time, reliability, or issues of long-term liability. According to Wilson and Gerard (2007), there are problems with permitting the injection of large quantities of a buoyant fluid in a Class I well, and a new Class VI category should be considered that excludes “no migration from the injection zone” and that represents a classification specifically tailored to CO2 geological storage. For example, the Frio Pilot project applied for a Class V permit (class used for all wells that do not fit classes I – IV) rather than a Class I non-hazardous injection permit for the reasons summarized by Hovorka et al. (2003) in their application to the Texas Commission on Environmental Quality (see Frio section).

The Interstate Oil and Gas Compact Commission (IOGCC) Task Force on Carbon Capture and Geologic Storage produced A Legal and Regulatory Guide for States and Provinces as a result of a two-phase, five-year effort (IOGCC, 2007). This Phase II report takes the form of a Guidance Document for U.S. states and Canadian provinces. Its purpose is to provide to a state or province contemplating adoption of a legal and regulatory framework for the storage of carbon dioxide (CO2) in geologic media the resources needed to draft a framework that meets the unique requirements of that particular state or province.

MGSC (Phase II & III) - Decatur

The MGSC (Midwest Geological Sequestration Consortium), ISGS, and Archer Daniels Midland Company (Khattri et al.) will work together on this carbon sequestration project, which will involve the capture and storage 333,000 tonnes of CO2 per year from ADM’s ethanol fermentation facility in Decatur, Illinois for three years. The originally planned Phase II small-scale injection of 10 kt of CO2 has been expanded to a combined Phase II and Phase III large-scale injection of 1 Mt of CO2 over 3 years. The injection target is the Cambrian Mt. Simon Sandstone (Figure 37), the most widespread saline reservoir in the Illinois basin, occurring at a depth interval of 1800-2300m at the test site. The Deployment Phase NETL factsheet for MGSC (2008) states that the Mt. Simon Sandstone is overlain by the Cambrian Eau Claire Formation, a regionally extensive, low-permeability shale and underlain by Precambrian granitic basement. The Mt. Simon is used extensively for natural gas storage in the northern half of Illinois, and detailed reservoir data from these projects show that the upper 200 feet of the Mt. Simon has the necessary porosity and permeability to be a good sequestration target. MGSC estimates that the average porosity of the Mt. Simon at the ADM site will be around 12%. The top of the Mt. Simon Sandstone at the ADM site is estimated to lie at a depth of approximately 5,500 feet. Within the Illinois Basin, the Devonian New Albany Shale and Ordovician Maquoketa Formation shale units will also function as significant regional seals. Also, many minor, thinner Mississippian and Pennsylvanian shale beds form seals for known hydrocarbon traps within the basin. All three significant seals are laterally extensive and appear, from subsurface wireline correlations, to be continuous within a 100-mile radius of the test site. The Eau Claire is estimated to be 300-500 feet thick and is expected to be the primary seal at the ADM site. The Ordovician Maquoketa Shale and the New Albany Shale are anticipated to act as secondary seals. There are no mapped regional faults and fractures within a 25-mile radius of the ADM site.

The CO2 will be obtained from ADM’s Ethanol Production Facility. Outlet CO2 streams from ethanol fermentor vents are typically 99%-plus pure CO2, and common impurities are ethanol and nitrogen in the range of 600 to 1000 ppmv each. Other impurities in lesser amounts often include oxygen, methanol, acetaldehyde, and hydrogen sulphide. The CO2 will be purified, dehydrated, compressed to ~2,000 psi and delivered to the wellhead as supercritical CO2. The dehydration/compression facility is proposed to be located near the north boundary of the ADM facility.

The safety and effectiveness of the storage will be monitored by the MGSC through an extensive MMV programme. Planned techniques include High Resolution Electrical Earth Resistivity (HREER), microseismic monitoring, vertical seismic profiling, geochemical monitoring, soil gas sampling, CO2 land surface flux monitoring, visible and infrared imaging, well logging, ground water monitoring, monitoring subsurface pressure and temperature, gas content and fluid chemistry and measuring CO2 injection rates, volume and isotopic composition. Monitoring will occur before, during, and post-injection. The program will rely heavily on 3-D seismic data collected during the first year of injection to monitor the plume’s position. The MMV program will be evaluated annually and modified as needed. Groundwater models such as MODFLOW and GFLOW will be used to develop a conceptual model for shallow groundwater flow and estimate the time for potential contaminants to travel outside the area of the injection site. This will provide a risk assessment for nearby water supplies in the unlikely occurrence of a CO2 leak either during or following CO2 injection. Geochemical models such as Geochemist’s workbench, PHREEQCI, and TOUGHREACT will be used to conduct thermodynamic modelling of shallow groundwater and injection-formation brine. These models will provide insight on the long-term fate of injected CO2 and will be used to study the regional impact of multiple injection wells on flow within a saline aquifer across the Illinois Basin. The project will begin in spring 2008 with the drilling of the injection well, with environmental monitoring beginning in October 2008 to collect background information over a year’s time. The sequestration and injection of CO2 is scheduled to begin in October 2009 and should conclude in 2012.

Figure 37. Regional diagram showing thickness of Mt. Simon Sandstone (Source: Deployment Phase NETL factsheet for MGSC, 2008).

The MGSC estimates that the Phase II and III project will cost US$91,826,766. US DOE funding totals US$70,353,741, while US$21,473,025 will come from non-DOE sources.

WESTCARB (Phase II) - Salt River

WESTCARB (West Coast Regional Carbon Sequestration Partnership) will conduct a three-phase field validation test in Northern Arizona to assess the CO2 storage potential of the region, the Arizona Utilities CO2 Storage Pilot. Three coal-fired power plants, Navajo, Coronado and Springerville, are located in the region and emit 30-40 Mt CO2 per year. Beginning in 2009, approximately 2,000 t purchased CO2 will be injected into the 200 m thick Martin Formation at a depth of 1050 m below the Colorado Plateau (Figure 38). The details of the project are summarised by (Trautz, 2007a). WESTCARB evaluated a range of monitoring techniques to identify the most cost-effective combination to achieve the project objectives. The program consists of analysing fluid composition, monitoring subsurface pressure, well logging, vertical seismic profiling (VSP), cross-well seismic imaging, caprock integrity, CO2 land surface flux monitoring and soil gas sampling. Results from the test will be used to extrapolate the regional storage potential of the Colorado Plateau in Northern Arizona. The capacity of the storage formations will be assessed relative to the size of regional sources of CO2.

WESTCARB estimates the total cost of the project to be US$5,500,000. The US DOE will contribute US$4,400,000 and non-DOE sources US$1,100,000.

Figure 38. Schematic showing the subsurface lithology in Northern Arizona. Injection is planned for the Devonian age Martin Formation.

WESTCARB (Phase II) - Rosetta-Calpine Saline

Two pilot tests involving CO2 injection will be performed at the Rosetta CO2 Storage project site. A thorough review of existing and abandoned natural gas fields in the southern Sacramento Valley, California was performed. The proposed field site for the pilot test is in a small-depleted and abandoned natural gas field located north of Thornton, California. Gas production began in the mid 1940s and continued through the late 1980s, producing nearly 1.52 x 109 m3 (53.6 billion cubic feet, Bcf) of gas from 14 wells. The Thornton Gas Field is an excellent geologic analogue to numerous gas fields in the Sacramento Valley, including the much larger 9.3 x 1010 m3 (3.3 Tcf) Rio Vista Gas Field located a few miles away near Rio Vista, California. The Rio Vista Gas Field is the largest onshore gas field in California. Thornton was also selected based on evidence of a favourable set of stacked gas reservoirs and saline formations, its close proximity to major transportation corridors, shallow depth to the gas pay zone 928 m and geologic evidence of a well-defined stratigraphic gas trap that would safely hold the CO2.

The first pilot test in 2009 will involve injecting up to 2000 tons of CO2 into a brine-filled zone in the McCormick sand, a very fine to medium grained, quartzitic sandstone. Two wells, a CO2 injector and an observation well, will be installed in a saline zone located beneath the gas trap in the McCormick sand (Figure 39). The current best estimate for the target depth of the saline test is 1037 to 1067 m. Both wells will be drilled to approximately the same depth and the casing will initially be perforated in the saline zone. CO2 injection will commence after logging and testing the wells. The Capay shale represents a regionally extensive reservoir cap, containing pockets of natural gas in thin interbedded sand lenses. The top of the McCormick sand, a depleted water-drive reservoir at a slightly greater depth of 1003 to 1021 m, is an alternative location if the Capay sand stringer is absent at the location of the new wells. The casing will be perforated in the gas zone after completing the first experiment and cementing the well perforations shut in the lower saline zone. The second experiment will consist of injecting CO2 into the depleted gas zone to assess the nature and extent of reservoir pressurisation and displacement of CH4 by CO2. The CO2 will be purchased from a local supplier and trucked to the pilot site. Information source: Factsheet for Rosetta-Calpine saline validation test (Trautz, 2007b).

WESTCARB is evaluating a range of monitoring techniques for tracking CO2 movement and detecting leaks. The techniques being considered include vertical seismic profiling (VSP), caprock integrity, electrical and electromagnetic techniques, CO2 land surface flux monitoring and soil gas sampling.

WESTCARB estimates the total cost of the project to be US$5,925,223. The US DOE will contribute US$3,545,000 and US$2,380,223 will be contributed by non-DOE sources.

Figure 39. Geologic section at the Rosetta pilot site. Information source: Factsheet for Rosetta-Calpine saline validation test (Trautz, 2007b).

WESTCARB (Phase III) - Kimberlina

The WESTCARB Partnership will conduct a field validation test in Kimberlina, California. The details of the project are summarised by (Myer, 2007). Small-volume injection testing will be conducted in 2009. From 2010, the project will inject 250,000 tons CO2 per year over 4 years into an aquifer in the San Joaquin Basin, below a proposed Clean Energy Systems (CES) oxy-combustion power plant with CCS. The new plant and infrastructure for capturing, compressing and injecting CO2 will be constructed next to the CES pilot plant installed at the site for R&D purposes.

Two formations are being considered for storage. These are the Olcese and Vedder sandstones, located at depths of 2,400 m and 2,700 m respectively. The units have thicknesses of 240 m and 150 m respectively at the injection site. WESTCARB estimates that their combined storage capacity is 400Mt in dissolved and residual capacity and 1,500 Mt in physical capacity (Myer 2007).

Monitoring will occur before, during and after injection. Activities planned include vertical seismic profiling, logging, coring, pressure, temperature and fluid testing, 3D seismic surveys, microseismic monitoring, CO2 flux monitoring and atmospheric CO2 monitoring.

WESTCARB estimates the total cost of the project to be US$90,719,100. The US DOE share of the costs will be US$67,000,000 and the non-DOE share US$23,719,000.

MRCSP (Phase II) - Appalachian Basin

MRSCP (Midwest Regional Carbon Sequestration Partnership) will inject 3,000 tonnes of CO2, at a rate of approximately 20 t/day, into an aquifer located in the Appalachian Basin alongside the Ohio River. The source of CO2 will be a pilot-scale Powerspan emission control system, to be installed at FirstEnergy’s R.E. Burger facility, a 413 MW coal-fired power plant. The CO2 will be transported to the injection site by a pipeline system comprising a 150 m, 3.5 inch outer diameter, above-ground pipeline from the capture facility and a 450 m, 2.375 inch outer diameter, buried pipeline to the injection well.

A number of potential storage formations have been identified at the site. These include the Tuscarora ”Clinton” sandstone located at a depth interval of 2474-2535 m and the Oriskany Sandstone at 1805-1814 m (Figure 40). The Partnership drilled an injection well to a depth of 2555 m in the year 2007, penetrating the Clinton formation.

The measurement techniques being considered for the monitoring program are those that can be applied using the injection well, as a monitoring well was judged to be uneconomic. These include analysis of water composition, monitoring subsurface pressure and logging. 3D seismic is also being considered.

Figure 40. Conceptual diagram of CO2 sequestration tests for Appalachian Basin site. Information source: Factsheet for Appalachian Basin saline validation test (Gupta, 2007a).

MRCSP (Phase II) - Michigan Basin

The MRCSP (Midwest Regional Carbon Sequestration Partnership) injected 10,241 tonnes of CO2 from February 18-March 8, 2008 into a deep saline aquifer located in the Michigan Basin near the Niagaran Reefs. The CO2 was obtained from the DTE Turtle Lake Gas Processing Plant, compressed onsite and transported to the storage location by a “White Frost” pipeline. The target aquifer is the Bass Islands Dolomite, located at a depth of 1049 -1072 m (Figure 41). The unit has an average porosity of 21 % and an average permeability of 22 mD. The confining layer is the Amherstburg Limestone. MRCSP drilled the injection well to a depth of 1770 m into the reefs in November 2006. An existing nearby oil well has also been recompleted to serve as a monitoring well.

The monitoring programme for the site includes monitoring introduced and natural tracers, water composition and subsurface pressure, soil gas sampling, well logging, vertical seismic profiling, cross-well seismic imaging and passive seismic monitoring. The MRCSP is also considering 3D seismic surveys as an option.

Figure 41. Conceptual diagram of CO2 sequestration tests for Otsego County Michigan site. Information source: Factsheet for Michigan Basin saline validation test (Gupta, 2007b).

MRCSP (Phase II) - Cincinnati Arch

MRSCP will inject up to 3,000 t CO2, at a rate of 100 t/day, into an aquifer in the sedimentary sequence along the Cincinnati Arch in Kentucky. The test will be conducted at the Duke Energy East Bend facility, a 650MW coal-fired power plant. The CO2 will be sourced from the Babcock and Wilcox oxy-coal combustion system in southeast Ohio and transported to the storage site by truck. The target aquifer is the Mt. Simon sandstone, located at a depth interval of 3,200 - 3,500 ft. The Partnership plans to begin drilling an injection well to the bottom of the reservoir in the year 2008. A monitoring well is also being considered. A variety of techniques have been proposed for the monitoring programme. These include analysing water composition, monitoring subsurface pressure, well logging, vertical seismic profiling and cross-well seismic imaging (Gupta, 2007a).

A total cost of US$23,745,399 is expected for the three Phase II MRCSP projects.


The details of MRCSP’s Phase III operations are summarised by Ball (2007). The project will involve one of two injection sites. The primary site is the Andersons Marathon Ethanol Plant currently being built in Greenville, Ohio. Beginning in late 2009, 280,000 t CO2 would be injected per year over 4 years at the site. The optional site is a 640 MW IGCC plant in Indiana, where 2,000,000 tons CO2 would be injected over 4 years, possibly beginning in the year 2012.

The storage formation for the primary site is the Mt. Simon Sandstone aquifer, located at a depth interval of approximately 1,000 -1,100 m. The formation has an average porosity of 12 % and permeability of 50-400 mD. CO2 will be injected using injection wells drilled to less than 4,000 ft. Monitoring wells will also be drilled to similar depths. The site will be monitored during and after injection. Proposed activities include cross-well seismic and microseismic monitoring, 3D seismic surveys, measuring injection pressure and volume and fluid sampling. A number of storage formations are being considered for the optional test site. The main target is the Mt. Simon aquifer located at a depth interval of 2,285 - 2,625 m at the site. In this location, the formation has an average porosity of 10 % and permeability of 10-200 mD. The secondary target is the Knox Carbonates.

The total cost of the Phase III project is estimated to be US$93,000,000. The US DOE will contribute US$61,000,000 and non-DOE sources US$32,000,000.

PCOR (Phase III) Fort Nelson

The Deployment Phase NETL factsheet for PCOR (2008) states that the Fort Nelson project will utilise 1.8 million tons of CO2 per year for six years, captured from one of the largest gas-processing plants in North America. The CO2 will be compressed and transported in a supercritical state via pipeline to the target injection location. While a specific brine formation and injection location have not yet been chosen, it is anticipated that the target zone will be a Devonian-age carbonate rock formation located in relatively close proximity to the gas plant (< 3 km) in north-eastern British Columbia. The thickest and most comprehensive seal for the carbonate rock formations under consideration are the massive and extensive Fort Simpson Formation shales, which are characterised by low permeability and high geomechanical strength. This cap provides a very competent seal for underlying brine-saturated formations. The cumulative average thickness of the Fort Simpson Formation is approximately 500 m, and in some areas the thickness can be in excess of 1000 m. The Fort Simpson Formation is laterally extensive, underlying thousands of square miles. Secondary seals also exist above the Fort Simpson Formation, the most competent and massive being the Banff Formation, which is predominantly shale and not less than 30 m thick in the Fort Nelson area.

The source of the CO2 will be the Spectra Energy Fort Nelson natural gas-processing plant in north-western British Columbia. The CO2 will be captured using an existing amine-based acid gas removal system, dried, compressed, and transported by pipeline as a supercritical fluid to a nearby injection site. Its composition will be approximately 85% CO2 and 15% H2S.

MMV techniques used will include the following: pressure monitoring, fluid sampling (oil, gas, water), pressure and geochemical monitoring of overlying formations, downhole geophysical monitors (passive microseismic and/or tiltmeters), surface CO2 measurements, ion chemistry and isotopes of sampled fluids, and tracer (e.g., perfluorocarbons) monitoring.

PCOR reports that this project and another project combined will cost US$135,586,059. US DOE funding totals US$67,000,000, while US$68,586,059 will come from non-DOE sources.

SECARB (Phase II) Mississippi

The Validation Phase NETL factsheet for SECARB (2008) states that the primary objective of this project is to locate and test suitable saline formations for storage of CO2 in proximity to large coal-fired power plants along the Mississippi Gulf Coast. The target formation for this field test is the Cretaceous Lower Tuscaloosa Massive Sand Unit in Jackson County, Mississippi. The test will include building detailed geological and reservoir maps to further assess the test site and conducting reservoir simulations to estimate injectivity, storage capacity, and long-term fate of injected CO2. Injection of 3,000 tons of CO2 at an approximate depth of 2,620 m will take place at Mississippi Power Company’s Plant Daniel, located near Escatawpa, Mississippi in late 2008. An injection well and an observation well were drilled at Plant Daniel during March-April 2008.

A total of 24 wells, including 20 oil & gas plus 4 Class II wells provided the essential deep subsurface information for the Mississippi Gulf Coast area. The nearest deep wells are about 5 to 10 miles away, limiting available geologic information for the plant area. EPA defined “Low Salinity” waters (<10,000 mg/l) are protected and exist at a depth of about 490 to 850 m below surface in Jackson County, while the freshwater (<1,000 mg/l) zone exists in shallower formations.

SECARB reports that this project and the other Phase II projects combined will cost US$20,344,442. US DOE funding totals US$14,663,953, while US$5,680,489 will come from non-DOE sources.

SECARB (Phase III) Early Test Saline and Anthropogenic Test Saline

The Deployment Phase NETL factsheet for SECARB (2008) states that it will conduct a two-step, large-volume injection test in the lower Tuscaloosa Formation, a key component of a larger, regional group of similar formations, in terms of deposition and character, called the Gulf Coast Wedge. The first step, or “Early Test,” will inject 1.4 million tonnes of CO2 per year for 18 months. The CO2 will come from a naturally occurring source that is commercially available, of high purity, highly reliable, and low cost. The source is the Jackson Dome and it will be delivered by Denbury Resources’ CO2 pipeline. The second step, or “Anthropogenic Test,” will inject 100,000 to 250,000 tonnes of CO2 per year for four years. The CO2 will be supplied from a pilot unit capturing CO2 from flue gas produced from a Southern Company power plant located near the injection site.

The Early Test will focus on the down-dip “water leg” of the Cranfield unit, operated by Denbury Resources, Inc. in Adams and Franklin Counties, Mississippi, about 15 miles east of Natchez, Mississippi, and near Cranfield. The area selected for the Early Test is immediately north of the SECARB Validation Phase “Stacked Storage” study underway in the oil rim field. The Anthropogenic Test will be conducted on or in proximity to a Southern Company plant site on the Gulf Coast. The Cretaceous lower Tuscaloosa Formation is one of the named stacked sandstone formations of the Gulf Coast Wedge. The Tuscaloosa contains an upper section of alternating shales and sands and a basal section, the Massive Sand Unit, which contains a thick layer of clean, coarse-grained sand. The Formation was deposited during a major period of global sea level rise, and its deposition has been interpreted as an upward gradation from fluvial and deltaic sedimentation (the Massive Sand) to shelf deposition (alternating sands and shales). The Massive Sand was deposited in a wave-dominated shallow coastal barrier environment. The well-sorted, clean, coarse-grained nature of the Massive Sand makes it an ideal candidate for CO2 injection due to its high permeability and porosity. As the sea level continued to rise, the shelf depositional environment gave way to a deep marine environment, during which the overlying middle (Marine) Tuscaloosa Formation was deposited. This formation consists of about 150 m of low-permeability shale, providing an excellent cap rock and primary seal to CO2 injection into the lower Tuscaloosa Formation.

The MMV programme planned by SECARB will span the 10-year Deployment Phase of the project. Each site will be well-instrumented with multiple sensor arrays. In the “Early Test,” sweep efficiency will be monitored by saturation measurements along well bores, cross well measurements, and vertical seismic profiling (VSP) and/or surface seismic methods. Proposed monitoring activities for the “Anthropogenic Test” will include:

  • well bore integrity assessed through Ultrasonic Imaging Tool (USIT) logging, annular pressure monitoring, and tracer injection;
  • assessment of areal extent of the plume through drilling and monitoring up-gradient wells, seismic surveys (3-D and VSP), and Reservoir Saturation Tool (RST) logs in observation wells;
  • monitoring for formation leakage through RST logging and using the VSP geophones to map and trace CO2 leakage; and
  • CO2 seepage through shallow subsurface monitoring for CO2, carbon isotopes, and tracers.

To help predict plume movement and assess the ultimate fate of the injected CO2, the project team will utilise two types of simulation models: GEM simulation software and TOUGHREACT.

SECARB reports that the projects will cost a total of US$98,689,241. US DOE funding totals US$66,949,078, while US$28,740,163 will come from non-DOE sources.

SWP (Phase III) – Farnham Dome

SWP’s Phase III aquifer project intends to accomplish a major deep saline sequestration deployment in an area known as Farnham Dome in Central Utah. This test will follow an injection schedule over 4 years (2008-2011), leading up to 900,000 tonnes of CO2 per year. The target formations are deep saline units present throughout the Southwest Partnership region, as well as in many states outside the region. The Farnham Dome injection site is located just southwest of the Uinta basin, near Price, Utah, 120 miles south of Salt Lake City. Farnham Dome is an elongated surface anticline located along the northern plunge of the San Rafael uplift. The area provides an excellent deployment test opportunity for analysis of high injection rates and high-resolution monitoring of CO2 in multiple rock layer horizons. These deep saline formations are major targets for commercial-scale sequestration associated with future coal-fired power plants planned for the area (SWP, 2008).

The Deployment Phase NETL factsheet for SWP (2008) indicates that the target formations are deep saline units present throughout the SWP region, as well as in many states outside the region. In all cases, the seal is the Morrison Formation, a 120 m thick Jurassic shale/gypsum/siltstone, also regionally present throughout the SWP states. At the study site and all other sites, the target units lie within a true “stacked” system—above the Morrison formation lies the Dakota formation, a Cretaceous-aged sandstone similar to the deep Triassic and Permian sands, and capped by the Pierre/Mancos shale, a very thick (500 m to 1500 m) shale unit. The SWP has gathered porosity, permeability, mechanical, compositional, and geophysical data associated with these target formations and seals.

The sources of CO2 include natural CO2 from the Jurassic-aged Nugget Sandstone or a coalbed methane (CBM) production field northwest of Price, Utah; the CBM operation currently vents over 100,000 tons of CO2 per year. A short pipeline will be required to transport captured CO2 to the injection site. All CO2 captured will be 97% pure, with the remainder nitrogen (air).

An extensive monitoring programme is planned to determine whether CO2 is securely sequestered. Techniques include vertical seismic profiling, cross-well seismic imaging, monitoring of tracers, water composition and subsurface pressure, well logging, repeat 3D seismic surveys, electrical and electromagnetic techniques, microgravity techniques, visible and infrared imaging, CO2 land surface flux monitoring and soil gas sampling. A variety of “in house” and commercial/public simulation tools will be used, including GEM, TOUGH2, TOUGHREACT, FEHM, CO2-PENS, COMSOL, THRUST3D, MRKEOS and SWEOS.

SWP estimates that the project will cost US$88,845,571. US DOE funding totals US$65,437,395, while US$23,408,176 will come from non-DOE sources.

BSCSP (Phase II & III) - Moxa Arch Injection

BSCSP will conduct two Phase II geologic storage projects. The two storage options being tested are mafic rock formations and saline aquifers. Beginning in the year 2008, the saline formation pilot test will involve injecting 3,000-5,000 tons CO2 into the Triassic Nugget Sandstone Formation in the Riley Ridge Field, Wyoming. The details of the project are summarised by (Thyne, 2007).

The Nugget Sandstone aquifer is located at a depth of 3350 m and has a total thickness of 215 m near the injection zone. The high permeability target zones have average thicknesses over 60 m and porosities over 15%. CO2 will be injected into the reservoir using new wells and existing wells drilled by Cimarex Energy for extracting helium and methane. Observation wells will be drilled for monitoring purposes. A variety of techniques are planned for monitoring the post-injection behaviour of CO2. These include vertical seismic profiling, microseismic techniques, microgravity, well sampling, soil gas surveys and tracers.

The total cost of the project is estimated to be US$7,973,762. The US DOE will contribute $2,976,806 while US$4,996,956 will come from non-DOE sources.

Following the Wyoming Phase II Saline Injection test, BSCSP will conduct a large-volume injection test at the site. A total of 2 million tons CO2 will be injected into the Triassic Nugget Sandstone Formation. The source of CO2 will be a Cimarex Energy gas plant to be built in the year 2008. The details of the project are summarised by (Spangler, 2007).The Partnership plans to have one injection well and at least four monitoring wells. Along with the fundamental monitoring methods, the monitoring programme may also include the use of eddy-correlation towers, LIDAR and IR detection tools and hyperspectral tools.

The total cost of the project is projected to be US$110,443,505. US$41,627,108 will be contributed by the US DOE and US$68,816,397 by non-DOE sources.

Other Planned Injection Projects


There are various projects in Canada that intend to inject CO2 into saline aquifers. All of these projects are in the early planning stages and include:

Heartland Area Redwater Project (HARP) – The Alberta Research Council (ARC) and the ARC Energy Trust of Calgary intends to evaluate a Devonian reef complex to store up to 1 Gt of CO2 in the near vicinity of the industrial complex northeast of Edmonton. Additional industry consist mainly large CO2 producers from the Edmonton area. The Heartland Area Redwater Project has three phases: phase one will evaluate in detail the size and suitability of the site for CO2 capture and storage, phase two will involve the drilling of a well to collect more detailed data, while phase three is planned to demonstrate actual CO2 injection and storage. The $1.8 million first phase is being funded by ARC Energy Trust, the Alberta Energy Research Institute (AERI) and Natural Resources Canada (NRCan) and is scheduled to be completed in spring 2009.

Wabamun Area CO2 Sequestration Project (WASP) - will assess the geological and technical requirements, economic feasibility and technical and regulatory issues related to the potential to safely store up to 1 Gt of CO2.The 16-month assessment is being coordinated by the University of Calgary’s Institute for Sustainable Energy, Environment and Economy (ISEEE). The $850,000-study is scheduled to be complete by mid-2009. Government funding is provided through the Alberta Energy Research Institute (AERI) and by the federal government’s Natural Sciences and Engineering Research Council (NSERC). Funding is also being supplied by energy-sector partners TransAlta, TransCanada Corporation, ARC Energy Trust and Penn West Energy Trust.

Alberta Saline Aquifer Project (ASAP) – The project is driven by Enbridge, a pipeline company, with provincial government money and 30 industry participants at 20K each in Phase I. The initial objective of this phase is to identify the top three aquifer storage sites in Alberta and is anticipated to be completed by the end of 2008. Phase 2 will involve pilot injection operations, which may be expanded to large-scale, commercial operations in future phases.

Aquistore - Storage of 1000 t/d in a deep saline aquifer near Regina, Saskatchewan. CO2 sourced from the COOP Refinery in Regina. Project to run between 2008 and 2012, managed by the Petroleum Technology Research Centre (PTRC). The costs are budgeted at CAD 50M.

QUEST - Project started by Shell Canada to store >1 Mt/yr from its oil sands upgrader in Fort Saskatchewan into a deep saline aquifer northeast of Edmonton. Project was stopped when Shell International took over Shell Canada in May 2007, but is likely to be followed up on in the future.


As integrated project under the 6th framework programme of the European Union, three sites have been identified by DYNAMIS for further study of their potential CO2 geological storage (

  • Mongstad, Norway, suggested by Statoil: Natural gas based plant with offshore CO2 storage.
  • Hamburg region, Germany, suggested by Vattenfall; Bituminous coal based plant with onshore or offshore CO2 storage.
  • East Midlands, England, suggested by E.ON UK; Bituminous coal based plant with offshore CO2 storage.

A fourth site in the North East UK has plans for offshore CO2 storage in an EOR field.


Australian projects planning to inject CO2 into saline aquifers are (Cook and Van Puyvelde, 2008):

  • Callide Oxyfuel, Queensland: Demonstration project that involves conversion of an existing 30MW unit at Callide A (currently underway), and capture of CO2. The second stage of the project will involve the injection and storage of up to 50,000 tonnes of captured CO2 in saline aquifers or depleted oil/gas fields, and will continue for up to five years, commencing in 2010. This project is expected to cost A$180 million. Partners involved in this project include CS Energy, IHI, ACA, Schlumberger, CCSD and CO2CRC.
  • Coolimba Power, Western Australia: Aviva Corporation Ltd recently announced a proposal for the development of 2x200MW oxyfuel coal-fired base-load power stations, with subsequent conversion to capture carbon dioxide during the combustion of coal. Storage is projected to commence after the oxy firing conversion is completed, potentially in 2011-12.
  • FutureGas, South Australia: A joint venture between Hybrid Energy Australia and Strike Oil will research and develop the carbon dioxide storage component of the FuturGas Project – an energy conversion development involving the gasification of lignite to syngas, for the production of synfuels. It is proposed that the CO2 (captured post-gasification), will be stored in the Otway Basin to the south of the lignite resources. Currently the project is at the feasibility stage, the plan being to commence full-scale CCS by 2016.
  • Monash CTL, Victoria: This proposed project will involve drying and gasification of brown coal, for conversion to synthetic diesel, followed by the separation of the produced CO2 (up to 10 million tonnes a year), and its transport and injection into a suitable storage site. This project which has an indicative start date of 2015 is estimated to cost A$6-7 billion. Capture and offshore storage is expected to commence in 2015. Partners involved in this project include Monash Energy, Anglo American and Shell.
  • ZeroGen, Queensland: This Queensland Government project, proposes to demonstrate integrating coal-based gasification and CCS Commercial 2011-2012. The CO2 will be transported approximately 200kms by pipeline for storage in the Denison Trough (up to 400,000 tonnes CO2 per annum). A feasibility study is underway but the project is estimated to cost in excess of A$1 billion dollars. Companies involved in the project include Shell and Stanwell.

Other CO2 Injection Projects

Two projects not injecting into saline aquifers, Weyburn in Canada and Otway in Australia, are presented in this section for comparison purposes, because comprehensive site characterisation and monitoring programs have been performed at these operations.

Otway, Australia

The CO2CRC has developed a research project which involves CO2-rich gas being extracted from a gas well (Buttress) then compressed and piped to a deeper depleted natural-gas field (Naylor). Here, the CO2 is injected through the new CRC-1 well and injection began in March 2008. Over two years, up to 100,000 tonnes of the CO2-rich gas stream at supercritical state will be injected into a depleted gas reservoir – the Waarre C Formation - at a depth of 2050 metres. CO2 will migrate up-dip within the 31m thick reservoir sandstone capped by the impervious thick seal rock (the Belfast Mudstone). Drilling of the new injection well to inject CO2 into the Waarre C Formation began on 15 February 2007 and was completed within budget on 15 March 2007. Located 309 m southeast from the Naylor-1 well, it is a vertical monobore well and was drilled to a depth of 2249 m into the Eumeralla Formation. Five cores were acquired with a total length of 42.9 m. Other samples collected include fluid, mud, gas and cuttings. The CO2 is derived from the Buttress-1 well, which was drilled in 2002 with the intention of producing natural gas. When it was found rich in CO2 it was decommissioned. Production well tests to confirm suitability as the production site for the Otway Project were carried out by CO2CRC in June 2006. The produced gas contains a significant proportion of CH4 (19%) but it was established that injection of this Buttress gas mixture would not compromise the research objectives of the Otway Project. The confirmed absence of mercury and hydrogen sulphide allows the injection of the produced Buttress gas straight into the depleted Waarre Formation, which already contains residual methane. The CO2 is delivered to the injection well via a pipeline that was installed between December 2007 and January 2008. It is 2.25 km long, stainless steel and 50 mm in diameter. The maximum design temperature and pressure are respectively 50oC and 15 MPa.

Figure 42. Conceptual diagram showing injection and monitoring installations for the Otway Pilot project.


A comprehensive monitoring program across the atmospheric, near surface and subsurface domains is underway. Monitoring and modelling activities will continue post-injection for several years and it is predicted that CO2 will be detected 6-9 months after the start of injection at the Naylor-1 site. The monitoring activities include: atmospheric monitoring; geochemical monitoring; and geophysical monitoring, including seismic surveys. Monitoring includes downhole geochemical and geophysical measurements at Naylor-1 observation well; hydrological monitoring of water levels, analysing groundwater chemistry from shallow aquifers and sampling soil gas; and atmospheric monitoring of gas composition. Atmospheric monitoring underway at the Otway site includes:

  • an atmospheric station with a CSIRO LoFlo CO2 analyser continuously measuring concentrations of CO2;
  • a CO2 flux tower continuously measuring surface-air CO2 fluxes of a representative area of the site; soil CO2 flux measurements taken at many point locations across the region;
  • modelling of the ecosystem CO2 and pre-existing industrial/agricultural CO2 sources;
  • measuring tracers to help confirm the origin of the CO2 emissions to the local atmosphere and to quantify emissions; and,
  • headspace gas sampling to establish the presence, concentration and distribution of any CO2 gases or related gases, and their distribution within three nominated water boreholes adjacent to the project.

Geochemical monitoring underway at the Otway site includes:

  • Chemical tracers (CD4 (perdeuterated methane), SF6 (sulphur hexafluoride) and Kr) are used to “tag” the CO2 and CH4 compounds of the injection stream in order to verify the CO2 plume behaviour;
  • Downhole samples of well-bore fluid and gas are collected at reservoir pressure from multiple levels and analysed for their chemical and isotopic composition to detect the arrival of CO2 at the Naylor-1 site and to characterise chemical changes associated with this; and
  • U-tubes are used to detect the arrival of CO2 at Naylor-1 through the identification of tracers injected at CRC-1 in order to characterise CO2 migration and behaviour within the Waarre C formation. During injection, the CO2 migrates from the CRC-1 injection well to accumulate below the residual methane cap at the Naylor-1 monitoring well pushing the point of gas-water contact (GWC) down. Injection will stop when the injected CO2 is detected at U-tube 3. These tracers enable researchers to identify the amount of time it takes CO2 injected at CRC-1 to travel to Naylor-1, track the movement of CH4 relative to CO2, provide additional information on the long-term fate of injected CO2 and confirm that there has been no leakage to shallow aquifers, soils or the atmosphere.

Seismic monitoring underway at the Otway site includes:

  • 4D surface seismic surveys;
  • High Resolution Travel Time (HRTT) which will enable monitoring of fine changes in fluid level and verify the volume of CO2 injected. The injected CO2 is expected to rise and collect beneath the gas cap. Continuous injection will force the GWC down. HRTT data will be acquired with permanently installed geophones strategically located above and below the GWC in the Naylor-1 monitoring well;
  • Vertical Seismic Profiling (VSP) using seismic sources located at the surface and receivers positioned in the boreholes; and
  • Microseismic surveys will check that the in-situ conditions of the reservoir have not led to fractures or fault reactivation. Downhole geophones are installed just above the packer within the Naylor-1 well and geophones are placed near the top of a nearby well.

CO2CRC finished construction for the project in April 2008. Table 24 shows a summary of the costs at this time.

Table 24. Otway Project Costs End of April 2008.

Item Cost (2008 A$) Cost (2008 US$)
Buttress-1 well testing 565,133 526,512
- Drilling and monobore completions, 50m of core and analysis 4,744,650 4,448,350
- Extra coring 75,000 69,875
- Workover to close initial perforations and run baseline logs 786,591 732,835
- Workover to run completion 1,076,826 1,003,236
2.25km, 50mm diameter, stainless steel pipeline 1,652,063 1,539,161
Process plant, compression based 3,140,954 2,926,301
Permits/licences 117,931 109,872
Process group 1,796,000 1,673,261
Project management 2,051,515 1,911,314
Abandonment 900,000 838,494
OPEX 1,450,000 1,350,908
- Pre-operations 799,333 744,707
- Year 1 475,000 442,539
- Year 2 175,667 163,662
Operations contingencies 33,875 31,560
CO2CRC Pilot Project Limited (CPPL) 4,367,000 4,068,559
- Management (legal/bank fees, etc.) 686,000 639,119
- Operations (insurance, licence fees, etc.) 1,026,000 955,883
- Tenements (Buttress and Naylor) 2,655,000 2,473,557
Total Operations 22,787,538 21,230,238
CRC Executive OBPP 1,874,000 1,745,931
CRC Geoscience 1,046,000 974,516
CRC M&V Personnel 1,251,000 1,165,507
CRC M&V Research 2,573,000 2,397,161
- Atmospheric monitoring 670,000 624,212
- Geochemical monitoring 703,000 654,957
- Geophysical monitoring 1,200,000 1,117,992
CRC Outreach and Risk 181,000 168,630
Total Science 6,925,000 6,451,746
Total Project Costs 29,712,538 27,681,983

Source: CO2CRC (2008)


The Petroleum Technology Research Centre (PTRC) with EnCana Resources runs the IEA GHG Weyburn CO2 Monitoring and Storage Project in south-eastern Saskatchewan, Canada. In September 2000, injection of CO2 commenced into the Weyburn Unit through 18 inverted 9-spot pattern wells at a rate of 5000 tonnes/day. A total of about 20 Mt is expected to be injected over the project life. The CO2 is captured from a coal gasification project in North Dakota and transported approximately 320 km by pipeline to the Weyburn Field. Injection occurs at a depth of 1500 m into the Mississippian Midale Beds, consisting of a lower ‘vuggy’ limestone unit and an overlying ‘marly’ dolostone unit. The reservoirs are sealed by the Midale Evaporite, which is a competent anhydrite layer.


The Weyburn CO2 EOR flood has been monitored using seismic imaging and geochemical sampling methods. In each case, baseline surveys were conducted before injection began. The monitoring methods used include (Wilson and Monea, 2004):

1) Analysis of the geochemistry of reservoir fluids and gases, including major ions, alkalinity, and stable carbon isotopes (δ13C). The short-term geochemical processes that were observed following injection of CO2 were: a) decreased pH caused by CO2 dissolution; b) dissolution of carbonates and increase in alkalinity caused by lower pH of reservoir fluids; and c) increase in total dissolved solids and an increase in pH, δ13C, Mg2+, and Ca2+ caused by mineral dissolution;

2) Seismic imaging methods including such time-lapse seismic data as: a) surface 3D 3-component seismic reflection surveys; b) surface 3D 9-component seismic reflection surveys for 4-patterns; and c) 3D 3-component vertical seismic profiles (VSP) for a single well. Also several non-repeat seismic surveys were conducted, including horizontal and vertical cross-well tomography surveys and vertical seismic profiles;

3) Microseismic monitoring is conducted using eight triaxial geophones cemented in a vertical well within 50 m of an injection well. Background seismicity was measured for five months prior to the start of injection into the nearby well and once injection began associated microseismicity was detected. Most seismic events that were detected appear to be associated with changes in production or injection where local pressure transients might be expected; and

4) Soil gas sampling was conducted on a 360 point grid and included analysis of: a) CO2, O2, CO2 flux, which showed seasonal variations presumably due to standard metabolic pathways; b) hydrocarbons which showed temporal variations that were not easily explained; and c) tracer gases such as radon, helium, and thoron which showed consistent spatial and statistical distributions, indicating that leakage was not taking place.

Project Costs

In the four years from the beginning of the project to 2004, a total of CAN $16.38 Million was spent on the project in four different areas (Table 25):

Table 25. Total project costs per theme over project life: 2000-2004 in CAN$Millions. Theme 1: Geological characterisation of the geosphere and biosphere; Theme 2: Prediction, monitoring and verification of CO2 movements; Theme 3: CO2 storage capacity and distribution predictions and the application of economic limits; and Theme 4: Long term risk assessments of the storage site. (Wilson and Monea, 2004).

Theme 2000 2001 2002 2003 2004 Total
1 $0.08 $0.27 $0.84 $1.64 $0.21 $3.04
2 $2.61 $2.42 $1.92 $1.93 $0.24 $9.11
3 $0.09 $0.43 $0.69 $0.92 $0.14 $2.27
4 $0.08 $0.27 $0.40 $0.93 $0.28 $1.95
Total over Project Life =         $16.38


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