This is an unusual article in a couple of ways. First of all, it is by some distance the longest that I have added to OilVoice and secondly it's only edited by me but written by my colleagues at Petrenel (www.petrenel.com).
I hope you find it useful: if you have any questions, please contact Stewart Whiteley or Anna Smith.
Carbon Capture and Storage: Options, Current Projects and Costs
Anna Smith and Stewart Whiteley
Petrenel, Silwood Park, Ascot, UK
www.petrenel.com
Climate change is a major global issue and its potential disastrous consequences are of concern for many countries. Through the Kyoto protocol, most industrialized countries made a commitment to reduce greenhouse gas emissions. More recently a climate change accord was finalised in June 2007 at the meeting of the Group of Eight nations in Germany. The G8 Summit Declaration stated the urgent need to “develop, deploy and foster the use of sustainable, less carbon intensive, clean energy and climate-friendly technologies in all areas of energy production and use, including renewable energies, carbon capture and storage, clean coal and nuclear power.”
According to the Summit Declaration, there’s a commitment “to take strong and early action to tackle climate change in order to stabilise greenhouse gas concentrations at a level that would prevent dangerous anthropogenic interference with the climate system.” G8 countries would pursue major cuts to greenhouse gases emissions and would seriously consider the possibility of halving global emissions by 2050. Against this background, the UK Government has committed to making an ambitious 60% reduction in UK Carbon Dioxide (CO2) emissions from 1990 levels by 2050, i.e. reducing emissions of carbon dioxide per head from around three tonnes of Carbon per year in 1990 to around one tonne of Carbon per year in 2050. Carbon Capture and Storage (CCS) is an approach to reducing CO2 emissions from large sources by capturing it before emission to the atmosphere, and storing it underground. It is considered by the Intergovernmental Panel on Climate Change (IPCC) to be an option in the portfolio of mitigation measures to achieve stabilisation of atmospheric greenhouse gas concentrations. The CCS process involves separating CO2 at the source of emission, transporting it to the storage location and isolating it from the atmosphere for a long-term period. Currently there are a wide range of scientific, technological, economic, safety and regulatory issues connected to carbon sequestration and there is a need for further research to address gaps in our knowledge.
Carbon Capture Options
A number of techniques (see Exhibit 1) have been developed to capture Carbon Dioxide emitted from industrial plants and processes and prevent it entering the atmosphere. The techniques invariably involve separating the Carbon Dioxide (or pre-combusted Oxygen) from other gases to produce a relatively pure post process or post combustion stream of CO2 that can then be transported and stored at minimum cost. Carbon Dioxide produced by the burning of fossil fuels with air can be captured before combustion (pre-combustion capture), or after combustion (post-combustion capture). Extracting Oxygen from air before combustion (Oxyfuel) also produces a relatively pure post combustion CO2 stream. Various industrial processes also give rise to relatively pure CO2 streams including the treatment of natural gas to remove CO2 or the conversion of Coal or Gas into liquid hydrocarbons.
Post-Combustion Scrubbing/Capture
Low pressure CO2 is removed from exhaust gas after combustion by separating CO2 from flue-gas using an amine absorbent. This technology can be retrofitted to existing equipment. It is commercially available on a large scale (for example Power plants with 500MW+ of generating capacity), but at present is the most expensive technique. It is being considered for the RWE N-power “clean coal” power plant project at Tilbury in the UK.
Pre–Combustion Decarbonisation (Hydrogen)
CO2 is captured from a mixture of hydrogen and CO2 formed by partial oxidation of the fuel in a reformer. The CO2 is compressed for storage and the hydrogen, which is produced as an intermediary product, can then be burnt to produce electricity and heat, mixed with natural gas, used to power fuel cells, or used as chemical feedstock.
A new build Integrated Gasification Combined Cycle (IGCC) power plant producing a pure stream of CO2 is a cheaper option than a retrofit of a power station with post-combustion capture. This technology needs further research and development. It has been proposed for use in BP’s Decarbonised Fuels Project involving carbon capture at the Peterhead Power Plant and storage of the captured CO2 in the Miller Field.
Oxyfuel or Oxygen-Fired Combustion
Fossil fuel is burned in the presence of pure oxygen, which has been separated from air, to produce a flue gas containing CO2 and water, which are readily separable. A similar technique is used in steel making. At present it is the most competitive and preferred technology for Carbon Capture in coal fired power stations. It has potentially lower capture costs, but needs further development.
CO2 Removal from Natural Gas
CO2 separation is achieved using membranes, solid adsorbents (zeolites) and cryogenics. This technology is widely used in food processing and by chemical industries, in particular for the separation of CO2 from natural gas. There are high capital costs of installing post combustion separation systems and a 25-35% energy increase. A new CO2 removal technology involving cryogenic separation is being developed in Australia by Cool Energy. CO2 is extracted by reducing the temperature of the gas stream after passing it through a valve that drops the pressure and reduces the temperature to below the CO2 freezing point. The solid CO2 separates from the vapour stream by gravity and drops to the bottom of the vessel where the CO2 is then heated and removed as liquid. The advantage of this process is that it does not involve chemicals and solvents and eliminates concerns about corrosion. Compared to other CO2 removal processes, it has fewer components and lower capital and operating costs. Cool Energy expects to operate a commercial plant within 18 months.
Combustion Technologies
There is a lot of interest in CCS technology from producers and generators of energy from coal. Coal, because of its abundance and cheapness, makes an attractive energy source for many countries, including China, India and America. Coal is also the dirtiest energy source in terms of emitting CO2. It produces around 40% of CO2 emissions from energy use. There are some advances in conventional coal-fired steam generation, such as ultra supercritical and ultra supercritical steam generation (USC), where supercritical pressure (3500 psia) and high temperatures at or above 593°C (1100 F) are used. This method reduces CO2 emissions by a fifth and increases efficiency by 39-46% for supercritical and up to 50% for ultra super critical power plants, according to the World Coal Institute. In comparison, conventional boilers run at about 30-38% efficiency.
An Integrated Gas Combined Cycle (IGCC) power plant produces synthetic gas (Syngas), from high-sulphur coal, heavy petroleum residues and biomass via partial oxidation. Syngas consists mainly of carbon monoxide and hydrogen. The impurities are removed from the coal gas before it is combusted, which results in fewer emissions (SOx, NOx, mercury and particulate emissions). Syngas can be burned for electricity generation, or used as a fuel in other applications, such as hydrogen powered fuel cell vehicles. Up to 100% of the carbon dioxide can be captured from IGCC plants, making the technology suitable for carbon dioxide storage. IGCC can achieve efficiencies of 42-46%.
In comparison, combined heat and power (CHP) power plants (cogeneration) can achieve over 80% overall efficiency, because CHP captures the heat that would otherwise be rejected in traditional energy generation. CHP simultaneously generates electricity and usable heat and it can use both fossil and renewable fuels. It is a form for decentralised energy technology, supplying heat and power at the point of use and avoiding energy losses in transmission.
The cost of generating electricity by an integrated gas combined cycle process with carbon capture is 35% more expensive than a pulverised-coal station without carbon capture. However generating electricity by pulverised-coal station with CCS is 60% more expensive than a pulverised-coal station without CCS.
Carbon Transport Options
It is possible to transport CO2 either by pipeline or tanker or both, pipeline being the most practicable option. The transportation of Carbon Dioxide by pipeline has been carried out for many years in connection with the use of Carbon Dioxide for Enhanced Oil Recovery. The USA has an extensive Carbon Dioxide pipeline transportation network taking natural Carbon Dioxide from the Rocky mountain area to oil fields in Texas, Colorado and Wyoming. Carbon Dioxide is most efficiently transported as a dense phase liquid and most Carbon Dioxide pipelines are operated at high pressures of typically 80 bar or over.
Carbon Storage and Utilisation Options
Exhibit 2 illustrates some of the options for Carbon Storage and utilisation.
Industrial use
Industrial use of CO2 has many useful applications, such as in the refrigeration and freezing of food products, fire extinguishing systems, carbonation of soft drinks, as feedstock in industrial applications, production of urea, plastics and rubber, and use in greenhouses. However the volume of CO2 emissions from large sources is much greater than industrial processes are able to utilise.
Ocean Storage
Some researchers have proposed the storage of CO2 in the deep ocean by injecting CO2 at depths below 3000m where it will be denser than water, and thus would be gravitationally stable. Additionally, it is thought that CO2 hydrate formation will impede the movement of CO2, which would finally be captured in a CO2 aqueous solution by diffusion. These assumptions have not been proven by experiments and ocean storage is in the research stage.
Deep oceans are the largest ecosystem on earth and one of the largest reservoirs of biodiversity, yet one of the least studied. There could be significant detrimental environmental impacts from CO2 injection on marine ecosystems. CO2 injection would produce a measurable change in ocean chemistry; and simulation models project a significant increase in acidity. Over centuries, ocean mixing will result in reduced isolation of injected CO2, and there will be a gradual release of CO2 into the atmosphere.
Experiments studying effects on marine organisms near the ocean surface show that adding small quantities of CO2 reduces rates of calcification, reproduction, growth, oxygen supply and mobility and increased mortality. Immediate mortality is expected close to injection points or CO2 lakes. The chronic effects on ocean ecosystems over large areas and long time scales have not been studied and it is currently unclear how or whether marine species and ecosystems would adapt to the sustained chemical changes as a result of CO2 injection. For these reasons, ocean storage is not considered to be a viable option by the majority of scientists.
Mineral Carbonation
Mineral carbonation (see Exhibit 3) involves CO2 removal from flue gasses and the fixation of CO2 using alkaline and alkaline-earth oxides, such as Magnesium Oxide (MgO) and Calcium Oxide (CaO), which are abundant in silicate rocks such as Serpentine and Olivine and in small quantities in waste streams (steel slags and ashes). Chemical reaction produces stable carbonates – Magnesium Carbonate (MgCO3) and Calcium Carbonate (CaCO3 – limestone), which can be disposed of in silicate mines or reused for construction.
The process is however currently energy intensive and research is focusing on the reduction of energy usage and the acceleration of reaction rates. Mineral carbonation would be most efficient if sources of CO2 are placed near outcrops of Serpentine. Assessments of technical feasibility, energy requirements, silicate reserves, environmental impact of mining and waste disposal are needed before the storage potential of carbon mineralisation can be properly evaluated.
Geological Storage
Several options for subsurface CO2 storage are being considered, as illustrated in Exhibit 4, such as depleted oil and gas reservoirs, enhanced oil and gas recovery, deep saline formations, and enhanced coal bed methane. In order to achieve large storage capacities underground, CO2 needs to be stored above its supercritical pressure, the pressure at which the gas liquifies. CO2’s supercritical pressure is about 74 times atmospheric pressure at 31C° and therefore typically needs to be stored at depths of 800 meters or more below the surface.
Enhanced Oil Recovery
Injection of CO2 for the purpose of EOR has been used by the oil industry since the early 1970’s, not for the purpose of CO2 storage, but to increase oil production. EOR techniques allow the extraction of oil which would otherwise not be recovered. It is the oldest technique among other carbon sequestration options and is commercially proven. There are around 70 projects worldwide, injecting a total of 33 Mt of CO2 per year. Most of the CO2 comes from natural sources, and about 3Mt/year from industrial, sources. Most CO2 Enhanced Oil Recovery takes place in the USA. Other enhanced oil and gas recovery projects are run in Turkey, Mexico, and the Russian Federation. The most significant commercial CO2 EOR project with a clear CO2 sequestration objective is in the Weyburn field in Canada. It is estimated that 120-130 Gtonne of CO2 could be stored globally as a result of EOR. However there could be relatively high leakage risks with this sequestration option, due to the poor condition of old and abandoned oil wells, and infrastructure. There is extensive geochemical, petrographic and core analysis evidence that shows that CO2, injected into oil fields for EOR, reacts with the water-rock system, causing carbonate mineral dissolution in the subsurface.
Techniques for substantially increasing the storage capacity over the amounts normally captured in EOR projects are being developed, such as adding injection horizons, injecting CO2 into an aquifer below the reservoir, injecting into the capillary transition zone or into residual oil zones. Modifications of water-alternating-gas injection schemes may also allow greater CO2 storage while at the same time controlling the cycling of injected CO2.
Depleted Gas and Oil Fields
In a depleted gas field, the CO2 occupies some of the void space that had previously been occupied by the natural gas. Some depleted gas fields are reused as buffer stores for natural gas production. The techniques of gas re-injection can be adapted to store CO2 in depleted fields. The storage potential in depleted gas fields is much larger in comparison to depleted oil fields as there are more of them. Globally, 690-900 Gtonnes of CO2 (almost 50 years of current global CO2 emissions) could be stored in depleted gas fields, substantially more than in depleted oil fields (about 130 Gtonne). Carbon storage in depleted oil & gas fields has a potential to be a cost effective and environmentally safe carbon sequestration option. Oil and gas fields have contained large volumes of buoyant fluids over geologic periods of time which suggests both adequate seal integrity in the past and that the reservoir has a certain level of porosity and permeability as well as a reasonable capacity. Extensive databases exist, as the geological structure and physical properties of most oil and gas fields have been extensively studied and characterised. In addition some of the infrastructure and wells may be used for CO2 storage injection.
CO2 leakage risks need to consider the potential breach of reservoir seal integrity by wells. The sealing of old abandoned wells, either with a mud-laden fluid or with cement plugs, may not be sufficient to contain a reactive and buoyant fluid like CO2. In many cases, even locating the old abandoned wells may be difficult. A reservoir seal’s integrity is more assured in a gas field than in an oil field. Storage in shallow reservoirs may not be possible because of doubtful seal integrity. A detailed understanding of the complex physicochemical processes comprising CO2, water, oil, gas and reservoir rock, and the dispersion and ultimate fate of injected CO2 is necessary if carbon sequestration in depleted oil and gas fields is to be validated as a safe and economic sequestration option.
Deep Saline Formations
Saline formations are deep sedimentary rocks saturated with formation waters or brines containing high concentrations of dissolved salts. These formations are widespread, and the water is unsuitable for agriculture or human consumption. Saline formation waters are used in health spas, for producing low-enthalpy geothermal energy, and by the chemical industry but otherwise have little use. The injection of CO2 into deep saline formations is similar to injection into oil & gas fields. It is estimated that saline aquifers have the largest volume potential to store CO2 worldwide. The IEA Greenhouse Gas Research and Development Programme estimated in the early 1990s that the global potential for storage of CO2 in deep saline reservoirs is between 400 and 10,000 Gtonne CO2. This would account for 20-500% of the total expected emissions between 2000 and 2050. Deep saline aquifers have the advantage of the largest storage capacities, among other geological storage options. Deep saline aquifers are present in most countries, storage locations are not limited to hydrocarbon-bearing areas, and these areas are rarely penetrated by wells. However saline aquifers have not been extensively explored, characterised and assessed for CO2 storage. Geologic information about specific sites is more limited than for oil and gas fields, and formations do not have the same assurance as in oil and gas reservoirs that there is a seal with closure capable of preventing the upward migration of CO2. Injecting CO2 could increase the risk of migration of salty waters towards potable water areas, and if CO2 leakage to the surface occurs, there is a potential for mobilisation of heavy metals in the topsoil and contamination of drinking water.
Certain areas are not suitable for CO2 storage, such as volcanic areas, mountains and geothermally favourable areas, as well as crystalline and metamorphic rocks (i.e. granite). In very arid regions, deep saline formations may be considered for future water supplies for desalinisation. During site selection a precise characterisation of the baseline conditions is very important. To reduce uncertainties, a wide range of sensitivity runs using simulation models are necessary, together with benchmarking the results with observations from laboratory experiments, field monitoring and natural analogs covering different timescales.
Enhanced Coal Bed Methane
Another possible carbon sequestration option is to inject CO2 into deep, unmineable (too thin or too deep, usually deeper than 800 meters) coal seams. Enhanced Coal Bed Methane recovery involves injecting CO2, which is adsorbed in the coal and stored in the pore matrix of the coal seams, releasing the trapped Methane. Coal is the most abundant mineral fuel in the world. The quantity of Methane gas stored in this coal is estimated to range from 84 to 360 T m3 (2,976-12,640 tcf), many times greater than the world’s proven gas reserves in conventional gas fields. CO2 sequestration in un-mineable coal beds could be an attractive option because of the potential for enhanced Methane recovery, however this technology is in its infancy with limited field trials. One of several determining factors in selection of a storage site is coal permeability, which varies widely and generally decreases with increasing depth as a result of cleat closure with increasing effective stress. Coal cleats, the natural fracture system in coals, begin to shut at roughly 1,600 meters, significantly reducing permeability; therefore the window for coal sequestration is probably from about 800 to 1,600 meters. Tests have not been conducted below roughly 1,800 meters. In addition, coal’s tendency to soften and swell in the presence of CO2 can reduce permeability and injectivity by orders of magnitude or more.
More work is needed to understand how coal petrology affects the adsorption and release of gases, such as the deep structure of cleats, the primary permeability control, and the process of CO2 trapping in coals at temperatures and pressures above the critical point. It is not clear how the sequestration process varies in the presence of other gases, such as Nitrogen. Whilst, carbon dioxide appears to make coal cleats shut, Nitrogen enhances coal cleat dilation and permeability, but has no sequestration potential. The volumetric ratio of CO2:CH4 absorbance ranges from as low as 1 for mature (higher-rank) coals such as Anthracite, to as high as 17 for younger, immature (lower rank) coal such as Lignite.
Studies suggest that CO2 will remain trapped as long as the coal is never mined and pressures and temperatures remain stable. However, as with any geological storage option, disturbance or the formation could negate any storage. Conflicts between future mining and CO2 storage options are possible, particularly for shallow coals. A great deal of scientific uncertainty surrounds coal bed sequestration. In comparison to other sequestration options, this method carries the greatest risk in terms of long term storage and further research and field trials are needed to demonstrate the safety and economic viability of this carbon storage option.
Long-Term Storage?
The report on CO2 capture and storage by the IPCC states that in appropriately selected geological reservoirs, based on observations from engineered and natural analogues as well as models, there is a probability of 90%-99% that 99% of CO2 would be retained over 100 years and there is a probability of 66%-90% that 99% of CO2 would be retained over 1,000 years. If continuous leakage does occur, it could offset the benefits of CCS mitigating climate change. There are a few gaps in our knowledge of CCS processes, including long-term storage, migration and leakage. This would require an enhanced ability to monitor and verify the behaviour of geologically stored CO2.
Conclusions on CO2 Storage
Geological carbon dioxide injection has a potential to mitigate carbon emissions from current large sources during the transition to post fossil based energy system. Because of the novelty of the technology, research and monitoring of current projects would help to assess long term safety of geological carbon storage. There are still many questions about environmental risk, safety and the costs of deploying CCS on a large scale. There is a need for further research to address gaps in our knowledge about CO2 interaction and behaviour in the subsurface.
Each geological option has its own benefits and drawbacks. In comparison to other carbon sequestration options, the permanence of carbon storage in coal beds seems to be less certain and a lot more research is needed before it can be applied on a large scale. While deep saline aquifers offer the largest storage capacities, research studies suggest that depleted gas fields appear to be the safest option from a geological and environmental perspective. Careful site specific investigations are necessary to make judgments about the suitability of a particular site for CO2 sequestration. Whilst sometimes CCS technology is advocated as “proven”, offering “zero” or “clean coal” energy solutions, long periods would be required to prove or disprove with 100% certainty the safety and viability of the technology. CCS technology does not solve the cause of global warming by eliminating the production of CO2, but it could prevent CO2 from entering the atmosphere, hopefully over the long term. It is one option in the portfolio of different measures, such as increasing the energy efficiency of current technologies, energy conservation, development of renewable energy technologies and other measures in the attempts to mitigate climate change.
Current and Planned CCS Projects
Worldwide there are a number of planned and ongoing demonstration projects for CO2 storage in both oilfields and aquifers, as may be seen in Exhibit 5 and Exhibit 6.
CCS General Research & Development Projects
FutureGen is an initiative in the USA to build the world’s first integrated sequestration and hydrogen production research power plant. The project was initiated in 2003 by President Bush with the goal of validating the technical and economic feasibility of producing electricity and hydrogen from coal, while sequestering the carbon dioxide. The project will employ coal gasification technology integrated with combined cycle electricity generation and the sequestration of carbon dioxide emissions. The project will require 10 years to complete and will be led by the FutureGen Industrial Alliance, Inc., a non-profit industrial consortium representing the coal and power industries, with the project results being shared among all participants, and industry as a whole. In 2006, 12 possible sites were short listed to four (two in Texas and two in Illinois) and a final decision on the preferred site location is expected to be taken towards the end of 2007. In the 2007 Budget, the UK Government announced that it intends to launch a competition in November 2007 to develop the UK’s first commercial-scale demonstration of CCS, with the aim to be operational by 2014. The Government is currently engaged in designing a competition framework for the UK CCS demonstration. Participating companies would require additional support because of the uncertainties with costs of full scale deployment. In addition to set criteria, the project developer will also be expected to include proposals for knowledge and know transfer to third parties. The Government intends to award contracts shortly for the successful prototype projects under the Carbon Abatement Technology (CAT) strategy to develop technologies for fossil fuel use that abate emissions.
Enhanced Oil Recovery
Enhanced Oil Recovery (EOR), using largely natural sources of Carbon Dioxide, has been carried out in the USA since the 1980’s for essentially commercial reasons. Although these commercial CO2 floods have indirectly resulted in significant carbon sequestration, it is only since 2000 that EOR projects with the combined objectives of enhancing oil recovery and storing anthropogenic (man made) CO2 have been initiated.
The most significant commercial CO2 EOR project with a clear CO2 sequestration objective is in the Weyburn field in Saskatchewan, Canada. It uses a dehydrated and compressed high pressure stream of CO2 produced from the Dakota Gasification Company, near Beulah in North Dakota, shipped to Weyburn through a 325 km long 12-14” diameter pipeline, as illustrated in Exhibit 7.
The project started in 2000 and is expected to run for 25 years, storing 20 MtCO2 over the lifetime of the project. Weyburn is an excellent test site because scientists and researchers had access to an extensive set of subsurface data before CO2 flooding of the oil field commenced.
In the UK, BP have been considering capturing CO2 from a planned power station to be built at Peterhead near Aberdeen and shipping the fluid to the Miller Field in the Northern North Sea for Enhanced Oil Recovery. This project was however postponed in 2007 pending clarification of the UK Government’s support for CCS. There is a proposal to capture CO2 at a gas power plant at Tjeldbergodden, Norway. Released CO2 will be piped to the oil and gas fields Draugen and Heidrun in the Norwegian Sea, where it will be injected into the reservoirs for enhanced oil recovery.
Saline Aquifers
The first project to inject CO2 for the purpose of storage started in the Sleipner field, Norway, in 1996. Gas produced from Sleipner contains 9% of CO2 which is separated and injected into the Utsira sand, a saline water-bearing formation, about 800 meters below the seabed of the North Sea, as illustrated in Exhibit 8. The participating companies were encouraged to reduce their emissions by the Norwegian government, who introduced a carbon tax of about $50 per ton of emitted CO2. Over the lifetime of the project a total of 20 MtCO2 is expected to be stored (approximately 1 million tonnes per year).
From 2004, the In Salah Gas Project, Algeria, injects 1 million tonnes per year CO2 into a gas reservoir at a depth of 1800m, as may be seen in Exhibit 9. It is estimated that over the lifetime of the project there will be 17 MtCO2 stored.
In Alberta, Canada, injection of acid gas (CO2 and H2S) into deep saline aquifers has been practiced for about 15 years at over 40 sites. This has been undertaken to limit sulphur emissions and monitoring has been limited.
Small scale injection of CO2 into the brine bearing Frio formation near Houston, Texas, in the USA was carried out in 2004, with a total planned storage quantity of 1,600t CO2. This project gathered significant geological information and included modelling of predicted CO2 behaviour.
Statoil is planning a CO2 re-injection programme in the Snøhvit field in the Barents Sea. Natural gas will be piped onshore for processing and the separated CO2 will be sent to an aquifer under the gas field.
Depleted oil and gas fields
In 2007 Total announced plans – shown in Exhibit 10 - to carry out a pilot CO2 capture and sequestration project in the Lacq basin in south-western France. The project, calls for up to 150,000 metric tons of CO2 to be injected into a depleted natural gas field in Rousse (Pyrenees) over a period of two years from the end of 2008. CO2 emitted from a steam production unit at the Lacq gas processing plant will be captured and oxygen will be used for combustion rather than air to obtain a more concentrated CO2 stream that will be easier to capture. Once purified, the CO2 will be compressed and conveyed via pipeline to the depleted Rousse field, 30 kilometres from Lacq, where it will be injected through an existing well into a rock formation 4,500 metres under ground. CO2 injection is scheduled to begin in November 2008. The project, which will cost nearly 60 million euros, will be carried out in partnership with Air Liquide and in cooperation with the French Petroleum Institute (IFP), the French Bureau of Geological and Mining Research (BRGM) and others.
Other examples of CO2 injection into depleted oil and gas fields include:
• Casablanca (Spain): an offshore oilfield, no longer in production.
• Lindach (Austria): the Lindach shallow onshore gas field, situated at a depth of 500 metres, is used to store CO2 generated by industrial processes.
• K12B (CRUST Project (CO2 re-use for underground storage) (Dutch North Sea): the CO2 produced by the operation of this offshore deposit is directly injected back into the vacated gas field. This gas field is operated by Proned, a Gaz de France subsidiary. This is a small pilot project.
• Gulf of Mexico, South Eugene Island 330.
Enhanced Coal Bed Methane
There has only been one commercial scale ECBM project in the world to date (San Juan Basin in the U.S.A, now discontinued.) although there are a number of completed and ongoing pilot projects and field trials in Canada (Alberta-ECBM project), Japan (Hokkaido project), Poland (RECOPOL project), and China (Qinshui Basin).
The RECOPOL project was an EU co-funded combined research and demonstration project to investigate the possibility of permanent subsurface storage of CO2 in coal. RECOPOL stands for: ‘Reduction of CO2 emission by means of CO2 storage in coal seams in the Silesian Coal Basin of Poland’. The project started in November 2001 and development of the pilot site, involving injection into underground coal seams at a depth of 1050-1090 m, several hundreds of meters below the deepest mine workings of the Silesia mine, began in summer 2003. An existing Coal Bed Methane well was cleaned up, repaired and put back into production. A new injection well was drilled 150 m from the production well. The whole scheme is shown in Exhibit 11.
Production started in the first half of June 2004, to establish a baseline production and first injection tests took place in the first week of July. CO2 break-through occurred in late 2004 and the trial was completed in 2005. A total of 203 tonnes of CO2 was brought in by trucks and injected (originally 1000 tonnes had been planned). CO2 was successfully injected in to the coal bed but CO2 induced swelling was significant and the injectivity was lower than expected. Long term trapping of the CO2 could not be demonstrated and enhanced methane production was lower than predicted.
Other ongoing projects include:
• Fenn Big Valley, Alberta, Alberta Research Council, 1997 – ongoing (CO2 and N2)
• Red Deer, Alberta, Suncor (CO2), from 2002
• Coal-Seq Project, Burlington Resources and BP, 1989 – ongoing (CO2 and N2)
• Simon Field, San Juan Basin, Colorado, BP Amoco, 1993-2002 (N2)
• Qinshui Project, China, ARC and China, 2002 – ongoing (CO2)
• JAPAN CO2 Sequestration in Coal Seams Project (JCOP), Japan, 2003 –ongoing.
Costs
The costs of carbon capture, transport, and storage have been reviewed by a number of institutions and organisations and indicative numbers have been widely reported in the public literature. Published costs are usually reported as cost per tonne of CO2 sequestered and calculated on an annual basis (opex plus capital repayment plus interest charge) though this is by no means universal. However whilst this publicly available information provides a good qualitative indication of costs, it needs to be treated with some caution. This said, the tables in Exhibit 12 and Exhibit 13 indicate some of the costs involved in CO2 capture and storage.
Even in the specialist communities there is a considerable controversy about the investment and operating costs associated with CO2 capture and storage. There are few common ground rules or standards, outside specific industries, on how to calculate CCS costs, and assumptions are rarely documented in sufficient detail to make reliable comparisons. It is often unclear whether reported unit costs include contingency, both capital and operating costs, are discounted or undiscounted, include interest payments, or take account of the carbon footprint of the project. Many of the projects undertaken to date are small to medium scale demonstration projects and extrapolation of unit costs obtained from these projects to an industrial scale may result in a considerable overestimation of costs. Some of the CCS techniques, particularly those associated with Carbon Capture, are novel and cost estimates are consequently inherently immature and inaccurate. Ongoing research is expected to significantly reduce capture costs in the short to medium term. Another very important issue is that costs commonly referenced in the public literature are often a few years old. CCS activities, as they utilise similar resources to the upstream oil and gas industry, will have been subject to the same substantial material and service cost inflation that has occurred in recent years. The Upstream Capital Cost Index, for example, has increased by at least 70% since the extensively referenced 2005 IPCC report was published.
CCS costs can conveniently be split into the cost of capture, transportation and storage. Capture costs vary widely depending on the industrial application. Some industrial processes for example Coal to Liquids conversion or natural gas processing generate relatively pure CO2 streams as part of the process and in such circumstances capture costs can form a relatively small part of the overall project costs. Capturing CO2 emitted from existing large coal fired power stations however requires considerable investment in additional pre or post combustion gas processing facilities and in such cases capture costs can be substantial and account for a large part of the overall project cost.
CO2 transport (pipeline) costs can be relatively well defined and are largely a function of the quantity to be transported and the distance to the storage location. Storage costs will depend on site-specific features (onshore versus offshore, reservoir or aquifer depth) and geological characteristics (permeability and formation thickness). In the report, published in 2005, the IPCC presented a range of typical Unit Costs for the different CCS components (based on data from 2002). The costs in US$/CO2 avoided of the separate components in the above mentioned tables cannot simply be summed to calculate the costs of the whole CCS system. All numbers are representative of the costs for large-scale, new installations, with natural gas prices assumed to be 2.8-4.4 US$GJ-1 and coal prices 1-1.5 US$ GJ-1. Over the long term, there may be additional costs for remediation and liabilities (IPCC, 2005). It is emphasised that since these cost estimates were prepared by the IPCC there has been significant cost inflation and that unit costs would currently be expected to be higher than those shown in the tables. As an indication of how costs have changed, a recent 2006/2007 evaluation of over 20 potential onshore CCS sites with minimal capture requirements (compression only) gave unit disposal costs of US$ 25 to 110 /tonne and a recent 2007 pre-feasibility study for an offshore project involving pre-combustion capture gave a Unit disposal cost of US$ 90/tonne. Disposal costs may, in some cases, be partly offset by revenue generated from the use or sale of CO2 for Enhanced Oil Recovery. However it is emphasised that EOR opportunities globally constitute a relatively small potential CO2 sink when compared against the total quantities of anthropogenic CO2 being produced from point sources. In the USA, for example, about 40 Million tonnes of CO2 is currently used annually for CO2 EOR and this is forecast to grow to around 200-250 Million tonnes per year by 2020. By comparison the total emissions from industrial sources in the State of Texas alone in 2002 amounted to 350 Million tonnes. CO2 Enhanced Oil Recovery, therefore, whilst clearly an important and preferred sequestration technique in the short to medium term where a CO2 market is present or can be developed, is likely to play a sub-ordinate role in most carbon storage projects.
References:
Friedmann 2005: University of Maryland.
FutureGen Alliance. (http://www.futuregenalliance.org/about.stm)
IEA Greenhouse Gas R&D Programme: Depleted Oil & Gas Fields for CO2 Storage;
IEA 2004: Prospects for CO2 Capture and Storage.
IEA Greenhouse Gas R&D Programme: CO2 Injection and Storage Activities.
IPCC 2005: CO2 CCS; Carbon Mitigation Initiative, Princeton University;
IPCC 2005: Special Report on Carbon Dioxide and Capture.
Karstad 2002: Geological Storage, including costs and risks, in saline aquifers.
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Author:
David Bamford
Sunday, June 22, 2008 15:07